HomeMy WebLinkAboutStaff Report 2512-5603CITY OF PALO ALTO
Finance Committee
Regular Meeting
Tuesday, April 21, 2026
Agenda Item
2.Staff Recommends the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution Approving the FY 2027 Electric Financial Forecast, Approving a
Reserve Transfer, and Amending Electric Rate Schedules E-1 (Residential Electric Service),
E-1 TOU (Residential Time of Use Electric Service), E-2 (Residential Master-Metered and
Small Non-Residential Electric Service), E-2-G (Residential Master-Metered and Small
Non-Residential Green Power Electric Service), E-4 (Medium Non-Residential Electric
Service), E-4-G (Medium Non-Residential Green Power Electric Service), E-4 TOU
(Medium Non-Residential Time of Use Electric Service), E-7 (Large Non-Residential
Electric Service), E-7-G (Large Non-Residential Green Power Electric Service), E-7 TOU
(Large Non-Residential Time of Use Electric Service), E-14 (Street Lights), E-16
(Unmetered Electric Service), E-EEC-1 (Export Electricity Compensation), and E-NSE-1
(Net Metering Net Surplus Electricity Compensation); CEQA Status: Not a project. Staff
Presentation
1
Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Utilities
Meeting Date: April 21, 2026
Report #: 2512-5603
TITLE
Staff and the Utilities Advisory Commission Recommends the Finance Committee Recommend
that the City Council Adopt a Resolution Approving the FY 2027 Electric Financial Forecast,
Approving a Reserve Transfer, and Amending Electric Rate Schedules E-1 (Residential Electric
Service), E-1 TOU (Residential Time of Use Electric Service), E-2 (Residential Master-Metered
and Small Non-Residential Electric Service), E-2-G (Residential Master-Metered and Small
Non-Residential Green Power Electric Service), E-4 (Medium Non-Residential Electric
Service), E-4-G (Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium
Non-Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-
7-G (Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-Residential
Time of Use Electric Service), E-14 (Street Lights), E-EEC-1 (Export Electricity Compensation),
and E-NSE-1 (Net Metering Net Surplus Electricity Compensation); CEQA Status: Not a
project.
RECOMMENDATION
Staff and the Utilities Advisory Commission (UAC) recommends the Finance Committee
recommend that the City Council adopt a Resolution (Attachment A):
1. Approving the Fiscal Year 2027 Electric Utility Financial Forecast shown in this staff report
and attachments; and
2. Approving the transfer at the end of FY 2026 of up to $5 million from the Electric Utility
Distribution Operations Reserve to the Electric Utility Capital Reserve; and Amending
Electric Rate Schedules (Attachment A, Exhibit 1) effective July 1, 2026 (FY 2027):
a. E-1 (Residential Electric Service)
b. E-1 TOU (Residential Time of Use Electric Service)
c. E-2 (Residential Master-Metered and Small Non-Residential Electric Service)
d. E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service
e. E-4 (Medium Non-Residential Electric Service)
f. E-4-G (Medium Non-Residential Green Power Electric Service)
g. E-4 TOU (Medium Non-Residential Time of Use Electric Service)
h. E-7 (Large Non-Residential Electric Service)
2
i. E-7-G (Large Non-Residential Green Power Electric Service)
j. E-7 TOU (Large Non-Residential Time of Use Electric Service)
k. E-14 (Street Lights)
l. E-EEC-1 (Export Electricity Compensation) to reflect forecasted avoided cost for FY
2027, and
m. E-NSE-1 (Net Metering Net Surplus Electricity Compensation) to reflect avoided
cost for CY 2025.
EXECUTIVE SUMMARY
This staff report provides the Finance Committee with a financial forecast for the Electric Utility
and provides an overview of the utility’s operations costs, capital costs, and debt and includes
recommended rate adjustments required to maintain the utility’s financial health. This work is
done annually as part of the budget and rate-setting cycle – this includes a proposed 6%
increase for FY 2027. Beyond 2027, the forecast shows additional increases that are slightly
lower than the forecasts prepared last year.1 Table 1 shows the proposed rate increases for FY
2027 through FY 2031. For the median consumption level, the CPAU residential electric monthly
bill is about $94.04. This is about 50% lower than the monthly bill for a PG&E customer with the
same consumption level, based on rates as of January 1, 2026.
• Attachment A contains a draft Council Resolution.
• Attachment A, Exhibit 1 contains a redline of the proposed changes to the Electric Utility
rate schedules.
• Attachment A, Exhibit 2 contains a summary of the financial details and CIP budgets
underlying the forecast.
• Attachment A, Exhibit 3 contains redlined Electric Utility Reserves Management
Practices describing the reserves and showing non-substantive revisions to align with
the state’s retitled “Cap and Invest” Program.
• Attachment B contains a summary of the Electric Utility communications strategy and
samples.
Table 1: Current Year (FY 2026) & Forecasted Overall Rate Trajectory from FY 2027 to FY 2031
FY 2026 Plan (prior year) 6% 6% 8% 8% 6% -
The drivers for this change relative to last year’s forecast include a new warehouse and laydown
1 The current year (FY 2026) Financial Forecast for the Electric Utility (approved June 16, 2025) is described in the
Finance Committee Staff Report 2412-3870 from April 15, 2025:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=64778&dbid=0&repo=PaloAlto
Changes made after the Finance Committee Staff Report are described in the City Council Report 2411-3776:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83992&dbid=0&repo=PaloAlto
Attachment D, Exhibit 1 to City Council Report 2411-3776 includes financial and Capital Improvement Program
(CIP) details: 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
Staff Report 2512-5784: https://cityofpaloalto.primegov.com/viewer/preview?id=0&type=8&uid=cb659172-6169-476a-
bd74-8b8d75c39d35
3
yard for grid modernization, replacement of emergency generators, and a new approach to grid
modernization described to the Utilities Advisory Commission on January 7, 2026.3 The new
“when and where” approach to grid modernization provides the opportunity to delay costly
system upgrades until electric customers are ready to replace gas appliances or install EV
chargers. This approach lowers the expected rate increases. The rate increases in the outer years
of the forecast could change as the Council finalizes plans for debt financing grid modernization
costs.
In the current year, FY 2026, below are key summary variables and the current and expected
trends informing the Electric Utility forecasted rates:
• power supply costs are expected to be slightly lower than forecasted a year ago; the main
driver for this shift is higher wholesale revenues for the City due to extremely high market
prices for resource adequacy capacity and renewable energy credits.
• The City’s load (consumption) for the current year is forecasted to be about 14% higher
than previously forecasted but is then conservatively expected to be relatively flat over the
next several years. Meanwhile, output from the City’s hydroelectric resources is forecasted
to be roughly equal to long-term average levels over the next few years.
• Hydroelectric revenue continues to be a large source of uncertainty in the City’s supply cost
forecasts. In the next five years, staff expects steadily increasing electric supply costs due to
increasing transmission access charges, rising renewable portfolio standard requirements,
and increasing resource adequacy purchase obligations.
• Capital spending and distribution system maintenance spending is rising due to inflationary
increases for material and construction, Foothill undergrounding project, grid modernization,
a dedicated fiber backbone for system protection, and an upgrade to the Hanover
Substation. Staff expects grid modernization and related capital costs to be offset after a
series of debt financing with the first bond issuance in FY 2027.
The City has recently undergone an assessment by Baker Tilly on various utility reserves and the
appropriate policies both overseeing reserve targets and administrative of reserve funds1. This
forecast does not take any of the recommendations into consideration specifically. Staff expect
to review the assessment and return during FY 2027, in advance of FY 2028 to the UAC and
Finance Committee to evaluate the appropriate policy updates for CPAU specifically.
Adjustments to reserves are recommended including:
• A transfer of an additional $6 million into the Hydroelectric Rate Stabilization Reserve
from the Operations Reserve to bring the reserve above the target and closer to the
current upper limit of the reserve. The higher balance will help ensure rate stability in
any upcoming drier years. The Hydroelectric Rate Stabilization Reserve has a balance of
$18.8 million, or approximately equal to the reserve’s target level of $19 million and is
3 Staff Report 2512-5638 Fiscal Year 2026 Mid-Year Electric Grid Modernization Update
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=85181&dbid=0&repo=PaloAlto and presentation on
pg. 9 https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=85181&dbid=0&repo=PaloAlto
4
used to manage the supply cost impacts associated with variations in generation from
hydroelectric resources.
• Electric Special Projects Reserve will increase during FY 2026, from $30.1 million to $31.2
million as a result of repayments for AMI work from the Water and Gas Utilities.
• Electric Distribution Operations Reserve is forecasted to be low at the end of FY 2026
because it reflects grid modernization costs, commitments, and reappropriations
planned to be reimbursed through the debt issuance. Staff expects that debt will be
issued in FY 2027 to cover the grid modernization costs already spent and planned over
the period FY 2025-FY 2028. On a combined basis, the Electric Distribution and Supply
Operations Reserves are within the guideline range and are forecasted to remain within
the guideline range throughout the five-year forecast period, FY 2027 to FY 2031.
Staff updated the forecast for the electric supply purchase costs for FY 2027. Net electric supply
purchase costs for the period are anticipated to be 1% higher ($0.85 million) than forecasted in
the FY 2026 Financial Forecast. The cost increase is due to reduced revenue from Renewable
Energy Credit sales as well as load growth. The load forecast for FY 2027 is 11% higher (94 GWh)
than forecasted for that period in the FY 2026 Financial Forecast.
BACKGROUND
The City of Palo Alto Utilities (CPAU) provides electricity, water, wastewater, natural gas, and
fiber optic services to the Palo Alto community. The Public Works Department also provides
refuse collection and processing for recycling, compost and garbage, wastewater treatment and
stormwater management. The City’s primary goals are to manage these services in a way that
ensures continued safe, reliable, environmentally sustainable, and cost-effective operations. As
a locally owned municipal utility, CPAU’s rates are designed to recover the costs of purchasing
and delivering these utility services to customers. The City strives to be transparent with
utilities customers about the reason for rate changes, including explaining the cost drivers,
benefits to customers, what the City is doing to keep costs affordable for ratepayers, and the
services and programs provided by the City to help customers keep utility bill costs low.
Attachment B outlines CPAU’s plan for communicating rate changes to customers. Staff are
presenting an overview of the financial forecast and rate change proposal for each utility
service to the Finance Committee prior to City Council review and approval in June 2026.
ANALYSIS
FY 2025 Costs and Revenues
Annual expenses for the Electric Utility increased during the most recent recorded time period
of FY 2020 through FY 2025. Electric supply costs increased as new renewable projects came
online, and transmission access charges have continued to rise as improvements are made to
the California grid. Capital improvement and operational expenses have increased due to
construction inflation, increased investment in the electric system, and the cost of contract field
crews to cover operational and construction work due to challenges with filling vacancies and
multi-year construction projects such as Foothills undergrounding and grid modernization.
In FY 2025, electric supply costs were moderately lower than budgeted, despite the City’s total
5
load being significantly higher than forecasted. This variance was driven primarily by the
continuation of favorable hydrological conditions and high resource adequacy (RA) market
prices. The record levels of precipitation the state received during FY 2023, followed by two
years of roughly average precipitation levels, led to reservoirs being significantly fuller than
normal in FY 2025, producing somewhat higher than average levels of hydroelectric generation
and enabling the City to sell some surplus generation to other utilities. In addition, the City is a
net seller of RA capacity, and extremely high RA prices during FY 2025 enabled the City to
realize significant RA sales revenue. Electric supply purchase costs increased 5% per year on
average from FY 2020 through FY 2025,5 and other operational costs increased 12% per year on
average over the same period.6
Table 2 compares the forecast vs. actual costs for FY 2025. Actuals were $56.4 million greater in
increased revenues or decreased costs. This primarily is because of a change in the timing of
grid modernization capital costs. While Table 2 shows an overall surplus, these funds were used
as operating reserves allowing the City to postpone debt financing of grid mod investments
until FY 2027. This surplus contributes to the lower than previously forecast rate adjustments in
future years (Table 1).
Table 2: FY 2025 Actuals vs. Prior Year’s Forecast ($000)
Higher revenues from higher load, surplus
sales, and transfers
(12,712) Revenue increase
Lower electric supply costs (4,070) Cost decrease
Lower operational costs (8,353) Cost decrease
Lower than forecast capital investment (31,274) Cost decrease
Forecasts
Overview
The FY 2027 forecasts are developed by escalating non-power costs from FY 2026 by estimated
rates of inflation as described in this report. Power costs are forecast separately and are
summarized below.
In FY 2026, total revenues are expected to be slightly greater than FY 2025 actuals. Sales
revenues are forecasted to increase by $12.6 million or 6.7% from FY 2025 actuals due to load
growth and the 6% rate adjustment effective July 1, 2025. All other revenues and transfers are
forecasted to be basically flat compared with FY2025. Surplus energy and RA sales were $37.4
million in FY2025 and are forecasted to be $37.5 million in FY 2026.
Compared with FY 2025, supply purchase costs are forecasted to be $18.8 million, or 17%,
higher in FY 2026. This forecasted increase in purchase costs is driven by higher resource
adequacy purchase costs and the significant increase in the City’s load, which has resulted in
greater market power purchase costs.
5 Electric Supply Purchases plus Surplus Energy Costs less Surplus Energy Sales.
6 Operating costs include Administration, Customer Service, Engineering, Operations & Maintenance, Resource
Management, and Rent less Discounts/Uncollectible.
6
Operations costs in FY 2026 are forecasted to be $9.3 million, or 22% higher than FY 2025
actuals. This large increase is due mainly to increases in Demand-Side Management program
expenses ($2.6 million) and increased engineering and operation and maintenance costs ($6.7
million). Operation expenses are increasing primarily due to a higher volume of contract work
being performed for system inspection and compliance maintenance (i.e. pole testing and
crossarm replacement). Vacancy savings will offset a portion of the contract work. Allocated
charges from other City departments are forecasted to increase 7% based on adopted FY 2026
budget numbers.
The FY 2026 estimate for the Capital Improvement Program (CIP) budget is $69.5 million,
including $30.5 million for grid modernization. In FY 2026 the Electric Utility’s reserves will fund
the capital investment, including grid modernization, while in FY 2027 CPAU plans to issue the
first grid modernization bond which will offset the capital costs paid for by customer rates or
Electric Utility reserves in that year. For capital costs, grid modernization investments are
expected to be substantial in FY 2027 through FY 2031 with bond financing occurring in FY
2027. In the longer term, debt service costs will grow as a result of the repayment of principal
and interest on the grid modernization bonds. However, the capital and debt service costs
combined are expected to be relatively steady from year to year until 2030 when the second
grid modernization bond is expected.
From FY 2026 through FY 2031, total revenues (rate revenues and revenues from other sources)
are expected to increase by 3.8% per year on average. Total supply purchases and operating
expenses are expected to increase by 3.2% on average annually. Capital investment and debt
service costs are rising due to the grid modernization project. In total, rates need to increase
6.0% in FY 2027 to cover rising costs, grid modernization CIP, and reserve targets.
Figure 1 shows the electric utility revenues, expenses, and proposed rate changes for the
recorded years 2020 through 2025, the current year (FY 2026), and the forecast for the next
five years. Staff proposes a 6% rate increase for FY 2027 and forecasts rate increases of 6% in FY
2028, 7% in FY 2029 through FY 2030 and 5% in FY 2031 to keep revenues in line with expenses
(see also Table 1 above).
The FY 2026 CIP cost bars in Figure 1 reflect a one-time timing issue with the startup of the grid
modernization project. The first year of spending was in FY 2025, but the first debt issuance will
not take place until FY 2027.
