HomeMy WebLinkAbout2026-04-21 Finance Committee Agenda PacketFINANCE COMMITTEE
Regular Meeting
Tuesday, April 21, 2026
Community Meeting Room & Hybrid
4:00 PM
Finance Committee meetings will be held as “hybrid” meetings with the option to attend by
teleconference/video conference or in person. Information on how the public may observe and
participate in the meeting is located at the end of the agenda. The meeting will be broadcast on
Cable TV Channel 26, live on YouTube https://www.youtube.com/c/cityofpaloalto, and streamed
to Midpen Media Center https://midpenmedia.org.
VIRTUAL PARTICIPATION CLICK HERE TO JOIN (https://cityofpaloalto.zoom.us/j/99227307235)
Meeting ID: 992 2730 7235 Phone: 1(669)900-6833
PUBLIC COMMENTS
General Public Comment for items not on the agenda will be accepted in person for up to three
minutes or an amount of time determind by the Chair. General public comment will be heard
for 30 minutes. Additional public comments, if any, will be heard at the end of the agenda.
Public comments for agendized items will be accepted both in person and via Zoom for up to
three minutes or an amount of time determined by the Chair. Requests to speak will be taken
until 5 minutes after the staff’s presentation or as determind by the Chair. Written public
comments can be submitted in advance to city.council@PaloAlto.gov and will be provided to
the Council and available for inspection on the City’s website. Please clearly indicate which
agenda item you are referencing in your subject line. Multiple individuals who wish to speak on
the same item may designate a spokesperson. Spokespersons must be representing five or more
verified individuals who are present either in person or via zoom. Spokespeople will be allowed
up to 10 minutes, at the discretion of the presiding officer. Speaking time may be reduced if the
presiding officer reduces the speaking time for individual speakers.
PowerPoints, videos, or other media to be presented during public comment are accepted only
by email to city.clerk@PaloAlto.gov at least 24 hours prior to the meeting. Once received, the
Clerk will have them shared at public comment for the specified item. To uphold strong
cybersecurity management practices, USB’s or other physical electronic storage devices are not
accepted.
Signs and symbolic materials less than 2 feet by 3 feet are permitted provided that: (1) sticks,
posts, poles or similar/other types of handle objects are strictly prohibited; (2) the items do not
create a facility, fire, or safety hazard; and (3) persons with such items remain seated when
displaying them and must not raise the items above shoulder level, obstruct the view or passage
of other attendees, or otherwise disturb the business of the meeting.
1 April 21, 2026
Materials submitted after distribution of the agenda packet are available for public inspection at www.paloalto.gov/agendas.
CALL TO ORDER
PUBLIC COMMENT
Members of the public may speak in-person ONLY to any item NOT on the agenda. 1-3 minutes depending on number of
speakers. Public Comment is limited to 30 minutes. Additional public comments, if any, will be heard at the end of the agenda.
ACTION ITEMS
1.Recommendation to the City Council to Adopt a Resolution Approving the Fiscal Year
2027 Gas Utility Financial Forecast, Reserve Transfer, General Fund Transfer, and
Amending Rate Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered
and Commercial Gas Service), and G-3 (Large Commercial Gas Service) ; CEQA Status: Not
a project under CEQA Guidelines Section 15378(b)(5)
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.
3.Recommendation to the City Council to: Adopt a Resolution Approving the Fiscal Year
2027 Schedule of Airport Rates and Charges; Accept the Palo Alto Airport Rates and
Charges Study; and Authorize Annual Adjustments to Airport Fees and Charges Based on
the Airport Benchmark Index (ABI), as Described in the Study; CEQA Status – Exempt
Under Section 15061(b)(3)
FUTURE MEETINGS AND AGENDAS
Members of the public may not speak to the item(s)
ADJOURNMENT
2 April 21, 2026
Materials submitted after distribution of the agenda packet are available for public inspection at www.paloalto.gov/agendas.
PUBLIC COMMENT INSTRUCTIONS
Members of the Public may provide public comments to teleconference meetings via email,
teleconference, or by phone.
1.Written public comments may be submitted by email to city.council@PaloAlto.gov.
2.For in person public comments please complete a speaker request card located on the
table at the entrance to the Council Chambers and deliver it to the Clerk prior to
discussion of the item.
3.Spoken public comments for agendized items using a computer or smart phone will be
accepted through the teleconference meeting. To address the Council, click on the link
below to access a Zoom-based meeting. Please read the following instructions carefully.
◦You may download the Zoom client or connect to the meeting in- browser. If using
your browser, make sure you are using a current, up-to-date browser: Chrome 30 ,
Firefox 27 , Microsoft Edge 12 , Safari 7 . Certain functionality may be disabled in
older browsers including Internet Explorer. Or download the Zoom application onto
your smart phone from the Apple App Store or Google Play Store and enter in the
Meeting ID below.
◦You may be asked to enter an email address and name. We request that you
identify yourself by name as this will be visible online and will be used to notify you
that it is your turn to speak.
◦When you wish to speak on an Agenda Item, click on “raise hand.” The Clerk will
activate and unmute speakers in turn. Speakers will be notified shortly before they
are called to speak.
◦When called, please limit your remarks to the time limit allotted. A timer will be
shown on the computer to help keep track of your comments.
4.Spoken public comments for agendized items using a phone use the telephone number
listed below. When you wish to speak on an agenda item hit *9 on your phone so we
know that you wish to speak. You will be asked to provide your first and last name before
addressing the Council. You will be advised how long you have to speak. When called
please limit your remarks to the agenda item and time limit allotted.
CLICK HERE TO JOIN Meeting ID: 992-2730-7235 Phone: 1-669-900-6833
Americans with Disability Act (ADA) It is the policy of the City of Palo Alto to offer its public
programs, services and meetings in a manner that is readily accessible to all. Persons with
disabilities who require materials in an appropriate alternative format or who require auxiliary
aids to access City meetings, programs, or services may contact the City’s ADA Coordinator at
(650) 329-2550 (voice) or by emailing ada@PaloAlto.gov. Requests for assistance or
accommodations must be submitted at least 24 hours in advance of the meeting, program, or
service.
3 April 21, 2026
Materials submitted after distribution of the agenda packet are available for public inspection at www.paloalto.gov/agendas.
California Government Code §84308, commonly referred to as the "Levine Act," prohibits an
elected official of a local government agency from participating in a proceeding involving a
license, permit, or other entitlement for use if the official received a campaign contribution
exceeding $500 from a party or participant, including their agents, to the proceeding within the
last 12 months. A “license, permit, or other entitlement for use” includes most land use and
planning approvals and the approval of contracts that are not subject to lowest responsible bid
procedures and have a value over $50,000. A “party” is a person who files an application for, or
is the subject of, a proceeding involving a license, permit, or other entitlement for use. A
“participant” is a person who actively supports or opposes a particular decision in a proceeding
involving a license, permit, or other entitlement for use, and has a financial interest in the
decision. The Levine Act incorporates the definition of “financial interest” in the Political Reform
Act, which encompasses interests in business entities, real property, sources of income, sources
of gifts, and personal finances that may be affected by the Council’s actions. If you qualify as a
“party” or “participant” to a proceeding, and you have made a campaign contribution to a
Council Member exceeding $500 made within the last 12 months, you must disclose the
campaign contribution before making your comments.
4 April 21, 2026
Materials submitted after distribution of the agenda packet are available for public inspection at www.paloalto.gov/agendas.
1
Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Utilities
Meeting Date: April 21, 2026
Report #: 2512-5607
TITLE
Recommendation to the City Council to Adopt a Resolution Approving the Fiscal Year 2027 Gas
Utility Financial Forecast, Reserve Transfer, General Fund Transfer, and Amending Rate Schedules
G-1 (Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas Service), and
G-3 (Large Commercial Gas Service) ; CEQA Status: Not a project under CEQA Guidelines Section
15378(b)(5)
RECOMMENDATION
Staff requests that the Finance Committee recommend that the City Council adopt a resolution
(Attachment A):
1. Approving the Fiscal Year 2027 Gas Utility Financial Forecast shown in this staff report and
attachments, which includes amending the Gas Utility Reserve Management Practices;
and
2. Approving the transfer of up to $1.5 million from the Gas Utility Operations Reserve to
the Distribution Rate Stabilization Reserve at the end of FY 2026; and
3. Transferring up to 18% of gas utility gross revenues received during FY 2025 (up to $10.7
million) to the General Fund in FY 2027; and
4. Amending Rate Schedules (Attachment A, Exhibit 1) effective July 1, 2026 (FY2027):
a. G-1 (Residential Gas Service)
b. G-2 (Residential Master-Metered and Commercial Gas Service)
c. G-3 (Large Commercial Gas Service)
On March 31, 2026, the Utilities Advisory Commission (UAC) met and discussed this item and
made the following recommendations to the City Council:
1. Approving the Fiscal Year 2027 Gas Utility Financial Forecast shown in this staff report and
attachments, which includes amending the Gas Utility Reserve Management Practices;
and
2. Approving the transfer of up to $1.5 million from the Gas Utility Operations Reserve to
the Distribution Rate Stabilization Reserve at the end of FY 2026; and
3. Maintain a rate increase of no more than 7% through a combination of reducing the
General Fund Transfer and potentially using other levers such as reserve levels; and
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 1 Packet Pg. 5 of 207
2
4. Amending Rate Schedules (Attachment A, Exhibit 1) effective July 1, 2026 (FY2027) by 7%:
a. G-1 (Residential Gas Service)
b. G-2 (Residential Master-Metered and Commercial Gas Service)
c. G-3 (Large Commercial Gas Service)
The Stakeholder Engagement section below contains more information about the UAC’s
discussion and describes the amount that the General Fund Transfer would need to be reduced
in FY 2027 to meet the 7% overall rate increase together with the increases in future rates that
would be necessary. Staff does not recommend tapping reserves further as the operations
reserve is projected to be below adopted reserve guidelines and the risk assessment level at the
end of FY 2027 and the CIP reserve balance is currently $0 and that is projected to remain at $0
at the end of FY 2027. Further reductions in reserves at this time could pose risks to the Gas
Utility’s financial stability and may affect its ability to maintain adequate funding for the
continued provision of safe and reliable service.
EXECUTIVE SUMMARY
This staff report provides the Finance Committee with a financial forecast for the Gas 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.
The Gas Utility financial forecast indicates a need for a 9% overall rate increase for FY 2027, which
includes a 14.5% increase to distribution rates, assuming no change in supply costs, effective July
1, 2026. Additionally, this forecast projects overall rate increases of 7% in FY 2028, and 6%
annually from FY 2029 through FY 2031.
Staff updated cost projections for the FY 2027 to FY 2031 five-year financial planning period using
the most recent load forecast, cost data, and escalation assumptions. Relative to the FY 2026
financial forecast 1, the updated forecast projects total gas usage to be about on average 4% lower
in the FY 2027 to FY 2031 period, resulting in decreased retail sales revenue. Total expenses are
expected to be about 8% lower than projected over the same period, driven primarily by lower
supply purchase due to lower sales, and lower general fund transfers from lower revenues.
Lower-than-projected gas usage is driving the need for a 9% overall rate increase in FY 2027. In
FY 2025 gas usage was 8% below the forecast; staff expects usage to continue to drop by
approximately 1.1% annually from FY 2027 through 2031. Lower sales have prevented reserves
from recovering to adequate levels. Operating and Capital Improvement Project (CIP) expenses
in the financial planning period will also rise, to pay for critical gas main replacements.
1 FY 2026 Financial Forecast for the Gas utility (approved June 16, 2025) is described in the Finance
Committee Staff Report 2412-3868:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=64777&dbid=0&repo=PaloAlto
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 2 Packet Pg. 6 of 207
3
Table 1 compares the overall rate trajectories reflected in the FY 2026 financial forecast, the FY
2027 preliminary rates report, and the current financial forecast proposal for the Gas Utility.
Table 1: Current Year (FY2026) and Projected Overall Rate Trajectory (FY 2027 to FY 2031)
During the preliminary rate discussion with the UAC on November 5, 2025 2, and the Finance
Committee on November 18, 2025 3, staff presented a rate trajectory of 9% in FY 2027, 7% in FY
2028, and 6% annually from FY 2029 through FY 2031. The current forecast maintains the same
rate changes but reduces the rate increase from 8% to 6% in FY 2031.
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.
The City is committed to transparency with utilities customers about the reason for rate changes,
including explaining the cost drivers, benefits to customers, what the City is doing to manage
costs for ratepayers, and the services and programs provided by the City to help customers keep
utility bill costs affordable. Staff prepare the financial forecast annually as part of the rate-setting
cycle. Attachment A, Exhibit 3 contains a set of Reserves Management Practices describing the
reserves. Attachment A, Exhibit 4 outlines CPAU’s plan for communicating rate changes to
customers. Next steps include presenting an overview of the financial forecast and rate change
proposal for each utility service to the Finance Committee in April and to the City Council in June
2026.
ANALYSIS
FY 2025 Costs and Revenues
Actual revenues in FY 2025 were approximately $5.6 million (8%) below projections in the FY
2026 financial forecast, mainly due to reduced revenues from lower gas commodity prices and
2 Staff Report 2503-4364:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84164&dbid=0&repo=PaloAlto
3 Staff Report 2508-5119:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83887&dbid=0&repo=PaloAlto
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 3 Packet Pg. 7 of 207
4
decreased gas consumption. On the expense side, supply costs were about $3.2 million (14%)
lower than projected, for the same reasons. Operations expenses were about $2.6 million (7%)
lower than projected, due to lower than projected operations and maintenance costs. Lastly, CIP
expenses were about $0.3 million (8%) lower than expected due to lower Distribution System
Improvements and Gas Meters and Regulators costs. Total net costs in FY 2025 were about $0.5
million lower than projected in the FY 2026 financial forecast. Table 2 summarizes the variances
from forecast.
Table 2: FY 2025 Actuals vs. Prior Year’s Forecast ($000)
Sales revenues lower than forecast,
Low Residential Tier 2 Consumption
5,554 Revenue Decrease
Supply purchases lower than forecast (3,237) Cost Decrease
Lower operations costs (2,561) Cost Decrease
CIP costs lower than forecasted (304) Cost Decrease
Projections
Overview
Compared to the prior forecast, FY 2026 revenues are projected to be about $4.9 million (6%)
lower, primarily due to lower projected sales revenues and connection fees revenues, offset by
higher other revenues, including about $1.3 million in revenues from uncashed Green settlement
refund checks. On the expense side, supply purchases are expected to be about $4 million (15%)
lower compared with last year’s forecast, driven by lower projected consumption and lower
projected market-based commodity and carbon offset costs. Distribution operations costs in FY
2026 are projected to be lower by about 1.3 million (4%), compared with last year’s forecast,
mainly due to lower projected operations and maintenance costs, including the deferral of the
Crossbore project from FY 2026 to FY 2027. Additionally, CIP costs in FY 2026 are expected to be
about $3.7 million (23%) higher, primarily due to higher projected CIP costs.
Looking ahead to the five-year forecast period from FY 2027 to FY 2031, supply-related costs are
expected to increase at an average annual rate of 2%, with commodity costs projected to
decrease by about 4% annually, while Carbon Offset and Cap-and-Invest compliance costs are
expected to increase annually by about 4% and 12% respectively, due to higher projected Carbon
Offset and Cap-and-Invest prices. Operations expense are forecasted to rise annually by an
average of 4% for the same period, while CIP costs are expected to increase annually by an
average of 10% from FY 2025 to FY 2031.
Figure 1 illustrates the actual revenues and expenses through FY 2025, along with projections
through FY 2031. The rate change percentages show the revenue percentage changes, excluding
supply-related rate changes.
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 4 Packet Pg. 8 of 207
5
Figure 1: Gas Utility Expenses, Revenues, Rate Changes Excluding Supply-Related Changes
*FY25 Commitments and Reappropriations reserves balances for Operations and Capital Investment are
anticipated to be utilized in FY 2026 and FY 2027.
Note: Excludes Cap-and-Invest auction sales revenue and Cap-and-Invest-related expenses, which directly impacts
the Cap-and-Invest reserve.
Load Forecast
Gas usage in Palo Alto declined from FY 2020 to FY 2022, mainly due to the impacts of the COVID-
19 pandemic. However, FY 2023 saw an increase in gas usage, likely driven by a modest recovery
from COVID-19 effects and colder than average winter temperatures. However, like previous
declines in gas usage due to economic factors, it is unlikely that consumption will return to pre-
pandemic levels. Instead, a long-term decline in gas usage is expected. Further changes, such as
the voluntary replacement of gas appliances with electric appliances and building electrification
are also expected to lower long-term usage. Staff will conduct strategic planning and financial
analysis separately from this financial forecast to develop a financial and infrastructure strategy
for the Gas Utility as the community electrifies. Any insights from that analyses will be integrated
into future financial forecasts.
Staff worked with a consultant to assist in the development of an updated gas load forecast,
which included statistically adjusted end-use (SAE) modeling, weather-normalized modeling,
economic factors, and high electrification assumption. The FY 2025 actual gas supply purchases
totaled 25,436,120 therms, representing a decrease of about 8% compared to projections in the
FY 2026 financial forecast. The lower-than-anticipated gas supply purchases in FY 2025 were
primarily due to lower residential consumption, particularly during the winter season, along with
improvements in energy efficiency and electrification-driven fuel-switching away from gas. The
result, shown in Figure 2, projects gas supply load for FY 2027 at 25,239,664 therms, about 3%
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 5 Packet Pg. 9 of 207
6
lower than prior year’s forecast. This downward projection was driven by weather-normalized
lower consumption in FY 2025. Over time, declining gas consumption is expected to increase
pressure on rates, as rising and fixed costs for gas operations and distribution will need to be
allocated across fewer units sold.
Figure 12: Gas Supply Load Forecast
Revenues
This financial forecast bases sales revenue projections on the load forecast. Except where stated
otherwise, these load forecasts are based on normal weather. Variations in weather have a
substantial impact on revenues. Changes in customer behavior, gas appliance efficiency
improvements, and electrification also impact gas usage. Staff regularly monitor emerging trends
and make updates to forecasts as needed.
Expenses
The Gas Utility’s costs fall into two main categories: gas supply costs and distribution-related
costs. Gas supply costs are the cost of the gas itself, transmission of the gas to Palo Alto, and
environmental expenses. These supply-related costs vary with the market or are set by other
entities and are passed through to customers. Distribution-related costs cover the operation and
capital improvement of the distribution system, and overall business operations, and are
collected through a distribution rate adjusted annually. Table 3 shows total Gas Utility costs. The
operations and capital costs are considered distribution costs.
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 6 Packet Pg. 10 of 207
7
Table 3: Gas Utility Costs ($000)
Fiscal Year
Commodity 8,918 10,270 11,383 10,717 10,373 10,263 9,631
Transportation 6,610 6,800 6,915 7,019 7,174 7,347 7,635
Carbon Offset 961 1,147 1,198 1,244 1,291 1,340 1,411
Cap-and-Invest 2,669 3,867 4,032 4,613 5,241 5,920 6,361
Operations 33,375 35,361 36,635 36,834 38,786 40,316 42,178
Capital 8,176 19,499 22,829 11,914 17,776 11,411 15,266
Supply Costs
Overall, supply expenses are projected to increase by an average of about 2% annually from FY
2027 through FY 2031. Gas commodity costs, which are the most variable component, account
for the largest share of overall costs. Although market forecasts currently indicate that gas prices
will remain relatively steady over the next several years, those forecasts are highly uncertain. The
financial forecast assumes that gas prices decrease by an average of about 4% annually during
the forecast period.
Transportation and environmental compliance costs are expected to rise gradually over the
forecast period. PG&E's local transportation rates, which have experienced steady increases in
recent years, are expected to rise by an average of 3% per year throughout the forecast period 4.
