HomeMy WebLinkAbout2025-11-05 Utilities Advisory Commission Agenda PacketUTILITIES ADVISORY COMMISSION
Regular Meeting
Wednesday, November 05, 2025
Council Chambers & Hybrid
6:00 PM
Utilities Advisory Commission meetings will be held as “hybrid” meetings with the option to
attend by teleconference/video conference or in person. To maximize public safety while still
maintaining transparency and public access, members of the public can choose to participate
from home or attend in person. Information on how the public may observe and participate in
the meeting is located at the end of the agenda. Masks are strongly encouraged if attending in
person. 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/96691297246 )
Meeting ID: 966 9129 7246 Phone: 1(669)900-6833
PUBLIC COMMENTS
Public comments will be accepted both in person and via Zoom for up to three minutes or an
amount of time determined by the Chair. All requests to speak will be taken until 5 minutes
after the staff’s presentation. Written public comments can be submitted in advance to
UAC@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.
PowerPoints, videos, or other media to be presented during public comment are accepted only
by email to UAC@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 type 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.
TIME ESTIMATES
Listed times are estimates only and are subject to change at any time, including while the
meeting is in progress. The Commission reserves the right to use more or less time on any item,
to change the order of items and/or to continue items to another meeting. Particular items may
be heard before or after the time estimated on the agenda. This may occur in order to best
manage the time at a meeting to adapt to the participation of the public, or for any other
reason intended to facilitate the meeting.
1 Regular Meeting November 05, 2025
Materials related to an item on this agenda submitted to the Board after distribution of the agenda packet are available for
public inspection at www.paloalto.gov/agendas
CALL TO ORDER 6:00 PM – 6:05 PM
AGENDA CHANGES, ADDITIONS AND DELETIONS 6:05 PM – 6:10 PM
The Chair or Board majority may modify the agenda order to improve meeting management.
PUBLIC COMMENT 6:10 PM – 6:25 PM
Members of the public may speak to any item NOT on the agenda.
APPROVAL OF MINUTES 6:25 PM – 6:35 PM
1.Approval of the Minutes of the Utilities Advisory Commission Meeting Held on
September 3, 2025
2.Approval of the Minutes of the Utilities Advisory Commission Meeting Held on October
1, 2025
UTILITIES DIRECTOR REPORT 6:35 PM – 6:50 PM
NEW BUSINESS
3.Recommendation to Approve the Draft 2026 Utilities Legislative Policy Guidelines Update
and to Receive the Update on 2025 State and Federal Legislative and Regulatory Activity.
CEQA Status: Not a Project. (ACTION 6:50 PM – 7:00 PM) Staff: Lena Perkins
4.Staff Recommends the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution Approving the 2026 Natural Gas Cost of Service Analysis Report,
Amending Rate Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered
and Commercial Gas Service), G-3 (Large Commercial Gas Service) and repealing G-10
(Compressed Natural Gas Service).
5.Discussion and Update on the Fiscal Year 2027 Preliminary Utilities Financial Forecast and
Rate Projections (DISCUSSION 7:20 PM – 8:50 PM) Staff: Lisa Bilir
FUTURE TOPICS FOR UPCOMING MEETINGS
COMMISSIONER COMMENTS AND REPORTS FROM MEETINGS/EVENTS
ADJOURNMENT
2 Regular Meeting November 05, 2025
Materials related to an item on this agenda submitted to the Board after distribution of the agenda packet are available for
public inspection at www.paloalto.gov/agendas
SUPPLEMENTAL INFORMATION
The materials below are provided for informational purposes, not for action or discussion during UAC Meetings (Govt. Code
Section 54954.2(a)(3)).
INFORMATIONAL REPORTS
12-Month Rolling Calendar
Public Letter(s) to the UAC
3 Regular Meeting November 05, 2025
Materials related to an item on this agenda submitted to the Board 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 UAC@PaloAlto.gov.
2.Spoken public comments using a computer 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.
◦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.
3.Spoken public comments using a smart phone will be accepted through the
teleconference meeting. To address the Council, download the Zoom application onto
your phone from the Apple App Store or Google Play Store and enter the Meeting ID
below. Please follow the instructions B-E above.
4.Spoken public comments 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: 966 9129 7246 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.
4 Regular Meeting November 05, 2025
Materials related to an item on this agenda submitted to the Board after distribution of the agenda packet are available for
public inspection at www.paloalto.gov/agendas
Item No. 1. Page 1 of 1
Utilities Advisory Commission
Staff Report
From: Alan Kurotori, Director Utilities
Lead Department: Utilities
Meeting Date: November 5, 2025
Report #: 2510-5347
TITLE
Approval of the Minutes of the Utilities Advisory Commission Meeting Held on September 3,
2025
RECOMMENDATION
Staff recommends that the Utilities Advisory Commission review and approve September 3,
2025 minutes.
Commissioner ______ moved to approve the draft minutes of the September 3, 2025 meeting
as submitted/amended.
Commissioner _____ seconded the motion
ATTACHMENTS
Attachment A: September 3, 2025 Draft Minutes
AUTHOR/TITLE:
Alan Kurotori, Director of Utilities
Staff: Kaylee Burton, Utilities Administrative Assistant
Item #1
Packet Pg. 5
Utilities Advisory Commission Minutes Approved on: Page 1 of 13
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF SEPTEMBER 3, 2025 REGULAR MEETING
CALL TO ORDER
Commissioner Phillips called the meeting of the Utilities Advisory Commission (UAC) to order at
6:00 p.m.
Present: Vice Chair Mauter (Remote), Commissioners Croft, Gupta, Metz, and Phillips
Absent: Chair Scharff and Commissioner Tucher
AGENDA REVIEW AND REVISIONS
None
ORAL COMMUNICATIONS
None
APPROVAL OF THE MINUTES
ITEM 1: ACTION: Approval of the Minutes of the Utilities Advisory Commission Meeting Held on
July 9, 2025
ACTION: Commissioner Gupta moved to approve the draft minutes of the July 9, 2025 meeting
as submitted.
Commissioner Metz seconded the motion.
Commissioner Metz thanked staff for appending his comments on Item 5 related to reliability
and resilience studies. Commissioner Phillips inquired if Commissioner Metz’s comments were
considered part of the minutes or an addition. Kaylee Burton, Utilities Administrative Assistant,
explained that Commissioner Metz’s comments were an addition to the minutes as a
supporting document.
The motion carried 5-0 with Vice Chair Mauter, and Commissioners Croft, Gupta, Metz, and
Phillips voting yes.
Item #1
Packet Pg. 6
Utilities Advisory Commission Minutes Approved on: Page 2 of 13
UTILITIES DIRECTOR REPORT
Alan Kurotori, Utilities Director, delivered the Director's Report.
On August 11, 2025, the City Council approved the amended water supply agreement with the
City and County of San Francisco. Staff brought to Council a rate change update due to a clerical
error in the rate schedule effective September 1, 2025. The change did not negatively impact
customers but was estimated to impact revenues by about $25,800 for rates associated with
the net surplus energy compensation package related to solar.
The Northern California Power Agency’s legislative tour included Santa Clara and Palo Alto. In
August, 30 federal and state legislative staff visited Rivian’s headquarters and stayed overnight
in Palo Alto. The Mayor and Vice Mayor spoke to the delegation. One topic of discussion was
Palo Alto’s public-private partnership with Tesla to pay a share of the Hanover Substation
upgrades.
There has been outreach to customers in the foothill areas susceptible to public safety power
shut-offs. Undergrounding of all lines serving the foothills in the city limits west of Highway 280
will be completed by the end of 2025. Because of supply chain issues, the pole-mounted
voltage regulator will be exchanged in early April but the rest of the lines will be de-energized.
Mr. Kurotori read a comment from the Palo Alto Unified School District (PAUSD) expressing
their appreciation to City staff. PAUSD commended the electric utility team for their
commitment and hard work that enabled the completion of updates to 9 school campuses prior
to the beginning of the schoolyear.
Social media was being used to notify customers of residential electrification rebates, and that
federal tax incentives will be ending at the end of this calendar year. As of September 1, the
Utility has approved 76 rebates and applications totaling $280,000 in reserves for Heat Pump
Water Heaters. The Utility’s website has information on rebates between $3500 to $7000,
depending on income and if the panel and circuits are upgraded. Customers can get tax breaks,
rebates from Palo Alto Utilities, and the State’s Tech Clean incentives when using those
contractors. Mr. Kurotori mentioned that some staff will be redeployed to work with CPAU
customers and their contractors to get their projects moving forward during this great
opportunity to electrify their home.
A full update on fiber to the premises will be presented at the October UAC meeting. The fiber
hut permit was approved. The secured perimeter of that substation will be expanded to include
the fiber hut.
One of the challenges with AMI was having a strong enough signal to read all the meters
remotely, so a new advanced metering infrastructure base station was put on the rooftop of
City Hall. The AMI conversion was about 90 percent complete with over 66,000 meters
currently on AMI. With the new base station, the conversion rate was anticipated to increase to
95 percent with an additional 4000 meters by the end of 2025. Due to a combination of age,
Item #1
Packet Pg. 7
Utilities Advisory Commission Minutes Approved on: Page 3 of 13
condition, difficult location, and having to coordinate with customers, the remaining 5 percent
of meters will be converted to AMI in 2026. A CPAU staff member posted a YouTube Shorts
video for anyone interested in the new base station and how it was installed.
NEW BUSINESS
ITEM 2: Discussion of Gas Utility Transition Study Scoping; CEQA Status – Not a Project
Item #1
Packet Pg. 8
Utilities Advisory Commission Minutes Approved on: Page 4 of 13
decline enough to enable staff attrition; therefore, the per-unit gas utility cost will increase for
remaining customers.
Item #1
Packet Pg. 9
Utilities Advisory Commission Minutes Approved on: Page 5 of 13
the importance of having a firm understanding of the legal risks. It was helpful to understand
the need for incentives versus unilateral decisions by the City and Utility. The opportunity for
avoided infrastructure could help to fund an incentive.
Item #1
Packet Pg. 10
Utilities Advisory Commission Minutes Approved on: Page 6 of 13
Commissioner Gupta asked the following questions. What progress has been made toward
meeting the goal of 44 percent reduction in single-family residential gas use by 2025 mentioned
in a table of electrification scenarios on Page 4 of the 2021 report? Do we capture and use data
to see how it might help with costs or is the data sample too small? Will the study provide
mapping to depict what blocks might be best to begin electrifying; perhaps color coding the
priorities with red, yellow, and green? Is it possible to model the holdout problem? Can we
model cost with a sensitivity analysis of 10, 20, 30 percent customers per block refusing
transition? There may be a natural disincentive for holdouts because the cost allocation will be
greater for the remaining customers as more folks disconnect from the gas system, which
should lead to more customers wanting to disconnect. When studies are presented to the
Commission and Council, Commissioner Gupta wanted to see an assessment of the social cost
or cost avoidance. For example, the EPA estimate of the social cost of carbon is $190 per ton of
carbon dioxide emissions. Based on the 2021 report numbers, Commissioner Gupta estimated
that electrifying all single-family homes would avoid 9 million therms, which could represent $9
to $11 million per year in avoided social damages. Can the current study’s output metrics
include miles of main retired per year, overall cost reductions in maintenance costs, and climate
cost avoided?
Commissioner Gupta noted Table 4 on Page 8 of the 2021 analysis projected a 17 percent
system average rate increase in FY 2025 with a mid-transition bulge, which disproportionately
impacted multifamily homes and small businesses. Can the rate impact be modeled by
customer class and income level under a few different rate designs to address equity concerns?