7
Figure 1: Electric Utility Revenues, Expenses, and Rate Changes:
Actual Costs through FY 2025 and Forecasts through FY 2031
Load Forecast
Staff conducted an updated load forecast for FY 2027, with forecast methodologies that
incorporated weather patterns, economic factors, and historical trends. This forecasted
electricity sales of 982,355 MWh and a peak electric load of 180 MW in FY 2027. Electricity sales
grew 4.6% in FY 2024 and 5% in FY 2025. Electric sales in FY 2026 are currently forecasted to
grow by 4.5% while the FY 2027 forecast is expected to remain relatively flat, only growing
0.2%. The main contributors to the recent electricity sales increases include growth in the E-7
and E-4 rate classes, driven primarily by small and medium data center expansions. From
around 1999 to 2019 the electric sales showed a gradual 1% annual decline due to loss of
manufacturing, energy efficiency, and rooftop solar adoption. The roughly 20-year decline prior
to 2019 was slightly mitigated by small increases in sales from building electrification and EV
charging.
Figure 2 shows the forecasted electricity sales through FY 2045. Electricity sales are expected to
only rise slightly as the rebound from COVID-19 is largely complete and further data center
projects are uncertain at this point. Building and vehicle electrification at a business-as-usual
level is included in the FY 2027 forecast. The “High Forecast” is shown for reference to illustrate
how increases in data center loads as well as a very large increase in the pace of building and
vehicle electrification could increase sales. Staff update the forecast annually based on the
most updated information for financial forecast purposes. While Palo Alto saw rapid electricity
growth in the prior 18-24 months, that growth has slowed substantially and is currently
8
trending approximately 1% below the forecast shown below in the orange line for FY 27
Expected Forecast (on a weather normalized basis). As more certainty emerges around the
residential and commercial growth staff will update this forecast in the preliminary rates
forecast towards the end of 2026.
Figure 2: Forecasted Electricity Sales
Figure 3 shows forecasted electricity peak demand through FY 2045. The forecast for FY 2027 is
roughly 20 MW higher than forecasts last year, reflecting recent growth from large and medium
commercial customers including some data centers. The “High Forecast” is shown for
reference, which presumes substantial data center growth as well as accelerated electrification
of buildings and vehicles. About half of the growth in the high scenario is from data centers and
about half is from electrification of buildings and vehicles. The high scenario is mostly used as a
scenario for transmission system planning. The peak demand forecast is a 1 in 2 forecast used
for planning, which means that it has a 50% chance of being exceeded, which is why the actual
in FY 2025 was higher than the expected peak in FY 2027 or going forward, caused by a weather
anomaly in FY 2025.
9
Figure 3: Forecasted Electricity Peak Demand
Revenues
The Electric Utility receives most of its revenues from sales of electricity to Palo Alto customers,
but about 20 to 25% comes from other non-rate revenue sources. Of these non-rate revenue
sources, about 80% represents wholesale revenues – from surplus energy sales, surplus RA
sales, and sales of renewable energy credits (RECs) that are in excess of the City’s renewable
portfolio standard (RPS) requirements. These revenues may offset electric supply purchase
costs, smooth rate increases, or fund reserves or other costs including the Electric General Fund
Transfer and local decarbonization programs. Of the remaining revenues, the largest sources
are interest income, customer connection fees for new or replacement electric services, and
carbon allowance sales revenues associated with the State’s Cap-and-Invest (formerly Cap-and-
Trade) program.
Staff expects Cap-and-Invest allowance revenues to decline starting in calendar year 2027 and
then increase throughout the remainder of the forecast period under the new draft calculations
from California Air Resources Board (CARB). Although CARB is still in the process of updating
the regulations, a revised regulation is expected to be adopted in 2026, with implementation
anticipated in 2027. The current proposal from CARB staff would reduce the City’s current
10
allowance revenue by approximately 40%, or about $2 million per year, from the current Cap-
and-Invest revenues to the electric fund. Staff will continue to update Cap-and-Invest related
revenues forecasts as more information becomes available.
Staff is recommending updates to the Electric Reserves Management Practices to change the
name of the Cap and Trade reserve to the Cap and Invest reserve (see Attachment A Exhibit 3).
The forecast for interest income assumes current interest rates continue, and there are no
major reserve reductions aside from what is anticipated in this forecast. If interest rates rise,
interest income could increase, and if reserves decrease (due to drought or a withdrawal from
the Electric Special Projects (ESP) reserve for a major project), interest income would decrease.
The load forecast and the rate changes proposed in this staff report provide the basis for sales
revenue forecasts.
Expenses
Although total load for FY 2026 is expected to be 16% higher than forecasted a year ago, overall
power supply costs are expected to be slightly lower than originally forecasted. The main
factors driving this favorable supply cost shift include executing several sales of excess RA and
REC supplies at higher than anticipated prices, and forecasted market power prices being
significantly lower than forecasted a year ago. Hydroelectric generation revenue continues to
be a very large source of uncertainty in the City’s supply cost forecasts and is expected to
decrease over time due to climate change. To reduce the downside risk associated with
hydroelectric uncertainty in the future, staff is now making its rate forecasts assuming that
long-term “normal” production from the City’s hydroelectric resources will be about 80% of
historical average levels for purposes of estimating future hydroelectric resource costs and
market purchase costs. Over the longer term, increasing transmission costs, rising renewable
energy procurement requirements, and increasing resource adequacy purchase obligations are
also expected to steadily increase electric supply costs.
Supply Purchases
As shown in Figure 4 below, the utility is forecasted to get roughly 43% of its energy from
hydroelectric projects in a normal year but received slightly more than that (44%) during FY
2025 due to the continuing favorable hydroelectric generation conditions resulting from the
rains of the 2022/2023 winter. In the longer term, contracts with renewable sources make up
approximately 53% to 56% of the portfolio. If hydroelectric output is lower than forecasted (as
was the case in FY 2022) or if loads increase further, some additional power purchases are likely
to come from unspecified market sources. Under the City’s Carbon Neutral Plan, CPAU
purchases additional RECs corresponding to the net amount of market energy it purchases.
Cost-mitigation Strategies
Utilities staff is working to mitigate increasing transmission costs by working with our federal
hydropower partners as well as partnering with the CPUC Ratepayers Advocates office in
litigating Transmission Owner Rate Cases where transmission costs have been improperly
assigned by California Investor Owned Utilities. Utilities staff is also working alongside the
11
Northern California Power Agency (NCPA) and federal hydropower staff to mitigate the
forecasted loss of revenues from RA sales in 2028 due to currently proposed CAISO procedure
changes.
Figure 4: Electricity Supply by Source
Figure 5 and Table 3 show the actual and forecasted costs for the electric supply portfolio,9 and
Figure 5 also shows average and actual hydroelectric generation.10 FY 2021 and FY 2022 had
lower than average hydroelectric generation, while FY2024 had higher than forecasted
generation. Starting in FY 2023 (in the FY 2024 Electric Utility Financial Plan) staff lowered its
forecast of an average hydroelectric year to more closely align with the past 10 years of
historical averages.
Renewable energy costs have stayed relatively flat overall, as one renewable energy contract
ended while another renewable project came online to fulfill the City’s carbon neutral and RPS
goals. The current market outlook is uncertain for newer renewables projects because of
headwinds from the recently introduced trade tariffs and reduced federal tax credits, along
with significant interconnection delays. CAISO transmission access charges are forecasted to
continue to increase as new transmission lines are built throughout California to accommodate
new renewable projects while older ones are retrofitted to reduce wildfire risk. In total, staff
9 Costs are shown net of wholesale revenues and cannot be directly compared with the electric supply purchase
figures shown in Attachment C: Electric Utility Financial Forecast Table.
10 Average hydroelectric generation based on the currently inactive E-HRA rate schedule.
12
anticipates that net electric supply costs will increase from an average of about $80 million
from FY 2022 through FY 2025 to about $126 million by FY 2031.
Figure 5: Electric Supply Portfolio Cost/Revenues
Table 3: Electric Supply Portfolio Costs/Revenues ($000)
Fiscal Year
Hydroelectric Cost 19,432 19,341 17,524 18,013 17,515 18,479 18,666
Net Market
Purchases/Sales (7,688) 11,244 15,016 14,748 21,041 22,722 22,048
(10,072) (8,301) (2,592) (3,905) (1,008) 3,193 3,445
Net Supply Costs
13
Operations
CPAU’s Electric Utility operations include the following activities:
• Administration includes direct costs for the Electric Utility for administrative and general
functions as well as shared utility administrative costs (costs allocated across all City
Departments). Specifically, administration includes financial management, insurance,
information technology expenses, work yard and inventories, tools, and other overhead
type activities;
• Debt service is used to fund long-term capital projects. Additional detail on Electric
Utility debt service is provided in the Debt Service section below;
• Customer Service including billing, printing and mailing, and customer support;
• Engineering work for maintenance activities (separate from long-term capital activities);
• Operations and Maintenance of the distribution system;
• Resource Management and Demand Side Management; and
• General Fund Transfers fund communications dispatch, fire training, graffiti removal
from poles and boxes, and Office of Emergency Services emergency response.
• Other Transfers including transfers to the City’s capital project fund, reserves, and
technology fund.
Figure 6 shows the Electric Utility operational costs from FY 2020 through FY 2031. Overall
operations costs are expected to rise annually by about 6% on average from FY 2026 to FY
2031. This is primarily driven by increased operations and maintenance and administrative
overhead allocations. Operations and maintenance costs are increasing primarily due to
inflation and the cost of using contract field crews for multi-year CIPs and to backfill for vacant
positions. These costs may be reduced depending on how much work is needed and may be
phased out as longer-term employees are gained. Administration costs are rising primarily due
to increasing support and labor from other City departments and Utilities Administration costs
resulting from filling of vacancies and increasing labor costs.
City staff are proactively engaged in seeking efficiencies that would lower operating costs and
those estimated savings are included in this forecast. Specifically, the utility is planning the
elimination of 4 FTE of meter readers in FY 2027 and 1 FTE and 3 hourlies for meter reading in
FY 2027 for a reduction of approximately $280,000 per year in the electric utility, while adding
credit card convenience fees equating to approximately $270,000 in the electric utility per year,
and reducing line clearing in the foothills following undergrounding of 49,200 feet of electric
overhead distribution lines is expected to reduce costs by approximately $200,000 per year in
the electric utility.
14
Figure 6: Electric Utility Operational Costs
Capital Improvement Program
Staff anticipates CIP spending for FY 2025 through FY 2031 to focus primarily on grid
modernization ($253.8 million). This includes upgrading the capacity of overhead and
underground distribution lines and distribution transformers, converting 4KV lines to 12KV, and
the complete re-building of the East Meadow and Hopkins Substations. Other significant one-
time projects include implementing a Master Plan for the City‘s main electric transmission
receiving station which connects the City’s electric grid to PG&E at the Colorado Substation,
which includes implementing a new 60KV breaker scheme and replacing older oil-filled circuit
breakers with new modern vacuum circuit breakers, replacing a 115KV to 60KV receiving
station transformer, replacing the 60KV/12KV transformer banks to increase capacity and
improve system reliability, as well as improving the substation‘s security posture with a security
wall and other security enhancements. Additional work includes completing the
undergrounding of power lines in the Foothills - expected to be complete in June 2026, and
completion of the Smart Grid (Advanced Metering Infrastructure) project - expected to be
complete for the Electric Utility by December 2026 and by December 2027 for the Water and
Gas Utilities. Ongoing projects include replacement of aging wood poles, and ongoing capital
investment in smaller projects on the electric distribution system to increase capacity and
improve reliability. Total spending over the forecast period, including the FY 2026 current year
estimated spending and actual FY 2025, is approximately $397.5 million. Table 4 shows the
latest projected budget and the CIP spending plan through 2031. These figures are preliminary
pending budget discussions starting in May.
Table 4: Electric Utility CIP Spending, Budgeted ($M)
15
*Actual values from FY 2025.
Debt Service
The Electric Utility pays debt service expenses related to the Calaveras Dam via NCPA. Typically
the Electric Utility funds CIP through fees and rates; however, with the significant cost and long-
term nature of Grid Modernization projects, staff expects to issue substantial amounts of debt
to fund projects through the forecast period and beyond through approximately FY 2035. Table
5 shows the estimated funding sources for the period. The timing and amount of debt issuance
will likely change as the grid modernization projects progress. At the time of this report, staff
estimates $85 million in debt issued in FY 2027 followed by $134 million issued in FY2030 which
includes FY 2032 CIP expenses in addition to the remaining $89 million for the 2025-2031
period.13
Note that the debt issuance in FY 2027 will be used to reimburse FY 2025 and FY 2026 grid
modernization expenses, resulting in the use of rate/reserve funding in those years and a
refund to the reserves in FY 2027 as the bond proceeds are applied to the actual capital costs
for grid modernization and related projects (see Council staff report 2411-3805,15 December 16,
2024 for a detailed discussion and accompanying Resolution 1020916).
Table 5: Electric Utility CIP Funding Sources Based on Cash Expenditures ($M)
Rate-Funded CIP (Non-Grid Modernization) $21.4 $39.0 $15.2 $15.9 $16.4 $17.7 $18.1 $143.7
Rate Funded Grid Modernization $11.0 $11.0 $11.0 $11.0 $11.0 $11.0 $11.0 $77.0
Total Pay-Go
Debt-Funded $2.7 $19.5 $15.8 $31.6 $15.0 $43.7 $45.3 $173.6
Total
The above plan assumes 43% debt-funded CIP over the 2025-2031 period. Retail rates fund the
remaining 57% of ongoing CIP and Grid Modernization.
Table 6 summarizes debt service secured by the Electric Utility’s revenues or reserves. Although
the Electric Utility is not responsible for the debt service payments listed in Table 6, it has
previously pledged reserves and net revenue as security for these non-electric bond issuances.
The Electric Utility’s reserves or net revenues would only be called upon if the responsible
utilities are unable to make the debt service payments. Staff does not anticipate that this will
occur. These pledges have not impacted electric rates. Staff forecasts that the Electric Utility’s
net revenues in each future year will exceed 125% of debt service (see Attachment A, Exhibit 2
Utility Financial Table, line 71).
The 2009 Water Revenue Bonds mature in June 2035; staff is evaluating the refinancing of
these bonds to address pledged reserves and net revenue over multiple utility funds. The 2011
Utility Revenue Refunding Bonds mature in June 2026.
13 $166.7 million less $85 million for the FY2027 bond is $89 million.
16
Table 6: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
Bonds, Series A Water $1,457 No Yes
Reserves
The Electric Utility currently has two primary contingency reserves: the Supply Operations
Reserve and the Distribution Operations Reserve. In addition, the Electric Utility has a Hydro
Stabilization Reserve, an Electric Special Projects (ESP) Reserve, and a Capital Reserve. Reserve
funds may be utilized with Council approval.
There are a variety of risks associated with the Supply Fund related to resource generation
variability, market price volatility, transmission cost increases, and regulatory changes to
market rules. Because of the high range of uncertainty in energy price predictions more than
two years into the future, this risk assessment is only performed for the first two fiscal years of
the forecast period. It is important to note that there is a very low likelihood of all adverse
scenarios occurring simultaneously (as the severity is defined in Table 7).
15 Staff report 2411-3805 “Adoption of a Resolution of Intention to Reimburse Expenditures for the Grid
Modernization and Related Projects of the Electric Utility System Infrastructure from the Proceeds of the Tax-
Exempt Utility Revenue Bonds.”