Because the Gas Utility is regulated under California’s greenhouse gas (GHG) regulations, the Gas
Utility incurs Cap-and-Invest compliance costs. The Cap-and-Invest program has been formally
renamed from Cap and Trade by the State. Staff will mention the program as Cap-and-Invest for
the remainder of this staff report. The regulation requires Palo Alto to purchase allowances based
on actual gas load. Staff estimates that Cap-and-Invest allowance costs will increase on average
by 12% annually over the forecast period.5
The Gas Utility also generates revenue from the sale of free allocated allowances. In FY 2024 and
in accordance with Council-approved Cap-and-Invest revenue uses (Council Resolution 100776)
and Council’s goal of reducing GHGs 80% by 2030, Palo Alto began allocating Cap-and-Invest
reserves to support programs such as the Full-Service Heat Pump Water Heater Program. In
4 The transportation rates for calendar years 2023-2026 reflect the rates in the adopted PG&E 2023 Gas
Transmission & Storage (GT&S) Cost Allocation and Rate Design (CARD) (D.24-03-002), afterward a 3% escalation
rate is applied.
5 Based on allowance broker quotes.
6 Council Resolution 10077:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=61567&dbid=0&repo=PaloAlto
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 7 Packet Pg. 11 of 207
8
Calendar Year 2024, Palo Alto received about $3.35 million in revenue from freely allocated
allowances from the State. About $0.72 million was spent on the heat pump water heater direct
installation and incentive program, while the remaining $2.63 million was transferred to the Gas
Cap-and-Invest reserve at the end of FY 2025 to fund future gas GHG emissions reduction
programs. The Gas Cap-and-Invest reserve has about $15.05 million at the end of FY 2025. The
types of S/CAP related expenditures for Gas Cap-and-Invest revenues are for residential and non-
residential building electrification pilot programs.
The City also has a Carbon Neutral Natural Gas plan7, which involves purchasing carbon offsets
equivalent to the emissions generated by the community's natural gas use. These high-quality
offsets fund projects that reduce GHG emissions, such as forest conservation or methane capture
from dairy farms. While purchasing carbon offsets is an important initial step in reducing carbon
emissions, the long-term goal is to decrease the community's natural gas usage by maximizing
efficiency and transitioning to high-efficiency electric appliances where feasible. Carbon offset
purchases totaled about $1.1 million in FY 2025, and carbon offset costs are projected to rise by
4% annually through the forecast period.
In response to the dramatically high natural gas prices that occurred during winter 2022-23 and
to mitigate the impact of short-term price spikes, staff implemented a gas hedging program
effective beginning winter 2023-24. The program includes a gas price mitigation adder in the
customer’s gas commodity charge while maintaining the practice of purchasing gas at market
prices. Funds collected from the gas price mitigation adder accrue in the Gas Distribution Rate
Stabilization Reserve and can be used to offset the impact of a potential gas market price spike
above the maximum gas commodity charge to customers. Through this program, about $1 million
has been funded and allocated in the Gas Distribution Rate Stabilization Reserve at the end of FY
2025. The program is designed to fund the reserve over a three-year period through the adder,
which is expected to result in approximately $4.5 million over three years to hedge against future
short-term gas price spikes.
Operations
Operations costs are projected to increase by about 4% annually on average from FY 2027
through FY 2031, primarily driven by increases in the general fund transfer and general cost
escalation. The operations costs in this forecast include $0.7 million for the cross-bore program
previously budgeted in FY 2026; this program has been deferred to FY 2027. This safety program
ensures that gas pipelines have not crossed through sewer laterals, which is infrequent but
possible during trenchless installation. This "cross-bore" configuration poses a risk of gas leaks as
due to accidental cut by a plumber using a cutting tool to clear a sewer line. While a majority of
sewer laterals have been inspected, staff has come across several services which are unable to
be scoped, due to either infiltration by roots or broken/collapsed pipe segments. Since the
7 Staff Report 7441: https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=80132&dbid=0&repo=PaloAlto
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 8 Packet Pg. 12 of 207
9
program’s inception, a total of 23 gas crossbores and 32 other utility crossbores have been found
and repaired. Figure 3 shows the actual and projected distribution operations costs.
Figure 3: Gas Distribution Utility Operations Costs
Capital Improvement Program
Staff anticipate annual capital expenditures will vary during the forecast period due to plans for
larger main replacement projects every other year, instead of smaller projects every year. This
main replacement schedule allows the Gas Utility to meet its main replacement needs while
addressing challenges in the current construction market, and optimizing current staffing
resources. Overall CIP costs are expected to increase by around 10% on average annually from
FY 2025 through FY 2031; this is due to higher projected CIP project and personnel costs.
On May 9, 2024, the Gas Utility received a recommendation letter from the U.S. Department of
Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) for the FY
2023 Natural Gas Distribution Infrastructure Safety and Modernization (NGDISM) Grant. Staff
expects this grant to provide approximately $16.5 million for capital-related work for
replacement of 4.8 miles of Polyvinylchloride (PVC) and steel pipe and purchase of methane
reducing equipment. As a condition of the grant, CPAU must maintain funding of the already-
planned Gas capital work over the next five-year period. This grant will replace and provide the
full funding for GMR 25 and construction will take place in FY 2026 and FY 2027. The original GMR
25 budget of $9.8 million, initially scheduled for FY 2025, has been reallocated and split between
GMR 26 and GMR 27, with construction now planned for FY 2027 and FY 2029, respectively. CPAU
Projection
Administration
Operations
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 9 Packet Pg. 13 of 207
10
will continue to look for other grant opportunities to help fund the replacement of PVC and steel
distribution mains in the gas system.
This financial forecast also includes transfers of about $6 million each year in FY 2030 and FY 2031
from the Operations Reserve to the CIP Reserve to gradually increase the currently depleted CIP
Reserve to within the guideline range by end of FY 2030. The adopted CIP reserve guideline
ranges from a minimum of $3.1 million to a maximum of $15.5 million.
As residential and commercial buildings in Palo Alto are electrified, the City may be able to retire
some PVC and steel mains in neighborhoods where these materials exist. Staff is developing an
efficient phasing plan for electrification and the scaling back of the gas infrastructure, while
assessing both operations and financial implications.
The prior financial forecast included CIP budgets of $3 million annually in gas decommissioning
costs from FY 2028 through FY 2030. This project has been removed from the current year’s
forecast pending additional modeling analysis.
Table 4 shows the CIP cost categories and projected spending.
Table 4: Projected CIP Spending ($000)
*Includes unspent funds from previous years carried forward or reappropriated
**A portion of project salaries and benefits has been allocated to the Gas Main Replacement budget in the table
above for FY 2027-31, with a larger share assigned in FY 2027 to meet grant reimbursement requirements
Debt Service
The Gas Utility currently makes debt service payments on one bond issuance. Table 5 shows
debt service for this bond and debt service coverage ratio for the financial forecast period. Debt
service on this bond will be completed by the end of FY 2026.
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 10 Packet Pg. 14 of 207
11
Table 5: Debt Service Coverage Ratio ($000)
Revenues 79,185
Expenses (Excluding CIP and Debt Service) (44,956)
Net Revenues 34,229
Coverage Ratio 4,270%
Reserves
The Operations reserve level was below the minimum at the end of FY 2024 and FY 2025. This is
due to about a total of $4.7 million in FY 2024 and $8.6 million in FY 2025 (shown in hashed red
bar in the figure below) being held in the CIP Reappropriations Reserve. The full $16.5 million is
expected to be fully reimbursed through grant funding to match actual expenses as stated in the
CIP section above, therefore, the actual Operations Reserve is expected to remain healthy.
While the Operations Reserve is projected to remain above the minimum guideline at the end of
FY 2026, higher-than-expected expenses are forecasted which may reduce the balance below the
risk-assessment threshold at the end of FY 2027. The reserve is then projected to recover above
the minimum guideline level by FY 2028 and return to target levels by FY 2031. Figure 4 shows
the actual and projected year-end balance.
Figure 4: Operations Reserve Projection
Table 6 summarizes the risk assessment calculation for the Gas Utility through FY 2031. The risk
assessment is intended to be covered by the Operations Reserve and includes the revenue
shortfall that could occur due to:
1. Maximum non-commodity revenue percentage variance from the previous ten years; and
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 11 Packet Pg. 15 of 207
12
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
CIP Contingency for FY 2030 and after is not needed due to resuming the use of the CIP
reserve.
Table 6: Gas Distribution Risk Assessment ($000)
Total Distribution Revenue 39,847 45,114 49,670 53,641 57,877 62,454
Risk of Revenue Loss @14% 5,591 6,330 6,970 7,527 8,121 8,763
CIP Budget 19,499 22,829 11,914 17,776 - -
CIP Contingency @10%* 1,950 2,283 1,191 1,778 - -
*CIP budget is excluded from FY 2030 onward
Reserve Transfers
Staff estimates that the gas price mitigation adder in the gas commodity charge will collect about
$1.36 million in FY 2026 for the gas hedging program 8. Although these funds are initially collected
in the Operations Reserve, they should be transferred to the Gas Distribution Rate Stabilization
Reserve to be available to mitigate the impact of potential gas market price spikes exceeding the
maximum gas commodity charge to customers. Staff proposes transferring up to $1.5 million
from the Gas Utility Operations Reserve to the Gas Distribution Rate Stabilization Reserve at the
end of FY 2026. The projected transfer is listed in row 12 in Table 7 below and the amount is
included in part of the Operations transfer out in row 11. The exact transfer amount will be
determined at year end based on calculations aligned with the gas hedging program.
Reserve Balances
Figure 5 shows the CIP Reserve balances. The CIP Reserve is fully depleted (zero balance);
however, planned transfers in FY 2030 and FY 2031 will replenish the CIP Reserve and reach the
minimum guideline level by FY 2030. Per the Reserves Management Practices (Attachment A,
Exhibit 3), Section 6, any rate plan that does not return CIP reserves above minimum levels within
one year requires Council approval.
8 Staff Report 2401-2510:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=82970&dbid=0&repo=PaloAlto; the utility collected
about $1.05 million for this program in FY 2025, which was transferred from the Operations Reserve to the Gas
Distribution Rate Stabilization reserve at the end of FY 2025.
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 12 Packet Pg. 16 of 207
13
Figure 5: Gas CIP Reserve Levels
Figure 6 shows year-end reserve balance levels for each reserve. Table 7 shows reserve starting
and ending balances, revenues, transfers expenses, capital program contribution and
operations reserve guideline levels.
Figure 6: Gas Utility Year-End Reserves Levels
Note: Excludes Cap-and-Invest Reserve
Projection
Distribution Rate
Stabilization
Reappropriations
Operations Reserve
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 13 Packet Pg. 17 of 207
14
Table 7: Operations, CIP, Cap-and-Invest, and Debt Service Reserve Starting and Ending
Balances, Revenues, Transfers To/(From) Reserves, Capital Program Contribution To/(From)
Reserves, Total Reserve Changes, and Reserve Guideline Levels ($000)
*Operations Reserve represents the Gas Supply Fund Rate Stabilization Reserve and the Gas Distribution Fund
Operations Reserve combined.
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 14 Packet Pg. 18 of 207
15
Proposed Rates
Table 11 shows the current and proposed monthly service charges, and Table 12 shows the
current and proposed distribution volumetric charges for all rate schedules. As previously
noted, supply-related charges are pass-through charges that are updated periodically. The latest
charges are shown in the City’s Rates website 9. The proposed rates reflect the proposed rate
increases compared to the current rates, which are based on the Natural Gas Cost of Service
and Rate Study and were adopted by City Council at the December 1, 2025 meeting 10.
Table 11: Current and Proposed Monthly Service Charges
Rate Schedule (as of 2/1/2026)
Proposed Rates
(effective 7/1/2026)
Change
($)
Change
(%)
(Residential)
(Small Commercial)
G-2 (≤ 220 scfh)
G-2 (> 220 and < 4,000 scfh)
G-2 (≥ 4,000 scfh)
(Large Commercial)
Table 12: Current and Proposed Gas Distribution Charges
Rate Schedule (as of 2/1/2026)
Proposed Rates
(effective 7/1/2026)
Change
($) (%)
(Residential)
Tier 1 Rates $ 1.0456 $ 1.1972 $ 0.1516 14.5%
Tier 2 Rates 2.5203 2.8857 0.3654 14.5%
(Residential Master-Metered and Small Commercial)
Uniform Rate $ 1.2204 $ 1.3973 $ 0.1769 14.5%
(Large Commercial)
Uniform Rate $ 1.1874 $ 1.3595 $ 0.1721 14.5%
Bill Impacts
Table 13 shows the impact of the proposed July 1, 2026 rate changes on the median monthly
residential bill for representative average winter and summer bills, excluding supply-related
cost changes. The annual gas bill for the median residential customer is projected to be 9%
9 City’s Rates Website https://www.cityofpaloalto.org/files/assets/public/v/25/utilities/rates-schedules-for-
utilities/residential-utility-rates/monthly-gas-volumetric-and-service-charges-residential-3.pdf
10 Staff Report 2506-4908:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84117&dbid=0&repo=PaloAlto
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 15 Packet Pg. 19 of 207
16
higher in FY 2027 than FY 2026. The actual impact may be different because customer gas
usage varies and commodity price changes monthly.
Table 13: Bill Impact of Proposed G-1 Gas Rate Changes ($/Month)
(Therms/month)
Bill Amount
(Current Rates1)
Bill Amount
(Proposed Rates2)
Change
Summer
Winter
Annual Median
1. Calculated based on FY25 actual supply rates with current distribution rates; assumes current
distribution rates were effective for the full year. If the current rate calculation instead applies
Council-approved rates for July 2025 – January 2026, followed by cost-based adjustments
from February 2026 – June 2026, the residential bill is projected to increase by about 14%
from FY26 to FY27.
2. Calculated based on FY25 actual supply rates with proposed distribution rates; assumes no
change to supply-related rates.
Table 14 shows the impact of the proposed rate changes, effective July 1, 2026, on
representative commercial customer bills, excluding supply-related cost changes. The G-2 usage
levels listed below represent the median usage for the three G-2 rate class groupings. For the
G-3 rate class, the usage reflects a sample large commercial customer with an annual
consumption of approximately 250,000 therms.
Table 14: Bill Impact of Proposed G-2 and G-3 Gas Rate Changes ($/Month)
(Therms/month)
Bill Amount
(Current Rates1)
Bill Amount
(Proposed Rates2) $/mo %
(Residential Master-Metered and Small Commercial)
35 $ 102 $ 112 $ 10 10%
280 668 728 60 9%
2,648 5,850 6,351 502 9%
(Large Commercial)
20,834 $ 43,576 $ 47,133 $ 3,557 8%
1. Calculated based on FY25 actual supply rates with current distribution rates
2. Calculated assuming no change to supply-related rates
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 16 Packet Pg. 20 of 207
17
Bill Comparisons/Competitiveness
Table 15 presents the median residential bills for Palo Alto and Pacific Gas and Electric Company
(PG&E) customers. The bill calculations for PG&E customers are based on PG&E Climate Zone X,
an area which includes Palo Alto’s surrounding communities. The calculated monthly gas bill for
the median Palo Alto residential customer is about 11% lower than that of a PG&E customer
with equivalent consumption. This difference is primarily attributable to the City’s fixed monthly
service charge; PG&E does not apply a similar charge.
Table 15: Residential Monthly Equivalent Natural Gas Bill Comparison, at Current Rates
($/Month)
Season (Therms) Palo Alto PG&E % Difference
Summer 17 $ 51 $ 39 30%
Winter 51 117 157 (26%)
Annual Average 31 78 88 (11%)
Note: Calculated based on FY25 actual supply rates with current distribution rates
Table 16 presents the median monthly commercial bills for Palo Alto and PG&E customers. Palo
Alto bills have been higher than PG&E’s bills over the years, mainly due to higher service
charges.
Table 16: Commercial Monthly Equivalent Natural Gas Bill Comparison, at Current Rates
($/Month)
Sector (Therms) Palo Alto PG&E % Difference
Commercial 280* $ 668 $ 583 15%
Large Commercial 20,834** 43,576 29,637 47%
Note: Calculated based on FY25 actual supply rates with current distribution rates
*Based on median usage for Palo Alto G-2 rate class with meter capacity of >220 and <4,000 Scfh
**Based on annual usage of about 250,000 therms
Cap-and-Invest Reserve Transfer
Because the Cap and Trade program has been renamed the Cap-and-Invest program, this staff
report requests the renaming of the Cap and Trade Reserve to the Cap-and-Invest Reserve. In
accordance with Section 11 of the Gas Reserve Management Practices and Council-approved
Cap-and-Invest revenue uses (Council Resolution 10077 11), staff is authorized to transfer
revenues from allocated allowance auction proceeds to the Cap-and-Invest Reserve at the end
of each fiscal year. Additionally, staff may utilize funds from the Cap-and-Invest Reserve to
11 Council Resolution 10077:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=61567&dbid=0&repo=PaloAlto
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 17 Packet Pg. 21 of 207
18
support greenhouse gas (GHG) reduction programs by transferring funds from the Cap-and-
Invest Reserve to the Operations Reserve.
General Fund Transfer
The Gas Utility's transfer to the City’s General Fund is a component of the City’s gas rates. This
transfer was first authorized by voters in 1950 and reaffirmed in November 2022 with the
passage of Measure L, which authorizes a transfer amount up to 18% of the gross revenues of
the Gas Utility. This financial forecast proposes a transfer of $10.7 million in FY 2027, 18% of FY
2025 gross revenues. This transfer of 18% is in alignment with the assumptions in the FY 2026
Adopted Budget process.
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 2026. Then the City Council will
consider the proposed financial forecasts and amended rate schedules concurrent with the FY 2027
budget, expected in June, at which time Council will review the proposed rate changes. If Council
approves, the rates will become effective July 1, 2026.
FISCAL/RESOURCE IMPACT
The resource impact of the recommendations summarized in this report is the continued
financial solvency of the Gas Utility.
Based on the proposed rates increase as shown, the estimated revenue impacts in FY 2027 would
be an increase of $5.5 million in the Gas Fund, not including fluctuations in commodity
revenue/cost. Additionally, because the Gas Utility Equity Transfer is based on gross operating
revenues, General Fund revenues would increase from $9.7 million in FY 2026 to $10.7 million in
FY 2027, an increase of $1.0 million. General Fund utility users tax revenue, in addition to General
Fund Revenues, would increase by $0.2 million from estimated $3.0 million in FY 2026 to $3.2 in
FY 2027. If the proposed 9% rate increase, including the 18% general fund transfer assumption,
is approved, the estimated General Fund revenue impact would total $13.9 million in FY2027.
The 18% general fund transfer assumption was also assumed in the FY 2027-36 Long Range
Financial Forecast 12.
POLICY IMPLICATIONS
The proposed Gas Utility rate adjustments are consistent with Council-adopted Reserve
Management Practices (Attachment A, Exhibit 3) and were developed using a cost-of-service
study and methodology consistent with the California constitution and industry-accepted cost of
service principles. If reserves fall below the minimum guidelines, Council approval is required for
12 FY 2027-36 Long Range Financial Forecast: https://www.paloalto.gov/files/assets/public/v/1/administrative-
services/city-budgets/fy-2027-city-budget/lrff-cmr-2512-5601-1.20.2026.pdf
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 18 Packet Pg. 22 of 207
19
a rate plan that requires more than one year to return reserves to within guideline levels. This
staff report serves as the required plan.
STAKEHOLDER ENGAGEMENT
On November 5, 202513, staff presented the preliminary rate proposals at the UAC meeting.
Some Commissioners raised affordability concerns and expressed interest in exploring innovative
operating cost reductions rather than relying on the traditional approach of deferring capital
investments.
On November 18, 2025 14, staff presented the same preliminary rate proposals to the Finance
Committee. Committee members focused on benchmarking rates against comparable utilities.
They also inquired about cost-containment strategies. Additional discussion centered on reserve
guidelines and the associated risk assessment. Members emphasized that the absence of rate
increases during the pandemic created a catch-up scenario that should be avoided in the future.
On March 31, 202615, staff presented the rate proposal to the UAC. Commissioners voted 4-3 to
recommend an overall rate increase of 7% for FY 2027, instead of the staff proposed overall rate
increase of 9%, and identify potential options to address the resulting gap, including reducing the
General Fund Transfer and further lowering reserves. Commissioners raised concerns about the
gas utility's long-term financial sustainability, highlighting the challenge of planning for end-of-
life of the gas system while managing rising operating and capital costs. Commissioners also
questioned whether CIP spending could be adjusted (spending levels required by the $16.5mil
DOT grant), and one requested a more detailed load forecast as part of next year's report. Lastly,
Commissioners debated the General Fund Transfer assumption, with some recommending a
reduction from 18% and the use of reserves as levers to moderate the rate increase.