What is the relationship between this study and our electrification goals, and how does it relate
to grid modernization? The 2020 study estimated $30 million to $75 million of electric grid
upgrades needed for electrification of single-family residents because several transformers
were overcapacity. Will this study inform the approach on grid modernization? Is the core gas
network defined as the 86-mile skeletal system modeled in the 2020 report? Does this study
relate to Palo Alto’s approaches on building codes and its effect on the City’s electrification
goals? For example, even if there are gas appliances, require new constructions or remodels to
place 220 volt outlets behind the stove and dryer or for an EV charger. Has staff looked at
PG&E’s Gas Asset Analysis tool to see what information was used to build that tool? Ithaca,
New York has a Green New Deal initiative aiming for 100 percent electrification. Commissioner
Gupta offered to email a list of studies to staff.
Mr. Abendschein addressed Commissioner Gupta’s questions. The scenarios on Page 4 of the
2021 report arrived at 44 percent by taking a straight-line approach from 2021 to 2030. The
2021 report was completed before S/CAP developed climate goals. As climate goals were
developed, it was understood that instead of a straight line it would be an S-curve with not
many early adopters, followed by significant acceleration, and then people at the end who will
not get off gas without a big push. Mr. Abendschein did not have the number of current
residential gas users with him but recalled 3 percent of homes had no gas, and 6 percent
verified but as many as 10 percent have at least 1 major all-electric appliance, which was a
significant improvement from the 2020 study where 168 homes had no gas. Mr. Abendschein
Item #1
Packet Pg. 11
Utilities Advisory Commission Minutes Approved on: Page 7 of 13
thought the data was not statistically significant yet but was helpful to validate the models in
the gas transition study and to provide a base level of information for analyses on the electric
side. Knowing the location of all-electric homes in addition to the AMI data for those homes will
help with the electric utility’s capacity planning.
Item #1
Packet Pg. 12
Utilities Advisory Commission Minutes Approved on: Page 8 of 13
Commissioner Phillips was supportive of the scope of this study but had the following concerns
and questions. Imposing increased costs on a smaller set of people will result in a tremendous
burden and at some point becomes unviable. Palo Alto was the smallest gas utility in California
at 24,000 customers, with the next largest being the City of Long Beach with 500,000
customers. What decisions have to be made and what are the options? Is it technically and
economically feasible to have a gas utility with 15,000 customers spread across Palo Alto’s
geography or will it require an infusion from the General Fund or other sources of funds?
Commissioner Phillips was very concerned about the social justice aspect because the people
impacted cannot afford to transition. Is there was a way to combine with PG&E to avoid having
a tiny group of customers bear the City’s fixed cost for gas? Has anybody else gone from the
scale of Palo Alto’s gas utility to 20 percent or 40 percent over a 5 or 10-year period, and what
was their experience?
Mr. Abendschein stated the preliminary results of the S/CAP funding study showed
electrification was a net benefit for the community overall, which included the loss of gas utility
revenue but did not include distribution cost savings within the gas utility. There will be savings
from not buying gas commodity from outside the city. Around 60 percent of costs are variable
in the gas utility. The gas transition study will assess the scale of the impact from massively
declining gas sales. Staff expected that outside funds and a plan was needed on how to handle
the cost of abandonment, especially when it starts getting to the tail end. Broader discussion
and a policy decision were needed on which groups or if all groups within the community will
we hold gas rates steady and for what purposes. The legal and financial dimensions needed to
be considered. Early indications from the S/CAP funding study were that there were available
resources and potential solutions. Mr. Abendschein did not have examples of shutting down a
gas utility but shutting down other utilities and large infrastructure could be looked at as
models of a stream of revenue that dried up at a certain point, such as landfill closings and
decommissioning nuclear power.
Commissioner Phillips said that decommissioning a nuclear reactor was part of a much broader
utility system, and every nuclear decommissioning he saw had underestimated costs often by a
factor of 2. Commissioner Phillips was concerned about underestimations with regard to gas.
Commissioner Phillips offered to talk offline with Mr. Abendschein about other approaches.
Mr. Abendschein mentioned that the work plan and S/CAP funding study will include funding
sources. There will be sensitivities around the cost estimates.
Mr. Kurotori commented that the City was making investments and maintaining the gas system
in accordance with all state and federal requirements. The recent CPUC audit of our system was
clean. The gas transition study will provide options and alternatives as well as awareness of
potential pitfalls.
ACTION: No Action
Item #1
Packet Pg. 13
Utilities Advisory Commission Minutes Approved on: Page 9 of 13
ITEM 3: Recommend that the City Council Approve Amendment No. 1 to the Memorandum of
Agreement Between California Alternative Energy and Advanced Transportation Financing
Authority and City of Palo Alto to Extend the Term of the Agreement from Two Years to Five
Years and Continue Offering the GoGreen Home Energy Financing Program for Palo Alto
Residents
Item #1
Packet Pg. 14
Utilities Advisory Commission Minutes Approved on: Page 10 of 13
Mr. Swaminathan replied there were about 100 contractors serving Santa Clara County.
ACTION: Commissioner Metz motioned to recommend that the City Council approve
Amendment No. 1 to the Memorandum of Agreement between the California Alternative
Energy and Advanced Transportation Financing Authority and the City of Palo Alto to extend
the term of the agreement from 2 years to 5 years, and continue offering the GoGreen Home
Energy Financing Program for Palo Alto residents.
FUTURE TOPICS FOR UPCOMING MEETINGS ON October 1, 2025 AND REVIEW OF THE 12-
MONTH ROLLING CALENDAR
Item #1
Packet Pg. 15
Utilities Advisory Commission Minutes Approved on: Page 11 of 13
November. A fellow working for the City was developing a white paper on data centers, and it
will be scheduled as soon as staff is available to review it. The City had a strong process in
working with businesses to make sure they pay their fair share of the capacity increases
necessary to serve their needs. For example, Tesla funded a lot of the Hanover substation
improvements and Tesla partnered with the City on the improvements to the distribution
substation serving all customers. The Tesla contract included protections on their ramp rate
and use to insulate customers from potential revenue loss or stranded assets. The grid
modernization strategy will be scheduled as soon as possible but included looking at our
distribution system serving our residential customers, analyzing our 60 kV subtransmission
system and capacity needs, substations, the useful life of existing transformers and breakers
and standardizing them, and how we can do distribution ties to increase reliability and
resiliency.
COMMISSIONER COMMENTS and REPORTS from MEETINGS/EVENTS
Item #1
Packet Pg. 16
Utilities Advisory Commission Minutes Approved on: Page 12 of 13
discussion. Commissioner Phillips wondered if there was a better process to keep the UAC
informed, and to make sure the Finance Committee and City Council had full advantage of the
UAC’s recommendations and consultations.
Item #1
Packet Pg. 17
Utilities Advisory Commission Minutes Approved on: Page 13 of 13
Commissioner Gupta attended the MSC Open House and reported it was a wonderful and
educational event, and highly recommended attending it next year. The MSC Open House
offered rides on a line truck and there was free soft serve ice cream. Commissioner Gupta
learned about our stormwater management and saw it visually in a model display.
Commissioner Phillips did not attend this year’s MSC Open House but attended the 2 previous
years and agreed it was a great event.
ADJOURNMENT
Commissioner Metz moved to adjourn.
Vice Chair Mauter seconded the motion.
The motion carried 5-0 with Vice Chair Mauter, Commissioners Croft, Gupta, Metz, and Phillips
voting yes.
Meeting adjourned at 7:55 p.m.
Item #1
Packet Pg. 18
Item No. 2. Page 1 of 1
Utilities Advisory Commission
Staff Report
From: Alan Kurotori, Director Utilities
Lead Department: Utilities
Meeting Date: November 5, 2025
Report #: 2510-5354
TITLE
Approval of the Minutes of the Utilities Advisory Commission Meeting Held on October 1, 2025
RECOMMENDATION
Staff recommends that the Utilities Advisory Commission review and approve October 1, 2025
minutes.
Commissioner ______ moved to approve the draft minutes of the October 1, 2025 meeting as
submitted/amended.
Commissioner _____ seconded the motion
ATTACHMENTS
Attachment A: October 1, 2025 Draft Minutes
AUTHOR/TITLE:
Alan Kurotori, Utilities Director
Staff: Rachael Romero, Administrative Associate II
Item #2
Packet Pg. 19
Utilities Advisory Commission Minutes Approved on: Page 1 of 17
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF OCTOBER 1, 2025 REGULAR MEETING
CALL TO ORDER
Chair Scharff called the meeting of the Utilities Advisory Commission (UAC) to order at 6:05
p.m.
Present: Chair Scharff, Vice Chair Mauter, and Commissioners Phillips and Tucher
Absent: Commissioners Croft, Gupta, and Metz
AGENDA REVIEW AND REVISIONS
Alan Kurotori, Utilities Director, made the Commission aware that Agenda Item 4 was modified
from a discussion to an action item.
ORAL COMMUNICATIONS
1. Sven Thesen was a chemical engineer with experience in air quality and electric car
policy. In the last 3 years, it was discovered that natural gas stoves produce benzene and
nitrous oxides, which are known carcinogens and can lead to asthma. With closed
windows and the fan off, levels reach 12 times the World Health Organization’s
recommended standards. Mr. Thesen’s daughter suffered from exercise-induced
asthma and his father died of lung cancer. Mr. Thesen asked the UAC to agendize an
item about what the Utility can do about providing a product known to cause cancer
and asthma.
2. Avroh Shah was as Junior at Palo Alto High School, led the Advocacy Committee of the
Palo Alto Student Climate Coalition, and was on the Executive Committee of the Sierra
Club Student Coalition. Mr. Shah urged the Utility to act responsibly and use utility bill
inserts or explore other ways to educate residents about the health risks and
consequences of using natural gas, and alternative solutions.
3. Hamilton Hitchings said the Public Safety Building (PSB) was a top candidate for a City
microgrid. The PSB had 72 hours of backup power through a generator and fuel supply.
A solar array on top of the adjacent garage fed into the PSB. When the PSB was built,
the planned battery storage for the solar array was eliminated for budget reasons.
Battery storage would extend the PSB’s backup power, making it more resilient. Solar
power generated during the day could reduce late afternoon peak loads on the City’s
Item #2
Packet Pg. 20
Utilities Advisory Commission Minutes Approved on: Page 2 of 17
grid. LFP portable battery technology was mainstream affordable, safer than older lithium ion
options, and a practical investment. Palo Alto’s Emergency Services Volunteer organization,
composed of 700 residents, recommended AT&T Fiber because its passive fiber network will
stay on at least 72 hours after a power outage if residents powered their fiber modem, which
Mr. Hitchings experienced twice during 8-hour outages. Volunteers use the internet to report
critical incidents to cloud-based servers. Mr. Hitchings asked how long the City’s fiber hut will
remain powered during an outage and if the City’s planned fiber service will remain up as long
as residents powered their modems. A reliable UPS battery to power a home fiber modem and
router for 24 hours costs about $500 and around $200 for a solar panel to recharge it. For the
many Palo Alto residents who conduct important business from home, uninterrupted service
was vital for business continuity and a deciding factor in which fiber service they choose.
APPROVAL OF THE MINUTES
UTILITIES DIRECTOR REPORT
Item #2
Packet Pg. 21
Utilities Advisory Commission Minutes Approved on: Page 3 of 17
receive Cap-and-Invest monies; those funds will go to electric utilities in those service
territories. Unfortunately, Assembly Bill 1273 for the extension of large hydroelectric from 2030
to 2045 was vetoed. Palo Alto had a commitment to carbon-free resources and worked with
WAPA, which was a federal hydropower. Assembly Bill 1273 was added to an existing bill on
how the CPUC approved rates. Palo Alto will look at having a standalone bill for hydroelectric
extension in the next legislative session. If not, Palo Alto needed to procure to meet renewable
portfolio requirements, which affected affordability because of competition with other Utilities
trying to meet their renewable portfolio standard requirements.