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83165&dbid=0&repo=PaloAlto
16 Council Resolution 10209 (Dec. 16, 2024)
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=62094&dbid=0&repo=PaloAlto
17
Table 7: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Estimates of Adverse
Outcomes (M$)
FY 2027 FY 2028
1. Load Net Revenue 5.3 5.1
1.2 2.1
3. REC Purchases 0.5 0.5
4. REC Sales 1.0 0.8
5. Market Price 1.9 1.5
6. Resource Adequacy 4.5 2.1
7. Transmission/CAISO 5.4 5.8
8. Plant Outage 1.0 1.0
9. Western Cost 1.6 1.4
10. Legislative & Regulatory 0.0 0.0
11. Supplier Default 0.2 0.2
Electric Supply Fund Risks 22.6 20.5
Of the risks faced by the Electric Utility’s Supply Fund for FY 2027, the largest two factors are
related to potential transmission cost increases above staff’s current forecast ($5.4 million) and
the reduction of total load (and the associated retail sales revenue) may be lower than
forecasted ($5.3 million). Together, these two risks account for almost half of the overall
Electric Supply Fund risk. Other risks are related to production from the City’s renewable
contracts and market prices for purchases and sales of energy and resource adequacy (Items 2
through 6 in Table 7 above), totaling $9.0 million or 40% of the total risk.
The risk of very low hydroelectric output is another significant risk for the City; because the
utility’s costs for its hydroelectric resources are almost entirely fixed, costs do not decline when
the output of those resources is low, but the utility needs to buy power to replace the lost
output. However, this risk (which is estimated at $5.6 million for FY 2027) is mitigated via the
Hydro Stabilization Reserve.
Table 8 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2031. The risk assessment for the Distribution Operations Reserve includes the
revenue shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
18
Table 8: Electric Distribution Fund Risk Assessment ($000)
Total non-commodity revenue 89,007 92,567 98,121 104,990 111,289 116,853
CIP Contingency (10%)
Total Risk Assessment value
Figure 7 illustrates the combined Supply and Distribution Operating Reserve balances. The
combined balances have met the reserve minimum, and future rate adjustments balance rate
stability and achievement of the reserve target.
Figure 7: Operating Reserve, End of Year Balance
Reserve Transfers
Reserve transfers are made at the end of each fiscal year so that the Electric Utility meets its
financial goals and policies. At the end of FY 2025, the Electric Utility’s combined Operations
19
Reserves for Distribution and Supply totaled $46.6 million, which is close to the target level of
$49.5 million.19
By the end of FY 2026, the Electric Utility repaid the remainder ($7.5 million) of the June 30,
2018 and June 30, 2022 loans totaling $15 million to the Electric Special Projects Reserve,
bringing the reserve balance from $22.6 million to $30.1 million.20 These funds covered higher
costs during the pandemic, lower hydroelectric generation during the drought, and high winter
energy prices during 2022-2023.This forecast also reflects repayments of $1 million per year
from FY 2027 through FY 2030 to the Electric Special Projects Reserve for loans to the water
and gas utilities for AMI investments.
The Electric Utility has a Hydroelectric Stabilization Reserve that is used to manage the supply
cost impacts associated with variations in generation from hydroelectric resources. In FY 2025,
$1.4 million was placed into the Hydro Stabilization Reserve as a result of favorable hydro
conditions, bringing the hydro reserve balance to $18.8 million, which is within the target
hydro reserve amount of $19.0 million.21 Replenishing this reserve reduces the risk that, in
the event of unforeseen condition declines in hydro conditions, the City will need to use the
Hydro Rate Adjuster to recover higher supply costs.
Staff completed a $5 million transfer from the Supply Operations Reserve to the Distribution
Operations Reserve. Attachment A, Exhibit 2, Electric Utility Financial Details table, line 60,
shows the FY 2025 year-end Electric Operations Reserve (Supply and Distribution combined) is
$46.6 million, which slightly exceeds the reserve target of $42 million. Figures 9 and 10 show
19 Attachment D, Exhibit 1 to Staff Report 2411-3776, June 16, 2025, Table 1, line 66:
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
20 In FY 2018 Council approved a $10 million transfer from the Electric Special Projects Reserve to the Operations
Reserve to mitigate higher supply costs due to the drought, the costs of new renewable energy projects coming
online and increasing transmission charges. See Staff Report 8186
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=77755&dbid=0&repo=PaloAlto. $5 million was
repaid in FY 2020; See Staff Report 11341
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=86876&dbid=0&repo=PaloAlto, In FY 2022 Council
approved an additional $5 million transfer from the ESP Reserve to the Operations Reserve to avoid rate increases
exceeding 5%. (Staff Report 13661, June 13, 2022)
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=2238&dbid=0&repo=PaloAlto. This left a total
outstanding loan of $10 million. In FY 2024, $2.5 million was repaid (Staff Report 2411-3776, June 16, 2025,
Attachment D, Exhibit 1, line 55 shows the balance in the Electric Special Project Reserve increased by $2.5 million
in FY 2024 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).
21 Electric Utility Reserves Management Practices, Section 7 d; Attachment D, Exhibit 3 to Staff Report 2411-3776,
June 16, 2025: https://www.paloalto.gov/files/assets/public/v/1/agendas-minutes-reports/agendas-minutes/city-
council-agendas-minutes/2025/june-16/rates-attachments/attachment-d-exhibit-3-fy26-electric-reserves-
management-practices.pdf
20
the actual and projected reserve balances for each of these reserves. The Operations Reserve
will be used temporarily to fund the grid modernization project until debt is issued in FY 2027.
Additionally, in accordance with the Electric Utility Reserve Management Practices (Attachment
A, Exhibit 3), staff transferred $2 million from the Supply Operations Reserve to the Cap and
Invest Reserve based upon actual Cap and Invest costs and revenues. The City maintains a Cap
and Invest Program Reserve within the Electric fund to hold any revenues from the sale of
carbon allowances freely allocated by CARB to the Electric Utility that are not spent within the
fiscal year. Cap and Invest Program revenues are provided to the Electric Utility to support a
wide variety of carbon reducing activities. Until the establishment of the REC Exchange
program, adopted by Council in August 2020 (Staff Report #11556),25 all of the Cap and Invest
Program revenue was spent on purchasing renewable energy and none was held in reserve.
In accordance with Council’s August 2020 direction, the City began selling City-owned
renewable energy (Category 1 RECs, which mostly represent in-state renewable energy) and
replacing them with purchased Category 3 RECs, which represent mostly out-of-state
electricity. This exchange takes advantage of market conditions to reduce supply costs, funds
electric utility programs and capital investment, and raises funds for local emissions reduction.
On December 12, 202226 Council approved continuation of the program with 100% of revenue
going to local emissions reduction. In accordance with Council policy, staff will fund the Cap and
Invest Program Reserve with unspent revenues from the sale of carbon allowances freely
allocated to the Electric Utility in an amount equal to 100% of each FY’s Renewable Energy
Credit (REC) Exchange program revenues, currently estimated to be about $0.5M per year
through FY 2029, for future local decarbonization projects.
Last year’s financial plan amended the Electric Utility Reserve Management Practices to direct
staff to transfer any unspent CIP budget that is not reappropriated or encumbered at the end of
each fiscal year to the CIP Reserve. These represent ratepayer funds already collected for the
purpose of CIP investment, and retaining them in the CIP Reserve allows the City to use them to
fund future unanticipated CIP expenses (such as mid-year budget adjustments due to increased
costs for specific projects) that were not included in a financial forecast. It is recommended to
transfer of up to $5 million from the Electric Distribution Operations Reserve to the CIP Reserve
in FY 2026. The Capital Reserve balance is $0.9 million, which is below the minimum guideline
range. Staff will evaluate the year-end results in FY 2026 and complete a transfer to the Capital
Reserve to bring it up to the minimum guideline if this is feasible.
CIP Reserve Balance
The Electric Utility also has a CIP Reserve to both cover short-term capital contingencies and
also for large, one-time projects that the Utility would otherwise need to debt-fund. Figure 8
25Staff Report 11556
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=86875&dbid=0&repo=PaloAlto
26December 12, 2022 Staff Report #14375
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=82045&dbid=0&repo=PaloAlto
21
below reflects the maximum and minimum CIP Reserve guideline levels, starting in FY 2020
through FY 2031. The maximum reserve level is equal to the running 4-year average of
forecasted CIP expenses. Because of the fluctuating annual dollar amounts and timing of CIP
projects budgeted to occur during the forecast period, as well as the potential for new ongoing
projects to be included in the CIP plan in later years, four years of budgeted CIP are used to
calculate the reserve maximum levels. The minimum CIP Reserve level is 20% of the maximum
CIP Reserve guideline level.
Last year’s Financial Plan recommended funding the CIP Reserve to its minimum level by the
end of FY 2025, and Council approved a $5 million transfer in FY 2025 for this purpose;
however, the transfer was not made in FY 2025. It is recommended that this $5 million transfer
be made in FY 2026, as shown below.
Figure 8 shows that the CIP reserve is not forecasted to be above the minimum guideline by the
end of FY 2026. Per the Reserves Management Practices (Attachment A, Exhibit 3), Section 10,
any rate plan that does not return CIP reserves to minimum levels within one year requires
Council approval. Currently, reserves are being used to fund grid modernization spending as
well as non-grid modernization Electric CIP spending in the current year. This will allow the
Electric Utility to delay the first bond issuance for grid modernization to FY 2027.
Figure 8: Electric CIP Reserve Adequacy
Reserves balances based on these revenue forecasts are shown in Figure 9 (for Supply Fund
Reserves) and Figure 10 (for Distribution Fund Reserves), below.
22
The reserves charts below show significant increases in the Distribution Operations Reserve as
these funds will be replenished following grid modernization investments prior to the bond
funding in FY 2027.
Figure 9: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2026 and Forecasts through FY 2031
Figure 10: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2026 and Forecasts through FY 2031
23
Table 9 shows the forecasted balance of each of the Electric Utility reserves for the period
covered by this Financial Forecast. See also: Attachment A, Exhibit 2: Electric Utility Financial
Table.
Table 9: Electric Utility Reserves Starting and Ending Balances, Revenues, Transfers To/(From)
Reserves, and Reserve Guideline Levels for FY 2026 to FY 2031 ($000)
1
2
3
4
5
6
7
8
Distribution Operations
Capital Reserves
Electric Special Projects
Hydro Stabilization
Cap and Trade
Public Benefits
Low Carbon Fuel Standard (LCFS)
Revenues
11
12
13
14
Distribution
Cap and Trade
Public Benefits
Low Carbon Fuel Standard
Transfers from Supply Operations Reserve to Other Reserves or to Distribution Fund
17
18
19
Electric Special Projects
Hydro Stabilization
Cap and Trade
Transfers from Distribution Operations Reserve to Other Reserves or to Supply Fund
22
23
Capital Reserves
Low Carbon Fuel Standard
Expenses
26
27
28
29
30
Distribution Non-CIP
Distribution Planned CIP
Cap and Trade
Public Benefits
Low Carbon Fuel Standard
Ending Reserve Balance
2+11+24+26+27=33
3+22=34
4-17=35
5+18=36
6-19+28=37
7+13+29=38
8+14+23+30=39
Distribution Operations
Capital Reserves
Electric Special Projects
Hydro Stabilization
Cap and Trade
Public Benefits
Low Carbon Fuel Standard (LCFS)
Operations Reserve Guidelines (Supply)
Operations Reserve Guidelines (Distribution)
Capital Reserve Guidelines
24
Proposed Rates
Bill Impacts
The City adopted its current electric rates effective July 1, 2025. The current FY 2026 and
proposed FY 2027 rates are reflected in Table 10 below. All FY2027 commodity rates are
increased by 7% and FY2027 distribution rates are increased by 4.5%. Rate components that are
weighted more toward supply costs (summer energy rates) increase at a higher percentage
compared with rate components comprised more heavily of distribution costs (demand rates).
The results in a 6% overall adjustment for each rate schedule.
Table 10: Current and Proposed Electric Rates
Rate Schedule Change Change (%)
(Residential)
Tier 1 Energy ($/kWh) 0.20570 0.21761 0.01191 6%
Tier 2 Energy ($/kWh) 0.22944 0.24317 0.01373 6%
Customer Charge ($/month) 5.15 5.44 0.29 6%
(Small Non-Residential)
Summer Energy ($/kWh) 0.26485 0.28059 0.01574 6%
Winter Energy ($/kWh) 0.17290 0.18307 0.01017 6%
Customer Charge ($/month) 6.22 6.57 0.35 6%
(Medium Non-Residential)
Summer Energy ($/kWh) 0.16171 0.16872 0.01030 7%
Winter Energy ($/kWh) 0.11579 0.12125 0.00696 6%
Summer Demand ($/kW) 47.59 51.66 2.49 5%
Winter Demand ($/kW) 24.94 27.33 1.24 5%
Customer Charge ($/month) 119.53 133.44 7.20 6%
(Large Non-Residential)
Summer Energy ($/kWh) 0.14262 0.14738 0.00946 7%
Winter Energy ($/kWh) 0.09245 0.09579 0.00609 7%
Summer Demand ($/kW) 42.41 45.87 2.26 5%
Winter Demand ($/kW) 29.20 32.02 1.45 5%
Customer Charge ($/month) 547.36 611.03 32.95 6%
Table 11 shows the impact of the proposed July 1, 2027 rate changes on the residential and non-
residential bills for various consumption levels. The increase for all rate classes is 6%.
25
Table 11: Impact of Proposed Electric Rate Changes on Customer Bills in FY 2027
Rate
Schedule
Usage
(kWh/mo)
Peak
Demand
kW-mo
Change
(%)
E-1
(Residential)
300 NA $66.86 $70.72 $3.86 6%
Median)
NA
$80.23
$84.87
$4.64
6%
Median) NA $97.72 $103.36 $5.65 6%
650 NA $143.60 $152.00 $8.40 6%
1,200 NA $269.80 $285.74 $15.95 6%
(Small Non-
1,000
NA
$225.10
$238.40
$13.31
6%
(Medium
Non-
160,000 274 $32,253.66 $34,152.67 $1,899.01 6%
856 $100,515.02 $106,433.66 $5,918.64 6%
(Large Non-
2,000,000
3,424
$355,194.24
$377,128.71
$21,934.47
6%
Net Energy Metering Compensation Rates
The City operates two Net Energy Metering (NEM) programs. Solar customers served by the
City of Palo Alto's (CPAU) original NEM program, also called NEM 1, are compensated at retail
rates for electricity they export to the grid, and solar customers served by the NEM successor
program, or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are
compensated at the Export Electricity Compensation (E-EEC-1) rate for exported electricity.
Customers on the NEM 1 program who have chosen to have the value of any annual net
generation they produced over the past 12 months credited back to their account do so under
the Net Metering Net Surplus Electricity Compensation (E-NSE-1) rate. The Net Surplus
Electricity Compensation rate represents the City’s avoided cost or value of customer-
generated electricity in Palo Alto over the preceding year, which is calculated based on the
value of the energy and RECs, avoided capacity charges, avoided transmission and ancillary
service charges, and avoided transmission and distribution (T&D) losses. Staff proposes a slight
increase to the E-NSE-1 rate to $0.1064/kWh based on updated avoided cost calculations that
reflect higher historical transmission charges and historical RA market prices in 2025 relative to
their levels in 2024.
26
Under the City’s NEM successor program, participating solar customers in Palo Alto are billed at
the current retail rate for electricity drawn from the grid, and receive a credit for electricity they
export to the grid at the E-EEC-1 rate. This compensation rate also reflects the avoided cost or
value of customer-generated electricity in Palo Alto, calculated on a forward-looking basis for
the upcoming fiscal year. As shown in the table below, the current avoided cost rate for solar
generation in Palo Alto is $0.1206/kWh, which is higher than the City’s forecasted avoided cost
(due to decreases in forecasted resource adequacy and REC prices compared to a year ago),
and thus requires the proposed NEM compensation rate (E-EEC-1) to decrease to $0.0990/kWh.