With a 7% instead of 9% overall rate increase, while maintaining the same reserve target at the
end of FY 2031, the General Fund Transfer for FY 2027 would need to drop from 18% of gross
revenues received during FY 2025 ($10.7 million) to 15.5% ($9.3 million), a reduction of $1.4
million and additional rate increases would be needed in future years. The following table shows
the rate impacts expected in the future without changing assumptions in additional years:
13 Staff Report 2503-4364:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84164&dbid=0&repo=PaloAlto
14 Staff Report 2508-5119:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83887&dbid=0&repo=PaloAlto
15 Staff Report 2512-5641:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=87025&dbid=0&repo=PaloAlto
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 19 Packet Pg. 23 of 207
20
Table 17: Proposal and 15.5% General Fund Transfer Projected Overall Rate Trajectory
Additional feedback from the April 21 Finance Committee meeting will be incorporated in the
financial forecast and included in the proposal presented to City Council in June 2026 concurrent
with the budget adoption process. Additionally, during the April 21 Finance Committee meeting,
staff will discuss additional options (“levers”) to reach the lower rate increase recommended by
the UAC and any associated short-term and long-term implications.
Attachment A, Exhibit 4 contains examples of CPAU’s communication and outreach methods
including the use of the Utilities 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 community messaging platforms.
ENVIRONMENTAL REVIEW
The Finance Committee’s review and recommendation to the City Council on the FY 2027 Gas
Utility financial forecast and rate adjustments does not meet the California Environmental
Quality Act’s definition of a project, pursuant to Public Resources Code Section 21065, thus no
environmental review is required.
ATTACHMENTS:
Attachment A: FY27 Gas Resolution
Attachment A, Exhibit 1: FY27 Gas Rate Schedules
Attachment A, Exhibit 2: FY27 Gas Utility Financial Details
Attachment A, Exhibit 3: FY27 Gas Reserve Management Practices
Attachment A, Exhibit 4: FY27 Gas Communications Plan
Attachment B: FY27 Gas Presentation (FC)
APPROVED BY:
Alan Kurotori, Director of Utilities
Staff: Eric Wong, Resource Planner
Item 1
Item 1 Staff Report
Item 1: Staff Report Pg. 20 Packet Pg. 24 of 207
Attachment A *NOT YET APPROVED*
Resolution No.
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2027 Gas Utility Financial Forecast and Reserve Transfers,
General Fund Transfer, and Amending Rate Schedules G-1
(Residential Gas Service), G-2 (Residential Master-Metered and
Commercial Gas Service), and G-3 (Large Commercial Gas Service)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations, including reserves.
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 attached to and made
part of the Financial Forecasts or Plans.
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 Amended Reserves Management
Practices (Exhibit 3 1) and FY 2027 Gas Utility Financial Forecast presented to the Finance
Committee on March 17, 2026 2 and updated by the June 15, 2026 Council report, (Exhibit 23),
which is attached to this resolution and made a part of the staff report presented to the City
Council.
SECTION 2. The Council hereby approves the transfer of up to $1.5 million
from the Gas Utility Operations Reserve to the Distribution Rate Stabilization Reserve at
1 Exhibit 3 <<link>>
2 Meeting Agenda Item #: XX <<link>>
3 Exhibit 2 <<link>>
Item 1
Attachment A - FY27 Gas
Resolution
Item 1: Staff Report Pg. 21 Packet Pg. 25 of 207
Attachment A *NOT YET APPROVED*
the end of FY 2026.
SECTION 3. The Council hereby approves the transfer of up to 18% of gas utility
gross revenues received during FY 2025 to the general fund in FY 2027.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-1 (Residential Gas Service) is hereby amended to read as shown in Exhibit 14.
Utility Rate Schedule G-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 G-2 (Residential Master-Metered and Commercial Gas Service) is hereby
amended to read as shown in Exhibit 1. Utility Rate Schedule G-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 G-3 (Large Commercial Gas Service) is hereby amended to read as shown in
Exhibit 1. Utility Rate Schedule G-3, as amended, shall become effective July 1, 2026.
SECTION 7. The City Council finds that revenues derived from the gas rates approved
by this resolution do not exceed the funds required to provide gas service and shall not be used
for any purpose other than providing gas service, and the purposes set forth in Article VII,
Section 2, of the Charter of the City of Palo Alto.
SECTION 8. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
SECTION 9. The Council finds that approving the FY 2027 Gas Utility Financial
Forecast 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 it 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 gas 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 Title 14 of the California Code of
Regulations 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.
/ /
4 Exhibit 1 <<link>>
Item 1
Attachment A - FY27 Gas
Resolution
Item 1: Staff Report Pg. 22 Packet Pg. 26 of 207
Attachment A *NOT YET APPROVED*
/ /
/ /
/ /
Item 1
Attachment A - FY27 Gas
Resolution
Item 1: Staff Report Pg. 23 Packet Pg. 27 of 207
Attachment A *NOT YET APPROVED*
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
Item 1
Attachment A - FY27 Gas
Resolution
Item 1: Staff Report Pg. 24 Packet Pg. 28 of 207
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-1 Effective 027-01-2026
dated 072-01-20265 Sheet No G-1-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from City of Palo Alto
Utilities:
1.Separately-metered single-family residential Customers;
2.Separately-metered multi-family residential Customers in multi-family residential
facilities.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES:Per Service
Monthly Service Charge: .............................................................................................$ 22.42 19.58
Tier 1 Rates: Per Therm
Supply Charges:
1.Commodity (Monthly Market-Based) ......................................... $0.10-$4.00
2.Cap and Trade Compliance Charge ............................................ Pass-through
3. Transportation Charge ................................................................. Pass-through
4.Carbon Offset Charge .................................................................. $0.00-$0.10
Distribution Charge:.......................................................................................$ 1.1971
1.0456
Tier 2 Rates: (All usage over 100% of Tier 1)
Supply Charges:
1.Commodity (Monthly Market-Based) ......................................... $0.10-$4.00
2.Cap and Trade Compliance Charge ............................................. Pass-through
3. Transportation Charge ................................................................. Pass-through
4.Carbon Offset Charge .................................................................. $0.00-$0.10
Distribution Charge:.............................................................................................$ 2.8857
2.5203
Attachment A, Exhibit 1 Item 1
Attachment A, Exhibit 1 -
FY27 Gas Rate Schedules
Item 1: Staff Report Pg. 25 Packet Pg. 29 of 207
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-2 Effective 027-01-2026
dated 072-01-20265 Sheet No G-1-2
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.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
purchase discount1 and $0.055 per Therm for mitigating the impact of short-term natural
gas market price spikes2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s
compliance obligations. The Cap and Trade Compliance Charge changes in response to
changing market conditions, retail sales volumes and the quantity of allowances required,
and is calculated based on the Cap-and-Trade Program’s quarterly auction allowance
closing prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse
gases produced when Gas is burned. The Carbon Offset Charge changes in response to
changing market conditions, sales volumes and the quantity of offsets purchased within
the Council-approved per Therm cap.
The Transportation Charge is a pass-through charge based on the current PG&E G-WSL3
(Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
Attachment A, Exhibit 1 Item 1
Attachment A, Exhibit 1 -
FY27 Gas Rate Schedules
Item 1: Staff Report Pg. 26 Packet Pg. 30 of 207
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-3 Effective 027-01-2026
dated 072-01-20265 Sheet No G-1-3
The Commodity and Carbon Offset Charges will fall within the minimum/maximum
ranges set forth in Section C. Current and historic per Therm rates for the Commodity,
Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the
City Utilities website.4
2. Seasonal Rate Changes:
The Summer period is effective April 1 to October 31 and the Winter period is effective
from November 1 to March 31. 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 for each period. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Calculation of Usage Tiers
Tier 1 Natural Gas usage is calculated and billed based upon a level of 23 Therms per 30
day Billing Period during the Summer period, and 60 Therms per 30 day Billing Period
during the Winter period, based on Meter reading days of Service, and rounded to the
nearest whole Therm. As an example, Tier 1 Natural Gas is calculated at 0.767 Therms per
day during the Summer period (.767 Therms per day x 30 days = 23 Therms) and 2.0
Therms per day during the Winter period (2 Therms per day x 30 days = 60 Therms). For
further discussion of bill calculation and proration, refer to Rule and Regulation 11.
{End}
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.paloalto.gov/files/assets/public/utilities/rates-schedules-for-utilities/residential-utility-rates/monthly-gas-
volumetric-and-service-charges-residential.pdf
Attachment A, Exhibit 1 Item 1
Attachment A, Exhibit 1 -
FY27 Gas Rate Schedules
Item 1: Staff Report Pg. 27 Packet Pg. 31 of 207
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-1 Effective 072-01-2026
dated 027-01-20265 Sheet No G-2-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use less than 250,000 Therms per year at one site;
2. Master-Metered residential Customers in multi-family residential facilities.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge:
For Meters with maximum capacity:
1. Up to 220 Standard Cubic Feet per Hour (scfh) .............................................$ 33.47 29.24
2. Above 220 scfh and less than 4,000 scfh ....................................................$ 108.27 94.56
3. 4,000 scfh and above ..................................................................................$ 479.84 419.08
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) ......................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges ........................................................... Pass-through
3. Transportation Charge .................................................................................. Pass-through
4. Carbon Offset Charge ................................................................................... $0.00-$0.10
Distribution Charge: ..................................................................................................$ 1.3973
1.2204
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.
The meter’s maximum capacity used to determine the applicable Monthly Service Charge
for G-2 Gas Service is the installed Meter’s City of Palo Alto-approved maximum
capacity in standard cubic feet per hour (scfh), measured at 7 inches of water column or
equivalent to 0.25 pounds per square inch.
Attachment A, Exhibit 1 Item 1
Attachment A, Exhibit 1 -
FY27 Gas Rate Schedules
Item 1: Staff Report Pg. 28 Packet Pg. 32 of 207
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-2 Effective 072-01-2026
dated 027-01-20265 Sheet No G-2-2
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
purchase discount1 and $0.055 per Therm for mitigating the impact of short-term natural
gas market price spikes2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge changes in response to changing
market conditions, retail sales volumes and the quantity of allowances required, and is
calculated based on the Cap-and-Trade Program’s quarterly auction allowance closing
prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced when Gas is burned. The Carbon Offset Charge changes in response to changing
market conditions, sales volumes and the quantity of offsets purchased within the Council-
approved per Therm cap.
The Transportation Charge is a pass-through charge based on the current PG&E G-WSL3
(Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity and Carbon Offset Charges will fall within the minimum/maximum
ranges set forth in Section C. Current and historic per Therm rates for the Commodity,
Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the
City Utilities website.4
{End}
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.paloalto.gov/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-charges-
commercial.pdf
Attachment A, Exhibit 1 Item 1
Attachment A, Exhibit 1 -
FY27 Gas Rate Schedules
Item 1: Staff Report Pg. 29 Packet Pg. 33 of 207
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-1 Effective 072-01-2026
dated 027-01-20265 Sheet No G-3-1
A. APPLICABILITY:
This schedule applies to Customers receiving Gas Service from the City of Palo Alto Utilities, who
use at least 250,000 Therms per year at one site.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: $ 1,960.65 1,712.36
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges .................................................... Pass-through
3. Transportation Charge .......................................................................... Pass-through
4. Carbon Offset Charge ........................................................................... $0.00-$0.10
Distribution Charge: ................................................................................................$ 1.3595 1.1874
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.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
purchase discount1 and $0.055 per Therm for mitigating the impact of short-term natural
gas market price spikes2.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
Attachment A, Exhibit 1 Item 1
Attachment A, Exhibit 1 -
FY27 Gas Rate Schedules
Item 1: Staff Report Pg. 30 Packet Pg. 34 of 207
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-2 Effective 072-01-2026
dated 027-01-20265 Sheet No G-3-2
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge changes in response to changing
market conditions, retail sales volumes and the quantity of allowances required, and is
calculated based on the Cap-and-Trade Program’s quarterly auction allowance closing
prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced when Gas is burned. The Carbon Offset Charge changes in response to changing
market conditions, sales volumes and the quantity of offsets purchased within the Council-
approved per Therm cap.
The Transportation Charge is a pass-through charge based on the current PG&E G-WSL3
(Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity and Carbon Offset Charges will fall within the minimum/maximum
ranges set forth in Section C. Current and historic per Therm rates for the Commodity,
Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the
City Utilities website.4
2. Request for Service
A qualifying Customer may request Service under this schedule for more than one Account
or Meter if the Accounts are located on one site. A site consists of one or more contiguous
parcels of land with no intervening public right-of- ways (e.g. streets).
3. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable City of Palo
Alto full-service rate schedule.
{End}
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.paloalto.gov/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-charges-
commercial.pdf
Attachment A, Exhibit 1 Item 1
Attachment A, Exhibit 1 -
FY27 Gas Rate Schedules
Item 1: Staff Report Pg. 31 Packet Pg. 35 of 207
Attachment A, Exhibit 2
6
7
5
6
Item 1
Attachment A, Exhibit 2 -
FY27 Gas Utility Financial
Details
Item 1: Staff Report Pg. 32 Packet Pg. 36 of 207
Attachment A, Exhibit 2
6
7
5
6
Gas Utility Capital Improvement Program (CIP) Financial Details
Item 1
Attachment A, Exhibit 2 - FY27 Gas
Utility Financial Details
Item 1: Staff Report Pg. 33 Packet Pg. 37 of 207
Attachment A, Exhibit 3
6
7
5
7
GAS UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Gas Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015
to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets
as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Gas Utility’s Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
Section 3. Distribution Fund Reserves
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Gas Utility’s Capital
Improvement Program (CIP), as described in Section 6 (CIP Reserve)
d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 8 (Operations Reserve)
f) For tracking unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the gas utility under the State’s Cap-
and- Trade Invest Program, as described in Section 11 (Cap- and- Trade Invest Program
Reserve)
g) 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 9
(Unassigned Reserves)
Item 1
Attachment A, Exhibit 3 -
FY27 Gas Reserve
Management Practices
Item 1: Staff Report Pg. 34 Packet Pg. 38 of 207
Attachment A, Exhibit 3
6
7
5
7
Section 4. Reserve for Commitments
1. These guideline levels are
calculated for each fiscal year of the Financial Planning Period and approved by Council
resolution.
1 The guideline levels were corrected to match the Council-approved language updated from the
FY 2021 Financial Plan.
2 Each month is calculated based upon 1/12 of the annual budget.
3 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual
average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use to
derive the annual average would be FY 2022 through FY 2025 etc.
Minimum Level 20% of the maximum CIP Reserve guideline level l
Maximum Level Average annual (12 month)2 CIP budget, for 48 months of
budgeted CIP expenses3
Item 1
Attachment A, Exhibit 3 -
FY27 Gas Reserve
Management Practices
Item 1: Staff Report Pg. 35 Packet Pg. 39 of 207
Attachment A, Exhibit 3
6
7
5
7
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds may
be added to this reserve. If there are funds in this reserve in excess of the maximum level
staff must propose to transfer these funds to another reserve or return them to
ratepayers in the next Financial Plan. Staff may also seek Council approval to hold funds
in this reserve in excess of the maximum level, if they are held for a specific future purpose
related to the CIP.
Section 3. Rate Stabilization Reserve
The Rate Stabilization Reserve is used to manage the trajectory of future Funds may be added
to the Rate Stabilization Reserve by action of the City Council and held to manage the
trajectory of future year rate increases. Withdrawal of funds from the Rate Stabilization
Reserve requires Council action. If there are funds in the Rate Stabilization Reserve at the end
of any fiscal year, any subsequent Gas Utility Financial Plan must result in the withdrawal of
all funds from this Reserve by the end of the Financial Planning Period.
Section 4. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves
described in Section 4-Section 7 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the 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 O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the 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, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
Item 1
Attachment A, Exhibit 3 -
FY27 Gas Reserve
Management Practices
Item 1: Staff Report Pg. 36 Packet Pg. 40 of 207
Attachment A, Exhibit 3
6
7
5
7
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Gas Utility’s Fund Balance
shall be automatically included in the Unassigned Reserve described in Section 9, below.
Section 5. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas Utility’s
Fund Balance will be held in the Unassigned Reserve. If there are any funds in the 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 Gas 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 2015, and the next
Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a plan
to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff may
present an alternative plan that retains these funds or returns them over a longer period of
time.
Section 6. Intra-Utility Transfers Between Supply and Distribution Funds
The Gas Utility records costs in two separate funds: the Gas Supply Fund and the Gas
Distribution Fund. At the end of each fiscal year staff is authorized to transfer funds between
the Gas Supply Fund and Gas Distribution Fund if consistent with the purposes of the two
reserves involved in the transfer and in order to balance gas utility reserves to avoid negative
balances. For example, Gas Distribution revenues are needed to pay for certain supply-
related costs such as administration of the Gas Supply Fund. Such transfers shall be included
in the ordinance closing the budget for the fiscal year.
Section 7. Cap- and- Trade Invest 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 gas utility, under the State’s Cap- and-
Trade Invest 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- Trade Invest Program
(the Policy), adopted by Council Resolution 9487 in January 2015, and amended by Council
Resolution 10077 in October 2022. At the end of each fiscal year, the Cap- and- Trade Invest
Program Reserve will be adjusted by the net of revenues and expenses associated with the
Cap- and- Trade Invest program.
Item 1
Attachment A, Exhibit 3 -
FY27 Gas Reserve
Management Practices
Item 1: Staff Report Pg. 37 Packet Pg. 41 of 207
Attachment A, Exhibit 4
1
0
7
1
4
COMMUNICATIONS PLAN AND OUTREACH EXAMPLES – GAS UTILITY
The proposed gas utility rate adjustments are part of the City of Palo Alto Utilities (CPAU) ongoing
effort to maintain the financial health and reliability of the Gas Utility while managing the impacts of
declining gas consumption and increasing operating and capital expenses.
Reasons for the Proposed Rate Increase
During the pandemic, the city kept overall Gas Utility rate increases to 2% to 3% annually and utilized
reserve funding to cover costs. In the winter of 2022-23, surging gas prices depleted the Gas Utility
reserves, which were used to cover the difference between actual gas costs and the revenue generated
by charging customers the Council-approved maximum gas commodity charge. Reserves need to be
replenished over time to ensure funds are available for safety and reliability needs, while managing
ongoing cost inflation.
The Gas Utility financial results have been affected by lower-than-expected sales revenues driven by
reduced gas usage and lower commodity prices. Although supply purchases have also been below
expectations, these savings were insufficient to offset revenue shortfalls. Additionally, capital
improvement program (CIP) expenses exceeded projections, largely due to emergency repair work and
rising labor costs.
Looking ahead, staff project a continued decline in gas consumption due to electrification trends and
long-term efficiency improvements, which will place upward pressure on rates as fixed operational and
capital costs are spread across fewer therms sold. To maintain reliable operations, meet reserve
targets, and fund essential infrastructure projects, staff are recommending a 9% overall rate increase in
FY 2027. This includes a 14.5% increase in distribution rates and assumes stable supply-related charges.
Communication Plan and Messaging Strategy
Staff will implement a comprehensive communication plan to ensure that gas customers and
community stakeholders understand the reasons for the proposed rate adjustment and CPAU’s efforts
to minimize bill impacts. Key communication objectives are to:
Increase transparency by clearly explaining how lower gas sales, infrastructure reinvestment,
and reserve requirements contribute to the need for the rate adjustment.
Emphasize stability and fairness by highlighting the stepwise approach to rate adjustments and
the alignment of rates with actual cost-of-service principles, consistent with City Council
direction and Proposition 26.
Demonstrate fiscal stewardship by sharing that staff have pursued federal and state funding
support (including Department of Transportation, FEMA, and CalOES grants) to offset
emergency costs and provide additional main replacement.