Item #2
Packet Pg. 22
Utilities Advisory Commission Minutes Approved on: Page 4 of 17
residential disconnect fee went to the Finance Committee. Monies in the S/CAP program could
pay for the disconnection of gas service if a resident electrified their home. For consistency,
staff followed past practice of whether an item or update goes to the UAC or Finance. The
municipal fee schedule update was a larger process with the City, so staff could not separate
utility-related fees but could provide it as information if the UAC was interested.
NEW BUSINESS
ITEM 1: Information Report: Utilities Quarterly Report for FY 2025-Q3/Q4
Item #2
Packet Pg. 23
Utilities Advisory Commission Minutes Approved on: Page 5 of 17
center load growth. For the electric utility, revenue from REC and RA sales was higher than
expected. As a result, our electric net supply cost was below budget. Higher RA purchase costs
were projected to result in higher electric net supply costs in FY 2026.
Item #2
Packet Pg. 24
Utilities Advisory Commission Minutes Approved on: Page 6 of 17
and had the same climate. If CPAU had more outages than Santa Clara because of our foothills,
it was a reasonable explanation.
Item #2
Packet Pg. 25
Utilities Advisory Commission Minutes Approved on: Page 7 of 17
provided. Commissioner Tucher mentioned he forwarded other comments to staff and offered
to further discuss this topic offline with staff. Commissioner Tucher suggested abandoning the
quarterly report, and he asked his fellow commissioners if the quarterly report should continue
and if it was a good use of staff’s time.
ACTION: No action required.
ITEM 2: Discussion of Preliminary Analysis of the Infrastructure Impacts Associated with Gas
Item #2
Packet Pg. 26
Utilities Advisory Commission Minutes Approved on: Page 8 of 17
had. Some inconsistencies were noticed in the underlying data. The numbers were likely to
change after data cleaning but the preliminary and final results were anticipated to be similar.
Monte Carlo simulations were done of main abandonment under various electrification
scenarios. Cost categorization and estimates of cost impacts under electrification scenarios
were partially complete. Evaluation of impacts on customer groups had not started. Identifying
mitigations was in the brainstorming stage. The four electrification scenarios modeled were 20,
40, 60, and 80 percent reductions in gas sales, which considered residential and small/medium
commercial at 25, 50, 75, and 100 percent water and space heating electrification, respectively,
and 0 percent reduction for large commercial and industrial.
Item #2
Packet Pg. 27
Utilities Advisory Commission Minutes Approved on: Page 9 of 17
folks who had gas, people who had electric resistance heating could benefit from heat pumps
as well.
Item #2
Packet Pg. 28
Utilities Advisory Commission Minutes Approved on: Page 10 of 17
S/CAP funding study will look at different strategies and information will be presented to the
UAC when it becomes available.
Item #2
Packet Pg. 29
Utilities Advisory Commission Minutes Approved on: Page 11 of 17
assumption was not included in this study. Mr. Abendschein was not sure they could predict
where people will electrify. Mr. Abendschein pointed out that when you offload the risk of
stranded assets onto another entity, they usually find a way to make you pay for it. The PG&E
option and every other option will be considered. Palo Alto wanted to set an example. Utilities
face similar challenges statewide and are going through planning processes. Planners believe
there is a way to gracefully shrink the gas system.
Item #2
Packet Pg. 30
Utilities Advisory Commission Minutes Approved on: Page 12 of 17
Mr. Abendschein said fugitive emissions were estimated but were relatively small compared to
primary combustion emissions. There had been past discussions with other UACs about
upstream emissions beyond Palo Alto’s gas system.
ACTION: No action required.
ITEM 3: Discussion of Implementation Plan for Voluntary Residential Electric Service Time-of-
Use Rates
Item #2
Packet Pg. 31
Utilities Advisory Commission Minutes Approved on: Page 13 of 17
frequently asked questions (FAQs) on the City’s website will be a resource to help customers
understand the new TOU rate, benefits of shifting energy use away from peak hours, and will
help alleviate demands on customer service staff. A list of initial FAQs is provided in the staff
report. Recommendations from industry partners such as the American Public Power
Association and examples of other utilities’ FAQs helped guide the proposed draft FAQs. The
FAQs will evolve as the TOU program is implemented.
Item #2
Packet Pg. 32
Utilities Advisory Commission Minutes Approved on: Page 14 of 17
people knew the reason that power was cheap at 2 p.m. is because solar is abundant.
Commissioner Tucher inquired if the utility was starting to use AMI analytics to build usage
patterns to model how and when customers were using power, and then see how those curves
change when people switch to TOU. NEM-1 will be less compelled by TOU when solar
households pay nothing for power during the summer but the TOU differential in November
and December will be attractive.
ACTION: No action required.
Item #2
Packet Pg. 33
Utilities Advisory Commission Minutes Approved on: Page 15 of 17
ITEM 4: Reaffirmation of the Carbon Neutral Plan and the Renewable Energy Credit Exchange
Program; CEQA Status: Not a project
Jim Stack, Senior Resource Planner, delivered a slide presentation. The Council adopted a
Carbon Neutral Plan in 2013 using an annual accounting standard, meaning we considered
ourselves carbon neutral if our annual supplies of carbon neutral generation were the same or
greater than our annual load. At that time, emissions did not vary drastically over the course of
the day or year, so the duck curve was not prominent. As more solar was interconnected on the
grid, the duck curve became more pronounced. In the middle of the day, especially in the spring
and fall, the electricity on the grid is clean and has very low emissions intensity. In the evening
when the sun goes down, gas generation has to come online and the grid becomes much
dirtier. In 2020, Council updated the Carbon Neutral Plan to hourly accounting, a stricter and
more rigorous accounting standard where every hour of the year we look at our load and
carbon-neutral generation, and any surplus or deficit position we have in each hour is weighted
by the average emissions intensity of grid power during that hour. In 2020, Council also
adopted the Renewable Energy Credit (REC) Exchange Program to sell some of our surplus in-
state renewables (Bucket 1 RECs) and exchange them on a one-for-one basis for out-of-state
renewables. There was no climate impact associated with REC exchanges. There was a large
price differential between in-state and out-of-state renewables because of the State’s RPS
requirements and preferential treatment to in-state renewables.
For 2020 and 2021, staff was directed to allocate 2/3 of REC revenue to offset supply costs and
1/3 of revenue allocated to local decarbonization efforts. In 2022, Council reauthorized the REC
Exchange Program and directed allocation of all REC net revenue toward local decarbonization
efforts, and directed staff to come back in 2025 to review the results and obtain Council
reauthorization of the REC Exchange Program. In 2020 and 2021, the REC Exchange Program
drew in roughly $2 million per year in net revenue with Bucket 1 REC prices around $15 to $20
per REC and Bucket 3 prices around $5, providing an arbitrage opportunity. In 2023 and
particularly in 2024, the REC Program net revenue was about $18.5 million over those 2 years,
because Bucket 1 REC prices increased to about $75 to $80 per REC, and Bucket 3 prices did not
change. In 2025, revenue was about $3.5 million and Bucket 1 REC prices were roughly in the
$18 range. From 2020 to 2025, the program’s total net revenue was about $28.5 million, about
$3.5 million was allocated toward offsetting supply costs and the remainder was set aside for
funding electrification efforts for local decarbonization purposes through the S/CAP. To date,
the funding for S/CAP initiatives such as electrification has come primarily from Public Benefits
Funds, Low Carbon Fuel Standard Credit sales, and gas Cap-and-Trade allowance sales.
A portion of the revenue from sales of carbon allowances received from the State was put into
the Cap-and-Trade reserve and earmarked for decarbonization programs. In 2023 and 2024, the
REC Exchange Program net revenue greatly exceeded the revenue from carbon allowance sales,
which was usually about $5 million per year, so staff will return at a future UAC meeting with a
recommendation for handling this unanticipated situation. For the next 5 years, the REC
Exchange Program is projected to bring in about $2 million per year in net revenue with most of
Item #2
Packet Pg. 34
Utilities Advisory Commission Minutes Approved on: Page 16 of 17
it coming in 2026-2028 based on the REC forecast and current supply portfolio. Afterward, the
opportunity to bring additional revenue will start dropping rapidly due to the RPS requirement
level increasing yearly until it reaches 60 percent in 2030, so the amount of excess in-state
renewables will diminish over time. Load is also increasing and some older power purchase
agreements are set to expire, which reduces the volume of RECs that can be exchanged. Signing
additional PPAs for in-state renewables, which staff was working on, will increase the amount
of RECs available to exchange.
ACTION: Commissioner Phillips moved staff’s recommended motion for the UAC to recommend
that the City Council:
Item #2
Packet Pg. 35
Utilities Advisory Commission Minutes Approved on: Page 17 of 17
1) Reaffirm the Carbon Neutral Plan, including the use of RPS-eligible, unbundled RECs
(Bucket 3 RECs) to neutralize any residual emissions resulting from the use of an hourly
emissions accounting methodology;
2) Reaffirm the continuation of the REC Exchange Program, whereby the City exchanges
bundled RECs from its long-term renewable resources (Bucket 1 RECs) for Bucket 3
RECs, to the maximum extent possible, while maintaining compliance with the State’s
RPS regulations, in order to allocate additional revenues toward local decarbonization
efforts; and
3) Direct staff to return to the UAC and City Council in 2028 to provide another review of
the program’s impacts.
Vice Chair Mauter seconded the motion.
Motion passed 4-0.
COMMISSIONER COMMENTS and REPORTS from MEETINGS/EVENTS
Commissioner Tucher called attention to an article in the local newspaper entitled “Data
Centers Drive Surging Electricity Demand.” Commissioner Tucher personally thought data
centers were misunderstood or lacked analysis. Data centers were a major portion of the load
forecast starting this year. Commissioner Tucher heard staff talk about the growth of data
centers but there had never been a discussion about who were the customers that were
building data centers and why were they building them in Palo Alto. Power was cheaper in Palo
Alto relative to PG&E. Commissioner Tucher wanted staff to understand the local market
opportunity and trend for data centers. To obtain a deeper understanding, Commissioner
Tucher wanted a detailed discussion agendized on data centers. Commissioner Tucher
suggested staff could talk to local industry experts on data centers.
Commissioner Phillips wanted to know the Utility’s stance on data centers, whether we should
say we want to build more data centers because they will lower residential rates or we do not
want data centers, keeping in mind that other aspects from the City point of view need to be
considered.
Alan Kurotori, Utilities Director, intended to agendize data centers in December.
ADJOURNMENT
Chair Scharff moved to adjourn.
Meeting adjourned at 8:33 p.m.
Item #2
Packet Pg. 36
Item No. 3. Page 1 of 9
7
1
8
0
Utilities Advisory Commission
Staff Report
From: Alan Kurotori, Utilities Director
Lead Department: Utilities
Meeting Date: November 5, 2025
Report #: 2504-4593
TITLE
Recommendation to Approve the Draft 2026 Utilities Legislative Policy Guidelines Update and
to Receive the Update on 2025 State and Federal Legislative and Regulatory Activity. CEQA
Status: Not a Project.
RECOMMENDATION
Staff recommend the Utilities Advisory Commission (UAC):
Recommend the Policy and Services Committee and the City Council approve the Draft
2026 Utilities Legislative Policy Guidelines Update, and
Accept this staff report providing an update on state and federal activities in 2025.