This decrease in the overall avoided cost is driven by a significant drop in forward electricity
market prices and forward RA prices. Table 12 shows the current and proposed NEM buyback
rates that would be effective on July 1, 2026.
Table 12: NEM Buyback Rates – Current vs. Proposed
Rate $/kWh $/kWh
Palo Alto Green (PAG) Program
The Palo Alto Green (PAG) program provides CPAU’s commercial customers an opportunity to
voluntarily pay a premium to receive renewable electricity credits to match their energy usage.
Under this program, CPAU staff purchase and retire Green-e certified renewable energy
certificates (RECs) in the wholesale market on behalf of PAG customers. This enables
participating commercial customers to claim credit for the REC purchases in order to satisfy
their corporate sustainability goals and meet federal “green certification” requirements.
The PAG charge is a pass-through charge; the revenue collected through the PAG rate premium
is intended to fully recover the costs of administering the program. The PAG program has very
low overhead costs (e.g., the cost of hiring an auditor to carry out an annual Green-e
verification process for the program), so most of the program cost is the purchase cost of the
RECs. In the past year the wholesale cost of Green-e certified RECs in the Western US market
has remained relatively flat at around $6 per REC. As such, the PAG rate premium should
remain at $7.5 per 1,000 kWh block (0.75 cents/kWh), enough to cover the cost of the RECs and
program overhead. The PAG rate premium is reflected on the rate schedules for Residential
Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium
Non-Residential Green Power Electric Service (E-4-G), and the Large Non-Residential Green
Power Electric Service (E-7-G).
27
Bill Comparisons/Competitiveness
For the median consumption level, the CPAU residential electric monthly bill is about $94.04.
This is about 50% lower than the monthly bill for a PG&E customer and about 24% higher than
the bill for a City of Santa Clara (Silicon Valley Power) customer with the same consumption
level, based on rates as of January 1, 2026. PG&E bill calculations are based on the “average”
bundled total rates, including the annual climate credit, and Climate Zone X, which includes
most nearby comparison communities.
Santa Clara’s electrical system benefits from a higher load factor with a significantly larger
commercial load compared to Palo Alto’s, resulting in a more efficient distribution system and
lower rates. However, unlike Palo Alto, Santa Clara’s system is not 100% carbon neutral, as part
of its electricity is generated from natural gas.
Table 13 provides sample residential bills for Palo Alto (effective 7/1/2026), PG&E (effective
1/1/2026), and the City of Santa Clara (effective 7/1/2026) at various usage levels.
Table 13: Residential Monthly Electric Bill Comparison ($/mo.)
Usage (kWh) 7/1/2026 1/1/2026 1/1/2026
For commercial customers, the CPAU electric monthly bill is about 43% to 53% lower than the
bill for a PG&E customer, depending on usage levels. Compared to the City of Santa Clara, CPAU
commercial bills are approximately 15% lower to 12% higher, depending on usage levels, based
on rates as of January 1, 2026.
Table 14 presents sample commercial bills for Palo Alto (effective 7/1/2026), PG&E (effective
1/1/2026), and the City of Santa Clara (effective 7/1/2026) at various usage levels.
Table 14: Commercial Monthly Electric Bill Comparison ($/mo.)
Usage (kWh)
Palo Alto
7/1/2026
PG&E
1/1/2026
Santa Clara
1/1/2026
1000 $238.40 $432.56 $263.86
160,000 $34,152.67 $69,209.60 $28,924.47
500,000 $106,433.66 $191,670.00 $90,174.88
2,000,000 $377,128.71 $618,760.00 $360,401.49
28
General Fund Transfer
The City calculates the General Fund Transfer from its Electric Utility based on a methodology
adopted by Council in 2009, which has remained unchanged since then.29 Each year it is
calculated according to the 2009 Council-adopted methodology and does not require additional
Council action.
Next Steps
Staff will incorporate the Finance Committee’s recommendations into the draft financial
forecast and attachments and bring those to the City Council in June. The City Council will
consider the proposed financial forecast and rate schedules with the FY 2027 budget review
and adoption process in June 2026. If Council approves the proposed rate changes, the rates
will become effective July 1, 2026.
FISCAL/RESOURCE IMPACT
FY 2027 revenues from retail rates are forecasted to increase 6.7% or $13.3 million from FY
2026 forecasted levels if Council adopts this financial forecast’s recommendations. General
Fund expenses (due to the rate increases) are expected to increase and revenues (due to the
General Fund Transfer) are also expected to increase because the City is a non-residential
utility customer. General Fund impact from streetlight expenses due to the rate increase is
forecasted to increase by about $0.1 million. General Fund revenues from the General Fund
Transfer and utility users tax would increase $0.4 million (from an estimate of $17.6 million in
FY 2026 to an estimated $18.0 million in FY 2027) and $0.6 million (from $8.9 million in FY
2026 to $9.5 million in FY 2027), respectively.
POLICY IMPLICATIONS
The proposed electric rate adjustments are consistent with Council-adopted Reserve
Management Practices that are part of the Financial Forecast and were developed using a cost-
of-service study30 and methodology consistent with the California Constitution and industry-
accepted cost of service principles.
29 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to the General Fund Transfer methodology.
30 Staff Report 2404-2842, June 17, 2024, beginning on packet page 709
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=6490&dbid=0&repo=PaloAlto&searchid=e295a977-
520e-4aed-b382-b7e802821bcd
31 Staff Report 2503-4364, November 5, 2025 “Discussion & Update on the FY 2027 Preliminary Utilities Financial Forecast
& Rate Projections” https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84164&dbid=0&repo=PaloAlto&searchid=ffbb0624-
&cr=1
29
STAKEHOLDER ENGAGEMENT
At the UAC on November 5, 2025, staff discussed the preliminary rate proposals .31 The UAC did
not take any action on this item. The video of the meeting is available on the City’s website at
the following link: https://youtube.com/watch?v=1e6NrB2KDCw?feature=share. UAC members
expressed concern about utility affordability and subsequently formed a UAC Subcommittee to
examine affordability of water and electric rates.
At the Finance Committee on November 18, 2025, staff again discussed the preliminary rate
proposals. The Finance Committee took no action. Committee members inquired about cost-
containment strategies, and discussed reserve guidelines and associated risk management.
Committee members emphasized that the absence of rate increases during the pandemic
created a catch-up scenario that should be avoided in the future. The video of the meeting is
available on the City’s website at the following link: https://youtube.com/watch?v=-
sb3qACeMAU?feature=share.
At the UAC meeting on March 31, 2026 the UAC reviewed the Electric rate proposals and
financial forecast and voted 6-1 to approve the staff recommendation. The agenda for the
meeting is available here:
https://cityofpaloalto.primegov.com/Portal/Meeting?meetingTemplateId=20055 and the video
recording of the meeting is available at this link:
https://www.youtube.com/watch?v=UgYIcdEiI8w
During the discussion, the UAC Subcommittee reported out on their meeting to discuss Electric
rate affordability and reported that they discussed rates in general, data centers, and rebates
to low-income customers. The discussion noted that the rate increases have decreased from
the initial proposal in the outer years of the forecast. Regarding data centers, the discussion
noted that the City’s consultant ran the model and found that the addition of data centers
would result in reductions to marginal cost. Additionally, the discussion addressed increasing
the eligibility thresholds as well as electric discount levels to low-income customers and the
UAC Subcommittee was agreement with this approach (this proposal will be brought forward
through a separate report to the City Council).
Individual Commissioners also commented during the discussion. One Commissioner requested
information in the future showing a histogram of the number of customers at each level of
electricity usage and their bill impacts. Two Commissioners mentioned that they would like to
see staff revisit the cost of service for the residential Time-of-Use rates and one Commissioner
said the Time-of-Use rates are not very compelling because the differential between the peak
and off-peak rates are not very high. One Commissioner recommended discussing the utility
rate increases relative to broader inflation indices and recommended synchronizing the electric
load forecast and the gas load forecast considering electrification efforts. One Commissioner
recommended clearer calculation proofs to support the proposal. Additionally, a Commissioner
recommended agendizing a discussion of the Baker Tilly Utility Reserves report.
Additional feedback from the Finance Committee meetings in 2026 will be incorporated in the
30
financial forecast and included in the proposal presented to the City Council in June 2026 during
the budget adoption process.
Attachment B contains examples of CPAU’s communication and outreach methods including
the use of the Utilities Department website, utility bill inserts, messaging on utility bills and
MyCPAU online account management platform, email newsletters, print and digital ads in local
publications, social media, and business and neighborhood customer presentations.
ENVIRONMENTAL REVIEW
The Finance Committee’s review and recommendation to the Council on the FY 2027 Electric
Resolution, Financial Forecast, and proposed rate adjustments, does not meet the California
Environmental Quality Act’s definition of a project, pursuant to Public Resources Code Section
21065 and under CEQA Guidelines Section 15378(b)(4) and (b)(5), because it is a governmental
fiscal and administrative activity which will not cause a direct or indirect physical change in the
environment, thus no environmental review is required.
ATTACHMENTS
Attachment A: FY27 Electric Resolution
Attachment A, Exhibit 1: FY27 Electric Rate Schedules
Attachment A, Exhibit 2: FY27 Electric Utility and CIP Financial Details
Attachment A, Exhibit 3: FY27 Electric Reserves Management Practices (redline)
Attachment B: FY27 Electric Communications Plan and Samples
Attachment C: Staff Presentation
AUTHOR/TITLE:
Alan Kurotori, Director of Utilities
Staff: Lisa Bilir, Assistant Director of Utilities Resource Management Division
* NOT YET APPROVED *
Attachment A
1
02703252026
Resolution No. _
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2027 Electric Utility Financial Forecast and Reserve Transfer, and Amending Utility
Rate Schedules E-1 (Residential Electric Service), E-1 TOU (Residential Time of Use
Electric Service), E-2 (Residential Master-Metered and Small Non-Residential Electric
Service), E-2-G (Residential Master- Metered and Small Non-Residential Green Power
Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G (Medium Non-
Residential Green Power Electric Service), E-4 TOU (Medium Non-Residential Electric
Time of Use Service), E-7 (Large Non Residential Electric Service), E-7-G (Large Non-
Residential Green Power Electric Service), E-7 TOU (Large Non-Residential Electric Time
of Use Service), E-14 (Street Lights), E-EEC-1 (Export Electricity Compensation), and E-
NSE-1 (Net Metering Surplus Electricity Compensation)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) assesses the financial position of its utilities
with the goal of ensuring adequate revenue to fund operations. This includes making long-term
projections of market conditions, the physical condition of the system, and other factors that
could affect utility costs, and setting rates adequate to recover these costs. It does this with the
goal of providing safe, reliable, and sustainable utility services at competitive rates. The City
adopts Financial Forecasts or Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices (Exhibit 3) and Electric
Utility and CIP Financial Details (Exhibit 2) in addition to the Electric Financial Forecast staff
report presented to the City Council.
C. 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.
D. On June 15, 2026, the City Council heard and approved the proposed rate increase
at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the fiscal year (“FY”) 2027 Amended Electric
Utility Reserve Management Practices (Exhibit 3) and Electric Utility and CIP Financial Details
(Exhibit 2) presented to the Finance Committee on April 21, 2026 as updated by the June 15,
* NOT YET APPROVED *
Attachment A
2
02703252026
2026 Council report including the Electric Financial Forecast, which are attached to and made
a part of the staff report presented to the City Council;
SECTION 2. The Council hereby approves the transfer of up to $5 million from the
Electric Utility Distribution Operations Reserve to the Electric Utility Capital Reserve by the end
of FY 2026, as described in the FY 2027 Electric Utility Financial Forecast (Exhibit 2)
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2026;
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 TOU (Residential Time of Use Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-1, as amended, shall become effective July
1, 2026;
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2 (Residential Master-Metered and Small Non-Residential Electric Service) is
hereby amended to read as attached and incorporated. Utility Rate Schedule E-2, as amended,
shall become effective July 1, 2026;
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service) is hereby amended to read as attached and incorporated. Utility Rate
Schedule E-2-G, as amended, shall become effective July 1, 2026;
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2026;
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Non-Residential Green Power Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall
become effective July 1, 2026;
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Non-Residential Time of Use Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended,
shall become effective July 1, 2026;
* NOT YET APPROVED *
Attachment A
3
02703252026
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective
July 1, 2026;
SECTION 11. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become
effective July 1, 2026;
SECTION 12. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Non-Residential Time of Use Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall
become effective July 1, 2026;
SECTION 13. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated.
Utility Rate Schedule E-14, as amended, shall become effective July 1, 2026;
SECTION 14. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-EEC-1 (Export Electricity Compensation) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-EEC-1, as amended, shall become effective July 1, 2026;
SECTION 15. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-NSE-1 (Net Surplus Electricity Compensation Rate) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-NSE-1, as amended, shall become effective
July 1, 2026;
SECTION 16. 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 17. 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.
//
//
//
//
* NOT YET APPROVED *
Attachment A
4
02703252026
SECTION 18. The Council finds that approving the Electric Reserves Management
Practices, Electric Financial Forecast, and Electric Reserve transfer does not meet the California
Environmental Quality Act’s (CEQA) definition of a project under Public Resources Code Section
21065 and CEQA Guidelines Section 15378(b)(5), because each is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental assessment is required. The Council finds that
changing electric rates to meet operating expenses, purchase supplies and materials, meet
financial reserve needs and obtain funds for capital improvements necessary to maintain service
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 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 SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-1-1 Supersedes Sheet No E-1-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to separately metered single-family residential dwellings receiving
Electric Service from the City of Palo Alto Utilities.
B.TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C.UNBUNDLED RATES:
Per kilowatt-hour (kWh)Commodity Distribution Public Benefits Total
Tier 1 usage $
0.110990373
$
0.1002509593
$ 0.0063704 $
0.217610570
Tier 2 usage
Any usage over Tier 1
0.143083372 0.093728968 0.0063704 0.243172944
Customer Charge
($/month)
5.4415
D.SPECIAL NOTES:
1.Calculation of Cost Components
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.
2.Calculation of Usage Tiers
Tier 1 Electricity usage shall be calculated and billed based upon a level of 15 kWh per
day, prorated by Meter reading days of Service. As an example, for a 30-day bill, the Tier
1 level would be 450 kWh. For further discussion of bill calculation and proration, refer
to Rule and Regulation 11.
{End}
Attachment A
RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-1-TOU-11 Sheet No E-1-TOU-1
Ddated 1-1-2026 Effective 7-1-2026
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 e kWh Commodit Distribution Public Benefits Total
Summer Perio
Ener Char e
Peak $ 0.249893354
$
0.09772351 $ 0.0063704
$
0.3539833
09
Off-Peak 0.08826249 0.09772351 0.0063704
0.1923582
04
Su er Off-Peak 0.071586690 0.09772351 0.0063704
0.1756766
45
Winter Perio
Ener Char e
Peak $ 0.178746705
$
0.09772351 $ 0.0063704
$
0.2828366
60
Off-Peak 0.11805033 0.09772351 0.0063704
0.2221409
88
Su er Off-Peak 0.083837835 0.09772351 0.0063704
0.1879277
90
Customer Char e $/month 5.4415
RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-1-TOU-12 Sheet No E-1-TOU-2
Ddated 1-1-2026 Effective 7-1-2026
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.