Promote understanding of long-term trends by contextualizing the rate increase within the
broader transition to community electrification and declining gas demand.
Item 1
Attachment A, Exhibit 4 -
FY27 Gas Utility
Communications Plan
Item 1: Staff Report Pg. 38 Packet Pg. 42 of 207
Attachment A, Exhibit 4
1
0
7
1
4
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
updates at www.paloalto.gov/RatesOverview, social media, print and digital advertising, and
participation in community outreach events. Public communication materials about rate changes will
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 will emphasize rate adjustments are necessary to sustain safe, reliable, and financially
sound gas operations consistent with voter-approved guidelines and the city’s long-term energy
strategy. In addition, CPAU continues to explore cost-containment measures for each utility fund.
Stakeholder Engagement
Public meetings before the UAC, Finance Committee, and City Council to present rate proposals
and solicit community feedback.
Communication with community partners—including key accounts, business, residential
customer groups and associations, and low-income assistance advocates—to ensure rate
impacts and mitigation options are well understood.
Customer service training for Utilities staff to ensure consistent messaging in addressing
customer inquiries.
Item 1
Attachment A, Exhibit 4 -
FY27 Gas Utility
Communications Plan
Item 1: Staff Report Pg. 39 Packet Pg. 43 of 207
Attachment A, Exhibit 4
1
0
7
1
4
Item 1
Attachment A, Exhibit 4 -
FY27 Gas Utility
Communications Plan
Item 1: Staff Report Pg. 40 Packet Pg. 44 of 207
April 21, 2026 PaloAlto.gov
FY 2027 Gas Utility Financial Forecast and Proposed Rate Changes
Finance Committee
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 41 Packet Pg. 45 of 207
2
Gas Utility At-a-Glance
•210.5 miles of distribution mains
•195 miles of service lines; 18,000
service lines
•53 Staff
•$62 million Operating Budget (FY 2026)
•$24 million Capital Budget (FY 2026)
•$86 million Total Budget (FY 2026)
•23.7 million therms sales
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 42 Packet Pg. 46 of 207
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
•Support infrastructure replacement and repair
•Gas Main Replacement Projects (GMR #25 and #26): ~$31.8 M (GMR #25 100%
grant funded for $16.5 M)
•Design and Construction of ~52,500 feet of aging PVC and steel gas mains and
services
•Arastradero Creek Repairs: total ~$2.7 M (FY25-27)
•Design and permitting for the relocation of damaged 8-inch gas main crossing
the creek during the 2023 atmospheric storm event
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 43 Packet Pg. 47 of 207
4
The Value of Utility Services and How Funds are Used
•Advanced Meter Infrastructure (AMI)
•21,492 gas meter installations completed
•Gas Main Replacement (GMR) Project #24B
•Replaced approximately 18,500 linear feet of aging gas mains and services with polyethylene pipe
•Leak Detection and Mitigation
•Ground leaks dropped significantly to 66 (29% decrease) and meter leaks also saw a downward
trend with 382 found (23% decrease)
•Excavation and Damage control
•Improvement in infrastructure safety with only 15 damages recorded in 2025 (40% decrease in
third-party strikes from the year before)
•Sub-standard Material Replacement
•Total sub-standard gas-services were reduced to 668 remaining units (7% overall reduction)
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 44 Packet Pg. 48 of 207
5
About one-third of the rate is “supply-
related”: Gas Commodity, Transportation,
Cap-and-Invest, and Carbon Offsets. These
rates vary monthly according to market-driven
costs that are passed directly to customers.
The remaining portion of the rate is set based
on the City’s costs for maintaining and
replacing gas infrastructure, customer service,
billing, administration, etc. and general fund
transfer. These rates are being discussed here
tonight.
Gas Cost Structure and Rate Design
Average of FY 2024-25
Total: $60 Million
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 45 Packet Pg. 49 of 207
6
Gas Cost and Revenue Projections
Note
•Rate % changes exclude supply-related cost
changes
•The grant-funded $16.5M CIP project is
projected to be under construction in FY26-27
•Excludes Cap-and-Invest auction sales
revenues and expenses
6
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 46 Packet Pg. 50 of 207
7
Gas Bill Comparisons ($/Month)
Residential
Commercial and Multi-Family Master-Metered Note:
•Calculated based on FY25 actual supply rates, and
assumes no change to supply-related rates
•FY26: Assumes current distribution rates for the
full year
•PG&E bills are calculated using Climate Zone X and
include a climate credit for residential
•G-2 bills are calculated based on the median
usages for each meter capacity group
The residential annual median difference
(11%) compared with PG&E reflects higher
weight to the winter months because of
higher usage during those months.
Palo Alto residential bills are higher than
PG&E in the summer because PG&E does
not have a monthly meter charge.
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 47 Packet Pg. 51 of 207
8
FY 2027 Rate Increase Drivers
8
Note: The % changes were calculated based on current FY 2027 revenues
apportioned into cost categories based on the average actual costs in FY24 and FY25.
Rate Increase Drivers
•Operations: personnel costs
•Lower Sales Revenue: due to lower
projected gas usage
•CIP: gas main replacement cost
increases (for non-grant-funded
project)
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 48 Packet Pg. 52 of 207
9
Gas Supply Load Forecast
•FY25: actual gas usage
approximately 8% below
forecast
•FY27-31: projected gas usage
approximately 4% lower than
the previous forecast;
declining at a rate of 1.1%
per year
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 49 Packet Pg. 53 of 207
10
Gas Operations Reserve Projections
Note: About $4.73 in FY24 and $8.57 M in FY25 (shown in hashed red bar) held in the
CIP Reappropriations Reserve to be reimbursed through grant
Risk Assessment (Blue Line): Based on the
maximum historical non-commodity revenue
variance for the past 10 years and 10% of CIP
budget (up to FY29)
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
Historical Operations Reserve Impacts
FY 20-22: Pandemic Related Usage decline
FY 23: Gas spike, Usage high with colder than
average winter
FY 24: FY 23 costs paid in FY 24 (e.g., price
spike impacts)
FY 25: Usage 8% below projected
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 50 Packet Pg. 54 of 207
11
Gas CIP Reserve Projections
11
Reserve Minimum: 20% of the
maximum CIP Reserve guideline
level
Reserve Maximum: Average
annual CIP budget for 48
months of budgeted CIP
expense
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 51 Packet Pg. 55 of 207
12
Gas Reserve Projections
Note: Excludes Cap and Trade Reserve
12
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 52 Packet Pg. 56 of 207
13
Communication and Outreach
Key Messages
•Reasons for rate increases and benefits to customers:
•Safety, reliability, infrastructure upgrades, system
maintenance
•Competitive rates to other utilities and neighboring cities
•What the City is doing to keep costs down
•Programs 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
Utility bill insert about gas safety
Installing new piping for the Gas Main
Replacement Project #24B
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 53 Packet Pg. 57 of 207
Recently Implemented Cost Containment
14
•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)
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 54 Packet Pg. 58 of 207
15
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)
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 55 Packet Pg. 59 of 207
16
FY 2027 Proposed Budget Deductions
Reduction in operating expenses due to Utilities Department-wide budget refinements
and improved efficiencies (Gas only):
•Eliminate vacant Meter Reader positions: $225K
•Outsource utility bill printing and mailing: $35K
•Implement credit card processing fee: $315K
•Transfer from pension trust: $300K
Sources of additional potential budget reductions:
•Council priority on organizational efficiencies
•Leverage internal resources between departments
•Citywide Hiring Review Committee evaluates recruitments
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 56 Packet Pg. 60 of 207
17
Summary of Gas Rate Proposal
FY 2027 Financial Forecast Projection
•9% overall rate increase in FY 2027 (14.5% increase in distribution rates), approximately $7.30/month
increase for the median residential customer
Drivers of 5-Year Rate Trajectory
•Decreasing retail sales
•Rising Capital Improvement Project (CIP) costs and maintain reserve levels
Compared with Preliminary Rates (November 2025)
•Updated and projecting lower retail sales and supply costs
•Higher CIP costs; lower operations costs
*excludes supply-related rate changes, does not illustrate customer class cost-of-service adjustments (February 2026)
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 57 Packet Pg. 61 of 207
18
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)
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 58 Packet Pg. 62 of 207
19
Recommendation
Staff Recommends the Finance Committee Recommend that the City Council Adopt a
Resolution:
1.Approving the Fiscal Year 2027 Gas Utility Financial Forecast, including Amending
the Gas Utility Reserve Management Practices; and
2.Approving the transfer of up to $1.5 million from the Gas Utility Operations Reserve
to the Distribution Rate Stabilization Reserve at the end of FY 2026; and
3.Transferring up to 18% of gas utility gross revenues received during FY 2025 (up to
$10.7 million) to the General Fund in FY 2027; and
4.Amending Rate Schedules, effective July 1, 2026 (FY 2027):
a.G-1 (Residential Gas Service)
b.G-2 (Residential Master-Metered and Commercial Gas Service)
c.G-3 (Large Commercial Gas Service)
Item 1
Attachment B - FY27 Gas Presentation (FC)
Item 1: Staff Report Pg. 59 Packet Pg. 63 of 207
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)
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 1 Packet Pg. 64 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 2 Packet Pg. 65 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 3 Packet Pg. 66 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 4 Packet Pg. 67 of 207
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.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 5 Packet Pg. 68 of 207
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.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 6 Packet Pg. 69 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 7 Packet Pg. 70 of 207
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.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 8 Packet Pg. 71 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 9 Packet Pg. 72 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 10 Packet Pg. 73 of 207
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.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 11 Packet Pg. 74 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 12 Packet Pg. 75 of 207
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.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 13 Packet Pg. 76 of 207
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)
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 14 Packet Pg. 77 of 207
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.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 15 Packet Pg. 78 of 207
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 $1,457 No Yes
Reserves
The Electric Utility currently has two primary contingency reserves: the Supply Operations
Reserve and the Distribution Operations Reserve. In addition, the Electric Utility has a Hydro
Stabilization Reserve, an Electric Special Projects (ESP) Reserve, and a Capital Reserve. Reserve
funds may be utilized with Council approval.
There are a variety of risks associated with the Supply Fund related to resource generation
variability, market price volatility, transmission cost increases, and regulatory changes to
market rules. Because of the high range of uncertainty in energy price predictions more than
two years into the future, this risk assessment is only performed for the first two fiscal years of
the forecast period. It is important to note that there is a very low likelihood of all adverse
scenarios occurring simultaneously (as the severity is defined in Table 7).
15 Staff report 2411-3805 “Adoption of a Resolution of Intention to Reimburse Expenditures for the Grid
Modernization and Related Projects of the Electric Utility System Infrastructure from the Proceeds of the Tax-
Exempt Utility Revenue Bonds.”
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83165&dbid=0&repo=PaloAlto
16 Council Resolution 10209 (Dec. 16, 2024)
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=62094&dbid=0&repo=PaloAlto
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 16 Packet Pg. 79 of 207
17
Table 7: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
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.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 17 Packet Pg. 80 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 18 Packet Pg. 81 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 19 Packet Pg. 82 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 20 Packet Pg. 83 of 207
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.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 21 Packet Pg. 84 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 22 Packet Pg. 85 of 207
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 ($000)
1
2
3
4
5
6
7
8
Distribution Operations
Capital Reserves
Electric Special Projects
Hydro Stabilization
Cap and Trade
Public Benefits
Low Carbon Fuel Standard (LCFS)
Revenues
11
12
13
14
Distribution
Cap and Trade
Public Benefits
Low Carbon Fuel Standard
Transfers from Supply Operations Reserve to Other Reserves or to Distribution Fund
17
18
19
Electric Special Projects
Hydro Stabilization
Cap and Trade
Transfers from Distribution Operations Reserve to Other Reserves or to Supply Fund
22
23
Capital Reserves
Low Carbon Fuel Standard
Expenses
26
27
28
29
30
Distribution Non-CIP
Distribution Planned CIP
Cap and Trade
Public Benefits
Low Carbon Fuel Standard
Ending Reserve Balance
2+11+24+26+27=33
3+22=34
4-17=35
5+18=36
6-19+28=37
7+13+29=38
8+14+23+30=39
Distribution Operations
Capital Reserves
Electric Special Projects
Hydro Stabilization
Cap and Trade
Public Benefits
Low Carbon Fuel Standard (LCFS)
Operations Reserve Guidelines (Supply)
Operations Reserve Guidelines (Distribution)
Capital Reserve Guidelines
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 23 Packet Pg. 86 of 207
24
Proposed Rates
Bill Impacts
The City adopted its current electric rates effective July 1, 2025. The current FY 2026 and
proposed FY 2027 rates are reflected in Table 10 below. All FY2027 commodity rates are
increased by 7% and FY2027 distribution rates are increased by 4.5%. Rate components that are
weighted more toward supply costs (summer energy rates) increase at a higher percentage
compared with rate components comprised more heavily of distribution costs (demand rates).
The results in a 6% overall adjustment for each rate schedule.
Table 10: Current and Proposed Electric Rates
Rate Schedule Change Change (%)
(Residential)
Tier 1 Energy ($/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%.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 24 Packet Pg. 87 of 207
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.
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 25 Packet Pg. 88 of 207
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).
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 26 Packet Pg. 89 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 27 Packet Pg. 90 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 28 Packet Pg. 91 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 29 Packet Pg. 92 of 207
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
Item 2
Item 2 Staff Report
Item 2: Staff Report Pg. 30 Packet Pg. 93 of 207
* 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,
Item 2
Attachment A - FY27 Electric
Resolution
Item 2: Staff Report Pg. 31 Packet Pg. 94 of 207
* 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;
Item 2
Attachment A - FY27 Electric
Resolution
Item 2: Staff Report Pg. 32 Packet Pg. 95 of 207
* 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.
//
//
//
//
Item 2
Attachment A - FY27 Electric
Resolution
Item 2: Staff Report Pg. 33 Packet Pg. 96 of 207
* 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
Item 2
Attachment A - FY27 Electric
Resolution
Item 2: Staff Report Pg. 34 Packet Pg. 97 of 207
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 Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 35 Packet Pg. 98 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 36 Packet Pg. 99 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 37 Packet Pg. 100 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 38 Packet Pg. 101 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 39 Packet Pg. 102 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 40 Packet Pg. 103 of 207
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.
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 41 Packet Pg. 104 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 42 Packet Pg. 105 of 207
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.
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 43 Packet Pg. 106 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 44 Packet Pg. 107 of 207
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.
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 45 Packet Pg. 108 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 46 Packet Pg. 109 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 47 Packet Pg. 110 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 48 Packet Pg. 111 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 49 Packet Pg. 112 of 207
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.
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 50 Packet Pg. 113 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 51 Packet Pg. 114 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 52 Packet Pg. 115 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 53 Packet Pg. 116 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 54 Packet Pg. 117 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 55 Packet Pg. 118 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 56 Packet Pg. 119 of 207
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.
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 57 Packet Pg. 120 of 207
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.
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 58 Packet Pg. 121 of 207
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)
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 59 Packet Pg. 122 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 60 Packet Pg. 123 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 61 Packet Pg. 124 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 62 Packet Pg. 125 of 207
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.
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 63 Packet Pg. 126 of 207
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)
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 64 Packet Pg. 127 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 65 Packet Pg. 128 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 66 Packet Pg. 129 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 67 Packet Pg. 130 of 207
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,
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 68 Packet Pg. 131 of 207
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.
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 69 Packet Pg. 132 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 70 Packet Pg. 133 of 207
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
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 71 Packet Pg. 134 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 72 Packet Pg. 135 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 73 Packet Pg. 136 of 207
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}
Item 2
Attachment A, Exhibit 1 -
FY27 Electric Rate
Schedules
Item 2: Staff Report Pg. 74 Packet Pg. 137 of 207
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.
Item 2
Attachment A, Exhibit 2 - FY27 Electric
Utility and CIP Financial Details
Item 2: Staff Report Pg. 75 Packet Pg. 138 of 207
Attachment A, Exhibit 2
7
4
8
0
Electric Utility Capital Improvement Program (CIP) Financial Details
Item 2
Attachment A, Exhibit 2 - FY27 Electric
Utility and CIP Financial Details
Item 2: Staff Report Pg. 76 Packet Pg. 139 of 207
Attachment A, Exhibit 3
7
4
8
1
ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
Item 2
Attachment A, Exhibit 3 -
FY27 Electric Reserves
Management Practices
(redline)
Item 2: Staff Report Pg. 77 Packet Pg. 140 of 207
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;
Item 2
Attachment A, Exhibit 3 -
FY27 Electric Reserves
Management Practices
(redline)
Item 2: Staff Report Pg. 78 Packet Pg. 141 of 207
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.
Item 2
Attachment A, Exhibit 3 -
FY27 Electric Reserves
Management Practices
(redline)
Item 2: Staff Report Pg. 79 Packet Pg. 142 of 207
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:
Item 2
Attachment A, Exhibit 3 -
FY27 Electric Reserves
Management Practices
(redline)
Item 2: Staff Report Pg. 80 Packet Pg. 143 of 207
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
Item 2
Attachment A, Exhibit 3 -
FY27 Electric Reserves
Management Practices
(redline)
Item 2: Staff Report Pg. 81 Packet Pg. 144 of 207
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.
Item 2
Attachment A, Exhibit 3 -
FY27 Electric Reserves
Management Practices
(redline)
Item 2: Staff Report Pg. 82 Packet Pg. 145 of 207
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
Item 2
Attachment B - FY27 Electric
Communications Plan and
Samples
Item 2: Staff Report Pg. 83 Packet Pg. 146 of 207
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.
Item 2
Attachment B - FY27 Electric
Communications Plan and
Samples
Item 2: Staff Report Pg. 84 Packet Pg. 147 of 207
Attachment B
6
8
6
0
Item 2
Attachment B - FY27 Electric
Communications Plan and
Samples
Item 2: Staff Report Pg. 85 Packet Pg. 148 of 207
March 31, 2026 PaloAlto.gov
FY 2027 Electric Rate Proposal
Utilities Advisory Commission
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 86 Packet Pg. 149 of 207
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
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 87 Packet Pg. 150 of 207
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
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 88 Packet Pg. 151 of 207
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
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 89 Packet Pg. 152 of 207
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.
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 90 Packet Pg. 153 of 207
6
Electric Cost and Revenue Projections Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 91 Packet Pg. 154 of 207
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%
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 92 Packet Pg. 155 of 207
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 $18.7 million
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 93 Packet Pg. 156 of 207
9
Electric Utility CIP Spending ($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%
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 94 Packet Pg. 157 of 207
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%
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 95 Packet Pg. 158 of 207
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
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 96 Packet Pg. 159 of 207
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)
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 97 Packet Pg. 160 of 207
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)
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 98 Packet Pg. 161 of 207
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
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 99 Packet Pg. 162 of 207
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 Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 100 Packet Pg. 163 of 207
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);
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 101 Packet Pg. 164 of 207
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)
Item 2
Attachment C - Staff Presentation
Item 2: Staff Report Pg. 102 Packet Pg. 165 of 207
Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Public Works
Meeting Date: April 21, 2026
Report #:2602-5923
TITLE
Recommendation to the City Council to: Adopt a Resolution Approving the Fiscal Year 2027
Schedule of Airport Rates and Charges; Accept the Palo Alto Airport Rates and Charges Study;
and Authorize Annual Adjustments to Airport Fees and Charges Based on the Airport
Benchmark Index (ABI), as Described in the Study; CEQA Status – Exempt Under Section
15061(b)(3)
RECOMMENDATION
Staff recommends that the Finance Committee recommend that the City Council:
1. Adopt a resolution approving the Fiscal Year 2027 Schedule of Airport Rates and
Charges;
2. Accept the Palo Alto Airport Rates and Charges Study; and
3. Authorize annual adjustments to airport fees and charges based on the Airport
Benchmark Index (ABI), as described in the Study, as part of the annual Municipal Fee
Schedule adoption.
EXECUTIVE SUMMARY
Airport operating revenues have not progressed with rising operating and capital costs,
resulting in structural pressure on the Airport Enterprise Fund. In response, the City
commissioned a comprehensive Rates and Charges Study to ensure the Airport remains
financially self-sustaining in accordance with Federal Aviation Administration (FAA)
requirements.