EXECUTIVE SUMMARY
Due to its unique regulatory environment, the Utilities Department has its own set of legislative
guidelines that are brought before the UAC and Council periodically for review. The Draft 2026
Utilities Legislative Policy Guidelines Update presented in this staff report remain unchanged
from the most recent guidelines approved in 2023.
The year 2025 was challenging for utilities regulatory and legislative matters. The California
legislature tackled several major issues with tens of millions of dollars at stake for the City of
Palo Alto Utilities (CPAU). Overall, the state legislative activities were positive for CPAU and
should help control electricity costs, lower statewide electric carbon emissions, and increase
electric supply reliability. The two major state legislative actions driving these positive impacts
include establishing an independent governance board for the new regional electricity market
and reauthorization of the Cap-and-Trade program. On the other hand, a new federal
administration made large changes to promote fossil fuels, accelerate phaseout of energy tax
credits that support renewable energy and environmental programs, cut the federal power
marketing administration workforce, and levy larger tariffs. Utilities costs are expected to
increase due to the increased tariffs, but the full impact of the federal legislative and policy
changes is still emerging.
Item #3
Packet Pg. 37
Item No. 3. Page 2 of 9
7
1
8
0
BACKGROUND
Due to the highly regulated nature of utilities, Utilities Legislative Guidelines have been used to
enable effective staff advocacy in line with the City Advocacy Process Manual.1 The broad and
technical scope from dozens of bills introduced annually requires frequent communication with
utility associations and often direct staff advocacy to advance and protect CPAU and customer’s
interests. The Utilities Legislative Guidelines were created to provide guidance to these
activities. These guidelines have been reviewed annually by the UAC and approved by the City
Council since at least 2009.2
The recommended Draft 2026 Utilities Legislative Policy Guidelines Update are unchanged from
the most recent version approved on April 3, 2023.3 The 2023 guidelines were almost entirely
unchanged going back to the version approved in 2020,4 as they were intended to be perennial
guidelines.
State and federal-level utilities legislation in 2025 was tumultuos. In California, rising electricity
rates and the devastating Los Angeles wildfires led to energy affordability and wildfire
mitigation taking center stage. Key legislation included the establishment of an independent
governance structure for a day-ahead regional electricity market (AB 825 Petrie-Norris) and the
reauthorization of the Cap & Trade program, now Cap & Invest (AB 1207 (Irwin)/SB 840
(Limón)). On the federal side, the new federal administration took significant steps to limit
renewable energy investment, promote fossil fuels, and roll back environmental protections.
Central to that effort was the One Big Beautiful Bill Act (H.R. 1), which accelerated the phase
out of most renewable energy and electric vehicle federal tax credits.
ANALYSIS
Utilities Legislative Policy Guidelines
The Utilities Legislative Guidelines have enabled effective and nimble advocacy on utility
legislation and regulations. Intended to be perennial and subject to UAC and Council review,
the most recent guidelines were approved by the City Council on April 3, 2023. The guidelines
were not updated in 2024 and 2025 due to their fundamentally perennial nature. The 2026
guidelines presented in Attachment A include only grammatical changes. As in the past, CPAU
staff will use these guidelines when advocating with policymakers, lobbyists, and utilities
associations. Given the highly technical and fast-paced nature of utility legislation and
1 https://www.paloalto.gov/files/assets/public/v/1/intergovernmental-affairs/advocacy-manual-updated-jan-
2020.pdf
2 https://www.paloalto.gov/files/assets/public/v/1/agendas-minutes-reports/agendas-minutes/utilities-advisory-
commission/archived-agenda-and-minutes/agendas-and-minutes-2009/11-04-2009-meeting/item-4_-util-
legislative-policy-guidelines-2010.pdf
3 City Council, April 3, 2023, SR 2301-0895: https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=82266
4 City Council, January 1, 2023, SR 10772:
Item #3
Packet Pg. 38
Item No. 3. Page 3 of 9
7
1
8
0
regulatory updates, the guidelines will continue to allow the Utilities Director to approve formal
advocacy actions such as submitting written letters or meeting with lawmakers.
State Legislation in 2025
Major California Legislation
AB 825 (Petrie-Norris) Establishment of an independent governance board for a regional day-
ahead electricity market.
CPAU lobbied for AB 825 through direct advocacy from staff and elected officials in line
with Item 10 of the current Utilities Legislative and Policy Guidelines.
AB 1207 (Irwin)/SB 840 (Limón) Cap-and-Trade reauthorization
Item #3
Packet Pg. 39
Item No. 3. Page 4 of 9
7
1
8
0
many of CPAU’s local decarbonization programs. Another important item in the bill is the
directive to CARB to transition away from free allowances for gas corporations and instead give
them to electric utilities. Since CPAU is not defined as a gas corporation (e.g. investor-owned
utility), it will continue to receive free allowances for its gas utility. CPAU may receive additional
free allowances to its electric utility. These new auction proceeds must be returned to
customers as a rebate. These two provisions safeguard CPAU’s existing Cap-and-Trade revenue,
which is worth approximately $7 million per year through 2030. Lastly, AB 1207 changes the
name of the program to Cap-and-Invest. CPAU will be tracking how the California Air Resources
Control Board will be updating the implementation and changes to Cap-and-Invest Revenues
which will continue to 2045.
CPAU advocated for AB 1207 both directly and through NCPA and CMUA in accordance
with Items 1 – 4 and 10 in the 2023 Utilities Legislative Guidelines.
While CPAU did not directly advocate for SB 840, we favored its passage in line with
Item 10 in the Utilities Legislative Policy Guidelines.
AB 130 (Committee on Budget) effected many changes to housing policy but most
importantly for the City, it suspended changes to building codes, including green
building codes, until 2031. The City was able to adopt reach codes for the 2025
California Building Standards Code update before the suspension took effect; one of
only a handful of cities to do so.
o This was monitored in accordance with Items 1, 3, and 10 of the Utilities
Legislative Policy Guidelines.
AB 1410 (Garcia) requires utilities to develop appropriate and feasible procedures to
maximize automatic enrollment of customers in alerts for electric service outages and
updates by March 2026.
o This was monitored in accordance with Items 1 and 10 of the Utilities Legislative
Policy Guidelines.
Item #3
Packet Pg. 40
Item No. 3. Page 5 of 9
7
1
8
0
SB 31 (McNerney) changes acceptable usage rules for recycled water in certain facilities,
such as buildings with food preparation areas, to allow additional uses of recycled
water.
o This was monitored in accordance with Items 4 and 11 of the Utilities Legislative
Policy Guidelines.
SB 72 (Caballero) was sponsored by CMUA and revises The California Water Plan to
expand consulted stakeholders, periodically assess expected future water usage, and
create a plan to secure additional water supplies to address expected water shortfalls
due to climate change.
o This was monitored in accordance with Items 4 and 9 of the Utilities Legislative
Policy Guidelines.
SB 254 (Becker) is the legislature’s energy affordability bill. Spanning 101 pages, SB 254
seeks to reduce transmission construction cost by limiting investor-owned utility (IOU)
returns, reduce wildfire mitigation costs through numerous actions, and creates other
provisions aimed at reducing electricity rates. Specific to POUs like CPAU, wildfire
mitigation plans will only need to be submitted every four years rather than annually,
alleviating a significant administrative burden without compromising wildfire safety.
o This was supported in accordance with Items 1, 3, and 9 of the Utilities
Legislative Policy Guidelines.
Notable bills that failed in this year’s session include:
AB 1273 (Patterson) would have continued the current treatment of Palo Alto's legacy
hydropower beyond 2030 to 2045, allowing more than 40% of generation to be from
large hydropower in a particularly wet year. However, AB 1273 had two parts, with the
primary purpose prohibiting the California Public Utilities Commission (CPUC) from
placing significant electric rate increases for investor-owned utilities on its consent
calendar. Governor Newsom objected to this part, as he feared it would delay important
CPUC rate proceedings. In his veto letter, the Governor signaled support for clarifying
language about hydroelectricity for publicly owned utilities but decided to veto the
legislation due to the potential impact to the CPUC. CPAU and our partners at NCPA
remain optimistic that a hydroelectricity provision may be included in an appropriate
piece of legislation in the future.
o Staff lobbied for this in accordance with Items 1, 6, and 10 of the Utilities
Legislative Policy Guidelines.
AB 222 (Bauer-Kahan) would have required the CEC to assess electrical load trends for
data centers and for the CPUC to assess the extent to which new data center loads
result in cost shifts to other electric utility customers.
o This was monitored in accordance with Item 3 of the Utilities Legislative Policy
Guidelines.
Item #3
Packet Pg. 41
Item No. 3. Page 6 of 9
7
1
8
0
AB 353 (Boerner) would have required internet service providers to offer internet
service at $15/month to low-income customers.
o This was monitored in accordance with Items 1, 3, and 6 of the Utilities
Legislative Policy Guidelines.
AB 1218 (Soria) would have increased penalties for stealing copper and possessing
known stolen copper.
o This was monitored in accordance with Item 9 of the Utilities Legislative Policy
Guidelines.
SB 332 (Wahab) would have, among other items related to investor-owned utilities,
required POUs to post online information related to the number of service terminations
because of nonpayment.
o This was monitored in accordance with Items 1 and 12 of the Utilities Legislative
Policy Guidelines.
SB 445 (Wiener) originally would have required binding arbitration between
transportation projects and utilities if utility infrastructure would be impacted by the
transportation project. Later amendments narrowed the scope to non-binding solutions
for utility infrastructure impacted by the California High Speed Rail Project. The author
has stated his intent to revive this bill in 2026.
o This was monitored in accordance with Items 1, 6, and 9 of the Utilities
Legislative Policy Guidelines.
SB 454 (McNerney) would have established a per- and polyfluoroalkyl substances (PFAS)
mitigation program and upon appropriation by the legislature, would create a state fund
to aid in reducing or eliminating PFAS in drinking water, recycled water, wastewater,
and stormwater.
o This was monitored in accordance with Item 2 of the Utilities Legislative Policy
Guidelines.
SB 541 (Becker) would have directed the CEC to analyze the cost effectiveness of load
shifting programs and strategies and to biennially estimate the load shifting potential of
each electric utility.
o This was monitored in accordance with Items 1 and 4 of the Utilities Legislative
Policy Guidelines.
SB 618 (Reyes) would have required POUs to include in their wildfire mitigation plans
appropriate and feasible procedures to compensate customers impacted by
deenergizing power lines.
o This was monitored in accordance with Items 1, 3, and 6 of the Utilities
Legislative Policy Guidelines.
Item #3
Packet Pg. 42
Item No. 3. Page 7 of 9
7
1
8
0
AB 93 (Papan) would have required data centers, when applying for an initial business
license, to provide water suppliers with an estimate of water usage and provide annual
water reports.
o This was monitored in accordance with Item 6 of the Utilities Legislative Policy
Guidelines.
SB 292 (Cervantes) would have required POUs to post online an annual reliability report
that identifies the frequency and duration of interruptions in service.
o This was monitored in accordance with Items 1 and 12 of the Utilities Legislative
Policy Guidelines.
State Regulatory Action in 2025
There were not many major regulatory actions taken at the state level in 2025 other than
amendments to the Low Carbon Fuel Standard (LCFS). CARB approved amendments in
November 2024 to accelerate a decrease in transportation fuel carbon intensity, which reduces
the credits generated by low emission fuels like electricity and increases the deficits generated
by high emission fuels like gasoline. As a supplier of electricity, CPAU receives several million
dollars annually in LCFS credit revenues and uses them to fund electric vehicle-related
programs. The LCFS amendments will decrease the number of credits CPAU receives but the
tighter supply of credits should increase credit prices, thus the amendments are expected to be
revenue neutral for CPAU. Despite some administrative setbacks, the final amended regulation
went into effect on July 1, 2025.