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}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-1 Supersedes Sheet No E-2-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities:
1. Non-residential Customers receiving Non-Demand metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities receiving Non-
Demand metered Electric Service.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Per kilowatt-hour kWh Commodit Distribution Public Benefits Total
Summer Perio
$
0.161305075
$
0.112920806
$ 0.0063704
$
0.28059648
5
Winter Perio
0.09987334
0.07683352
0.0063704
0.18307729
0
Customer Charge ($/month)
6.5722
D. SPECIAL NOTES:
1. Calculation of Cost Components
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.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-2 Supersedes Sheet No E-2-2
Effective 7-1-20265 dated 7-1-20254
and the Winter Periods, the 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. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh
for twelve consecutive months, whereupon, at the option of the City, it may be removed.
{End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-G-1 Supersedes Sheet No E-2-G-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities who qualify for E-2 Service and choose to participate in the Palo Alto Green
Program:
1. Non-residential Customers receiving Non-Demand metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities receiving Non-Demand
metered Electric Service.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodit Distribution
Public
Benefits
Palo Alto
Green
Char e Total
Summer Perio
$
0.161305075
$
0.112920806
$
0.0063704 $ 0.0075
$
0.2880972
35
Winter Perio
0.09987334
0.07683352
0.0063704 0.0075
0.1905780
40
Customer Charge
($/month)
6.5722
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodit Distribution
Public
Benefits
Total
Summer Perio
$
0.161305075
$
0.112920806
$
0.0063704
$
0.2680594
85
Winter Perio
0.09987334
0.07683352
0.0063704
0.1830772
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-G-2 Supersedes Sheet No E-2-G-2
Effective 7-1-20265 dated 7-1-20254
90
Customer Charge
($/month)
6.5722
Palo Alto Green Char e (per 1000 kWh block) $ 7.50
D. SPECIAL NOTES:
1. Calculation of Cost Components
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.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon 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. Palo Alto Green Program Description and Participation
Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities
Department of enough renewable energy credits (RECs) to match 100% of the metered
energy usage at the Customer’s facility each month. Any Customer may alternately request
that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs.
CPAU will charge the Customer the Palo Alto Green Charge for each such requested block.
These REC purchases support the production of renewable energy, increase the financial
value of power from renewable sources, and create a transparent and sustainable market
that encourages new development of wind and solar power.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any time,
in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-G-3 Supersedes Sheet No E-2-G-3
Effective 7-1-20265 dated 7-1-20254
4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh
for twelve consecutive months, whereupon, at the option of the City, it may be removed.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-1 Supersedes Sheet No E-4-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to Demand metered Secondary Electric Service for Customers with
a maximum Demand below 1,000 kilowatts. This Rate Schedule may include Service to master-
metered multi-family facilities or other facilities requiring Demand metered Service, as
determined by the City.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodit Distribution
Public
Benefits Total
Summer Perio
Demand Char e er kW
$ 11.8709
$ 39.798.08
$ 51.6649.17
Ener Char e er kWh
0.133122441
0.02923797
0.0063704
0.168725842
Winter Perio
Demand Char e er kW
$ 2.7860
$ 24.553.49
$ 27.336.09
Ener Char e er kWh
0.08590028
0.02923797
0.0063704
0.121501429
Customer Char e $/month 133.4426.24
D. SPECIAL NOTES:
1. Calculation of Cost Components
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.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-2 Supersedes Sheet No E-4-2
Effective 7-1-20265 dated 7-1-20254
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the 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. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a Maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh
for twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type
Demand Meter which does not reset after a definite time interval may be used at the City's
option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 pm on weekdays.
4. Changing Rate Schedules
Customers may request a rate schedule change at any time to any City of Palo Alto full-
service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage
profile.
5. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-3 Supersedes Sheet No E-4-3
Effective 7-1-20265 dated 7-1-20254
to the Customer's electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change his system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
6. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio
$
9.098.50 $ 39.798.08 $ 48.886.58
Winter Perio 0.00 24.553.49 24.553.49
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3)
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-4 Supersedes Sheet No E-4-4
Effective 7-1-20265 dated 7-1-20254
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-1 Supersedes Sheet No E-4-G-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to Customers who qualify for E-4 Service and who choose to
participate in the Palo Alto Green Program.
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodit Distribution
Public
Benefits
Palo Alto
Green
Char e Total
Summer Perio
Demand Char e er kW $ 11.8709 $ 39.798.08
$
51.6649.1
7
Ener Char e er kWh 0.133122441 0.02923797 0.0063704 0.0075
0.1762265
92
Winter Perio
Demand Char e er kW $ 2.7860 $ 24.553.49
$
27.336.09
Ener Char e er kWh 0.08590028 0.02923797 0.0063704 0.0075
0.1290017
68
Customer Char e $/month 133.4426.24
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-2 Supersedes Sheet No E-4-G-2
Effective 7-1-20265 dated 7-1-20254
2. 1000 kWh Block Purchase Option:
Commodit Distribution
Public
Benefits Total
Summer Perio
Demand Char e er kW $ 11.8709 $ 39.798.08
$
51.6649.1
7
Ener Char e er kWh 0.133122441 0.02923797 0.0063704
0.1687258
42
Palo Alto Green Char e er 1000 kWh block $7.50
Winter Perio
Demand Char e er kW $ 2.7860 $ 24.553.49 $27.33
Ener Char e er kWh 0.08590028 0.02923797 0.0063704
0.1215014
29
Palo Alto Green Char e er 1000 kWh block $7.50
Customer Char e $/month 133.4426.24
D. SPECIAL NOTES:
1. Calculation of Cost Components
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.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the 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. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-3 Supersedes Sheet No E-4-G-3
Effective 7-1-20265 dated 7-1-20254
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has dropped
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the
City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type
Demand Meter, which does not reset after a definite time interval, may be used at the City's
option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays.
4. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full-service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
5. Palo Alto Green Program Description and Participation
Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities
Department of enough renewable energy credits (RECs) to match 100% of the metered
energy usage at the customer’s facility each month. Any Customer may alternately request
that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs.
CPAU will charge the Customer the Palo Alto Green Charge for each such requested block.
These REC purchases support the production of renewable energy, increase the financial
value of power from renewal sources, and creates a transparent and sustainable market that
encourages new development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any time,
in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-4 Supersedes Sheet No E-4-G-4
Effective 7-1-20265 dated 7-1-20254
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change the system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue Meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio
$
9.098.50 $ 39.798.08 $ 48.886.58
Winter Perio 0.00 24.553.49 24.553.49
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3)
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue Meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-5 Supersedes Sheet No E-4-G-5
Effective 7-1-20265 dated 7-1-20254
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-1 Supersedes Sheet No E-4-TOU-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This voluntary Rate Schedule applies to Demand metered Secondary Electric Service for
Customers with Demand between 500 and 1,000 kilowatts per month and who have sustained
this level of usage for at least three consecutive months during the most recent 12 month period.
This Rate Schedule may include Service to Master-Metered multi-family facilities or other
facilities requiring Demand metered Service, as determined by the City.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodit Distribution Public Benefits Total
Summer Perio
Demand Char e er kW
Peak $ 10.519.82 $ 19.9307 $ 30.4428.89
Max Deman 1.390 19.9307 21.320.37
Ener Char e er kWh
Peak
$
0.184127208 $ 0.02944817 $ 0.0063704
$
0.219940629
Mi -Peak 0.151744181 0.02944817 0.0063704 0.187557602
Off-Peak 0.114080662 0.02944817 0.0063704 0.14989083
Winter Perio
Demand Char e er kW
Peak $ 1.4031 $ 12.451.91 $ 13.8522
Max Deman 1.4031 12.451.91 13.8522
Ener Char e er kWh
Peak
$
0.12943096
$
0.02900775 $ 0.0063704
$
0.164805475
Mi -Peak 0.1021509547 0.02900775 0.0063704 0.137522926
Off-Peak 0.070516590 0.02900775 0.0063704
0.105880996
9
Customer Charge
$/month 133.4426.24
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-2 Supersedes Sheet No E-4-TOU-2
Effective 7-1-20265 dated 7-1-20254
D. SPECIAL NOTES:
1. Calculation of Cost Components
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.
2. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Energy
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 2:00 p.m. to 4:00 p.m. Monday through Friday (except holidays)
9:00 p.m. to 11:00 p.m.
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
WINTER PERIOD (Service from November 1 to April 30):
Energy
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 9:00 a.m. to 2:00 p.m. Monday through Friday (except holidays)
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-3 Supersedes Sheet No E-4-TOU-3
Effective 7-1-20265 dated 7-1-20254
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
TYPES OF DEMAND CHARGES: The Peak Demand Charge per Kilowatt applies to the
maximum peak-period Demand during the time periods noted above. The Maximum (Max)
Demand charge per Kilowatt applies to the maximum Demand at any time during the month. Both
Demand charges apply in each Billing Period, and the maximum peak-period Demand and
maximum Demand may occur at different times in the Billing Period depending on Customer
usage patterns.
SEASONAL RATE CHANGES: When the Billing Period includes use in both the Summer and
the Winter periods, the 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. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive
months, a Demand Meter will be installed as promptly as is practicable and thereafter continued
in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve
consecutive months, whereupon, at the option of the City, it may be removed.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time
periods as defined under Section D.2.
4. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said Rate Schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 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 Demand and kilowatt-hour usage.
5. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be offered,
but the City is not required to supply Service at a particular line voltage where it has, or will
install, ample facilities for supplying at another voltage equally or better suited to the Customer's
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-4 Supersedes Sheet No E-4-TOU-4
Effective 7-1-20265 dated 7-1-20254
electrical requirements, as determined in the City’s sole discretion. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any Customer
receiving the discount in this section. The Customer then has the option to change his system so
as to receive Service at the new line voltage or to accept Service (without voltage discount)
through transformers to be supplied by the City subject to a maximum kilovolt-ampere size
limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio
$
9.098.50 $ 39.798.08 $ 48.886.58
Winter Perio 0.00 24.553.49 24.553.49
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue Meter are not operating,
the Maximum Demand will be reduced by the sum of the Maximum Generation of those
non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced
below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the
standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-5 Supersedes Sheet No E-4-TOU-5
Effective 7-1-20265 dated 7-1-20254
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible
Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as
amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-1 Supersedes Sheet No E-7-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to Demand metered Service for large non-residential Customers with
a Maximum Demand of at least 1,000KW per month per site, who have sustained this Demand
level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodit Distribution
Public
Benefits Total
Summer Perio
Demand Char e kW $ 12.9107 $ 32.961.54 $ 45.873.61
Ener Char e kWh 0.136812786 0.0042002 0.0063704 0.147383792
Winter Perio
Demand Char e kW $ 3.022.82 $ 29.007.75 $ 32.020.57
Ener Char e kWh 0.085317973 0.00411393 0.0063704 0.095798970
Customer Charge
$/month 611.03578.08
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.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-2 Supersedes Sheet No E-7-2
Effective 7-1-20265 dated 7-1-20254
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the 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. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account
or one Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule,
consists of one or more Accounts which cover contiguous parcels of land with no
intervening public right-of-ways (e.g. streets) and which have a common billing address.
4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the
City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-
type Demand Meter which does not reset after a definite time interval may be used at the
City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 pm on weekdays.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-3 Supersedes Sheet No E-7-3
Effective 7-1-20265 dated 7-1-20254
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.8 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change his system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kVA size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue Meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio $ 9.8925 $ 32.961.54 $ 42.850.79
Winter Perio $0.00 29.007.75 29.007.75
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section D.4)
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-4 Supersedes Sheet No E-7-4
Effective 7-1-20265 dated 7-1-20254
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue Meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-1 Supersedes Sheet No E-7-G-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to Customers who qualify for E-7 Service and who choose to
participate in the Palo Alto Green Program.
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodit Distribution
Public
Benefits
Palo Alto
Green
Char e Total
Summer Perio
Demand Char e er kW $ 12.9107 $ 32.961.54
$
45.873.6
1
Ener Char e er kWh
0.13681278
6 0.0042002 0.0063704 0.0075
0.15488
4542
Winter Perio
Demand Char e er kW $ 3.022.82 $ 29.007.75
$
32.020.5
7
Ener Char e er kWh
0.08531797
3 0.00411393 0.0063704 0.0075
0.10329
09720
Customer Char e $/month 611.03578.08
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-2 Supersedes Sheet No E-7-G-2
Effective 7-1-20265 dated 7-1-20254
2. 1000 kWh Block Purchase Option:
Commodit Distribution Public Benefits Total
Summer Perio
Demand Char e er kW $ 12.9107 $ 32.961.54
$
45.873.6
1
Ener Char e er kWh
0.13681278
6 0.0042002 0.0063704
0.14738
3792
Palo Alto Green Char e er 1000 kWh block $ 7.50
Winter Perio
Demand Char e er kW $ 3.022.82 $ 29.007.75
$
32.020.5
7
Ener Char e er kWh
0.08531797
3 0.00411393 0.0063704
0.09579
8970
Palo Alto Green Char e er 1000 kWh block $7.50
Customer Char e $/month 611.03578.08
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.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the 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. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-3 Supersedes Sheet No E-7-G-3
Effective 7-1-20265 dated 7-1-20254
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has dropped
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the
City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type
Demand Meter which does not reset after a definite time interval may be used at the City's
option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays.
4. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account
or one Meter if the Accounts are at one site. A site, for the purposes of this Rate Schedule,
consists of one or more Accounts which cover contiguous parcels of land with no
intervening public right-of-ways (e.g. streets) and which have a common billing address.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile
6. Palo Alto Green Program Description and Participation
Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities
Department of enough renewable energy credits (RECs) to match 100% of the metered
energy usage at the Customer’s facility each month. Any Customer may alternately request
that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs.
CPAU will charge the Customer the Palo Alto Green Charge for each such requested block.
These REC purchases support the production of renewable energy, increase the financial
value of power from renewal sources, and creates a transparent and sustainable market that
encourages new development of wind and solar.
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-4 Supersedes Sheet No E-7-G-4
Effective 7-1-20265 dated 7-1-20254
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any time,
in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.8 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a qualified line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's Electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change the system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
9. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue Meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Capacity)
Summer Period $ 9.8925 $ 32.961.54 $ 42.850.79
Winter Period 0.00 29.007.75 29.007.75
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3)
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-5 Supersedes Sheet No E-7-G-5
Effective 7-1-20265 dated 7-1-20254
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue Meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-1 Supersedes Sheet No E-7-TOU-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This voluntary Rate Schedule applies to Demand metered Service for non-residential Customers
with a Maximum Demand of at least 1,000KW per month per site, who have sustained this
Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodit Distribution Public Benefits Total
Summer Perio
Demand Char e er kW
Peak $ 12.191.39 $ 17.066.33 $ 29.257.72
Max Deman 1.5646 17.066.33 18.627.79
Ener Char e er kWh
Peak
$
0.194738199 $ 0.0042002 $ 0.0063704 $ 0.2053019205
Mi -Peak 0.160494999 0.0042002 0.0063704 0.171066005
Off-Peak 0.120651276 0.0042002 0.0063704 0.131222282
Winter Perio
Demand Char e er kW
Peak $ 1.5646 $ 15.074.42 $ 16.635.88
Max Deman 1.5646 15.074.42 16.635.88
Ener Char e er kWh
Peak
$
0.130812225 $ 0.00411393 $ 0.0063704 $ 0.141293222
Mi -Peak
0.103230964
8 0.00411393 0.0063704 0.113710645
Off-Peak 0.071266660 0.00411393 0.0063704 0.081747657
Customer Char e $/month 611.03578.08
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-2 Supersedes Sheet No E-7-TOU-2
Effective 7-1-20265 dated 7-1-20254
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.
2. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Energy
Peak: 4:00 pm to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 2:00 p.m. to 4:00 p.m. Monday through Friday (except holidays)
9:00 p.m. to 11:00 p.m.