The Study recommends targeted adjustments to landing fees, fuel flowage fees, lease rates,
and select administrative charges. These changes are designed to restore structural balance,
improve cost recovery, and generate sufficient reserve capacity to support required Capital
Improvement Program (CIP) sponsor contributions.
Item 3
Item 3 Staff Report
Item 3: Staff Report Pg. 1 Packet Pg. 166 of 207
Collectively, the recommended rates strengthen the long-term financial stability of the Airport
Enterprise Fund and position the Airport to meet its operational and capital obligations going
forward independently from support from other City funding sources.
BACKGROUND
1 approving the Schedule of Fees and Charges for PAO. Since then, the fees
have increased by the Consumer Price Index of the San Francisco-Oakland-San Jose area.
The Airport is currently planning approximately $12.5 million in capital projects through 2030,
including both federally assisted and locally funded projects. While most federally eligible
projects are expected to receive significant grant funding, the City remains responsible for
sponsor match contributions and for fully funding projects that are not grant-eligible.
FAA Grant Assurance 24 requires the City to maintain a fee and rental structure that makes the
Airport as self-sustaining as possible, while Grant Assurance 25 restricts airport revenue to
airport-related purposes. Considering the increasing operating costs, planned capital
investments, and limited reserves, staff determined that a comprehensive review of airport
rates and charges was necessary.
2 for the City has risen by 46% during the same time frame.
1 Resolution 9453, August 2014;
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=53806&dbid=0&repo=PaloAlto&searchid=a871830a
-2a7c-4021-8f05-798c291e28fb
2 This is an annual increase in fees calculated primarily based on the average increase in salaries and benefits to
maintain cost recovery levels year over year.
Item 3
Item 3 Staff Report
Item 3: Staff Report Pg. 2 Packet Pg. 167 of 207
This targeted adjustment realigns lease revenues with operating costs, supports required
capital improvement sponsor contributions, and maintains compliance with FAA requirements
that non-aeronautical uses be charged at fair market value. The proposed increase remains
within the range of comparable airports and reflects a measured approach to restoring long-
term financial stability. The study notes that if revenues do not meet expectations, PAO will
need to defer CIP projects in the future.
ANALYSIS
Rates and Charges Study Overview
The Rates and Charges Study evaluates the Airport’s financial position using a hybrid
compensatory-residual methodology consistent with FAA guidance. Under this approach,
market-based rates are applied where appropriate, and landing fees are calibrated to ensure
that total airport revenues are sufficient to cover operating costs, capital needs, and reasonable
reserves without generating excessive surplus as an enterprise.
The Study includes:
A peer airport analysis comparing PAO to similar general aviation airports in California;
A review of existing aeronautical and non-aeronautical fees;
A landing fee analysis based on aircraft weight and actual airport use; and
A multi-year financial forecast assessing reserve balances under various fee scenarios.
Key Findings
The Study found that:
Airport operating and capital costs have increased faster than existing fees;
Transient aircraft account for a substantial share of runway use but contribute a
relatively small portion of total revenue; and
Without fee adjustments, the Airport Enterprise Fund risks continued structural deficits
that could limit the City’s ability to maintain infrastructure and meet FAA obligations.
Study Recommendations
The proposed options are suggested by the consultant to meet the capital improvement needs
of the airport:
Item 3
Item 3 Staff Report
Item 3: Staff Report Pg. 3 Packet Pg. 168 of 207
5. Modify the tie-down parking rate structure to differentiate landing fee and daily parking
rates with the landing fee established at $3.00 / 1,000 lbs. Maximum takeoff weight
(MTOW) for non-commercial flights, and $9.00 / 1,000 lbs MTOW for commercial flights,
and,
6. Benchmark future fee schedule increases to an Airport Benchmark Index (ABI) blending
the City’s General Rate Increase (GRI) and the San Francisco-Oakland-Hayward CPI-U
index at a 2:1 ratio.
Fuel Flowage
Fuel Flowage are fees charged by PAO on every gallon of aviation fuel dispensed into an aircraft
on the field, and this fee represent a stable revenue source that supports airfield maintenance
and capital improvements. While PAO’s existing fuel flowage fee is the highest within the
regional range, the study notes that it is not uncommon for general aviation airports to have a
fuel flowage rate between $0.20-0.25 per gallon.
Therefore, the study recommends increasing the current fuel flowage of $0.21 to $0.25 per
gallon to increase fuel flowage revenue.
Per the lease agreement with the fuel provider at PAO, the fuel flowage fee will not be assessed
on unleaded aviation fuel or sustainable aviation fuel until the sale of those fuels exceeds 50%
of total fuel sales at the airport.
Increase Monthly Vehicular Parking Rate and establish daily rates to one-fifth of the monthly
rate
The Study recommends increasing the monthly vehicular parking rate from $90 to $100 and
establishing a daily rate at one-fifth of the monthly rate. The Study recommends the Mobile
Truck Operations Permit be increased to $30 per day and $150 per month.
These adjustments modernize PAO’s parking fee structure, improving consistency between
daily and monthly rates. The revised structure aligns parking fees more closely with comparable
airports while maintaining affordability for tenants based at the airport.
The airport fee would be in the mid-range of peer airports with the typical range between $4.00
and $30.00.
Apply a Commercial Non-Aeronautical Permit Fee Equal to 10% of Gross Receipts
The Fee Study recommends applying a Commercial Non-Aeronautical Permit Fee equal to 10%
of gross receipts for applicable operators conducting business at PAO. This fee applies to
revenue generated from the sale of goods or services to the public or to PAO users, including
but not limited to ride share companies, mobile vending, special events, vehicle rental, or other
ground-based commercial services not supporting flight operations. This fee does not apply to
business leases at PAO, as these are negotiated through individual leases.
Item 3
Item 3 Staff Report
Item 3: Staff Report Pg. 4 Packet Pg. 169 of 207
This fee ensures that commercial activities benefiting from PAO facilities contribute
appropriately to the cost of maintaining the infrastructure and services. Under FAA policy, non-
aeronautical uses of airport property must be charged at fair market value, and revenue
derived from these activities must remain within the Airport Enterprise Fund.
The proposed structure aligns with peer airport practices and promotes equitable cost recovery
by capturing revenue from operators who generate income through airport-based activity
without holding traditional aeronautical leases. This approach strengthens PAO’s financial
sustainability while maintaining fairness across user groups.
Revised Transient Landing Fee Structure
The Study finds that transient aircraft account for a significant portion of runway use but
contribute a disproportionately small share of total airport revenue. A transient aircraft is an
aircraft that uses PAO on a temporary basis but is not based at PAO and does not occupy a long-
term hangar or tiedown under a license agreement. Landing fees provide a direct, FAA-
supported mechanism to recover costs associated with airfield use and the maintenance of
runway and taxiway infrastructure.
Benchmark future fee increases on ABI
The Airport Benchmark Index (ABI) is a newly recommended method for making predictable
annual adjustments to airport fees and charges, with a goal of better aligning annual
Item 3
Item 3 Staff Report
Item 3: Staff Report Pg. 5 Packet Pg. 170 of 207
adjustments with actual cost increases.
The ABI incorporates:
FISCAL/RESOURCE IMPACT
Item 3
Item 3 Staff Report
Item 3: Staff Report Pg. 6 Packet Pg. 171 of 207
3. Support planned capital improvements without reliance on debt financing in the near
term.
While several recommendations are not readily quantifiable, the fuel flowage fee and transient
landing fee are expected to generate approximately $52,000 and $154,000, respectively, in
additional annual revenue during the first year of implementation.
Collectively, these revenue increases will strengthen the Airport Enterprise Fund and generate
additional reserve capacity within the fund balance to support future capital improvement
program project sponsor contributions. As shown in Table 1 below, these additional fees will
generate a surplus of $35,037. This surplus includes continuing with the CIP projects for the
next fiscal year. Without the additional fees the Airport Enterprise Fund would have a deficit of
$171,512.
Table 1: Analysis of Changes in Fee Structure
Fee Current Status Revised
Expected Revenue
Increase
Fuel Flowage $0.21/gallon $0.25/gallon $52,026
Vehicle Parking $11/day or $92/month $20/day or $100/mo
Mobile Truck Operating
Permit $30/day or $77.50/month $30/day or $150/month
$7,000
Commercial Non-
Aeronautical Permit fee
10% gross receipts only
charged to Rental Car services
10% gross receipts to all non-
commercial operators
Non-commercial Transient
Landing Fees No charge $3/1000lbs
Transient Commercial
Landing Fees $25 - $95 $9/1000lbs
Transient Tie-Down Parking Based on weight and hours of
parking
Simplified to Daily Rate with first
4 hours paid for by landing fee
$154,523
Annual Increase Based on CPI Airport Benchmark Index which
is 2/3 GRI & 1/3 CPI
All revenue generated under the proposed fee adjustments will remain within the Airport
Enterprise Fund and will be used solely for airport operating and capital purposes in compliance
with FAA Grant Assurances 24 and 25. The revised fee structure supports PAO’s obligation to be
as financially self-sustaining as possible under existing circumstances.
PAO remains at the most expensive airport in the Bay Area and is at the top range of fees as
shown below in Table 2. A commercial aircraft with a MTOW of 12,500 would be billed $117
per landing at the airport, placing PAO at the top range for Commercial Landing Fees in the Bay
Area.
Item 3
Item 3 Staff Report
Item 3: Staff Report Pg. 7 Packet Pg. 172 of 207
Table 2: Bay Area Airport Comparison
Fee PAO Range Bay Area Airport Range
Tie-down $206.00 - 470.00 $48.00 - $411.50
Hangars $0.92 - $1.00 $0.36 - $0.87
Transient $5.50 - $30.00 $0.00 - $27.00
Non-commercial Landing Fee $3.00 / 1000 lbs $0.00
Commercial Landing Fee $9.00 / 1000lbs $2.00 - $106.00
Vehicle Parking $11.50 $0.00 - $20.00
Fuel Flowage $0.25 $0.05 - $0.15
STAKEHOLDER ENGAGEMENT
Staff coordinated internally with the Administrative Services Department throughout the
development of the Airport Rates and Charges Study.
In addition to internal coordination, staff engaged with the Palo Alto Airport Association during
the study. The Association was kept informed of the study scope methodology, and preliminary
findings. This outreach was intended to promote transparency, ensure stakeholder awareness,
and provide an opportunity for feedback prior to bringing the item forward for Council
consideration.
ENVIRONMENTAL REVIEW
The proposed action is exempt from the California Environmental Quality Act (CEQA) pursuant
to CEQA Guidelines Section 15061(b)(3), as it can be seen with certainty that adoption of the
fee schedule will not result in a direct or indirect physical change in the environment.
ATTACHMENTS
Attachment A: PAO Rates and Charges Study
Attachment B: Resolution PAO Rates and Charges Adjustment
APPROVED BY:
Brad Eggleston, Director Public Works/City Engineer
Item 3
Item 3 Staff Report
Item 3: Staff Report Pg. 8 Packet Pg. 173 of 207
FINAL REPORT
September 17, 2025
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 9 Packet Pg. 174 of 207
2
Palo Alto Airport (PAO or Airport) is a towered, single runway airport owned and operated by the City of Palo Alto
(City or Sponsor) for public use. The Airport is categorized as a General Aviation Regional role in the Federal Aviation
Administration’s (FAA) National Plan of Integrated Airport System (NPIAS) with 331 based aircraft on 102 acres
located within the city of Palo Alto, CA. The airfield consists of Runway 13/31, a 2,441’ x 70’ asphalt runway with an
LNAV MDA non-precision instrument approach.
In August 2014, the County of Santa Clara transferred the PAO back to the City. Since that time, staff has been
bringing the Airport up to current Federal Aviation Administration (FAA) standards through several capital projects.
In August 2019, the City consolidated a General Fund loan totaling $3.4M to support operating and capital expenses
spanning FY 2011 to 2018. Additional revenue from airport operations is required to finance necessary capital
projects and ensure the long-term financial health of the Airport.
The Palo Alto Airport Master Plan is currently under development by C&S Engineers. The Master Plan depicts
proposed facilities on the Airport Layout Plan (ALP). The Airport Capital Improvement Plan (ACIP) projects capital
expenses and project phasing of facilities on the ALP. C&S updated the ACIP in 2024 prescribing $4.7M in capital
projects between 2025 and 2030.
Federal grants provide funding equal to approximately 90% of the eligible project costs in exchange for obligations
to uphold FAA Grant Assurances. The Sponsor’s 10% match is typically offset by grants from the California
Department of Transportation (Caltrans). However, state funding through Caltrans is limited and not all capital
projects are eligible for federal and/or state funding. The PAO budget calls for an additional $5.8M in federally
funded projects not on the current ACIP and $384k in capital projects not eligible for federal funding. In all, the
Airport plans to fund $12.5M in capital projects requiring $1.4M of Sponsor contributions through 2030.
City has engaged Ascension Group Partners (AGP) to conduct this Rates and Charges Study with the purpose of
determining appropriate aeronautical fees sufficient to cover the Airport’s operating expenses and funding
requirements for planned capital projects. A survey of market-based rates and charges was conducted for a peer set
of airports along with a landing fee analysis, which uses a residual cost-recovery methodology to determine landing
fees adequate to cover the Sponsor’s obligations without accumulating an excessive reserve. This report
supplements the Rent Study Analysis conducted by AGP in August 2023 that evaluated market rates for aeronautical
and non-aeronautical facilities for a similar peer set of airports.
The following options are suggested to meet capital development funding needs at PAO:
1.Defer capital projects when capital reserve is insufficient to fund Sponsor contribution,
2.Adopt Minimum Standards and complete the Master Plan prior to conducting any Request for Proposal
(RFP) for commercial aeronautical facility development,
3.Adjust Fee Schedule by 2.4% in line with the San Francisco-Oakland-Hayward CPI-U index for CY 2024.
4.Increase office and non-aeronautical ground rents by an additional 5.6% over CPI adjustment for FY26.
5.Increase the fuel flowage fee from $0.21 to $0.25,
6.Increase monthly vehicular parking rate from $90 to $100 and establish daily vehicular parking at 1/5th
of the monthly rate and the Mobile Truck Operating Permit at five times the daily rate,
7.Establish a Hangar Ground Lease Origination / Transfer fee at 2% of sale or assessed value,
8.Apply a Commercial Non-Aeronautical Permit fee equal to 10% of gross receipts,
9.Modify the tie-down parking rate structure to differentiate landing fee and daily parking rates with the
landing fee established at $3.00 / 1,000 lbs. maximum take off weight (MTOW), and
10.Benchmark future fee schedule increases to an Airport Benchmark Index (ABI) blending the City’s
General Rate Increase (GRI) and the San Francisco-Oakland-Hayward CPI-U index at a 2:1 ratio.
Palo Alto Airport is entering a sustained, capital intensive period of facility redevelopment without a substantial
reserve to finance construction projects. The proposed Aeronautical Fee Schedule in Exhibit A would fund planned
capital projects and end FY2026 with a positive reserve fund by making minimal changes to consolidate and
standardize current aeronautical fees beyond the 2.4% annual CPI adjustment.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 10 Packet Pg. 175 of 207
3
1.0 Airport Rates and Charges
Grant Assurance 24, Airport Fees and Rents, requires the airport maintain a fee and rental structure for the facilities
and services at the airport which will make the airport as self-sustaining as possible under the circumstances existing
at the particular airport. Airport proprietors must employ a reasonable, consistent, and transparent (i.e., clear and
fully justified) method of establishing rates and charges, and adjustments on a timely and predictable schedule. FAA
will not ordinarily investigate the reasonableness of a general aviation airport’s fees absent evidence of a progressive
accumulation of surplus aeronautical revenues. In establishing new fees, and generating revenues from all sources,
airport owners and operators should not seek to create revenue surpluses that exceed the amounts to be used for
airport purposes, including reasonable reserves and other funds to facilitate financing and to cover contingencies.
FAA Grant Assurance 25 ensures all airport-generated revenue be used solely for the capital or operating costs of
that airport (or other FAA‑approved airport-related purposes) and prohibits diverting those funds to non‑airport
entities or uses, including through the use of inappropriate direct or indirect operating expenses.
A hybrid compensatory-residual methodology is applied to determine the Airport’s rates and fees. Under this
methodology, PAO charges market-based rates comparable to a peer set of airports (Peer Set) for the lease of airport
property and airport-related services to aeronautical users while establishing any approved non-aeronautical use of
the Airport at fair market value. The Airport’s landing fee is calibrated to balance operating and capital budgets after
cross-crediting other airport revenues and any reserves.
2.0 Market-Based Rate Survey
A market-based survey of rates and charges was conducted on a Peer Set of ten comparable airports. Seven criteria
were used in the evaluation: NPIAS role, number of based aircraft, TFMSC C-II operations, Air Traffic Control Tower
(ATCT), and Instrument Landing System (ILS) facilities, acres of land, and distance from PAO. Data was acquired from
the FAA Form 5010-1 Airport Master Record database. The Traffic Flow Management System Count (TFMSC)
operations for Airport Reference Code C-II aircraft or above was acquired from the FAA Aviation System Performance
Metrics Web Data System.
Figure 1. PAO Airport Peer Set.
All airports in the Peer Set were scored on the seven criteria by indexing the value for each airport minus the value
for PAO on a scale of 0 to 1 with the highest score given to airports identical to PAO and the lowest score given to
airports most dissimilar to PAO. PAO received a score of 1 in each of the seven criteria for a total index score of 7.0.
San Carlos (SQL) was the most similar airport with an index score of 6.96: NPIAS Role (1.00), based aircraft (0.98),
TFMSC C-II Operations (1.00), ATCT (1.00), and ILS (1.00), acres (0.99), and distance (0.98). The ten most similar
airports were included in this Peer Set (Figure 1).
Code Name City State
RNWY
Length Acres NPIAS Role ILS ATCT
Based
Aircraft
CII
TFMSC Distance Index
PAO PALO ALTO PALO ALTO CA 2443 102 Regional N Y 331 0 0 7.0000
SQL SAN CARLOS SAN CARLOS CA 2621 110 Regional N Y 323 0 8 6.9621
RHV REID-HILLVIEW SAN JOSE CA 3100 179 Regional N Y 330 0 18 6.9484
CCR BUCHANAN FLD CONCORD CA 5001 495 National N Y 340 1980 37 6.7201
HWD HAYWARD EXEC HAYWARD CA 5694 543 National N Y 446 1846 14 6.4857
FUL FULLERTON MUNI FULLERTON CA 3121 86 Regional N Y 312 0 340 6.2698
WHP WHITEMAN LOS ANGELES CA 4120 184 Regional N Y 223 1 303 6.1037
CMA CAMARILLO CAMARILLO CA 6013 650 National N Y 383 2920 281 6.0938
HHR HAWTHORNE MUNI HAWTHORNE CA 4884 80 National N Y 184 1849 324 5.8557
MER CASTLE ATWATER CA 11802 1360 Local N Y 71 118 85 5.8372
WVI WATSONVILLE MUNI WATSONVILLE CA 4502 330 Regional N N 282 13 40 5.7555
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 11 Packet Pg. 176 of 207
4
Airports from the previous Rent Study Analysis conducted by AGP were also included in the peer set. These airports
were selected by flagging regional general aviation service airports with a tower, non-Part 139 certificated, non-
precision approaches, airports with +/- 300 based aircraft, +/- 2,000 feet difference from PAO’s longest runway, and
within the state of California. The PAO Airport 2023 Peer Set (Figure 2) contained four airports included in the
current peer set.
Figure 2. PAO Airport 2023 Peer Set.
2.1 Ground Lease and Hangar Rent Rates
Ground lease and hangar rent rates are difficult to compare because property leases are uniquely determined based
on existing improvements, access to the airfield, negotiation between parties, appraisals, and/or comparative
properties. Surveying ground lease and hangar rent rates is informative, but such rates are not universally
comparable from airport to airport. Ground lease rates are typically influenced by terms specified in the lease, such
as required scheduled improvements over the lease term or conditions such as improvement reversion requirements
at the end of the term.