Federal Action in 2025
The federal administration has brought significant changes to the energy and climate mitigation
landscape. The White House issued several executive orders aimed at “unleashing America’s
energy dominance” and increasing federal efficiency. These orders did the following:
Imposed tariffs on a wide range of countries and products including solar cells,
batteries, steel, aluminum, and numerous electrical grid components. These tariffs have
increased both energy prices and operational equipment prices.
Staff reductions at federal agencies including the Bureau of Reclamation (BOR) and the
Western Area Power Administration (WAPA). These two agencies manage the federal
hydroelectric power projects in California that provide approximately 40% of CPAU’s
electricity supply. The resulting 20% reduction in workforce heightens the risk to the
financial and operational efficiency of these projects and increases concerns for health
and public safety. Employee attrition continues to this day.
Streamlined permitting and approval of fossil fuel projects on federal land while slowing
approval or rejecting renewable energy projects on federal land. While this does not
have a direct impact on CPAU, it’s expected to increase wholesale electricity prices by
restricting electricity generation in a time of growing demand.
Item #3
Packet Pg. 43
Item No. 3. Page 8 of 9
7
1
8
0
Reduced or eliminated federal appliance efficiency standards for both energy and water.
Another major federal action was the passage of the federal budget bill, dubbed the One Big
Beautiful Bill Act (H.R.1). The main energy and climate focus of the bill was the sunsetting of
renewable energy, electric vehicle, and energy efficiency federal tax credits. Specific impacts
included:
Elimination of the $7,500 electric vehicle tax credit after September 30, 2025.
Elimination of residential energy efficiency tax credits after December 31, 2025.
Elimination of solar and wind energy tax credits after December 31, 2027, unless the
projects begin construction by July 4, 2026.
o Projects receiving material assistance from Russia, China, North Korea, and Iran,
dubbed foreign entities of concern, are not eligible for tax credits. This is
significant because many solar and battery projects are sourced from China.
The impact of these recissions are significant. Some renewable energy projects have been
suspended or canceled while those continuing construction are offering energy contracts at
higher prices. Electric vehicle sales increased in the run-up to the September 30, 2025 tax credit
deadline but sales are expected to fall past that date. CPAU is experiencing these effects as is
the entire utility sector.
California’s environmental and energy policy has been directly targeted by the federal
administration’s actions. Perhaps most importantly, Congress, at the direction of the White
House, rescinded California’s Environmental Protection Agency (EPA) waiver that enabled the
Advanced Clean Cars II regulation to go into effect. Rescinding the waiver effectively cancels
California’s 2035 ban on non-zero emission vehicles, though the legality of this revocation is
being challenged by the state. These federal moves introduced market uncertainty into the
zero-emission vehicle market, especially for heavy duty vehicles, and is shrinking the pool of
available vehicles needed for compliance with regulations like Advanced Clean Fleets.
Additionally, one executive order9 mentioned California’s Cap & Trade program as an example
of environmental overreach that needs to be curbed by the federal government. These actions
directly impact CPAU revenues and decarbonization programs. As a result, staff are continually
monitoring federal actions and seeking ways to mitigate their impacts.
FISCAL/RESOURCE IMPACT
There is no fiscal or resource impact associated with adopting legislative guidelines for the
Utilities Department.
STAKEHOLDER ENGAGEMENT
9 Executive Order mentioning Cap and Trade https://www.whitehouse.gov/presidential-
actions/2025/04/protecting-american-energy-from-state-overreach/
Item #3
Packet Pg. 44
Item No. 3. Page 9 of 9
7
1
8
0
The guidelines were informed through a stakeholder review process involving internal
departments and external associations.
ENVIRONMENTAL REVIEW
ATTACHMENTS
AUTHOR/TITLE:
Item #3
Packet Pg. 45
UTILITIES LEGISLATIVE POLICY GUIDELINES: 2026 UPDATE
City of Palo Alto Utilities Department (CPAU) staff will use the below guidelines as well
as the City’s guidelines to help determine any advocacy position or action on Utilities-
related issues. Formal advocacy, such as submitting written letters or comments and
meeting with policymakers and/or staff, requires the approval of the Utilities Director or
their designee.
Item #3
Packet Pg. 46
Item No. 4. Page 1 of 15
22273783.1
Utilities Advisory Commission
Staff Report
From: Alan Kurotori, Director Utilities
Lead Department: Utilities
Meeting Date: November 5, 2025
Report #: 2506-4905
TITLE
Staff Recommends the Utilities Advisory Commission Recommend that the City Council Adopt a
Resolution Approving the 2026 Natural Gas Cost of Service Analysis Report, Amending Rate
Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas
Service), G-3 (Large Commercial Gas Service) and repealing G-10 (Compressed Natural Gas
Service). CEQA Status: Not a Project under Public Resources Code Section 21065.
RECOMMENDATION
Staff requests that the Utilities Advisory Commission recommend that the City Council adopt a
resolution (Attachment A):
1. Approving the 2026 Natural Gas Cost of Service Analysis Report (Attachment B); and
2. Amending Rate Schedules (Attachment C) effective for gas usage beginning February 1,
2026 (FY 2026):
a. G-1 (Residential Gas Service)
b. G-2 (Residential Master-Metered and Commercial Gas Service)
c. G-3 (Large Commercial Gas Service)
3. Repealing Rate Schedule G-10 (Compressed Natural Gas Service)
EXECUTIVE SUMMARY
This report seeks the Utilities Advisory Commission’s recommendation that the City Council
approve the 2026 Natural Gas Cost of Service Analysis Report (2026 Report) shown in
Attachment B and adopt revised gas rate schedules shown in Attachment C. The 2026 Report
updates the allocation of costs among customer classes and refines the G-2 rate schedule to
better reflect the cost to serve customers with different meter capacities. The proposed rate
adjustments are designed to ensure equity among rate classes, maintain compliance with cost-
of-service principles under California law, and align with the City’s financial and policy
Item #4
Packet Pg. 47
Item No. 4. Page 2 of 15
22273783.1
objectives for affordability, transparency, and long-term sustainability. The proposed rate
adjustments are also consistent with the City Council-approved design principles.1
The Gas Utility implemented an across-the-board rate increase on July 1, 2025 to meet the
higher costs of providing service to its customers. New data presented in this 2026 Report
demonstrates that a shift in certain costs among classes of users would more equitably meet
the overall revenue requirement. The 2026 Report does not propose any budget or overall
revenue increase; instead, the focus of the 2026 Report is on a proportional rebalancing
through rate design changes. These rebalanced rates are proposed to be effective on February
1, 2026, and the 2026 Report also provides the analytical basis for allocating costs among
classes to meet revenue requirements in future years. The following report describes the
changes recommended in the 2026 Report as well as the reasons for those changes. In
summary:
1) Updating the weighted meter cost - the 2026 Report refreshes the Gas Utility’s rates
with the best possible cost information, which is necessary to achieve fair and cost-
based rates.
2) Updating the Average & Excess (A&E) Method – the 2026 Report’s cost allocation
approach better aligns rates with how the distribution system is designed and built in
light of declining average gas use. Infrastructure is sized based on energy usage and
peak demand which supports the A&E classification as both “demand” and “energy.”
This change is necessary to develop a fair and appropriate allocation of expenses across
customer classes.
3) Applying the Base & Excess Method for Residential Tier Rate – the 2026 Report’s
calculations present the best method for the G1 tiered rate design because the usage
profile supports measuring excess demand using the highest peak month and because
system infrastructure is designed to meet a single January peak.
4) Refining the G-2 (Multi-family Master-Metered and Commercial) Rate Schedule – the
2026 Report recommends separating this class into three meter capacity groupings by
Standard Cubic Feet per Hour (scfh), because the larger meters require a higher cost to
serve. This refinement results in a higher monthly service charge for larger capacity
meters to better reflect customer-related fixed costs in the fixed monthly service
charge.
The overall bill impact to the median use residential customer from the recommendations in
the 2026 Report is an 8% increase, while the bill impact for commercial customers ranges from
a 58% decrease for small commercial customers to a 7% increase for the largest G-2
commercial customers. Table 6 below shows additional bill impact details.
1 Staff Report 2507-4958, September 15, 2025 outlines the five design principles:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=043ab
d5a-f59f-4702-ad04-845541a8133f
Item #4
Packet Pg. 48
Item No. 4. Page 3 of 15
22273783.1
Staff worked closely with guidance from the Utilities Advisory Commission Gas COSA
Subcommittee on developing the recommendations in the 2026 Report. Staff would like to
thank the Subcommittee members for their extensive efforts including meeting four times
between August and October 2025. Gas COSA Subcommittee members will provide a verbal
report to the full UAC at the November 5, 2025 meeting.
PROJECT DESCRIPTION
This project is a study to update the City’s Natural Gas Cost of Service Analysis (2026 Report),
which provides the analytical foundation for and recommends adopting new City gas rates that
continue to be fair and legally compliant. The 2026 Report evaluates the gas utility’s revenue
requirements, allocates costs among customer classes based on cost-causation principles, and
proposes updated rate designs for each class based on the most up-to-date information
available to the City.
The 2026 COSA includes an updated financial forecast (consistent with the Council-approved
FY2026 Gas Utility Financial Forecast),3 refined cost allocation methodologies, and new meter
capacity groupings for the G-2 rate schedule. The proposed rate changes ensure rates are
aligned with actual service costs.
BACKGROUND
In June 2025, the City Council (Council) approved the overall gas utility rate increase for FY 2026
but deferred approval of the Cost of Service Analysis (COSA) pending further UAC review.4 On
July 9, 2025, the Utilities Advisory Commission (UAC) considered Design Principles for the Gas
and Electric Cost of Service Rates and voted to move forward with Proposition 26 as the Gas
COSA design principles and to form a UAC Subcommittee to work with staff and the consultant
to develop a new 2026 gas COSA and provide regular report-outs to the full UAC.5
Subsequently, staff worked closely with the UAC Gas COSA Subcommittee to review key study
assumptions and recommendations.
On September 15, 2025, the Council directed staff to follow the reasonable-cost analysis
required by Proposition 26 and to collaborate with the UAC to develop revised gas rates to be
effective in January 2026, based on the following design principles:
3 Staff Report 2411-3776, June 16, 2025,
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=35104f
06-6925-4fe3-89c7-b0e53e6eec42;
Resolution 10232 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62153
4 On June 16, 2025, the City Council voted 5-1-1, (Lythcott-Haims no, Stone absent) to return the updated COSA to
the UAC for further review. See June 16, 2025 action minutes for action item 22, Gas Utility item e:
https://cityofpaloalto.primegov.com/Public/CompiledDocument?meetingTemplateId=16148&compileOutputType
=1
5 July 9, 2025, UAC voted 6-1 with Gupta voting no; see action minutes
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=40dc6
4ea-7e0c-4dca-9235-61e1a6516b07
Item #4
Packet Pg. 49
Item No. 4. Page 4 of 15
22273783.1
1.Rates must be based on the reasonable cost to serve customers. This is the
overriding principle for the cost of service analysis (COSA); all other rate design
considerations are subsidiary to this basic premise.
2.The COSA should involve a review of all existing rate schedules for applicability in
the COSA.
3.The impact of any proposed changes on low-income customers should be evaluated
in alignment with state law, including, without limitation, Public Utilities Code
sections 890 and 898.