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
WINTER PERIOD (Service from November 1 to April 30):
Energy
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 9:00 a.m. to 2:00 p.m. Monday through Friday (except holidays)
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-3 Supersedes Sheet No E-7-TOU-3
Effective 7-1-20265 dated 7-1-20254
TYPES OF DEMAND CHARGES: The Peak Demand Charge per Kilowatt applies to the
maximum peak-period Demand during the time periods noted above. The Maximum (Max)
Demand charge per Kilowatt applies to the maximum Demand at any time during the month. Both
Demand Charges apply in each Billing Period, and the maximum peak-period Demand and
maximum Demand may occur at different times in the Billing Period depending on Customer
usage patterns.
SEASONAL RATE CHANGES: When the Billing Period includes use in both the Summer and
the Winter periods, the 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. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account or one
Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule, consists of
one or more Accounts which cover contiguous parcels of land with no intervening public right-of-
ways (e.g. streets) and which have a common billing address.
4. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive
months, a Demand Meter will be installed as promptly as is practicable and thereafter continued
in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve
consecutive months, whereupon, at the option of the City, it may be removed.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time
periods as defined under Section D.2.
5. Changing Rate Schedules
Customers electing to be served under E-7 TOU must remain on said Rate Schedule for a minimum
of 12 months. Should the Customer so wish, at the end of 12 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 Demand and kilowatt-hour usage.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is supplied,
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-4 Supersedes Sheet No E-7-TOU-4
Effective 7-1-20265 dated 7-1-20254
a discount of 2.8 percent for available line voltages above 2 kilovolts will be offered, but the City
is not required to supply Service at a particular line voltage where it has, or will install, ample
facilities for supplying at another voltage equally or better suited to the Customer's electrical
requirements, as determined in the City’s sole discretion. The City retains the right to change its
line voltage at any time after providing reasonable advance notice to any Customer receiving the
discount in this section. The Customer then has the option to change his system so as to receive
Service at the new line voltage or to accept Service (without voltage discount) through
transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio $ 9.8925 $ 32.961.54 $ 42.850.79
Winter Perio 0.00 29.007.75 29.007.75
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue Meter are not operating,
the Maximum Demand will be reduced by the sum of the Maximum Generation of those
non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced
below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the
standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-5 Supersedes Sheet No E-7-TOU-5
Effective 7-1-20265 dated 7-1-20254
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible
Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4) , as
amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No. E-14-1 Supersedes Sheet No. E-14-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to all street and highway lighting installations ranging in voltages from
120 to 480 which CPAU elects to operate and maintain.
B. TERRITORY:
Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City.
C. RATES: $ Per Lamp Per Month –
CPAU supplies electricity and
switching and maintains lighting
system, including lamps and glassware.
Lamp Rating:
Street Lights
Mercury-Vapor Lamps
400 watts 56.743.53
High Pressure Sodium Vapor Lamps
70 watts 37.495.37
100 watts 48.075.35
150 watts 65.722.00
250 watts 101.0295.30
Light Emitting Diode (LED) Lamps
70 watts-equivalent 14.073.27
100 watts-equivalent 22.080.83
150 watts-equivalent 29.477.80
175 watts-equivalent 33.321.43
250 watts 49.686.87
Traffic Signals
12” Head Total (Red Yellow Green) 28.757.12
8” Head Total (RYG) 24.963.55
12” Arrow Total (RYG) 27.025.49
12” Beacon 10.8019
Pedestrian Head 9.9236
Controller 21.250.05
Speed Signs 98.292.73
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No. E-14-2 Supersedes Sheet No. E-14-2
Effective 7-1-20265 dated 7-1-20254
D. SPECIAL CONDITIONS:
1. Point of Delivery: Delivery will be made to the Customer's system at a Service point or at points
designated by CPAU. CPAU will furnish the Service connection to one point for each lamp or group
of lamps, provided the Customer has designed the system to include the minimum number of delivery
points. CPAU will make all underground connections to CPAU’s system at the Customer's expense.
2. Switching: CPAU will perform switching (on CPAU's side of the points of delivery) at no Charge,
provided there are at least 10 kilowatts of lamp load on each circuit separately switched, including all
lamps on the circuit whether served under this Rate Schedule or not. An extra charge of $2.50 per month
will be made for each circuit separately switched unless such switching installation is made for CPAU's
convenience.
3. Annual Burning Schedule: The rates in this Rate Schedule apply to lamps which will be turned on
and off once each night in accordance with a regular burning schedule approved by CPAU and not
exceeding 4,100 hours per year.
4. Maintenance: The rates in this Rate Schedule include all labor necessary for replacement of
glassware, including inspection and cleaning. Maintenance of glassware by CPAU is limited to standard
glassware that is commonly used and manufactured in reasonably large quantities, as determined by
CPAU in its sole discretion. The rates include maintenance of circuits between lamp posts and of circuits
and equipment in and on the posts, provided these are all of good standard construction as determined
by CPAU. CPAU in its sole discretion may decline to grant rates for maintenance of systems with non-
standard glassware, or inadequate circuitry and equipment. Rates applied to any agency other than the
City of Palo Alto also include painting of posts with one coat of good ordinary paint, as determined by
CPAU to be needed to maintain good appearance. Maintenance does not include replacement of posts
damaged by third parties or acts of nature.
5. Rates For Lamps Not on this Rate Schedule: In the event a Customer installs a lamp which is not
represented on this Rate Schedule, CPAU will prepare an interim rate reflecting CPAU's estimated costs
associated with the specific lamp. This interim rate will serve as the effective rate for billing purposes
until the new lamp rating is added to Rate Schedule E-14.
{End}
EXPORT ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-EEC-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-EEC-1 Sheet No. E-EEC-1
dated 79-1-2025 Effective 79-1-20265
A. APPLICABILITY:
This Rate Schedule applies in conjunction with the otherwise applicable Rate Schedules for each
Customer class. This Rate Schedule may not apply in conjunction with any time-of-use Rate Schedule.
This Rate Schedule applies to Customer-Generators as defined in Rule and Regulation 2 who are either
not eligible for Net Energy Metering or who are eligible for Net Energy metering but elect to take
Service under this Rate Schedule.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. RATE:
The following compensation rate shall apply to all electricity exported to the grid.
Per kWh
Export electricity compensation rate $ 0.09901206
D. SPECIAL CONDITIONS
1. Metering equipment: Electricity delivered by CPAU to the Customer-Generator or received by
CPAU from the Customer-Generator shall be measured using a Meter capable of registering the
flow of electricity in two directions (aka “bidirectional meter”). The electrical power
measurements will be used for billing the Customer-Generator. CPAU shall furnish, install and
own the appropriate Meter.
2. Billing:
a. CPAU shall measure during the billing period, in kilowatt-hours, the electricity delivered
and received after the Customer-Generator serves its own instantaneous load.
b. CPAU shall bill the Customer-Generator consumption charges for the electricity delivered
by CPAU to the Customer-Generator based on the Customer-Generator’s applicable Rate
Schedule.
c. In the event the electricity generated exceeds the electricity consumed and therefore is
received by CPAU, the Customer will receive a credit for all electricity received by CPAU
at the buyback Rate designated in section C above.
{End}
NET METERING NET SURPLUS ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-NSE-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-NSE-1 Sheet No. E-NSE-1
dated 097-01-2025 Effective 79-1-20265
A. APPLICABILITY:
This Rate Schedule applies to eligible residential and small commercial Net Energy Metering Election
A Customers who, at the end of an annual settlement period, as described in Rule 29, are Net Surplus
Customer-Generators of electricity who elect to receive monetary compensation as such preference is
indicated on the net surplus electricity election form. This Rate Schedule only applies to Customers
who participate in Net Energy Metering, and does not apply to Customers that take service under the
City’s Net Energy Metering Successor Rate, as each of these terms are defined in Rule and Regulation
2.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. RATES:
Per kWh
Net Surplus Electricity Compensation rate $ 0.106412
D. SPECIAL CONDITIONS
1. Net Surplus Electricity Compensation Rate eligibility shall be determined as specified in Rule 29.
Net surplus electricity, as specified in Rule 29, if applicable, will be multiplied by the above
compensation rate to determine the Customer’s annual net surplus electricity compensation stated
in dollars.
2. Additional terms, conditions and definitions govern Net Energy Metering Service and
Interconnection, as described in Rule 29.
{End}
Attachment A, Exhibit 2
7
4
8
0
Electric Utility Financial Details
1 FISCAL YEAR FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030 FY 2031
2
3 STARTING RESERVES
4 Reappropriations (Non-CIP)--56,811 120,000 253,000 640,000 ------
5 Commitments (Non-CIP)3,910,695 3,518,525 3,512,355 (2,321,000)9,400,307 6,937,396 6,848,100 6,848,100 6,848,100 6,848,100 6,848,100 6,848,100
6 Restricted for Debt Service ------------
7 Emergency Plant Replacement ------------
6 Low Carbon Fuel Standard (LCFS) Reserve -6,340,000 6,943,525 7,235,894 6,711,544 6,534,038 6,372,000 2,127,332 166,153 340,874 666,446 -
7 Cap and Trade 1,189,000 1,189,000 2,230,759 4,123,000 6,674,629 5,624,568 4,174,999 3,121,266 1,245,432 870,724
8 Underground Loan Reserve 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659
9 Public Benefits Reserves 809,700 1,904,547 3,027,599 3,890,872 5,672,542 7,268,279 8,163,067 11,046,567 7,451,112 6,053,766 4,400,296 2,472,477
10 Electric Special Projects Reserve 41,664,855 46,664,855 46,664,855 24,649,000 20,148,855 22,648,855 30,148,855 31,168,855 32,188,855 33,208,855 34,228,855 35,248,855
11 Hydro Stabilization Reserve 11,400,000 15,400,000 15,400,000 400,000 400,000 17,400,000 18,767,410 18,767,410 24,767,410 24,767,410 24,767,410 24,767,410
12 Capital Reserves 879,964 5,879,964 879,964 879,964 879,964 879,964 879,964 5,879,964 8,879,964 12,379,964 15,879,964 19,379,964
13 Rate Stabilization Reserves ------------
14 Electrification Reserve 4,500,000 4,500,000 2,036,520 2,036,520 2,036,520 2,036,520 2,036,520 2,036,520
14 Operations Reserves (Supply & Dist)46,743,752 38,851,877 30,216,268 28,559,158 38,881,723 32,218,564 46,580,650 41,633,917 56,723,486 59,948,249 63,070,426 59,790,387
15 Unassigned 313,418 1,499,585 1,754,427 ---------
16 TOTAL STARTING RESERVES 106,449,043 120,786,012 110,371,463 65,329,547 89,805,353 103,876,755 127,197,855 125,859,893 143,963,258 149,431,664 153,870,109 152,141,097
17
18 REVENUES
19 Net Sales 137,026,504 129,389,001 130,557,545 164,554,954 178,549,357 186,619,683 199,175,456 212,866,263 226,681,747 243,235,642 259,619,706 272,874,132
20 Wholesale Revenues 20,686,925 25,959,207 25,529,188 30,745,937 37,702,239 44,274,671 45,315,800 33,648,756 24,964,997 23,577,203 22,911,675 23,270,287
21 Other Revenues and Transfers In 15,260,937 9,324,996 9,348,837 32,788,973 14,607,837 13,180,520 12,009,997 12,323,712 12,868,533 12,829,829 14,393,370 14,493,775
22 TOTAL REVENUES 172,974,366 164,673,204 165,435,570 228,089,864 230,859,433 244,074,874 256,501,253 258,838,731 264,515,278 279,642,674 296,924,751 310,638,194
23
24 EXPENSES
25 Electric Supply Purchases 97,716,399 106,202,833 120,493,223 128,512,096 106,529,511 115,700,909 134,879,280 131,684,730 127,336,048 137,690,208 147,088,139 149,295,896
26 Operating Expenses
27 Administration
28 Allocated Charges 6,146,498 6,674,515 5,732,098 9,664,335 14,356,076 14,248,772 15,274,813 16,015,859 16,615,221 17,237,319 17,883,026 18,553,248
29 Rent 5,666,805 5,949,976 6,069,000 6,324,000 6,640,200 7,037,534 7,382,387 7,836,208 8,147,666 8,471,523 8,808,273 9,158,430
30 Equity Transfer 13,134,000 13,638,000 14,138,000 14,534,000 14,904,000 15,985,000 17,564,000 17,951,000 19,059,000 20,369,000 21,690,000 23,118,000
31 Transfers and Other Adjustments (3,000,057)(4,027,621)4,065,654 619,705 453,252 677,820 2,070,933 733,130 762,455 792,954 824,672 1,049,696
32 Subtotal, Administration 21,947,247 22,234,870 30,004,752 31,142,040 36,353,528 37,949,125 42,292,133 42,536,197 44,584,342 46,870,796 49,205,971 51,879,374
33 Resource Management 2,870,524 2,781,010 2,824,285 3,086,893 5,102,246 4,152,346 4,285,263 4,469,529 4,633,561 4,803,612 4,979,905 5,162,667
34 Demand Side Management 2,733,047 3,819,646 4,086,083 4,354,087 4,967,273 5,769,928 8,338,258 13,053,972 9,256,769 9,991,199 11,350,629 11,545,346
35 Operations and Mtc 13,450,568 15,988,315 16,576,083 20,538,544 19,842,146 18,381,420 23,227,725 23,631,341 25,160,068 26,166,470 27,213,129 28,301,654
36 Engineering (Operating)2,051,303 2,408,524 1,806,550 2,022,434 2,545,886 2,723,538 3,287,287 3,419,962 3,556,760 3,699,031 3,846,992 4,000,872
37 Customer Service 2,228,469 2,320,338 2,974,968 1,328,808 3,930,754 3,417,594 3,525,344 3,674,819 3,821,812 3,974,684 4,133,672 4,299,018
38 Allowance for Unspent Budget ------------
39 Subtotal, Operating Expenses 45,281,157 49,552,702 58,272,721 62,472,805 72,741,832 72,393,951 84,956,010 90,785,819 91,013,312 95,505,793 100,730,297 105,188,931
40 Capital Expenses
41 Capital Program Contribution 15,539,840 21,487,061 34,524,744 21,656,368 22,345,178 40,857,331 35,590,601 10,122,012 33,300,545 34,109,160 35,697,564 36,369,985
42 Capital-Related Debt Service 100,000 100,000 100,000 20,789 ---5,743,235 5,243,235 5,243,235 14,096,062 13,549,699
43 Subtotal, Capital Expenses 15,639,840 21,587,061 34,624,744 21,677,157 22,345,178 40,857,331 35,590,601 15,865,247 38,543,780 39,352,394 49,793,626 49,919,684
44 TOTAL EXPENSES 158,637,396 177,342,596 213,390,688 212,662,058 201,616,522 228,952,192 255,425,891 238,335,797 256,893,140 272,548,395 297,612,063 304,404,512
45
46 ENDING RESERVES
47 Reappropriations (Non-CIP)-56,811 120,000 253,000 640,000 -------
48 Commitments (Non-CIP)3,518,525 3,512,355 (2,321,000)9,400,307 6,937,396 6,848,100 6,848,100 6,848,100 6,848,100 6,848,100 6,848,100 6,848,100
49 Restricted for Debt Service ------------
50 Emergency Plant Replacement ------------
51 Low Carbon Fuel Standard (LCFS) Reserve 6,340,000 6,943,525 7,235,894 6,711,544 6,534,038 6,372,000 2,127,332 166,153 340,874 666,446 546,992 -
52 Cap and Trade 1,189,000 1,189,000 2,230,759 4,123,000 6,674,629 5,624,568 4,174,999 3,121,266 1,245,432 870,724 605,387
53 Underground Loan Reserve 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659
54 Public Benefits Reserves 1,904,547 3,027,599 3,890,872 5,672,542 7,268,279 8,163,067 11,046,567 7,451,112 6,053,766 4,400,296 2,472,477 228,311
55 Electric Special Projects Reserve 46,664,855 46,664,855 24,649,000 20,148,855 22,648,855 30,148,855 31,168,855 32,188,855 33,208,855 34,228,855 35,248,855 35,248,855
56 Hydro Stabilization Reserve 15,400,000 15,400,000 400,000 400,000 17,400,000 18,767,410 18,767,410 24,767,410 24,767,410 24,767,410 24,767,410 24,767,410
57 Capital Reserve 5,879,964 879,964 879,964 879,964 879,964 879,964 5,879,964 8,879,964 12,379,964 15,879,964 19,379,964 22,879,964
58 Rate Stabilization Reserve ------------
59 Electrification Reserve 4,500,000 4,500,000 2,036,520 2,036,520 2,036,520 2,036,520 2,036,520 2,036,520 2,036,520
60 Operations Reserve (Supply & Dist)38,851,877 30,216,268 28,559,158 38,881,723 32,218,564 46,580,650 41,633,917 56,723,486 59,948,249 63,070,426 59,790,387 65,033,573
61 Unassigned 1,499,585 1,754,427 ----------
62 TOTAL ENDING RESERVES 120,786,012 110,371,463 65,329,547 89,805,353 103,876,755 127,197,855 125,859,893 143,963,258 149,431,664 153,870,109 152,688,088 158,374,779
63
64 OPERATIONS RESERVE
65 Min (60 days of non-capital expenses)21,857,032 24,040,300 26,410,239 28,907,176 26,944,782 28,180,609 33,306,359 34,837,681 33,850,664 36,153,389 39,434,718 -
66 Target (90 days of non-capital expenses)32,785,549 36,060,449 39,615,359 43,360,764 40,417,173 42,270,914 49,959,538 52,256,521 50,775,996 54,230,083 59,152,077 -
67 Max (120 days of non-capital expenses)43,714,065 48,080,599 52,820,479 57,814,351 53,889,564 56,361,219 66,612,717 69,675,361 67,701,328 72,306,778 78,869,436 -
68 Risk Assessment Value 6,033,288 6,428,010 6,730,204 6,415,268 8,570,046 10,357,906 10,583,893 8,353,152 11,111,462 11,737,022 12,395,429 12,903,955
69
70 DEBT SERVICE COVERAGE RATIO
71 Net Revenues (125% of Debt Service)517%212%-66%535%722%1426%891%390%509%511%285%332%
72 Available Reserves (5x Debt Service)*16.4 13.6 8.4 9.4 11.6 28.5 25.7 13.0 14.2 14.7 7.7 8.3
*For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants.