The 2023 Rent Study Analysis (Exhibit C) provides a detailed review of market rental and ground lease rates at
comparable airports. Ground lease rates are often bifurcated for unimproved sites with no utilities or taxiway access
and improved sites that have utilities and taxiway access. However, the most common structure in the survey was a
single aeronautical ground lease rate. Palo Alto’s Aeronautical Ground Lease rates are above the market average of
$0.59 / sq. ft annually but still within the Peer Set range.
Palo Alto’s airport owned T-hangar rental rates are priced below market average. Non-aeronautical rents are above
average but the FAA requires these rates be assessed at fair market value. Compliance Guidance Letter 2018‑3
(CGL‑2018‑3) Appraisal Standards for the Sale and Disposal of Federally Obligated Airport Property augments FAA
Order 5190.6B – Airport Compliance Manual, Chapter 17 and Appendix Z, by defining the appraisal process and
documentation standards required to determine fair-market value for leases and sales of non‑aeronautical land and
facilities.
The study found that airport fees have not kept pace with operating and capital expenses. As a result, the Airport
Enterprise Fund has begun to operate at a deficit and increased fees are necessary to achieve the Airport’s financial
self-sufficiency. Without corrective action, the funding deficit will begin to limit the Airport’s ability to meet
operational demands and fund critical infrastructure projects.
The table below illustrates the City’s General Rate Increase (GRI) since FY 2019 and corresponding lease rate
increases. The GRI methodology is used by the City of Palo Alto to keep fees in line with the cost of service, new or
changes to service delivery, and changes in cost recovery levels. From FY 2019 to FY 2025, lease rates increased by
approximately 24% while the GRI increased by 36% over the same period.
Code Name State Runway Length Acres NPIAS Role ILS ATCT
Based
Aircraft CII TFMSC Distance Index
PAO PALO ALTO CA 2443 102 Regional N Y 331 0 0 7
SQL SAN CARLOS CA 2621 110 Regional N Y 323 0 8 6.9621
FUL FULLERTON MUNI CA 3121 86 Regional N Y 312 0 340 6.2698
CMA CAMARILLO CA 6013 650 National N Y 383 2920 281 6.0938
WVI WATSONVILLE MUNI CA 4502 330 Regional N N 282 13 40 5.7555
TRK TRUCKEE-TAHOE CA 7001 2280 Regional N Y 114 1017 167 5.7369
LVK LIVERMORE MUNI CA 5253 644 Regional Y Y 400 1233 23 5.6816
SMO SANTA MONICA MUNI CA 3500 215 Local N Y 74 121 314 5.582
SAC SACRAMENTO EXEC CA 5503 540 Regional Y Y 172 319 80 5.3565
SBP SAN LUIS RGNL CA 6101 340 Non-Hub Y Y 327 11330 174 5.3502
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 12 Packet Pg. 177 of 207
5
Table A. GRI vs Lease Rate Increases.
GRI 100.00 Lease 100.00
FY19 2.6% 102.60 3% 103.00
FY20 7.5% 110.30 3% 106.09
FY21 2.6% 113.16 3% 109.27
FY22 2.0% 115.43 3% 112.55
FY23 4.6% 120.74 4% 117.05
FY24 7.5% 129.79 3% 120.56
FY25 5.2% 136.54 3% 124.18
FY26 6.8% 145.82 8% 134.12
AGP recommends a revised airport fee schedule based on an analysis of the Airport’s operating budget and CIP
funding requirements. As part of this review, AGP also recommends an 8% increase in lease rates for new commercial
aeronautical leases after July 1, 2025 to better align revenues with the increasing operating costs. With this proposed
increase, lease rates between FY 2019 and FY 2026 will have increased 34%, or 3.75% per year. During the same
period, the GRI increased 46%, or 4.85% per year.
The updated lease rates for FY26 are critical to restore fiscal stability and ensuring that the Airport remains self-
sustaining under FAA policy and grant assurance requirements. The decision to implement a moderate but necessary
increase is consistent with the City’s obligation under FAA Grant Assurance 24 to maintain a fee and rental structure
that will make the airport as self‑sustaining as possible under the circumstances existing at that particular airport.
The use of the GRI is also consistent with FAA Order 5190.6B – Airport Compliance Manual guidance on escalation
provisions in Section 9.5, Terms and Conditions Applied to Tenants Offering Aeronautical Services, subpart (e) that
periodic adjustments be based on a recognized index to reflect inflation and other changing economic conditions.
An Airport Blended Index (ABI) combining GRI/CPI rate increases would account for year-over-year salary and benefit
increases calculated by the City in the GRI while the CPI covers all other cost increases. The ABI formula of 2/3 GRI +
1/3 CPI is justified based on 2/3 of the Airport fund expenses from salaries and benefits.
2.2 Fuel Flowage Fee
Fuel flowage fees are a charge on fuel sales by Fixed Base Operators (FBOs) remitted to the Airport. Similar to ground
lease rates, airports occasionally bifurcate fuel flowage fees for jet fuel and avgas. Several airports in the Peer Set
exercise their exclusive right to provide sole fueling services at the airport, and therefore, do not have a published
fuel flowage fee. Only three airports in the Peer Set include a retail fuel flowage fee in their fee schedule: Concord
($0.08 retail, or 4.5% of wholesale, $0.95 self-fuel), Fullerton ($0.15), Livermore ($0.11 - $0.15 depending on
volume), San Carlos ($0.10), Camarillo ($0.06), Hayward (greater of $0.05 or 3%). Despite PAO having the highest
published fuel flowage fee in the Peer Set, it is not uncommon for general aviation airports in the region to have
retail fuel flowage fees between $0.20 - $0.25 per gallon.
2.3 Other Airport Fees and Charges
Airports in the Peer Set were selected on characteristics similar to those found at PAO. However, many other
circumstances influence the revenue-generating ability of the airport to cover capital and operating expenses toward
the FAA’s stated goal of self-sufficiency described in Grant Assurance 24. These circumstances influence the
opportunities available to PAO for additional revenue-generation. Thus, comparable market rates are informative in
determining appropriate rates at PAO, but market rates may reflect other budget-balancing revenue sources that
are not available to the Airport.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 13 Packet Pg. 178 of 207
6
Fees found at Peer Set airports not charged by PAO include non-aeronautical permit fees and hangar ground lease
origination / transfer fees. Non-aeronautical permit fees charged to rental car agencies or transportation network
companies (TNCs) such as Uber, Lyft, and Turo are typically 10% - 12% of gross revenue or a fixed price per parking
space. PAO has established a fee for car rentals equal to 10% of gross receipts, but not for TNC’s. Additionally, the
existing Commercial Aeronautical Permit Fee of $134.50 annually be changed to a tiered structure that collects a
fixed fee at lower thresholds while establishing a percentage of gross receipts fee for operators generating significant
revenue. Ground lease origination / transfer fees are typically a fixed amount, ranging from $150 - $1,000, but can
be 1% - 3% of the assessed or sale value like those collected at Camarillo. Similarly, some airports collect a percentage
of revenue for subleasing of commercial aeronautical storage based on hangar square footage.
PAO could add or change the following fees while remaining within the range of Peer Set market rates:
Figure 3. Other Airport Fees.
2.4 Transient Landing Fees
These fees allow the City to capture value created by their continued investment in airport infrastructure from based
tenants. However, transient aircraft account for 27% of general aviation landed weight at PAO, yet transient landing
fees only represent 0.08% of aeronautical revenue. Landing fees represent a mechanism immediately available to
PAO for an increased source of sustainable, relatively inelastic revenue. Unlike hangar rent or fuel flowage fees,
landing fees assess actual airport use that correlates with the operating and capital needs of the airfield.
Commercial landing fees are assessed on aircraft weight. General aviation has traditionally been subsidized by
commercial operators on the justification that heavier aircraft contribute more to the deterioration of runway
pavement than lighter aircraft. However, load is less of a factor on runway deterioration when used primarily by
aircraft within the pavement’s designed weight bearing capacity or in environments with heavy moisture, extreme
temperatures, and frequent freeze-thaw cycles. While aircraft load can be a significant factor in runway
deterioration, it isn’t the only factor or even the primary factor in many cases. Therefore, a flat rate may be applied
for aircraft under a minimum weight threshold that represent a high share of operations but don’t significantly
contribute to pavement deterioration. Based aircraft are typically exempt from landing fees as they pay into the
airport system through ground, hangar, or tie-down rents and other fees. This has the secondary benefit of
encouraging based aircraft registration, which may increase available state funding.
•Current Fee:$10.50 / day
•Typically $4-$30/day or $50-$150/monthVehicular Parking Fee:
•Potential Fee:$1,500 annually / 1.75x monthly storage fee
•Recent standard at GOO and WVI as well as SNS and O52
Derelict / Non-Operational
Aircraft Storage Fee
•Current Fee:$134.50 annually
•Fixed fee of $150 -$1,400 min. annually; SQL: $500 monthly
Commercial Aeronautical
Permit Fee
•Current Fee:10% of Gross Receipts for Rental Cars only
•Ranges 10-12% , $100 per vehicle/month or fixed annual fee
Commercial Non-
Aeronautical Permit Fee
•New Fee: 2% of greater sale or assessed value
•Typically fixed fee of $150-$1,000; CMA: 2% of sale/assessed valueHangar Transfer Fee
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 14 Packet Pg. 179 of 207
7
3.0 Landing Fee Methodology
A transient landing fee model provides a scalable, legally supported, and increasingly practical option thanks to third-
party fee collection services. This model enables airports to align fees more closely with facility use and fund capital
reserves without overburdening based tenants. PAO currently charges a fixed tier landing fee for commercial
operators based on the aircraft Maximum Take Off Weight (MTOW) ranging from $24.50 to $93.00 per landing.
General aviation aircraft are charged a tie-down parking fee for 0-8 hours tiered on aircraft weight. This charge acts
as a landing fee equivalent to an average of $2.05 / 1,000 lbs. MTOW.
Landing fees vary widely in the Peer Set with some based on a fixed tier like PAO but more commonly assessing a
rate per 1,000 lbs. MTOW, or a hybrid of both. Truckee Tahoe (TRK) is one such airport that has established the
maximum of the Peer Set range at $8 / 1,000 lbs. for all aircraft > 5,500 lbs. up to 22,000 lbs., $10 / 1,000 lbs. for
aircraft 20,000 lbs. to 36,000 lbs., and $14 / 1,000 lbs. for aircraft 26,000 lbs. to 80,000 lbs, and $16 / 1,000 lbs. for
aircraft over 80,000 lbs. MTOW. Others in the Peer Set charge landing fees ranging from $1.44 / 1,000 lbs. for aircraft
over 12,500 lbs at Camarillo to $3.00 / 1,000 lbs for general aviation aircraft over 6,000 lbs.
The transient aircraft landed weight at PAO for September 1, 2024 through April 14, 2025 of 22,956,000 pounds was
calculated using data from 1200.aero to extrapolate the FY 2025 baseline of 37,075,000 pounds. Applying the tie-
down parking fee (0-8 hours) to all transient landings, PAO would have collected approximately $74,892 in landing
fees, representing 12% of tie-down revenue budgeted for FY 2025.
As a cost recovery mechanism, landing fees can be determined by dividing expenditures, less all other airport
revenues and any reserve funds, by the anticipated landed weight for the rate setting period. The ACIP provides
estimated costs and timing for implementation over the 5-year planning period. Capital project expenditures assume
FAA Airport Improvement Program (AIP) federal grants fund approximately 90%1 (Figure 4). The Sponsor
participation of capital projects is approximately 10% of federally eligible projects and 100% of locally funded
projects (Figure 5).
Figure 4. Federal ACIP-eligible Projects.
Figure 5. Locally Funded Projects.
Operating expenses were forecasted by calculating the future value of the FY2025 projected expenses for the Airport
operating fund at a 3% annual growth rate. FAA policy requires sponsors charge direct operating expenses only when
costs can be specifically identified with airport functions and must allocate all other overhead through an
FAA‑approved cost allocation plan prepared in accordance with OMB Uniform Guidance (2 CFR Part 200 Subpart E),
ensuring indirect costs are GAAP‑consistent, reasonable, similarly billed to comparable sponsor units, limited to
employee salaries and wages, and not billed directly as pass‑through expenses. The City should evaluate any internal
policies for direct and indirect expenses allocated to the Airport for conformance with FAA Order 5190.6B – Airport
Compliance Manual and FAA Order 5100.38D – AIP Handbook.
1 The FAA Reauthorization Act of 2024 provides a 95% match in federal funds through FY 2026.
Year Airport Capital Improvement Projects (ACIP) - Federal FY 2025 - 2030 (Oct 1 - Sep 30) 2024 Est. Cost Future Value
2025 AWOS III (Construction)2,532,000$ 2,532,000$
2026 Master Plan (Environmental)750,000$ 780,000$
2027 Airfield Solar Array (Design)500,000$ 541,000$
2028 Runway and Taxiway Reconstruction and Drainage Improvements (Environmental) 900,000$ 1,012,000$
2026 Access Road Reconstruction (Design)300,000$ 312,000$
2029 Airfield Electrical Improvement (Design)482,000$ 564,000$
2031
Year Locally Funded Projects 2024 Est. Cost Future Value
2026 Airport Customer Parking Charging Stations (Design & Phase I)25,000$ 26,000$
2026 Airport Temporary Office Buildings 359,000$ 373,000$
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 15 Packet Pg. 180 of 207
8
The General Aviation Landing Fee is calculated in Exhibit B using the methodology as set forth in Table A.
EXPENSE CATEGORY LINE ITEM
Line Item A. Operation and Maintenance Expenditures. This line item is the Airport’s costs for the operation,
maintenance, and repair of the Airport including salaries and employee benefits, utility costs,
ordinary maintenance, direct and indirect administrative and general expenses listed in the annual
operating budget of the Airport Revenue Fund for the rate setting period.
Line Item B. Operation and Maintenance Reserve. This line item is an amount equal to one fifth (1/5) of the
annual budget for Operation and Maintenance Expenses for the rate setting period.
Line Item C. Capital Improvement Plan Expenditures. This line item includes the sponsor’s participation of
federal, state, and locally funded capital projects and other capital expenditures attributable to
the airport cost center.
Line Item D. Capital Improvement Plan Reserve Charge. This line item includes financing and contingencies that
ensure airport self-sufficiency and a positive cashflow in future rate setting periods. The Capital
Improvement Plan Reserve Charge is the Sponsor’s CIP Participation of Uncompleted Projects
divided by the number of current and future rate setting periods in the CIP. The Sponsor’s CIP
Participation of Uncompleted Projects means the total capital expense of uncompleted CIP
projects less projected capital revenues from federal and state grant sources for future rate setting
periods in the CIP.
Line Item E. Airport Total Requirement. This line item is the sum of the following line items: Operation and
Maintenance Expenditures, Operation and Maintenance Reserve Charge, Capital Improvement
Plan Expenditures, and Capital Improvement Plan Reserve Charge.
Line Item F. Credits to Airport Total Requirement. This line item identifies the credits to the Airport Total
Requirement which include other airport revenues and the prior period ending balance of the
Airport Revenue Fund, if any. The Airport Revenue Fund is a reserve fund to facilitate financing
and cover contingencies. Any surplus revenue from the airport cost center will be transferred to
the Airport Revenue Fund at the end of the fiscal year.
Line Item G. Airport Net Requirement. This line item is the Airport Total Requirement less Credits to the Airport
Total Requirement.
Line Item H. Total Landed Weight is the sum of the Maximum Take Off Weight (MTOW) rounded up to the next
highest 1,000 pound interval of each transient aircraft landing at the Airport with a MTOW of 8,000
pounds or more. For aircraft with a MTOW of less than 8,000 pounds, the landed weight is
calculated as 1,000 pounds.
Line Item I. General Aviation Landing Fee. Airport Net Requirement divided by Total Landed Weight.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 16 Packet Pg. 181 of 207
9
4.0 Conclusion
Palo Alto Airport is entering a sustained, capital intensive period of facility redevelopment without a substantial
reserve to finance construction projects. Through 2030, the Airport is planning to fund $12.5M in capital projects
requiring $1.4M in Sponsor contributions. The proposed Aeronautical Fee Schedule in Exhibit A would maintain a
10% average of Uncompleted Projects Funding in Reserve over the planning period. The reserve balance is forecast
to remain above 0% during the planning period and end with 29% of the funding needed for Airport Electrical
Improvement upgrades in 2031. This analysis assumes the City will defer non-critical capital projects if the reserve
balance is insufficient to cover projected capital costs instead of pursuing debt financing.
Once the Master Plan is complete, the Airport may choose to conduct a Request for Proposal (RFP) for private
development of aeronautical facilities on airport-leased ground to realized additional revenues without funding
capital development. The proposed T-hangar reconstruction, box hangar replacement, expanded commercial office
development, and vertiport facilities could generate substantial revenue offsetting the need for higher aeronautical
fees in the future. Airport-funded development requires up-front investment but provides a higher return over the
lifespan of the project from facility rental revenues. Private development requires less upfront investment,
dependent on existing site conditions, and the airport receives ground rent revenue. Reversionary ground leases for
private developments are a common method for the airport to realize hangar rent revenues after the initial ground
lease term has expired and the private developer has recovered their initial investment.
Implementing a Hangar Ground Lease Origination / Transfer fee provides the Airport an opportunity to capture
additional revenue on the initial sale and subsequent transfer of private hangars on airport leased ground. Similarly,
collecting a Commercial Non-Aeronautical Recovery fee for off-airport operators enables the Airport to capture a
percentage of gross receipts generated from activity at the airport.
The waiver of landing fees for non-commercial transient aircraft operations is common among Peer Set airports.
However, removing this waiver at PAO presents the opportunity to generate substantial and immediate revenue
necessary to fulfill the City’s obligations for capital projects maintaining the airport in a safe and serviceable
condition required by federal grant assurances.
The following options are suggested to meet capital development funding needs at PAO:
1.Defer capital projects when capital reserve is insufficient to fund Sponsor contribution,
2.Adopt Minimum Standards and complete the Master Plan prior to conducting any Request for Proposal
(RFP) for commercial aeronautical facility development,
3.Adjust Fee Schedule by 2.4% in line with the San Francisco-Oakland-Hayward CPI-U index for CY 2024.
4.Increase office and non-aeronautical ground rents by an additional 5.6% over CPI adjustment for FY26.
5.Increase the fuel flowage fee from $0.21 to $0.25,
6.Increase monthly vehicular parking rate from $90 to $100 and establish daily vehicular parking at 1/5th
of the monthly rate and the Mobile Truck Operating Permit at five times the daily rate,
7.Establish a Hangar Ground Lease Origination / Transfer fee at 2% of sale or assessed value,
8.Apply a Commercial Non-Aeronautical Permit fee equal to 10% of gross receipts,
9.Modify the tie-down parking rate structure to differentiate landing fee and daily parking rates with the
landing fee established at $3.00 / 1,000 lbs. maximum take off weight (MTOW), and
10.Benchmark future fee schedule increases to an Airport Benchmark Index (ABI) blending the City’s
General Rate Increase (GRI) and the San Francisco-Oakland-Hayward CPI-U index at a 2:1 ratio.
The proposed Aeronautical Fee Schedule in Exhibit A would fund planned capital projects and end FY2026 with a
positive reserve fund by making minimal changes to consolidate and standardize current aeronautical fees beyond
the 2.4% annual CPI adjustment. These include standardizing monthly rates at five times the daily rate and
reclassifying the short-term tie down parking fee to a standardized landing fee per 1,000 lbs. based on the aircraft
maximum take off weight.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 17 Packet Pg. 182 of 207
EXHIBIT A – AERONAUTICAL FEE SCHEDULE (effective July 1, 2025)
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 18 Packet Pg. 183 of 207
*Aircraft not currently based in a hangar or tiedown at the Palo Alto Airport is considered a transient aircraft.