4.Determine the proper allocation of fixed and variable costs and how those can be
implemented in various rate designs.
5.Review non-rate revenue sources that may be available for rate discounts or
rebates.
These design principles form the basis for the 2026 Gas Cost of Service Analysis Report
presented as Attachment B to this staff report. Each design principle is discussed below in the
“Analysis - Gas COSA Design Principles” section.
ANALYSIS
Natural Gas Cost of Service Analysis
The Gas Utility’s rates are evaluated and implemented in compliance with cost-of-service
requirements set forth in the California Constitution and applicable statutory law. Staff engaged
the services of EES Consulting (EES) to review and revise the Gas Utility’s Cost of Service (COS)
for FY 2026.9 A copy of the FY 2026 COS study titled “City of Palo Alto 2026 Natural Gas Cost of
Service Analysis Report,” (2026 Report), October 2025 is included as Attachment B to this
report. The study examines and allocates the Gas Utility’s costs to each rate class to develop
proposed FY 2026 distribution rates and includes a recommendation to refine the G-2 rate
schedule as explained below.
Distribution Revenue Requirement
The 2026 Report contains gas sales forecasts and estimates for Gas Utility assets and expenses
(including estimated contributions to reserves). The 2026 Report allocates these assets and
expenses estimates using updated classification and allocation factors to ensure that the Gas
Utility’s costs are properly assigned to each rate class. The 2026 Report uses the same estimate
of total distribution revenue requirement of $41.3 million for FY 2026 that was approved by
Council on June 16, 2026 as part of the FY 2026 Gas Utility Financial Forecast.10 This distribution
revenue requirement includes operating expenses, capital costs and reserve contributions. At
current rates, projected revenues also equal $41.3 million for FY 2026, so there is no overall
rate or revenue increase required as part of the 2026 Report for the Gas Utility as a whole.
However, individual customer class rates will change as a result the realignments as
summarized in Table 1.
9 Since FY 2021, the City adjusted its distribution rates annually based on the COS study for FY 2020, which was
also conducted by EES.
10 Resolution 10232 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62153
Item #4
Packet Pg. 50
Item No. 4. Page 5 of 15
22273783.1
Table 1 illustrates the projected revenue collected from each customer class using current
distribution rates (for the full year of FY 2025-2026 assuming the rates were effective all year)
and using the rates resulting from the 2026 Report. The total revenue requirement is the same
as that shown in the Council-approved FY 2026 Gas Utility Financial Forecast. This revenue
requirement estimate includes distribution costs, certain supply costs (such as administrative
charges allocated to gas supply), and additional reserve contributions required to restore the
Gas Utility’s operations reserve to within the guideline range in FY 2026. Supply-related costs
that are collected via a pass-through charge are not included.
The 2026 Report updates and adjusts the cost-of-service classification and allocation factors,
which leads to revenue requirements for the rate classes that differ from the projected FY 2026
revenues at current rates. The percentage of revenue increase needed varies by customer class
—ranging from -10.6% for G-2 to 8.3% for G-1 and 7.9% for G-3.
Table 1: Projected Revenues, Revenue Requirement and Revenue Changes Needed
Key Changes in 2026 Report
During the development of the 2026 Report, staff worked collaboratively with EES to update
the Gas Utility’s costs and usage information and refresh the model inputs with current data.
Some of the key changes described in more detail below are:
1) Updates to the customer weighting factors for meter costs;
2) Updates to the Average & Excess classification and allocation factor for G2 and G3
customers, while changing some of the methods used to calculate that factor and
changing some of the cost categories it is applied to for improved consistency;
3) The use of the Base & Excess Methodology to develop residential (G1) tiered rates;
4) Refinement of the G2 (Residential Master-Metered and Commercial Gas Service) rate
schedule; and
5) Elimination of the supply charge ranges for the Cap-and-Trade Compliance Charge and
the Transportation Charge.
During 2025 public meetings on the Gas COSA before the UAC, Finance Committee, and
Council, and in letters from the public, the February 2025 draft of the Gas Utility’s cost-of-
service study was critiqued, and stakeholders suggested that the 2026 Report retain prior cost-
Item #4
Packet Pg. 51
Item No. 4. Page 6 of 15
22273783.1
of-service calculation methods. The UAC’s Gas COSA Subcommittee guided staff and EES to
examine this closely. Under this approach (retaining prior study methods and only updating
costs and revenues to current levels) the median residential monthly bill would be
approximately $80.88, which is $1.55 (or 2%) higher than the median bill under the 2026 Report
method shown in Table 1. Staff and EES do not recommend retaining the existing rate model
because it is not updated with relevant cost updates and is not updated with recent load, usage
and other relevant information); it would also result in a higher median residential customer
bill.
Customer Weighting Factors for Meter Costs
Table 2: Customer Weighting for Meter Costs: FY 2026
G1 G2 G3
Prior Values (May 2019)
Meter Costs (Materials)$72.84 $888.00 $1,505.00
Weighting $1,549,452 $2,029,080 $52,675
Resulting Allocator 42.7%55.9%1.5%
Updated Values (Oct 2025)
Meter Costs (Materials and Labor)$414 $1,262 $10,473
Weighting $8,761,310 $2,772,869 $308,954
Resulting Allocator 74.0%31.6%11.1%
13 This customer weighting
for meter costs update is one of the primary drivers for the rate rebalancing recommended in
13 The representative meters for the G1, G2, and G3 used in the 2020 COSA study were the CL250 House, 8C/175
Rotary and 5000 Rotary meters, respectively.
Item #4
Packet Pg. 52
Item No. 4. Page 7 of 15
22273783.1
this study. This update is necessary to refresh the Gas Utility’s rates using the best available
information and to reflect the latest costs so that rates remain fair and cost-based.
Average & Excess (A&E) Method for G2 and G3 Rates
Base & Excess Methodology for Residential Tiered G1 Rates
Item #4
Packet Pg. 53
Item No. 4. Page 8 of 15
22273783.1
Refinement of G-2 (Residential Master-Metered and Commercial Gas Service) Rate Schedule
The G2 customer class includes a wide range of customer types including restaurants, other
types of small business, office space and master-metered multi-family properties. This class
includes a wide range of meter types and capacities. Based on a review of existing G-2 services’
meter capacities, associated costs and recorded sales, the Study recommends refining the rate
schedule into three meter capacity groupings using Standard Cubic Feet per Hour (scfh), with a
higher monthly service charge for larger meter capacity. The larger meters require a higher cost
to serve because generally they have higher average use, require larger service lines to connect
the meter to the distribution system, and impose greater demand on the system. This meter
capacity grouping refinement will better reflect customer-related fixed costs in the fixed
monthly service charge. The volumetric distribution charge is the same for all G-2 customers.
Table 3 presents the meter capacity groupings recommended for G-2 monthly service charge
application. EES analyzed average consumption for various meter capacities in the G-2 rate
class and developed three meter capacity ranges and customer-related costs for each range.
15
G-2: ≤ 220 scfh Less than 220 standard cubic feet per hour (scfh)1,134
G-2: > 220 and < 4,000 scfh More than 220 scfh and less than 4,000 scfh 942
G-2: ≥ 4,000 scfh 4,000 scfh and above 116
Staff and EES analyzed whether separating multifamily customers from existing G-1 and G-2
rate classes would improve cost alignment. The analysis found limited justification for creating
a new class at this time. Usage patterns, load factors, and service characteristics among
multifamily customers were not sufficiently distinct to warrant separate treatment. Therefore,
no additional subclassification is recommended.
There are four pass-through supply charges: 1) Commodity Charge (monthly market based), 2)
Cap-and-Trade Compliance Charge, 3) Transportation Charge and 4) Carbon Offset Charge.
While the focus of the 2026 Report is the gas distribution charges, staff is proposing some
administrative modifications to the two of the gas supply pass-through costs that vary based on
external factors and market conditions. The 2026 Report recommends continuing to pass
through the Cap-and-Trade Compliance Charge and the Transportation Charge but eliminating
the range mechanism for each. There are no rate impacts of this change.
15 Meter capacities in this staff report are all at an assumed pressure of 7 inches of water column (equivalent to
0.25 pounds per square inch).
Item #4
Packet Pg. 54
Item No. 4. Page 9 of 15
22273783.1
The Cap-and-Trade Compliance Charge recover the costs of the City’s obligation under the
California Air Resources Board’s Cap-and-Trade Program to purchase allowances for all
greenhouse gas emissions associated with natural gas use within the City’s service territory.
Because these costs are regulatory, nondiscretionary, and beyond the City’s control,
maintaining a range is unnecessary.
Proposed Rates
17. The proposed rates reflect the 2026 Report adjustments.
Table 4: Current and Proposed Monthly Service Charges
Rate Schedule Current Rates
(as of 7/1/25)
Proposed Rates
(effective
2/1/26)
Change
($)
Change
(%)
(Residential)
(Residential Master-Metered and Commercial)
≤ 220 scfh)
> 220 and < 4,000 scfh)
≥ 4,000 scfh)
(Large Commercial)
Table 5: Current and Proposed Gas Distribution Charges
Rate Schedule Current Rates
(as of 7/1/25)
Proposed Rates
(effective 2/1/26)
Change
($)
Change
(%)
G-1 (Residential)
G-2 (Residential Master-Metered and Commercial)
G-3 (Large Commercial)
17 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
Item #4
Packet Pg. 55
Item No. 4. Page 10 of 15
22273783.1
Bill Impacts
Table 6 shows the impact of the proposed February 1, 2026 rate changes on the median
monthly residential bill for representative average winter and summer bills, excluding supply-
related cost changes.
Monthly Bill1
Rate Schedule Monthly Usage (Therms)Current
Rates
Recommended
FY2025-2026
Rate
Bill
Impact
Residential
Summer: 10; Winter: 30 $50.78 $54.73 8%
Summer: 17; Winter: 51
(median)
$73.44 $79.33 8%
Summer: 30; Winter: 80 $127.24 $134.60 6%
G-1
Summer: 45; Winter: 150 $247.31 $263.50 7%
Commercial
Small: 35 $242.74 $103.05 (58%)
Medium: 280 $739.59 $676.33 (9%)
G-2
Large: 2,648 $5,558.74 $5,927.83 7%
G-3 20,834 $42,696.69 $44,131.74 3%
The annual gas bill for the median residential customer is projected to be 8% higher due to the
cost-of-service adjustments. The actual impact may be different because customer gas usage
varies and commodity price changes monthly.
Table 7 presents the median residential bills for Palo Alto and PG&E customers from FY 2022 to
FY 2026. The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area
which includes Palo Alto’s surrounding communities.
In FY 2025, the estimated annual gas bill for the median Palo Alto residential customer was
about 16% lower than that of a PG&E customer with equivalent consumption. With the
implementation of the 2026 Report, Palo Alto median residential bills are expected to be about
8% lower than PG&E bills in FY 2026. This projection assumes PG&E does not implement
additional rate increases between now and July 2026.
Item #4
Packet Pg. 56
Item No. 4. Page 11 of 15
22273783.1
Table 7: Residential Annual Natural Gas Bill Comparison ($/year)
FY 2022 657.83 724.24 (9%)
FY 2023 891.89 845.03 6%
FY 2024 753.28 764.70 (1%)
FY 2025 836.93 991.24 (16%)
FY 2026 Current 881.31 1,040.18 (15%)
FY 2026 Recommended
Annual
(374 Therms)
952.02 1,040.18 (8%)
Table 8 presents the median commercial bills for Palo Alto and PG&E customers from FY 2022
to FY 2026. Palo Alto bills have been higher than PG&E’s bills over the years, mainly due to
higher customer charges. With the recommendations from the 2026 Report, commercial
customer charges have been adjusted downward for the majority of commercial customers,
making bills more competitive with PG&E. With the implementation of the 2026 Report and the
proposed rate increases, Palo Alto median commercial bills are expected to be about 16%
higher than PG&E bills in FY 2026, assuming PG&E does not implement additional rate
increases.