Attachment A, Exhibit 2
7
4
8
0
Electric Utility Capital Improvement Program (CIP) Financial Details
Attachment A, Exhibit 3
7
4
8
1
ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
Attachment A, Exhibit 3
7
4
8
1
d) To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 11 (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) For tracking revenues earned via the sale of Low Carbon Fuel Credits allocated by the
California Air Resources Board to the City, as well as expenses incurred, in accordance
with California’s Low Caron Fuel Standard program, as described in Section 15 (Low
Carbon Fuel Standard Reserve)
i) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves
for Commitments will be set to an amount equal to the total remaining spending authority
for all contracts in force for the Electric Supply Fund and Electric Distribution Fund,
respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves
for Reappropriations will be set to an amount equal to the amount of all remaining capital
and non-capital budgets that will be reappropriated to the following fiscal year for each Fund
in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies set forth in Resolution 9206 (Resolution of the Council of the City of Palo Alto
Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve and
Adoption of Electric Special Project Reserve Guidelines). These policies are included from
Resolution 9206 as amended to refer to the reserves structure set forth in these Reserves
Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2025;
f) Any uncommitted funds remaining at the end of FY 2030 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
Attachment A, Exhibit 3
7
4
8
1
Section 7. Hydroelectric Stabilization Reserve
after the
transfers described above shall be the basis for staff’s determination, with Council
approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-HRA) for
the following fiscal year.
Attachment A, Exhibit 3
7
4
8
1
Maximum Level Average annual (12 month)1 CIP budget, for
48 months of budgeted CIP expenses2
b) Changes in Reserves: At the end of each fiscal year staff will transfer from the Distribution
Operations Reserve to the CIP Reserve an amount equal to the amount of electric utility
unspent CIP budget at the end of the fiscal year reduced by the amount of any contractual
commitments and reappropriations. Any other additions to or withdrawals from the CIP
reserve require Council action.
c) Minimum Level:
i) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve reaching
its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is
below its minimum level at the end of FY 2017, staff must present a plan by June 30,
2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff
may present, and the Council may adopt, an alternative plan that takes longer than
one year to replenish the reserve, or that does so in a shorter period of time.
d) Maximum Level: If there are funds in this reserve in excess of the maximum level staff
must propose in the next Financial Plan to transfer these funds to another reserve or
return them to ratepayers in the funds to ratepayers, or designate a specific use of funds
for CIP investments that will be made by the end of the next Financial Planning period.
Staff may also seek City Council to approve holding funds in this reserve in excess of the
maximum level if they are held for a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period. The Council may approve exceptions
to this requirement, when proposed by staff to provide greater rate stabilization to
customers.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to 11 above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
Attachment A, Exhibit 3
7
4
8
1
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were funds
in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning Period is
FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign the funds
in the Unassigned Reserve by the end of FY 2017. Staff may present an alternative plan that
retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Attachment A, Exhibit 3
7
4
8
1
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
Section 15. Low Carbon Fuel Standard (LCFS) Reserve
This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the
California Air Resources Board to the City, as well as expenses incurred, in accordance with
California’s Low Caron Fuel Standard program. At the end of each fiscal year, the LCFS
Reserve will be adjusted by the net of revenues and expenses associated with California’s
LCFS program.
Section 16. Cap- and- InvestTrade Program Reserve
This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the electric utility, under the State’s Cap-
and- InvestTrade Program. Funds in this Reserve are managed in accordance with the City’s
Policy on the Use of Freely Allocated Allowances under the State’s Cap- and- InvestTrade
Program (the Policy), adopted by Council Resolution 9487 in January 2015. At the end of each
fiscal year, the Cap- and- InvestTrade Program Reserve will be adjusted by the net of revenues
and expenses associated with the Cap -and -InvestTrade program.
Section 17. Electrification Reserve
This reserve is used to track funding of City buildings, appliance and vehicle electrification
projects and programs, including development and implementation costs and associated
financial incentives, loans and rebates for participating customers. The reserve may be
funded by any lawful source of funds available for such programs, including new or ongoing
utility revenues derived from customer participation. The reserve balance shall be annually
adjusted based on the net of revenues and expenses associated with the City’s building
appliance and vehicle electrification projects and programs using this reserve.
Attachment B
6
8
6
0
COMMUNICATIONS PLAN AND OUTREACH EXAMPLES – ELECTRIC UTILITY
The Electric Utility Financial Forecast and proposed rate adjustments are designed to ensure the long-
term reliability, sustainability, and fiscal health of the city’s electric system while advancing grid
modernization and aligning with City Council priorities.
Reasons for the Proposed Rate Increase
The proposed rate increase reflects rising operational and capital costs driven by investments in grid
modernization, system reliability, renewable energy requirements, and cost inflation affecting labor,
materials, and transmission access. Electric grid modernization includes major infrastructure projects
such as substation upgrades and the conversion of legacy 4 kilovolt (kV) systems to 12kV to enhance
reliability and accommodate future electrification. Additionally, for the Electric Utility, the city is facing
increasing cost pressures for transmission access charges, Renewable Portfolio Standard (RPS)
compliance, and resource adequacy expenses which are expected to rise steadily through the forecast
period. There is also a continued need to replenish reserves for the Electric Utility.
The proposed rate adjustments are necessary to continue delivering safe, reliable, carbon-neutral
electricity and to ensure the Electric Utility remains financially self-sufficient while maintaining robust
reserves in accordance with adopted policies.
Communication Plan and Messaging Strategy
Staff will implement a proactive communication plan designed to provide clear, transparent, and
frequent information about the proposed rate changes, their underlying cost drivers, the city’s efforts
to minimize bill impacts, and continued commitment to affordable, sustainable, and reliable power.
Key communication objectives are to:
Increase transparency by clearly explaining the financial and policy reasons for the proposed
rate adjustments, including how grid modernization and system reinvestment benefit current
and future customers.
Emphasize that despite the proposed increases, Palo Alto’s average residential electric bill
remains significantly lower than PG&E and competitive with neighboring municipal utilities.
Reinforce that rate proposals are based on cost-of-service principles consistent with
Proposition 26 and approved by City Council.
Position the rate plan as an investment in system resilience, electrification readiness, and
operational reliability.
Emphasize stewardship, value, and reliability, underscoring that the proposed adjustments help
sustain world-class service and environmental leadership as the city transitions toward broader
electrification.
Communicate available programs such as energy efficiency rebates, low income and rate
assistance, and electrification incentives to help customers manage their bills.
Communication methods throughout the year, and specifically for rate changes, include direct
customer outreach through utility bill inserts, targeted community newsletters and/or blogs, website
Attachment B
6
8
6
0
updates at www.paloalto.gov/RatesOverview, social media, print and digital advertising, and
participation in community outreach events. Public communication materials about rate changes
feature FAQs, charts or other visuals including infographics showing the breakdown of utility costs that
correlate with the need for rate increases, and explanations of how customer classes are affected.
Messaging emphasizes rate adjustments are necessary to sustain safe, reliable, and financially sound
electric operations consistent with the city’s long-term energy strategy. Additionally, CPAU continues
to explore cost-containment measures to keep rates affordable and minimize customer bill impacts.
Stakeholder Engagement
Public meetings before the Utilities Advisory Commission (UAC), Finance Committee, and City
Council to present rate proposals, ensure consistency with adopted policy goals and fiscal
prudence, and solicit community feedback.
Coordination with community stakeholders including local businesses, electrification advocates,
environmental organizations, and customer assistance program partners to understand and
address concerns about affordability and system resilience.
Internal staff training to ensure consistent communication and responsive customer support
once rate adjustments take effect.
Attachment B
6
8
6
0
March 31, 2026 PaloAlto.gov
FY 2027 Electric Rate Proposal
Utilities Advisory Commission
2
Electric Utility At-A-Glance
•Purchase and deliver over 900,000,000 kWh annually
•29,994 metered services
•317 miles of high-voltage distribution line (36% overhead, 64%
underground)
•17 miles of sub-transmission
•Nine substations
•Over 2,200 transformers
•127 Staff
•$230 Million Operating Budget (FY 2026)
•$85 Million Capital Budget (FY 2026)
•$315 Million Total Budget (FY 2026)
•~60%renewable
•100% carbon neutral
Utilities undergrounding
in Foothills for wildfire
mitigation
Electric Grid
Modernization
3
Purpose of Rate Adjustments
•Preserve fair cost recovery for the services provided
•Maintain Long-Term Financial Stability
•Sustained financial support for ongoing utility operations
•Develop funding for planned replacement of aging infrastructure
•Supporting adequate reserve levels
•Adjust for changes in carbon free energy costs
•Increases in market resource adequacy requirements minus resource adequacy
revenue projected to decrease $4.4 million from FY 26 – FY 28
•Increased costs for renewable energy minus net renewables costs projected to
increase by $6.7 million from FY 26 – FY 28
•Support Council goals for electrification and wildfire mitigation
•Near completion of the 10-mile Foothills undergrounding project
•Entering period of increased capital expense for Grid-Modernization
4
Value of Utility Services and How Funds are Used
•Improved operations and preventative maintenance to increase
service reliability
•Grid Modernization to replace aging facilities, lower system outages,
and increase capacity for electrification
•Completion of the Advanced Metering Infrastructure (smart meters)
•Wildfire mitigation through Foothills undergrounding project
•Supply – actively evaluating market to purchase sustainable energy
and minimize costs
•Continued advocation for Ames transmission source
•Continued supply of carbon neutral energy
•Locally driven programs for electrification and GHG reductions
5
Electric Utility Cost Structure: Average FY 2024-2025
$79 M
Total Supply Costs
46%
•About half of the retail rate is
“supply-related.” which includes the
cost to buy and transport electricity
plus revenues from surplus sales
(energy and capacity)
•The remaining portion of the rate is
based on the City’s cost for
maintaining and replacing
infrastructure, customer service and
billing, administration, etc.