Charges” for the ensuing twelve (12) months shall be adjusted according to the Airport Benchmark Index calculated at 2/3rd
the City of Palo Alto’s General Rate Increase (GRI) and 1/3rd the Consumer Price Index (CPI) for the San Francisco‐Oakland‐San
Jose area of the United States Department of Labor, Bureau of Labor Statistics. In the case of an ABI decrease the rates will
remain the same. All fees are rounded up to the nearest fifty cents ($.50)
AIRCRAFT: All aircraft weights referenced in this document are defined by the aircraft manufacture and/or the Federal
Aviation Administration (FAA) as the certified maximum gross take‐off weight (MTOW) rounded up to the nearest 1,000 lbs.
Palo Alto Airport Schedule of Fees and Charges
Fiscal Year 2026 (July 1, 2025 ‐ June 30, 2026)
SECTION A. City‐Based Aircraft
Tail‐in Open Tie‐Down, improved pavement (monthly)
0 to 3,500 pounds $ 206.00
3,501 to 5,200 pounds $ 239.00
5,201 to 10,200 pounds $ 268.50
10,201 to 17,000 pounds $ 301.50
Taxi‐in Open Tie‐Down, improved pavement (monthly)
0 to 3,500 pounds $ 257.00
3,501 to 5,200 pounds $ 319.50
5,201 to 10,200 pounds $ 443.50
10,201 to 17,000 pounds $ 470.50
Large aircraft and helicopter designated tie‐downs (monthly) $ 470.50
SECTION B. City Non‐Based Aircraft*
Transient Aircraft, landing fee (non‐commercial) $ / 1,000 lbs. MTOW $ 3.00
Transient Aircraft, landing fee (commercial) $ / 1,000 lbs. MTOW $ 9.00
Transient Aircraft, tie‐down fees (daily for every 24 hour period, aircraft leaving within 4 hours of landing are exempt)
0‐3,500 pounds $ 14.00
3,501 to 5,200 pounds $ 16.00
5,201 to 17,000 pounds, taxi‐through, and helicopter $ 30.00
Transient Aircraft Late Fee
Added to each invoice not paid
within 30 days. $ 25.00
Transient Gliders will be charged for the number of tie‐downs they occupy.
SECTION C. Other Charges
Glider & Aircraft Trailer Parking Per Month $ 190.00
Automobile Daily Parking Permit $ 20.00
Monthly Parking Permit ‐ Automobiles Only $ 100.00
Monthly Automobile Apron Parking (Parking spots only
rented in association with a Tie‐down account) $ 55.00
Automobile Parking Citation Fee
Per Transaction (same as Transient
Aircraft Convenience Fee) $ 50.00
Annual or Replacement Gate Access Card Fee Per Card $ 31.00
Mobile Truck Operations Permit Per Day $ 30.00
Per Month $ 150.00
Fire Extinguisher Replacement Per Fire Extinguisher $ 218.00
Commercial Operators/FBO Waste Oil Fee Per Quart $ 1.50
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 19 Packet Pg. 184 of 207
SECTION D. Other Charges (not subject to annual ABI adjustment)
Aircraft Storage Late Fee Per Month $ 45.00
Fixed Base Operator Late Fee Per Month 10% of amount due
Hangar Sublease Fee Per Month per additional aircraft $ 25.00
Non‐Operational Aircraft Storage Fee Per Month 1.75x monthly storage fee
Fuel Flowage Fee for Palo Alto Airport Per Gallon $ 0.25
Self‐Fueling Permit Flowage Fee:
Individual aircraft owner/operator Annual Fee per aircraft $ 84.00
Aircraft owned or operated by a Flying Club Annual Fee per aircraft $ 731.00
Commercial Aeronautical Operations Fee Per Year $ 134.50
Commercial Non‐Aeronautical Fee (Rental Car and
Transportation Network Company Operations)
Payments made by credit card are subject to a 3% convenience fee. This fee does not apply to payments made by check, ACH
or Cash.
Per Month Expired Certificate of Insurance Fee $ 50.00
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 20 Packet Pg. 185 of 207
EXHIBIT B – PRO FORMA FINANCIAL ANALYSIS
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 21 Packet Pg. 186 of 207
Actual Forecasted
Fiscal Year (July 1 - June 30)2025 2026 2027 2028 2029 2030 2031
Operations Growth Rate 3.0%
Operating Expense Escalation Rate 3.0%
Capital Expense Escalation Rate 4.0%
Activity Based Fees
Fuel Flowage Fee $0.21 $0.21 $0.25 $0.25 $0.25 $0.25 $0.25
Transient Landing Fee ($/1k lbs)$3.00 $3.00 $3.00 $3.00 $3.00
Transient Landed Weight (000's)58,402 60,154 61,959 63,817 65,732 67,704 69,735
Fuel Sales (gallons)503,771 518,884 534,451 550,484 566,999 584,009 601,529
Rental Income Incraese 0%0%0%0%0%0%0%
Operations and Maintenance Expense 3,458,112$ 3,399,722$ 3,493,509$ 3,590,109$ 3,689,607$ 3,792,090$ 3,897,648$
Operations and Maintenance Reserve Charge 691,622$ 679,944$ 698,702$ 718,022$ 737,921$ 758,418$ 779,530$
Capital Project Expenditures -$ 80,600$ 27,050$ 101,200$ 56,400$ -$ 1,086,700$
Capital Improvement Plan Reserve Charge -$ 211,892$ 248,860$ 285,775$ 362,233$ 543,350$ -$
Airport Total Requirement 4,149,734$ 4,372,158$ 4,468,120$ 4,695,106$ 4,846,162$ 5,093,858$ 5,763,878$
Less Credits to Airport Total Requirement (232,358)$ 1,156,088$ 1,035,690$ 1,074,407$ 1,122,491$ 1,180,223$ 1,247,892$
AIRPORT NET REQUIREMENT BEFORE LANDING FEES 4,382,092$ 3,216,070$ 3,432,431$ 3,620,698$ 3,723,671$ 3,913,635$ 4,515,986$
AIRPORT OPERATING FUND
Airport Aeronautical Revenues
Rental Income 970,089$ 1,104,620$ 1,137,759$ 1,171,891$ 1,207,048$ 1,243,260$ 1,280,557$
Hangar Fees 1,303,269$ 1,289,010$ 1,327,680$ 1,367,511$ 1,408,536$ 1,450,792$ 1,494,316$
Fuel Commission 115,709$ 79,210$ 81,586$ 84,034$ 86,555$ 89,152$ 91,826$
Tie Down Fees 715,336$ 636,500$ 655,595$ 675,263$ 695,521$ 716,386$ 737,878$
Parking 17,946$ 19,220$ 19,797$ 20,390$ 21,002$ 21,632$ 22,281$
Other Utilities 103,405$ 66,240$ 68,227$ 70,274$ 72,382$ 74,554$ 76,790$
Misc. Revenues (Transient Fees / Charter Flights)27,431$ 30,440$ 31,353$ 32,294$ 33,263$ 34,260$ 35,288$
Incremental Landing Fees -$ -$ 154,523$ 159,159$ 163,933$ 168,851$ 173,917$
Incremental Rental Income -$ -$ -$ -$ -$ -$ -$
Incremental Fuel Commission -$ -$ 52,026$ 53,587$ 55,195$ 56,851$ 58,556$
TOTAL AIRPORT AERONAUTCAL REVENUES 3,253,185$ 3,225,240$ 3,528,546$ 3,634,403$ 3,743,435$ 3,855,738$ 3,971,410$
Airport Aeronautical Expenses
Salaries and Benefits (Operating & CIP)1,647,448$ 1,731,152$ 1,783,087$ 1,836,579$ 1,891,677$ 1,948,427$ 2,006,880$
Contract Services (ex-ACIP)374,333$ 270,900$ 279,027$ 287,398$ 296,020$ 304,900$ 314,047$
Supplies and Materials 52,842$ 76,472$ 78,766$ 81,129$ 83,563$ 86,070$ 88,652$
General Expenses 46,001$ 39,480$ 40,664$ 41,884$ 43,141$ 44,435$ 45,768$
Rents and Leases 670$ 6,630$ 6,829$ 7,034$ 7,245$ 7,462$ 7,686$
Direct and Indirect Charges 1,063,318$ 1,001,588$ 1,031,636$ 1,062,585$ 1,094,462$ 1,127,296$ 1,161,115$
Liability Insurance -$ -$ -$ -$ -$ -$ -$
TOTAL SALARY AND OPERATING EXPENDITURES 3,184,612$ 3,126,222$ 3,220,009$ 3,316,609$ 3,416,107$ 3,518,590$ 3,624,148$
Transfers Out
State DOT Loan Repayment -$ -$ -$ -$ -$ -$ -$
General Benefits Fund -$ -$ -$ -$ -$ -$ -$
Loan Repayment- General Fund 272,000$ 272,000$ 272,000$ 272,000$ 272,000$ 272,000$ 272,000$
Transfer to Technology Fund 1,500$ 1,500$ 1,500$ 1,500$ 1,500$ 1,500$ 1,500$
Transfer to Vehicle Fund -$ -$ -$ -$ -$ -$ -$
TOTAL TRANSFERS OUT 273,500$ 273,500$ 273,500$ 273,500$ 273,500$ 273,500$ 273,500$
TOTAL AIRPORT AERONAUTICAL EXPENSES 3,458,112$ 3,399,722$ 3,493,509$ 3,590,109$ 3,689,607$ 3,792,090$ 3,897,648$
TOTAL AIRPORT OPERATING PROFIT (204,927)$ (174,482)$ 35,038$ 44,294$ 53,828$ 63,648$ 73,762$
Airport Capital Improvement Fund - Ending Balance 1,361,010$ 1,186,528$ 1,221,566$ 1,265,860$ 1,319,687$ 1,383,335$ 1,457,097$
Reserve for Encumberances 241,595$ 581,046$ 581,046$ 581,046$ 581,046$ 581,046$ 581,046$
Unrestricted Fund Balance 1,119,415$ 605,482$ 640,520$ 684,814$ 738,641$ 802,289$ 876,051$
Item 3
Attachment A - PAO Rates and Charges Study
Item 3: Staff Report Pg. 22 Packet Pg. 187 of 207
Airport Capital Improvement Fund 2025 2025 2026 2027 2028 2029 2030
Airport Capital Improvement Fund - Revenues
Federal Grants (90% of Federal ACIP projects only)1,037,400$ 513,950$ 910,800$ 507,600$ -$ 5,694,300$
State Grants (0% of Federal ACIP and 0% of State Funded ACIP projects)-$ -$ -$ -$ -$ -$
TOTAL CAPITAL REVENUE 1,037,400$ 513,950$ 910,800$ 507,600$ -$ 5,694,300$
Airport Capital Improvement Fund - Expenses
TOTAL CAPITAL EXPENSES (See ACIP Below)10,016,000$ 1,118,000$ 541,000$ 1,012,000$ 564,000$ -$ 6,781,000$
Sponsor Participation of Capital Projects 1,351,950$ 80,600$ 27,050$ 101,200$ 56,400$ -$ 1,086,700$
Sponsor Participation of Uncompleted Projects 1,351,950$ 1,271,350$ 1,244,300$ 1,143,100$ 1,086,700$ 1,086,700$ -$
Percentage of Uncompleted Projects Funding in Reserve 83%48%51%60%68%74%
Airport Capital Improvement Projects (ACIP) - Federal FY 2025 - 2030 (Oct 1 - Sep 30)Future Value 2025 Est. Cost 2026 2027 2028 2029 2030 2031
2025 AWOS III (Construction)2,532,000$ 2,532,000$
2026 Master Plan (Environmental)780,000$ 750,000$ 780,000$
2027 Airfield Solar Array (Design)541,000$ 500,000$ 541,000$
2028 Runway and Taxiway Reconstruction and Drainage Improvements (Environmental) 1,012,000$ 900,000$ 1,012,000$
2026 Access Road Reconstruction (Design)312,000$ 300,000$ 312,000$
2029 Airfield Electrical Improvement (Design)564,000$ 482,000$ 564,000$
2031 Airfield Electrical Improvement (Construction) - Phase I 6,327,000$ 5,000,000$ 6,327,000$
Locally Funded Projects
2026 Airport Customer Parking Charging Stations (Design & Phase I)26,000$ 25,000$ 26,000$
2031 Airport Temporary Office Buildings 454,000$ 359,000$ 454,000$
Item 3
Attachment A - PAO Rates and Charges Study
Item 3: Staff Report Pg. 23 Packet Pg. 188 of 207
EXHIBIT C – 2023 RENT STUDY ANALYSIS
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 24 Packet Pg. 189 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
June 1st, 2023
Palo Alto Airport (PAO)
Rent Study Analysis
Long Beach, CA 90806
Phone: (562) 981-2659 | Fax: (562) 426-8236
Palo Alto Airport
Palo Alto, California
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 25 Packet Pg. 190 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
Mr. Andrew Swanson, C.A.E.
Airport Manager
250 Hamilton Ave
Palo Alto, CA 94301
RE: Airport Rates and Fees Analysis – Palo Alto (PAO)
Dear Mr. Swanson
The Aeroplex Group Partners LLC (AGP) is pleased to submit this report, a Rent Study Analysis for Palo
Alto Airport (PAO). Our report provides recommendations based on an analysis of those rates used at
comparable like airports, consistent with FAA Airport Compliance and Policy relative to rates and fees,
and as well accepted airport industry standards and best practices.
Palo Alto’s unique and diverse operations fleet mix provides opportunity for the airport sponsor to
maximize revenue with respect to aircraft hangar and land rates with the goal to make the Airport as
financially self-sustaining as possible. Evaluating the rates and fees structure for airport land on a regular
basis will best assure Palo Alto can meet its federal obligations and support fund generation that will
provide surplus funds for matching grant applications. AGP completed a survey of comparable rental
rates from a list of similar airports provided to us by PAO. The 10 comparable airports offer similar
physical and operational characteristics to Palo Alto. AGP has provided a recommendation on adjusting
the current rates, which we believe aligns Palo Alto with the FAA’s obligation to maintain financial self-
sustainability.
The Aeroplex Group Partners LLC is pleased to submit this report to Palo Alto Airport. We appreciate
the opportunity to conduct this work. We will remain available to answer any questions and provide
additional assistance.
Sincerely,
Justin Castagna
Justin Castagna, PMP, C.M.
Partner
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 26 Packet Pg. 191 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
Palo Alto Airport (PAO)
Airport Rent Study Analysis
I. BACKGROUND
a. Current Practices
II. ASSUMPTIONS
III. FEDERAL POLICY RELATED TO AIRPORT RATES AND FEES
a. Overview
b. Self-sustainability
c. Reasonable terms, without unjust discrimination
IV. STUDY FINDINGS
V. SUMMARY
VI. RECOMMENDATIONS
VII. CLOSING
VIII. RESOURCES
IX. APPENDIX
X. REFERENCES
Disclaimer: The information contained in this report is intended as a guide for the reader in better understanding the complexities,
policies, industry standards and airport leasing policies, rules, and procedures that apply to airports. It is not intended to replace any
necessary research and review of applicable law that may be required in a specific review of a particular case, nor is intended to give
legal advice or take the place of an attorney who can advise with respect to a particular situation. While every care is exercised in the
preparation of this report, AGP does not accept responsibility for an individual or entity’s reliance on its contents.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 27 Packet Pg. 192 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
BACKGROUND
Aeroplex Group Partners LLC (AGP) is pleased to submit this Airport Rent Study to the Palo Alto Airport
(PAO). This analysis includes a survey of the 10 comparable airports as noted above and the current
market rents for aircraft hangars, tie-downs, office, restaurant and improved land rates at PAO.
Consistent with FAA's Rates and Charges Policy for aeronautical rate setting, the most accurate and
effective methodology for establishing market rents for aeronautical property is through the assessment
of rental rates at similar and comparable airports, consistent with fair and reasonable rates and fees for
aeronautical property at airports. These airports were selected by flagging regional general aviation
service airports with a tower, non-Part 139 certificated, non-precision approaches, airports with +/- 300
based aircraft, +/- 2,000 feet difference from PAO’s longest runway, and within the state of California.
The 10 airports selected had at least four of the six characteristics in common with PAO.
Please note that market rents for off-airport, non-aeronautical properties were not utilized, as this
approach is problematic due to the different types of land use. The adjustment between off-airport,
non-aeronautical properties and on-airport, aeronautical properties would have to reflect the fact that
these land uses do not exhibit the same rights or restrictions. It is very difficult to determine the
adjustment applied to unencumbered off-airport, non-aeronautical rental rates to reflect the constraints
imposed by the Federal Aviation Administration (FAA), the Airport, and/or others pertaining to the
development and/or use of on-airport, aeronautical properties.
TABLE 1 – COMPARABLE AIRPORTS
Comparable Airports
Airport Code Location
San Carlos SQL San Carlos, CA
Fullerton Municipal FUL Fullerton, CA
Camarillo CMA Camarillo, CA
Watsonville Municipal WVI Watsonville, CA
Truckee Tahoe TRK Truckee, CA
McClellan-Palomar CRQ Carlsbad, CA
Santa Monica Municipal SMO Santa Monica, CA
Livermore LVK Livermore, CA
San Luis Obispo County SBP San Luis Obispo, CA
Sacramento Executive SAC Sacramento, CA
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 28 Packet Pg. 193 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
CURRENT PRACTICES AT PAO
Current PAO Rates
Hangar Type Rate
T-Hangar $0.85 - $0.88/sf
Box Hangar $0.85/sf
Executive/Corporate Hangar $0.78 - $1.11/sf
Tail-in Tie Down $196.00/mo
Taxi-in Tie Down $244.50/mo
Tie Down Rotorcraft $448.00/mo
Office $2.28 – $2.64
Restaurant $2.39/sf
Improved Land $0.74psf/yr
ASSUMPTIONS
It is noteworthy that the market rent opinions conveyed in this Rent Study Summary are based on the
lessee having full (unrestricted) and continued access /from the Subject Property) to PAO’s airside and
landside infrastructure. Additionally, it is important to note that the analysis was based on an evaluation
of triple net lease rates (wherein the lessee pays maintenance, utilities, insurance, and taxes associated
with the Subject Property).
Market rents are driven by the amount a willing buyer (lessee) pays to a willing seller (lessor). To the
extent that local economic and social factors affect rental rates at the national, regional, comparable,
and competitive airports, these economic factors will be rejected in the rental rate conclusions. To
derive the market rent opinions for the Subject Property, AGP has identified and analyzed (on a
comparative basis) the rents being charged and paid for similar properties (by component) at a cross-
section of airports that are considered most comparable to PAO.
AGP recognizes that there are differences between PAO and the comparable airports where there is no
identical comparison. Some of the comparable airports exhibit superior characteristics and some exhibit
inferior characteristics. In an effort to identify airports that were considered most comparable to PAO,
and to draw conclusions that reflect the conditions at PAO, the comparable airports were compared
using a number of aeronautical activity and infrastructure indicators.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 29 Packet Pg. 194 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
FEDERAL POLICY RELATED TO GENERAL AVIATION AIRPORT RATES AND FEES
FAA Airport Compliance Manual Order 5190.6B, chapter 18.2 requires all airports to adhere to policy
regarding airport rates and charges. “The Rates and Charges Policy provides comprehensive guidance on
the legal requirement that airport fees be fair, reasonable, and not unjustly discriminatory” (5190.6B,
18.2). Airport sponsors have the responsibility to establish a schedule of reasonable rental rates and
charges for the use of facilities and services and to periodically revise those charges to be comparable
with other airports having similar characteristics, facilities, and services.
The FAA encourages airports to incorporate the following objectives into their fee structures:
1.Requirement to Be Financially Self-Sustaining – Sponsors must maintain a fee and rental
structure, which based on the circumstances of that unique airport, makes the airport as
financially self-sustaining as possible.
2.Fair and Reasonable Fees – Unless otherwise agreed by aeronautical users, the airport
proprietor must allocate capital and operating costs among cost centers for those airfield
facilities and services directly used by the aeronautical users.
3.Equitable Treatment of Tenants and Users at Airport – To ensure that the revenues generated
by the tenants and users of the Airport will be consistent with the income potential of such
tenants and users at the Airport. In addition, fee structures should be reviewed, and possibly
revised, on a periodic basis with the goal of satisfying the reasonable expectation to maintain
competitive fee structures for the tenants and users of the Airport on an ongoing basis.