FY 2022 6,507.57 5,602.19 16%
FY 2023 8,844.11 6,506.91 36%
FY 2024 7,426.78 6,022.59 23%
FY 2025 8,395.81 6,734.69 25%
FY 2026 Current 8,875.07 6,989.03 27%
FY 2026 Recommended
Annual G-2
(3,356
Therms)
8,115.89 6,989.03 16%
*Calculated based on G-2 with meter capacity of >220 and <4,000 scfh
The following discussion outlines each of the Council’s adopted Gas COSA Design Principles and
addresses how the 2026 Report addresses the Design Principles.
The 2026 Report uses actual costs and adopted budgets, applying industry-accepted allocation
methods to assign fixed and variable costs based on each class’s use of the system.
Item #4
Packet Pg. 57
Item No. 4. Page 12 of 15
22273783.1
Design Principle 2: The COSA should involve a review of all existing rate schedules for
applicability in the COSA.
All existing rate schedules were reviewed for relevance and cost alignment. Customers with
similar usage characteristics remain grouped together, and the study recommends refining the
G2 class as described earlier. The study reviewed the separation of multifamily from G1 and the
separation of master-metered multifamily from G2 and did not find a strong basis for splitting
these groups further.
Staff also reviewed the G10 rate schedule, which applies to gas sold at the City’s Compressed
Natural Gas refueling station at the Municipal Services Center. This facility does not utilize the
distribution system, rather it is directly connected to the City’s intertie with PG&E. Since the
sole customer is the Public Works department, it is more efficient to recover fueling costs via an
interdepartmental cost recovery transfer than a separate rate schedule, and the City is
separately developing a cost-based fee for service administration.19 Changes in this fee do not
materially impact the COSA results.
The study evaluated rate impacts on low-income residential customers. Approximately 400
customers participate in the City’s low-income program which is ratepayer funded, consistent
with Public Utilities Code Sections 890 and 898, with average monthly usage of 30 therms. Most
customers would see bill impacts under $5 per month, and the total cost to mitigate all bill
impacts of the 2026 Report on low-income customers who are enrolled in the Low-Income Rate
Assistance program or the Low Income Home Energy Assistance Program would be
approximately $30,000 per year.
All rate classes include a fixed monthly charge to recover customer-related costs such as
metering, billing, and service connections. The 2026 Report recommends a scaled fixed charge
in the G-2 customer class to reflect the diversity within that class. The G-1 class includes a
tiered variable rate structure that distributes capacity costs between Tier 1 and Tier 2 using the
base and excess method to appropriately collect demand costs from customers impacting
system capacity costs. The G-2 and G-3 classes recover capacity costs through uniform
volumetric charges, maintaining simplicity while reflecting consistent cost drivers.
The 2026 Report also reviewed non-rate revenue sources that could potentially fund rate
discounts or rebates. In FY 2025, an estimated $0.399 million in interest income was available
19 The CNG station has a public station that is currently non-operational and a CNG station for refueling City
vehicles. Both portions of the station are operated by the Public Works department.
Item #4
Packet Pg. 58
Item No. 4. Page 13 of 15
22273783.1
for this purpose. At the end of FY 2025 there was $15.046 million available in the gas utility’s
Cap & Trade Reserve. The Cap & Trade Reserve holds revenues from the auction of freely
allocated Gas Utility greenhouse gas emission allowances. Cap & Trade reserve funds must be
spent in accordance with California Air Resources Board regulations as well as with the City
Council’s policies in Resolution 9487 and 10077.21 CARB’s regulations require that the City
utilize the auction sale proceeds exclusively for the benefit of the City’s natural gas retail
ratepayers and consistent with the goals of AB 32.22 The City Council’s policy allows for the use
of Gas Cap and Trade revenue for investment in energy efficiency programs for the natural gas
portfolio and retail customers, purchases or investment in cost-effective renewable biogas
resources for the gas portfolio, fuel switching from natural gas to electricity that reduces
greenhouse gas emissions, investment in other carbon reduction activities for the natural gas
utility, including system maintenance or replacement to reduce fugitive gas emissions; and
rebates to natural gas retail ratepayers. The policy expresses a preference for greenhouse gas
reduction activities over rebates.
FISCAL/RESOURCE IMPACT
There is no increase to the City’s revenues as a result of the implementation of the 2026
Report.
STAKEHOLDER ENGAGEMENT
The UAC reviewed staff’s proposals for the Electric and Gas utilities at its April 2, 2025 meeting.
Regarding staff’s 2025 COSA and Gas Utility proposal, the UAC recommended approval of staff’s
proposal with a 5-1 vote, with one abstention. The Commissioner who voted against the staff
proposal expressed concern about the cost-of-service study results and in particular the
increase in rates for the residential (G-1) customer class. The UAC also recommended through a
6-1 vote to recommend to the Finance Committee and Council to approve the use of
approximately $1.6 million of Cap-and-Trade allowance auction proceeds to provide a one-time
flat climate credit of $73.20 to each residential (G-1) customer only in FY 2026.23 The
Commissioner who voted against the climate credit option said that green funds should not be
used to subsidize the use of fossil fuels. The video of the meeting is available on the City’s
website at the following link: https://www.youtube.com/watch?v=021zJQHLADI
The Finance Committee reviewed staff’s proposals for the Electric and Gas Utilities at its April
15, 2025 meeting. The Finance Committee did not take any action on the Gas Utility proposal
and continued the discussion of that proposal to May 7, 2025. During the discussion of the Gas
Utility proposal on April 15, Finance Committee members expressed concern about the bill
21 Resolution 9487 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=53850 ; Resolution
10077 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=61567
22 Title 17 California Code of Regulations Sections 95892 (d)(2) and 95893 (d)(3).
23 The Gas Utility is a covered entity under California’s Cap-and-Trade program. California Air Resources Board’s
Cap-and-Trade regulations authorize utilities to distribute Cap-and-Trade auction proceeds to some or all
ratepayers in a non-volumetric manner. (See CA. Code of Regs. Tit. 17 Sec. 95893(d)(3)(C)).
Item #4
Packet Pg. 59
Item No. 4. Page 14 of 15
22273783.1
impact to median and low usage residential (G-1) gas customers resulting from the 2025
Natural Gas Cost of Service and Rate Study.27
Finance Committee members requested additional information on whether the Gas Utility
could continue to rely upon the 2020 Natural Gas Cost of Service and Rate Study for another
year, what would a higher one-time climate credit look like for G-1 customer bills and whether
it is possible to spread the one-time climate credit across customer bills for a year. Committee
members requested additional examples and cost drivers. On May 7, 2025 staff presented
additional information to the Finance Committee, including an interim alternative
recommendation to continue the current FY 2025 rate structure based on the 2020 Cost Study,
with rate increases to meet FY 2026 revenue requirements, and provide a climate credit to
some of the G-2 small commercial customers (small and medium meter capacities), using
approximately $1.1 million in funding from the City’s Cap and Trade program revenue28
If the 2025 COSA had been implemented July 1, 2025, G-2 small and medium customers would
have received a reduction in their monthly service charges, as well as an increase in the
distribution charge per therm. The climate credit amount was calculated to make the G-2 small
and medium customer groups pay the same net amount as a result of retaining the current FY
2025 rate structure from July through December 2025, relative to what G-2 small and medium
customers would have paid under the 2025 COSA rates. The total cost of this climate credit is
$1.1 million. After discussion, the Committee voted unanimously to recommend the City
Council: 1) Revise the proposed FY 2026 rates to retain the current FY 2025 rate structure, with
rate increases to meet the revenue requirement for FY 2026 in the gas utility; 2) In FY 2026
only, apply a combination of climate credit (using Cap and Trade auction revenues) and FY 2025
gas utility interest income to G-2 customers (small and medium meter capacities) in the total
amount of $1.1 million and 3) Refer staff to return to the Utilities Advisory Commission (UAC) to
further review the FY 2025 Cost of Service Study (COSA) assumptions and principles.
On May 12, 2025 staff briefed the City Council on this topic and Council members asked
questions and discussed the item but did not take any action.
On June 16, 2025 the City Council returned the issue of a one-time credit to the UAC to be
considered at the time they review the updated COSA.
On September 2, 2025, the Finance Committee considered the UAC’s recommendation to direct
staff to use Proposition 26 as the Design Principle for the Gas Cost of Service Analysis and work
with the UAC on review of a recommended gas rate schedule effective by January 2026. The
Finance Committee voted unanimously to recommend the City Council direct staff to follow the
reasonable-cost analysis required by Proposition 26, and that staff work with the UAC on a
27 Staff presented the 2025 City of Palo Alto Natural Gas Cost of Service and Rate Study to the UAC and Finance
Committee.
28 May 7, 2025 Finance Committee Meeting
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=530a4f
25-5455-4cec-a95c-5190d95d9a4f; Video: https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Item
2.a., 3.b. Supplemental Report https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Video
Item #4
Packet Pg. 60
Item No. 4. Page 15 of 15
22273783.1
recommendation to the Council on revised gas rates effective January 2026, including: (1) Rates
must be based on the reasonable cost to serve customers. This is the overriding principle for
the cost-of-service analysis (COSA); all other rate design considerations are subsidiary to this
basic premise; (2) The COSA should involve a review of all existing rate schedules for
applicability in the COSA; (3) The impact of any proposed changes on low-income customers
should be evaluated in alignment with California Law; (4) Determine the proper allocation of
fixed and variable costs and how those can be implemented in various rate designs; (5) Review
non-rate revenue sources that may be available for rate discounts or rebates.
ENVIRONMENTAL REVIEW
ATTACHMENTS
AUTHOR/TITLE:
Item #4
Packet Pg. 61
Attachment A
* NOT YET APPROVED *
1
6059692
Resolution No.
Resolution of the Council of the City of Palo Alto Approving the 2026
Natural Gas Cost of Service Analysis Report, Amending Rate Schedules
G-1 (Residential Gas Service), G-2 (Residential Master-Metered and
Commercial Gas Service), and G-3 (Large Commercial Gas Service), and
repealing G-10 (Compressed Natural Gas Service).
R E C I T A L S
A. The City of Palo Alto (“City”) periodically conducts a Natural Gas Cost of Service
Analysis to follow the reasonable-cost analysis required by Proposition 26.
B. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
C. On December ___, 2025, 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 2026 Natural Gas Cost of Service Analysis
Report (Attachment B to the staff report presented to the City Council on December __ 2025);
SECTION 2. 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 attached and incorporated.
Utility Rate Schedule G-1, as amended, shall become effective February 1, 2026 (Attachment C to
the staff report presented to the City Council on December __ 2025);
SECTION 3. 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 attached and incorporated. Utility Rate Schedule G-2, as amended, shall
become effective February 1, 2026 (Attachment C to the staff report presented to the City
Council on December __ 2025);
SECTION 4. 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 attached and
incorporated. Utility Rate Schedule G-3, as amended, shall become effective February 1, 2026
(Attachment C to the staff report presented to the City Council on December __ 2025);
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule Rate Schedule G-10 (Compressed Natural Gas Service) is hereby repealed,
effective February 1, 2026.