6
Electric Cost and Revenue Projections
7
Electric Bill Comparisons
Calculated using the "average" bundled total rates, and Climate Zone X,
which includes most nearby comparison communities
Includes the annual climate credit, and Climate Zone X, which includes most
nearby comparison communities
Usage (kWh/mo)
Palo Alto
7/1/2026
PG&E
1/1/2026
Santa Clara
1/1/2026
Difference from
PG&E
Difference from
Santa Clara
300 $71 $117 $53 -40%33%
(Median) 408 $94 $168 $72 -44%31%
650 $152 $283 $117 -46%30%
1,200 $286 $544 $218 -47%31%
Usage (kWh/mo)
Palo Alto
7/1/2026
PG&E
1/1/2026
Santa Clara
1/1/2026
Difference from
PG&E
Difference from
Santa Clara
1,000 $238 $433 $264 -45%-10%
160,000 $34,153 $69,210 $28,924 -51%18%
500,000 $106,434 $191,670 $90,175 -44%18%
2,000,000 $377,129 $618,760 $360,401 -39%5%
8
Electric Operating Reserve Projection
Reserve Target: 90 days of O&M and
commodity expense
Reserve Maximum: 120 days of O&M and
commodity expense
Reserve Minimum: 60 days of O&M and
commodity expense
Note: At year end FY 2025 the Hydro Stabilization Reserve balance was $18.7 million
9
Electric Utility CIP Spending ($M)
2025*2026 2027 2028 2029 2030 2031 Total
Grid Modernization $13.7 $30.5 $43.7 $39.9 $20.3 $52.2 $53.5 $253.8
All Other Capital Investment $21.4 $39.0 $15.2 $15.9 $16.4 $17.7 $18.1 $143.7
Total $35.1 $69.5 $58.8 $55.7 $36.7 $69.9 $71.7 $397.5
Rough Indication of Project Driver
Key Projects
Estimated
Cost
($M)
Estimated
Completion
Aging
Infrastructure
System
Reliability Capacity
Sub-Transmission Reconductor $4.6 FY2029 0%80%20%
4kV Substation & Distribution Conversions $80.4 FY2032 60%20%20%
Colorado Substation Upgrades $64.7 FY2031 50%30%20%
Adobe Creek Substation Upgrades $24.0 FY2033 40%30%30%
Grid-Mod 12kV Distribution Upgrades $243.6 Ongoing 40%20%40%
10
Electric Bill Impact
Rate Schedule Usage (kWh/mo)
Peak Demand
kW-mo
Monthly Bill
Change
(%)Current Rates Proposed Rates Change
E-1 (Residential)
300 NA $67 $71 $4 6%
(Summer Median) 365 NA $80 $85 $5 6%
(Winter Median) 450 NA $98 $103 $6 6%
650 NA $144 $152 $8 6%
1,200 NA $270 $286 $16 6%
E-2
(Small Non-
Residential)
1,000 NA $225 $238 $13 6%
E-4
(Medium Non-
Residential)
160,000 274 $32,254 $34,153 $1,899 6%
500,000 856 $100,515 $106,434 $5,919 6%
E-7
(Large Non-
Residential)
2,000,000 3,424 $355,194 $377,129 $21,934 6%
11
Communication and Outreach
Key Messages
•Reasons for rate increases and benefits to customers:
•Infrastructure upgrades, enhanced capacity, reliability,
redundancy, and safety; improved efficiencies
•Competitive rates to other utilities and neighboring cities
•What the City is doing to keep costs down
•City programs and services to help customers keep utility bill costs low
Outreach Strategies
•Public Meetings: UAC, Finance, City Council
•Print and Digital Communication:utility bill
inserts, website, email newsletters, City blog, videos
•Local Media Engagement: articles, interviews
Sample utility bill insert
about energy efficiency
Replacing a utility pole as
part of the Electric Grid
Modernization Project
Recently Implemented Cost Containment
12
•Expanded use of bank draft to reduce credit card fees
•Scheduled larger CIP projects every other year achieving efficient project management and lower construction costs
(estimated $50K per CIP project)
•Implemented mobile workforce applications, reducing administrative data entry time, freeing up staff for other work
Water, Gas, and Wastewater
•Established cross-functional field
crew to install water, gas, and
sewer services simultaneously at
new construction sites, reducing
hours spent in the field by
minimum 20%
Electric Utility
•Selling surplus Resource
Adequacy and Renewable Energy
Credits ($20+ million/year)
•Negotiated improvements to
Western hydroelectric contract
($2 million/year)
•Negotiated layoff of transmission
asset generating $550k/year
Water Utility
•Agreement with Valley Water
yielded $16 million in funding for
reverse osmosis facility to
improve recycled water quality
and $250K to $1M/year
•BAWSCA water bond refunding in
2023 achieved lower debt service
payments ($185K/year 2023-
2034)
13
Future Potential Cost Containment
•Implement new customer information system with reduced support costs
•Increase water and energy end use technical training for Customer Service
Representatives, reducing transferred phone calls and staff time
Water, Gas, and Wastewater
•Cluster gas main replacements
to reduce mobilization costs for
construction contractors ($5K -
$10K for each project group)
Electric Utility
•Prepay of renewable power purchase
agreements to monetize municipal tax-
exempt debt
•Optimize debt issuance timing and
amount for Grid Modernization to
minimize debt service costs to electric
customers
•Additional value from Western federally-
owned transmission ($500K/year)
•Challenge transmission rates via Northern
California Power Agency ($500K/year)
14
FY 2027 Proposed Budget Reductions (Electric)
Reduction in operating expenses due to Utilities Department-wide budget refinements
and improved efficiencies
•Eliminate vacant Meter Reader positions: $260K
•Outsource utility bill printing and mailing: $85K
•Implement credit card processing fee: $775K
•Transfer from pension trust: $600K
Sources of additional potential budget reductions:
•Council priority on organizational efficiencies
•Leverage internal resources between departments
•Reviewing on-call contracts to identify where filling vacancies could lower contract
costs
15
Proposal
•6% overall rate increase in FY 2027 (4.5% increase in distribution rates, combined with 7% increase in supply rates),
approximately $5.10/month increase for the median residential customer
Drivers of the 5-Year Rate Trajectory
•Investment in grid modernization funded by revenues and bond financing; first bond issuance in FY 2027; new
warehouse and laydown yard, replacement of emergency generators and new approach to grid modernization
described to the Utilities Advisory Commission on January 7, 2026
•In current year, power supply costs lower than budget; high market prices for Resource Adequacy capacity and
renewable energy credits have yielded higher wholesale revenues
•Longer-term transmission costs & renewable energy targets are rising and Resource Adequacy requirements are
tightening; Resource Adequacy costs are expected to increase while Resource Adequacy sales revenue declines
•Transfer $6 million to the Hydroelectric Rate Stabilization Reserve to help with rate stability in upcoming drier years
Compared with Preliminary Rates (November 2025)
•Reflects climate action budget; supply forecast update
Summary of Electric Rate Proposal
16
Residential Median Bill Projections (Bill $ and % change from prior year)
1)FY 2026 includes results of cost-of-service analysis; changes shown with commodity rates held constant; actual gas commodity rates vary monthly;
2)Storm water management fees increase by CPI index annually per approved 2017 ballot measure (2.4% in FY 2026 and 3% in FY 202 7);
17
Electric Recommendation
Staff recommends the Utilities Advisory Commission recommend that the City Council adopt a resolution
(Attachment A):
1.Approving the Fiscal Year 2027 Electric Utility Financial Forecast shown in this staff report and
attachments; and
2.Approving the transfer at the end of FY 2026 of up to $5 million from the Electric Utility Distribution
Operations Reserve to the Electric CIP Reserve; and
3.Amending Rate Schedules (Attachment A, Exhibit 1) effective July 1, 2026 (FY 2027): E-1 (Residential
Electric Service), E-1 TOU (Residential Time of Use Electric Service), E-2 (Residential Master-Metered
and Small Non-Residential Electric Service), E-2-G (Residential Master-Metered and Small Non-
Residential Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-Residential Time of
Use Electric Service), E-7 (Large Non-Residential Electric Service), E-7-G (Large Non-Residential Green
Power Electric Service), E-7 TOU (Large Non-Residential Time of Use Electric Service), E-14 (Street
Lights), E-EEC-1 (Export Electricity Compensation), and E-NSE-1 (Net Metering Surplus Electricity
Compensation)
April 21, 2026 PaloAlto.gov
FY 2027 Electric Rate Proposal
Finance Committee
2
Electric Utility At-A-Glance
•Purchase and deliver over 900,000,000 kWh annually
•29,994 metered services
•317 miles of high-voltage distribution line (36% overhead, 64%
underground)
•17 miles of sub-transmission
•Nine substations
•Over 2,200 transformers
•127 Staff
•$230 Million Operating Budget (FY 2026)
•$85 Million Capital Budget (FY 2026)
•$315 Million Total Budget (FY 2026)
•~60%renewable
•100% carbon neutral
Utilities undergrounding
in Foothills for wildfire
mitigation
Electric Grid
Modernization
3
Purpose of Rate Adjustments
•Preserve fair cost recovery for the services provided
•Maintain Long-Term Financial Stability
•Sustained financial support for ongoing utility operations
•Develop funding for planned replacement of aging infrastructure
•Supporting adequate reserve levels
•Adjust for changes in carbon free energy costs
•Increases in market resource adequacy requirements minus resource adequacy
revenue projected to decrease $4.4 million from FY 26 – FY 28
•Increased costs for renewable energy minus net renewables costs projected to
increase by $6.7 million from FY 26 – FY 28
•Support Council goals for electrification and wildfire mitigation
•Near completion of the 10-mile Foothills undergrounding project
•Entering period of increased capital expense for Grid-Modernization
4
Value of Utility Services and How Funds are Used
•Improved operations and preventative maintenance to increase
service reliability
•Grid Modernization to replace aging facilities, lower system outages,
and increase capacity for electrification
•Completion of the Advanced Metering Infrastructure (smart meters)
•Wildfire mitigation through Foothills undergrounding project
•Supply – actively evaluating market to purchase sustainable energy
and minimize costs
•Continued advocation for Ames transmission source
•Continued supply of carbon neutral energy
•Locally driven programs for electrification and GHG reductions
5
Electric Utility Cost Structure: Average FY 2024-2025
$79 M
Total Supply Costs
46%
•About half of the retail rate is
“supply-related.” which includes the
cost to buy and transport electricity
plus revenues from surplus sales
(energy and capacity)
•The remaining portion of the rate is
based on the City’s cost for
maintaining and replacing
infrastructure, customer service and
billing, administration, etc.
6
Electric Cost and Revenue Projections
7
Electric Bill Comparisons
Calculated using the "average" bundled total rates, and Climate Zone X,
which includes most nearby comparison communities
Includes the annual climate credit, and Climate Zone X, which includes most
nearby comparison communities
Usage (kWh/mo)
Palo Alto
7/1/2026
PG&E
1/1/2026
Santa Clara
1/1/2026
Difference from
PG&E
Difference from
Santa Clara
300 $71 $117 $53 -40%33%
(Median) 408 $94 $168 $72 -44%31%
650 $152 $283 $117 -46%30%
1,200 $286 $544 $218 -47%31%
Usage (kWh/mo)
Palo Alto
7/1/2026
PG&E
1/1/2026
Santa Clara
1/1/2026
Difference from
PG&E
Difference from
Santa Clara
1,000 $238 $433 $264 -45%-10%
160,000 $34,153 $69,210 $28,924 -51%18%
500,000 $106,434 $191,670 $90,175 -44%18%
2,000,000 $377,129 $618,760 $360,401 -39%5%
8
Electric Operating Reserve Projection
Reserve Target: 90 days of O&M and
commodity expense
Reserve Maximum: 120 days of O&M and
commodity expense
Reserve Minimum: 60 days of O&M and
commodity expense
Note: At year end FY 2025 the Hydro Stabilization Reserve balance was $18.7 million
9
Electric Utility CIP Spending ($M)
2025*2026 2027 2028 2029 2030 2031 Total
Grid Modernization $13.7 $30.5 $43.7 $39.9 $20.3 $52.2 $53.5 $253.8
All Other Capital Investment $21.4 $39.0 $15.2 $15.9 $16.4 $17.7 $18.1 $143.7
Rough Indication of Project Driver
Key Projects
Estimated
Cost
($M)
Estimated
Completion
Aging
Infrastructure
System
Reliability Capacity
Sub-Transmission Reconductor $4.6 FY2029 0%80%20%
4kV Substation & Distribution Conversions $80.4 FY2032 60%20%20%
Colorado Substation Upgrades $64.7 FY2031 50%30%20%
Adobe Creek Substation Upgrades $24.0 FY2033 40%30%30%
Grid-Mod 12kV Distribution Upgrades $243.6 Ongoing 40%20%40%
10
Electric Bill Impact
Rate Schedule Usage (kWh/mo)
Peak Demand
kW-mo
Monthly Bill
Change
(%)Current Rates Proposed Rates Change
E-1 (Residential)
300 NA $67 $71 $4 6%
(Summer Median) 365 NA $80 $85 $5 6%
(Winter Median) 450 NA $98 $103 $6 6%
650 NA $144 $152 $8 6%
1,200 NA $270 $286 $16 6%
E-2
(Small Non-
Residential)
1,000 NA $225 $238 $13 6%
E-4
(Medium Non-
Residential)
160,000 274 $32,254 $34,153 $1,899 6%
500,000 856 $100,515 $106,434 $5,919 6%
E-7
(Large Non-
Residential)
2,000,000 3,424 $355,194 $377,129 $21,934 6%
11
Communication and Outreach
Key Messages
•Reasons for rate increases and benefits to customers:
•Infrastructure upgrades, enhanced capacity, reliability,
redundancy, and safety; improved efficiencies
•Competitive rates to other utilities and neighboring cities
•What the City is doing to keep costs down
•City programs and services to help customers keep utility bill costs low
Outreach Strategies
•Public Meetings: UAC, Finance, City Council
•Print and Digital Communication:utility bill
inserts, website, email newsletters, City blog, videos
•Local Media Engagement: articles, interviews
Sample utility bill insert
about energy efficiency
Replacing a utility pole as
part of the Electric Grid
Modernization Project
Recently Implemented Cost Containment
12
•Expanded use of bank draft to reduce credit card fees
•Scheduled larger CIP projects every other year achieving efficient project management and lower construction costs
(estimated $50K per CIP project)
•Implemented mobile workforce applications, reducing administrative data entry time, freeing up staff for other work
Water, Gas, and Wastewater
•Established cross-functional field
crew to install water, gas, and
sewer services simultaneously at
new construction sites, reducing
hours spent in the field by
minimum 20%
Electric Utility
• Transmission Rate Case Litigation
($1.5 million/year in savings)
•Selling surplus Resource
Adequacy and Renewable Energy
Credits ($10 million last year)
•Savings in Western hydroelectric
contract (~$4 million/year)
•Transmission asset generating
revenue $550k/year
Water Utility
•Agreement with Valley Water
yielded $16 million in funding for
reverse osmosis facility to
improve recycled water quality
and $250K to $1M/year
•BAWSCA water bond refunding in
2023 achieved lower debt service
payments ($185K/year 2023-
2034)
13
Future Potential Cost Containment
•Implement new customer information system with reduced support costs
•Increase water and energy end use technical training for Customer Service
Representatives, reducing transferred phone calls and staff time
Water, Gas, and Wastewater
•Cluster gas main replacements
to reduce mobilization costs for
construction contractors ($5K-
$10K for each project group)
Electric Utility
•Prepay of renewable power purchase
agreements to monetize municipal tax-
exempt debt
•Optimize debt issuance timing and
amount for Grid Modernization to
minimize debt service costs to electric
customers
•Additional value from Western federally-
owned transmission ($500K/year)
•Challenge transmission rates via Northern
California Power Agency ($500K/year)
14
FY 2027 Proposed Budget Reductions (Electric)
Reduction in operating expenses due to Utilities Department-wide budget refinements
and improved efficiencies
•Eliminate vacant Meter Reader positions: $260K
•Outsource utility bill printing and mailing: $85K
•Implement credit card processing fee: $775K
•Transfer from pension trust: $600K
Sources of additional potential budget reductions:
•Council priority on organizational efficiencies
•Leverage internal resources between departments
•Reviewing on-call contracts to identify where filling vacancies could lower contract
costs
15
Proposal
•6% overall rate increase in FY 2027 (4.5% increase in distribution rates, combined with 7% increase in supply rates),
approximately $5.10/month increase for the median residential customer
Drivers of the 5-Year Rate Trajectory
•Investment in grid modernization funded by revenues and bond financing; first bond issuance in FY 2027; new
warehouse and laydown yard, replacement of emergency generators and new approach to grid modernization
described to the Utilities Advisory Commission on January 7, 2026
•In current year, power supply costs lower than budget; high market prices for Resource Adequacy capacity and
renewable energy credits have yielded higher wholesale revenues
•Longer-term transmission costs & renewable energy targets are rising and Resource Adequacy requirements are
tightening; Resource Adequacy costs are expected to increase while Resource Adequacy sales revenue declines
•Transfer $6 million to the Hydroelectric Rate Stabilization Reserve to help with rate stability in upcoming drier years
Compared with Preliminary Rates (November 2025)
•Reflects climate action budget; supply forecast update
Summary of Electric Rate Proposal
16
Residential Median Bill Projections (Bill $ and % change from prior year)
1)FY 2026 includes results of cost-of-service analysis; changes shown with commodity rates held constant; actual gas commodity rates vary monthly
2)Storm water management fees increase by CPI index annually per approved 2017 ballot measure (2.4% in FY 2026 and 3% in FY 2027)
17
Electric Recommendation
Staff and the UAC recommend the Finance Committee recommend that the City Council adopt a
resolution (Attachment A):
1.Approving the Fiscal Year 2027 Electric Utility Financial Forecast shown in the staff report and
attachments; and
2.Approving the transfer at the end of FY 2026 of up to $5 million from the Electric Utility Distribution
Operations Reserve to the Electric CIP Reserve; and
3.Amending Rate Schedules (Attachment A, Exhibit 1) effective July 1, 2026 (FY 2027): E-1 (Residential
Electric Service), E-1 TOU (Residential Time of Use Electric Service), E-2 (Residential Master-Metered
and Small Non-Residential Electric Service), E-2-G (Residential Master-Metered and Small Non-
Residential Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-Residential Time of
Use Electric Service), E-7 (Large Non-Residential Electric Service), E-7-G (Large Non-Residential Green
Power Electric Service), E-7 TOU (Large Non-Residential Time of Use Electric Service), E-14 (Street
Lights), E-EEC-1 (Export Electricity Compensation), and E-NSE-1 (Net Metering Surplus Electricity
Compensation)