Ensuring that any airport tenants are subject to the same rates, fees, and charges as are
uniformly applicable to other tenants offering similar services or utilizing similar facilities at the
Airport will assist in alleviating the potential for claims of unjust discrimination.
4.Escalation Provision. FAA guidance provides that ground leases with terms of five (5) or more
years should contain an escalation provision for periodic adjustments based on a recognized
economic index. An annual escalation provision helps the sponsor comply with Grant Assurance
24, Fee and Rental Structure, which requires the sponsor to make the airport as self-sustaining
as possible under existing circumstances for a specific airport. Thus, given the financial and
competitive goal, it is reasonable that Airports apply such a standard for shorter lease terms less
than five (5) years.
The FAA policy provides that airport sponsors may use different mechanisms and methodologies to
establish fees for different facilities, and for different aeronautical users, e.g., air carriers and fixed-base
operators. The FAA will consider these differences if called upon to resolve a dispute over aeronautical
fees or otherwise consider whether an airport sponsor complies with its obligation to provide access on
fair and reasonable terms without unjust discrimination. The FAA typically will not investigate the
reasonableness of an airport's fees absent evidence of a progressive accumulation of surplus
aeronautical revenues.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 30 Packet Pg. 195 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
STUDY FINDINGS
The tables below contain the specified airports’ metrics including Hangars, Tie-Downs, Office space,
Restaurant and Improved Land. The three types of hangars studied are T-Hangar, Box Hangar, and
Executive/Corporate Hangar. Due to the nature of varying hangar dimensions, an average was taken by
dividing all monthly rates by hangar square footages. Similarly to hangars, three different tie-downs
were evaluated. The three different types of tie downs are tail-in, taxi-in and rotorcraft. Sufficient
information was gathered to compare rates for tail-in and taxi-in however not enough rates were
compiled for rotorcraft simply because the majority of airports do not offer specific tie downs for
rotorcraft. Similarly to hangars, tie-down rates also vary widely based on aircraft weight so rates listed in
the tables below were calculated based on aircraft weighing under 12,500lbs. Office and Restaurant
rates were taken directly from fee schedules provided on a monthly per square foot basis. Improved
Land is the only rate that is calculated on a per square foot per year basis.
The results of the study indicate that the average rental rate for T-Hangar is $1.15 psf/month and
average rental rate for Box Hangars is $0.94 psf/month, both being slightly higher than the current rates
at PAO. However the rate for Executive/Corporate Hangar is $1.02 psf/month, which is in line with the
current range at PAO. The average monthly rate for a tail-in tie down is $141.16 and $162.25 for a taxi in
tie down, respectively. Both rates are slightly lower than the current rates for tie downs at PAO. The
average rates for Office, Restaurant and Improved Land are as follows: Office $1.99 psf/month,
Restaurant $1.76 psf/month & Improved Land $0.59 psf/yr. These rates are significantly lower than
current rates at PAO. Based on AGP’s research, there is sufficient data to derive reasonable conclusions
of market rent for Palo Alto Airport. The selection of comparable market-based rental rates is based
upon the information analyzed by the AGP team, with consideration to the sizes (SF), utility, and age of
structures. It is important to note that for the three different types of hangar rates, we analyzed and
compared on a rate per square foot basis. Since each airport has their own unique hangar sizes, AGP
wanted to show comparable rates for the same structure, which is achieved by analyzing the specific
rate per square foot on the space.
T-Hangar Rates per SF
Box Hangar Rates per SF
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 31 Packet Pg. 196 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
Executive/Corporate Hangar Rates per SF
PAO Rate $0.78 - $1.11
Minimum Rate $.37
Maximum Rate $2.56
Average Rate $1.02
Tail-in Tie down Rates per Month
Taxi-in Tie down Rate per Month
PAO Rate $244.50
Minimum Rate $125.00
Maximum Rate $221.00
Mean Rate $162.25
Tie down Rotorcraft Rate per Month
Office Rate per SF
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 32 Packet Pg. 197 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
Restaurant Rate per SF
Land Rates psf/yr
SUMMARY
Based on the results of all ten (10) surveyed airports, Palo Alto’s Airport’s range of various hangar rates
are below the average rate of surveyed airports, with the exception of Executive/Corporate hangars. Tie
down rates for both tail-in and taxi-in are higher than the average rate on the tables above. As stated
previously, there is not enough data to derive an average rate for rotorcraft tie downs. Office,
Restaurant and the annual Improved Land rates are higher than the average rate of surveyed airports.
All these findings should be evaluated within PAO’s overall inventory of similar land and buildings, so to
evaluate how these rates and fees, uniformly applied, can be used to support PAO’s budget and self-
sustainability compliance goal, with revenues to provide for new investment.
CLOSING
Rates and fees for all general aviation users, regularly and consistently adjusted, will best support PAO in
meeting its required grant assurance obligations to keep itself financially healthy and sustainable. As
suggested by FAA policy, PAO should consult with aeronautical users and stakeholders well in advance, if
practical, of introducing significant changes in charging systems and procedures or in the level of
charges. PAO should also provide adequate information to explain to the aeronautical users the survey
data justification for the change, the overall airport’s budget, and assess the need and reasonableness of
any proposal to adjust PAO’s land rates. For consultations to be effective, PAO should give due regard to
the views of aeronautical users and to the effect of any proposed changes in fees. Likewise, aeronautical
users should also consider the financial needs of PAO itself so that it remains a viable enterprise.
Understanding that consistent rate setting process will ensure that PAO remains self-sufficient, thereby
best eliminating any risk in requiring support from the Airport Sponsor’s general fund.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 33 Packet Pg. 198 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
RESOURCES
The ideas and concepts presented in this report are intended to be consistent with FAA Airport
Compliance Policy and industry standards and recommendations, combining all of this information in an
effort to assist Palo Alto Airport with best airport management practices available. These ideas and
concepts are consistent with information from the Airport Cooperative Research Program (ACRP), which
is funded by the FAA, whose information provides excellent resources and ideas. The ACRP carries out
applied research on problems that are shared by airport operating agencies on a variety of airport
subject areas. The primary participants in the ACRP are an independent governing board appointed by
the Secretary of the U.S. Department of Transportation, with representation from airport operating
agencies, other stakeholder, and relevant industry organizations.
APPENDIX
A. Definitions
Improved Land – Airport land having access (airside and landside) and utilities to the
property boundary
Market Rent – The rent a property (land or improvement) will most likely command in
the open market
Minimum – Minimum value present in the data range
Maximum – Maximum value present in the data range
Average – Arithmetic average of all data in the data range
B. Limiting Conditions
This report is subject to the following conditions and to other specific and limiting conditions as
described by Aeroplex Group Partners (AGP) in this report.
1. AGP assumes no responsibility for matters legal in nature affecting the Subject Property, nor
does AGP render any opinion as to the title of the Subject Property, which are assumed to be
good and marketable. The Subject Property have been analyzed as though free and clear and
held under responsible ownership and competent management.
2. Information, estimates, and opinions furnished to AGP and contained in this report were
obtained from sources considered to be reliable and are believed to be true and correct.
However. AGP assumes no responsibility for their accuracy.
3. Although parcel dimensions were taken from a source considered reliable, this should not be
construed as n land survey. A licensed engineer or land surveyor should verily the exact land
size.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 34 Packet Pg. 199 of 207
11
www.aeroplex.net
Development Consulting Management
Palo Alto Airport (PAO)
Airport Rent Study Analysis
4.Unless noted in this report the rental rate conclusions do not include contributory value of any
personal property, furniture, fixtures, equipment, or on-going business value.
5.It is assumed that the utilization of the land is within the boundaries or property lines of the
Subject Property and there is no encroachment or trespass unless noted in this report.
6.This report is prepared for the sole, exclusive use of the client. No third parties are authorized to
rely on this report without the prior written consent of AGP and the client.
7.It is assumed that all applicable zoning and use regulations have been complied with unless non-
conformity was stated, defined, and considered in this report.
8.It is assumed that all required licenses, certificates of occupancy, consents or other legislative or
administrative authority from any local, state, or federal government or private entity or
organization have been or can be obtained or renewed for any use on which the rental rate
conclusions are based.
9.Full compliance with all applicable federal, state, and local environmental regulators and laws is
assumed unless noncompliance is stated, defined, and considered in this report.
10.In this assignment, the existence of potentially hazardous material, gases, toxic waste, and
mold, which may or may not be present on the Subject Property, nor does AGP have any
knowledge of the existence of such materials on the Subject Property. To AGP’s knowledge, the
presence of potentially hazardous waste, materials, or gases has not been detected, or if
detected, it has been determined that the amount or level is considered to be safe according to
standards established by the Environmental Protection Agency (EPA}. However, AGP is not
qualified to detect such substances and does not make any guarantees or warranties that the
Subject Property have been tested for the presence of potentially hazardous waste, gases, toxic
waste, or mold and, if tested, that the tests were conducted pursuant to EPA-approved
procedures. The existence of any potentially hazardous waste, gases, toxic waste, or mold may
have an effect on the rental rate conclusions.
11.The American with Disabilities Act (ADA) became effective January 26, 1992. AGP has not made
a specific compliance survey and analysis of the Subject Property to determine whether or not
the Subject Property are in conformity with the various detailed analysis of the requirements of
the ADA. It is possible that a compliance survey of the Subject Property together with a detailed
analysis of the requirements of the ADA could reveal that the Subject Property are not in
compliance with one or more of the requirements of the ADA. If so, this this fact could have a
negative impact on the market rent conclusion. Since AGP has no direct evidence relating to this
issue, possible noncompliance with the requirements of the ADA was not considered in the
rental rate conclusions.
12.AGP assumes there are no hidden or unapparent conditions of the Subject Property or subsoil
that would render the Subject Property more or less valuable. AGP assumes no responsibility for
such conditions or for engineering that might be required to discover such facts.
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 35 Packet Pg. 200 of 207
www.aeroplex.net
Development Consulting Management
Airport Rent Study Analysis
13. No requirements shall be made of AGP to give testimony or appear in court by reason of this
report unless arrangements have been made previously. If any courtroom or administrative
testimony is required in connection with this report, additional fees and expenses shall be
charged for those services.
14. Possession of this report, or copy hereof, does not carry with it the right of publication nor may
it be used for any purpose whatsoever by any entity but the client without the prior written
consent of AGP and the client.
15. Neither all nor any part of the contents of this report shall be disseminated to the public
through advertising media or public means of communication without the prior written consent
of AGP and the client.
REFERENCES
FAA Airport Compliance webpage: www.faa.gov/airports/airport_compliance/
FAA Order 5190.6B: Airport Compliance Requirements
Policy Regarding Airport Rates and Fees (Federal Register Volume 78- Sept 2013)
https://www.federalregister.gov/documents/2013/09/10/2013-21905/policy-regarding-airport-
rates-and-charges
Notice of Amendment to Policy Regarding Airport Rates and Charges: July 2008
Final Policy Regarding Airport Rates and Charges: June 1996
https://www.gpo.gov/fdsys/pkg/FR-1996-06-21/pdf/96-15687.pdf
AIRPORT COOPERATIVE RESEARCH PROGRAM (ACRP)
Report 23 - Guidebook for compliance with grant agreement obligations to provide reasonable Access to
An AIP funded public use general aviation airport
REPORT 16 -Guidebook for Managing Small Airports
REPORT 36 -Airport/Airline Agreements- Practices and Characteristics
REPORT 47 -Guidebook for Developing and Leasing Airport Property
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 36 Packet Pg. 201 of 207
13
www.aeroplex.net
Development Consulting Management
Palo Alto Airport (PAO)
Airport Rent Study Analysis
Exhibit A
Airport Rent Study Analysis
—Attached—
Item 3
Attachment A - PAO Rates
and Charges Study
Item 3: Staff Report Pg. 37 Packet Pg. 202 of 207
Airport / Location
Airport
Code T-Hangar Box Hangar
Executive /
Corporate
Hangar
Tail-in Tie -
Down
Taxi-in Tie -
Down
Tie - Down
Rotorcraft Office Restaurant
Improved Land
Rate / SF per
Year
San Carlos Airport San
Carlos, CA SQL $1.55 N/A $1.45 $153.00 $221.00 $221.00 $2.20 - $2.50 $4.14 $0.42
Fullerton Municipal
Fullerton, CA FUL $1.93 $1.93 $2.23 $150.00 N/A N/A N/A $0.75 N/A
Camarillo Airport
Camarillo, CA CMA $0.54 $0.40 $0.40 $112.00 $153.00 N/A $0.50 $1.02 $0.98
Watsonville Muni
Watsonville, Ca WVI $0.38 $0.44 $0.56 $100.00 $125.00 N/A N/A $1.15 N/A
Truckee Tahoe Airport
Truckee, CA TRK $0.45 $0.55 $0.55 $300.00 N/A N/A $1.10 $1.19 N/A
McClellan-Palomar
Ramona, CA CRQ N/A N/A N/A $185.00 N/A N/A N/A $0.76 $0.82
Santa Monica Airport
Santa Monica, CA SMO $2.24 $2.56 $2.56 N/A N/A N/A $3.38 N/A N/A
Livermore Airport
Livermore, CA LVK $0.45 $0.40 $0.53 $126.00 N/A N/A $0.78 $1.16 $0.35
San Luis Obispo County
San Luis Obispo, CA SBP $2.24 $0.29 $0.53 $73.33 $150.00 N/A $4.87 $4.87 $0.50
Sacramento Executive
Sacramento, CA SAC $0.54 N/A $0.37 $71.14 N/A N/A $1.31 $0.84 $0.48
Min $0.38 $0.29 $0.37 $71.14 $125.00 $0.50 $0.75 $0.35
Max $2.24 $2.56 $2.56 $300.00 $221.00 $4.87 $4.87 $0.98
Average $1.15 $0.94 $1.02 $141.16 $162.25 $221.00 $1.99 $1.76 $0.59
Palo Alto Airport Palo
Alto, CA PAO $0.85 - $0.88 $0.85 $0.78 - $1.11 $196.00 $244.50 $448.00 $2.28 - $2.64 $2.39 $0.74
Aeroplex Group Partners
3333 E. Spring Street │ Suite 204 │ Long Beach │ Ca │
90806
Tel: (562) 981 - 2659 Fax: (562) 426 -8236
www.aeroplex.net
Subject
Summary of Airport Comparables
Item 3
Attachment A - PAO Rates and Charges
Study
Item 3: Staff Report Pg. 38 Packet Pg. 203 of 207
Page 1
Resolution No.
Resolution of the City Council of the City of Palo Alto Approving the Fiscal Year 2027 Schedule of
Airport Rates and Charges, Accepting the Palo Alto Airport Rates and Charges Study, and
Authorizing Annual Adjustments Based on the Airport Benchmark Index
R E C I T A L S
A. The City of Palo Alto (“the City”) owns and operates the Palo Alto Airport as an
enterprise fund is strives to be as self sustaining as possible through the collection of rates and
charges that are fair, reasonable, and not unjustly discriminatory.
B. The City periodically reviews airport rates and charges to ensure alignment with the
cost of providing airport facilities and services, industry best practices and applicable Federal
Aviation Administration (FAA) guidance.
C. The City retained a qualified consultant to prepare the Palo Alto Airport Rates and
Charges Study (“Study”), which evaluates the Airport’s financial condition, cost recovery, peer
airport comparisons, and rate-setting methodology
D. The Study provides a comprehensive financial framework and recommends updates
to the Airport’s rate structure to promote long-term financial sustainability, transparency, and
equity among users.
E. The Study includes the development of an Airport Benchmark Index (ABI) to allow
for predictable, modest, and data-driven annual adjustments to airport fees and charges.
F. This proposed Fiscal Year 2027 Schedule of Airport Rates and Charges is consistent
with the methodology and recommendations contained in the Study.
NOW, THEREFORE, the Council of the City of Palo Alto does hereby RESOLVE, as follows:
SECTION 1. The Fiscal Year 2027 Schedule of Airport Rates and Charges, attached hereto
as Exhibit A and incorporated by reference, is hereby approved.
SECTION 2. The Palo Alto Airport Rates and Charges Study is hereby accepted.
SECTION 3. The Public Works Director or designee is hereby authorized to implement
annual adjustments to Airport fees and charges based on the Airport Benchmark Index (ABI), as
described in the Study.
SECTION 4. The Council finds that the adoption of this resolution does not constitute a
‘project’ under Section 21065 of the California Public Resources Code and Sections 15378(b)(4) and
9b)(5) of the California Environmental Quality Act (CEQA) and the CEQA Guidelines, and therefore,
no environmental assessment is required.
INTRODUCED AND PASSED:
Item 3
Attachment B - Resolution
PAO Rates and Charges
Adjustment
Item 3: Staff Report Pg. 39 Packet Pg. 204 of 207
Page 2
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ____________________________
Chief Assistant City Attorney City Manager
____________________________
Director of Public Works
Item 3
Attachment B - Resolution
PAO Rates and Charges
Adjustment
Item 3: Staff Report Pg. 40 Packet Pg. 205 of 207
214.50$
248.50$
279.50$
313.50$
267.50$
332.50$
461.50$
489.50$
Large aircraft and helicopter designated tie-downs (monthly)489.50$
0 to 3,500 pounds 14.50$
3501 to 5,200 pounds 16.50$
5201 to to 17,000 pounds 31.00$
Transient Aircraft Late Fee
within 30 days 26.00$
Per Month 197.50$
21.00$
104.00$
57.00$
Aircraft Late Fee)52.00$
Per Card 32.00$
Per Day 31.00$
Per Month 156.00$
Per Fire Extinguisher 227.00$
Per Quart 1.50$
Section C. Other Charges
Monthly Automobile Parking (Parking spots only rented in
association with a Tie-Down account
Section B. City Non-Based Aircraft*
Palo Alto Airport Schedule of Fees and Charges
Fiscal year 2027 (July 1, 2026 - June 30, 2027
Section A. City-Based Aircraft
On each July first of every year, all rates in Section A. "Based Aircraft", Section B. "Non-Based Aircraft" and Section C. "Other
Charges" for the ensuring twelve (12) months shall be adjusted according to the Airport Benchmark Index calculated at 2/3rd
the City of Palo Alto's General Rate Increase (GRI) and 1/3rd the Consumer Price Index (CPI) for the San Francisco-Oakland-San
Jose area of the United States Department of Labor, Bureau of Labor Statistices. In the case of an ABI decrease the rates will
remain the same. All fees are rounded to the nearest fifty cents ($.50)
Item 3
Attachment B - Resolution
PAO Rates and Charges
Adjustment
Item 3: Staff Report Pg. 41 Packet Pg. 206 of 207
Aircraft Storage Late Fee Per Month 45.00$
Business Operator Late Fee Per Month 10% of amount due
Hangar Sublease Fee Per Month per additional aircraft 25.00$
Non-Operational Aircraft Storage Fee Per Month 1.75x monthly storage fee
Fuel Flowage Fee for Palo Alto Airport Per Gallong 0.25$
Self-Fueling Permit Flowage Fee:
Individual aircraft owner/operator Annual Fee Per Aircraft 84.00$
Aircraft owned or operated by a Flying Club Annual Fee Per Aircraft 731.00$
Per Year 134.50$
Operators who sublease to, or offer a
part of their services, car rental services,
shall pay a monthly fee based on the
gross receipts received from car rentals.
10 % gross reciepts
Commercial Agreement Transmittal Fee Per Agreement 1,124.00$
Hangar Ground Lease Origination / Transfer Fee Per Agreement 2% of sale or assessed value
Expired Certificate of Insurance Fee Per Month 50.00$
Transportation Network Company Operations)
Section D. Other Charges (not subject to annual ABI adjustment)
*Aircraft not currently based in a hangar or tie-down at the Palo Alto Airport is considered a transient aircraft. Non-revenue
generating transient charter aviation activities conducted in direct support of a recognized missions are exempt from landing
fees and the first 24 hours of transient parking; this exemption does not apply to flight training, instructional, or other ongoing
aviation services.
Item 3
Attachment B - Resolution
PAO Rates and Charges
Adjustment
Item 3: Staff Report Pg. 42 Packet Pg. 207 of 207