Item #4
Packet Pg. 62
Attachment A
* NOT YET APPROVED *
2
6059692
SECTION 6. The City Council finds as follows:
a. Revenues derived from the gas rates approved by this resolution do not exceed the
funds required to provide gas service.
b. Revenues derived from the gas rates approved by this resolution 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 7. 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 #4
Packet Pg. 63
Attachment A
* NOT YET APPROVED *
3
6059692
SECTION 8. The Council finds that approving the FY 2026 Natural Gas Cost of Service
Analysis Report 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.
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 #4
Packet Pg. 64
22213852.2
Natural Gas Cost of Service
Analysis Report
City of Palo Alto
P R E P A R E D B Y E E S C O N S U L T I N G
October 22 , 202 5
Item #4
Packet Pg. 65
16701 NE 80th Street Suite 102 Redmond, WA 980 52 425-889 -2700 Fax 866-611-3791 www.eesconsulting.com
G e o r g i a Te x a s A l a b a m a N e w H a m p s h i r e Wi s c o n s i n Mai n e Wa s h i n g t o n C a l i f o r n i a
Amber Gschwend, Director
amber.gschwend@gdsassociates.com
direct 425-655-1042
October 22, 2025
Lisa Bilir, Senior Resource Planner
City of Palo Alto
250 Hamilton Avenue
Palo Alto, CA 94301
SUBJECT: Draft 2026 Natural Gas Cost of Service Analysis Report
Dear Ms. Bilir:
Attached please find the draft 2026 Natural Gas Cost of Service Analysis (2026 Report) for the City of Palo
Alto (City) prepared by EES Consulting (EES), a GDS Associates company.
We based the conclusions and recommendations contained within this report on industry practice and
accepted rate setting principles consistent with California law. The assumptions are based upon the
financial and metering data provided by the City. The results are consistent with the cost of service and
rate making principles considered by the City.
EES developed this study in consultation with the City’s staff and legal counsel, and we appreciate the
internal efforts that have helped to refine the study. We also would like to thank the Utility Advisory
Commission subcommittee members for their input and feedback. Collaboration among all these
stakeholders has improved the recommendations and strengthened the foundation in this utility planning
effort. The findings, conclusions, and recommendations of this report supply the basis for the
recommended, fair and equitable rates.
Very truly yours,
Amber Gschwend
Director, EES Consulting Director, EES Consulting
amber.gschwend@gdsassociates.com russ.schneider@gdsassociates.com
Item #4
Packet Pg. 66
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING i
TABLE OF CONTENTS
1 EXECUTIVE SUMMARY ................................................................................................... 1
1.1 System Description ............................................................................................................................................. 2
1.2 Rate Study Overview .......................................................................................................................................... 3
1.2.1 Revenue Requirement .................................................................................................................. 3
1.2.2 Cost of Service Analysis ............................................................................................................... 5
1.2.3 Rate Design Recommendations .................................................................................................. 5
1.2.4 Rate Change Recommendations ............................................................................................... 10
2 REVENUE REQUIREMENT DEVELOPMENT ................................................................. 12
2.1 Overview of the City’s Revenue Requirement Methodology........................................................... 12
2.2 Supply Costs ....................................................................................................................................................... 12
2.3 Distribution Costs ............................................................................................................................................. 13
2.4 Debt Service and Rate-Funded Capital Improvement Program (CIP) .......................................... 13
2.5 General Fund Transfer .................................................................................................................................... 14
2.6 Miscellaneous/Other Revenues .................................................................................................................. 14
2.7 Transfers to/from Reserves ........................................................................................................................... 14
2.8 Summary of Revenue Requirement........................................................................................................... 14
3 COST OF SERVICE ANALYSIS ....................................................................................... 16
3.1 COSA Definition and General Principles .................................................................................................. 16
3.2 City Natural GAs Distribution COSA Methodology ............................................................................. 17
3.2.1 Functionalization ........................................................................................................................ 17
3.2.2 Classification and Allocation of Costs ..................................................................................... 17
3.3 Average & Excess (A&E) ................................................................................................................................ 22
3.3.1 Average & Excess Calculation ................................................................................................... 23
3.4 Customer Weighting for Meter Costs ...................................................................................................... 27
3.5 Customer Classes of Service ......................................................................................................................... 28
3.6 Cost of Service Results ................................................................................................................................... 28
4 RATE DESIGN ................................................................................................................ 33
4.1 Recommended Rate Design: Distribution ............................................................................................... 33
4.1.1 Residential (G1) .......................................................................................................................... 33
4.1.2 Small Commercial and Residential Master-Metered (G2) ..................................................... 36
4.1.3 Large Commercial (G3) .............................................................................................................. 39
Item #4
Packet Pg. 67
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING ii
4.2 Supply Charges ................................................................................................................................................. 39
Item #4
Packet Pg. 68
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 1
1 Executive Summary
The City of Palo Alto (City) retained EES Consulting (EES), a GDS Associates company, to perform a natural
gas cost of service analysis (COSA) and rate study for Fiscal Year 2025-2026 (FY 2025-2026)1 (2026 Report)
as part of its ongoing efforts to maintain fiscally prudent, fair, cost-based rates for its natural gas
customers. This 2026 Report is primarily concerned with the development of natural gas distribution
rates.
While distribution rates are the primary focus of this study, the City also charges four supply-related rates.
These supply-related rates recover the costs that are outside of the immediate control of the City, such
as the cost of purchasing gas and transporting it to the City’s distribution system. These four rates are: 1)
the gas commodity rate, which represents the cost of buying gas in the markets, 2) the gas transportation
rate, which represents the cost of transporting purchased gas to Palo Alto, 3) the Cap and Trade
compliance rate, which represents the cost of mandated participation in the State’s cap and trade
program, and 4) the carbon offset rate, which represents the cost of buying offsets for the City’s Carbon
Neutral Gas Portfolio. These four charges are discussed at the end of this report.
The recommendations from this report are the second step in a 2-step rate adjustment process. The City
adopted this 2-step approach as a phase-in of rate changes. The first adjustment was an 8.7% across the
board rate increase effective July 1, 2025. This second adjustment is a rebalancing adjustment across rate
classes based on the results of this study.
The starting point for this analysis was the study completed for FY 2019-2020 (2020 Study). The City
updated the 2020 COSA model for FY 2020-2021 period (2021 Study), with some assistance by EES. Since
then, the City has implemented distribution system rate adjustments by uniformly adjusting distribution
rates using the percent change in the distribution revenue requirement; thus, distribution rates since 2021
have reflected the 2020 Study framework with an 8.7% increase to all rate schedules in July of 2025 based
on the City’s budget increase.
This 2026 Report is a comprehensive update to the 2020 Study. All assumptions and inputs have been
updated and new rate designs incorporated into the recommendations. This 2026 Report also
incorporates the City’s design principles in its recommendations.2
1 July 2025 through June 2026.
2On September 15, 2025, (Staff Report 2507-4958) the City Council directed staff to follow the reasonable-cost
analysis required by Proposition 26, and that staff collaborate with the UAC to develop revised gas rates effective
January 2026, based on the following design principles: (1) Rates must be based on the reasonable cost to serve
customers. This is the overriding principle for the cost of service analysis (COSA); all other rate design considerations
are subsidiary to this basic premise.; (2) The COSA should involve a review of all existing rate schedules for
applicability in the COSA; (3) The impact of any proposed changes on low-income customers should be evaluated in
alignment with state law, including, without limitation, Public Utilities Code sections 890 and 898; (4) Determine the
proper allocation of fixed and variable costs and how those can be implemented in various rate designs; (5) Review
non-rate revenue sources that may be available for rate discounts or rebates.
Item #4
Packet Pg. 69
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 2
EES worked closely with the City’s technical staff, management, and Utility Advisory subcommittee
members to refine data inputs for gas sales, expenses, and assets. EES had no issues obtaining appropriate
data responses or clarification when necessary and commends the transparency of the process and the
capability of internal resources.
1.1 SYSTEM DESCRIPTION
The City’s gas utility serves approximately 23,386 customer accounts over an area of approximately 26
square miles. The gas utility is responsible for the operations and maintenance of the distribution system,
and it purchases all gas from outside suppliers. Total gas consumption in the City forecasted for FY 2025-
2026 is 25.8 million therms. It is expected for sales to continue near their current weather-adjusted level
of 25 to 26 million therms per year and near the current volume of services. Table 1-1 shows the number
of services and annual gas use for each rate class.
TABLE 1-1: NUMBER OF SERVICES UNDER CURRENT RATE SCHEDULES AND
FORECASTED ANNUAL USE IN FY 2025-2026
Rate Schedule Services Annual Use, therms
G1 Residential 21,163 9,762,524
G2 Residential Master Metered and Commercial 2,193 11,506,051
G3 Large Commercial 30 4,510,914
Total 23,386 25,779,489
Gas utility rate schedules consist of a fixed Monthly Service Charge ($/meter/month) and a volumetric
Distribution Charge ($/therm), which vary by rate class. Volumetric charges recover the proportional costs
of both commodity purchases and variable distribution (infrastructure) costs.
Table 1-2 summarizes the rate classes and current rate design for the distribution portion of the rate
schedule. It does not include these volumetric supply charges: Commodity Charge (Monthly Market
Based), Cap and Trade Compliance Charge, Transportation Charge, and Carbon Offset Charge.
Item #4
Packet Pg. 70
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 3
TABLE 1-2: CURRENT DISTRIBUTION RATE DESIGN
Utility Rate Schedule Description Current Rate Design
G1: Residential Separately metered:
Single-family residential customers
Multi-family residential customers
2-Tier Volumetric Charge with seasonal
lower-cost tier 1 quantities
Tier 1 Summer:1 20 therms/30-day-billing
Tier 1 Winter: 60 therms/30-day-billing
G2: Residential Master-
Metered and
Commercial (“Small
Commercial”)
Commercial customers who use less
than 250,000 therms per year at one
site, and master-metered residential
customers in multifamily residential
Volumetric Charge, $/therm
G3: Large Commercial
least 250,000 therms per year at one
3
Volumetric Charge, $/therm
1. Summer rates effective April 1 through October 31. Winter rates effective November 1 through March 31.
1.2 RATE STUDY OVERVIEW
The purpose of this report is to discuss the data inputs, assumptions, and results that were part of
developing the rate study. A comprehensive rate study generally consists of three separate, yet
interrelated analyses. These three analyses include a revenue requirement, COSA, and rate design.
1. Revenue Requirement Analysis: This analysis examines the various sources and uses of funds for the
utility, and it determines the overall revenue required to operate the utility.
2. Cost-of-Service Analysis (COSA): COSA is used to determine the fair allocation of the total revenue
requirement to the various customer classes of service (e.g., residential, small commercial, large
commercial). This analysis provides a determination of the level of revenue responsibility of each class
of service and the adjustments from current revenues required to meet the cost of service.
3. Rate Design Analysis: The third analysis involves evaluating the rate design options available and
designing rate schedules that can be applied to each rate class to collect revenues to cover the cost
to serve customers in that class.
1.2.1 Revenue Requirement
The first step in completing a rate study is to develop the revenue required from rates. A revenue
requirement analysis compares the overall rate revenue demands of the utility based on its forecasted or
budgeted expenses less any sources of non-rate revenue. Over the course of the study period, the City
prepared several financial analyses that included a forecast of FY 2025-2026 sales, revenues, and
expenses. The City has an in-depth accounting and data system that keeps track of ongoing and budgeted
or approved expenditures. EES based the forecasts on projected FY 2026 expenses and sales estimates for
3 In addition to these standard rate classes, City of Palo Alto Utilities (CPAU) provides service to its CNG facility. This
facility does not utilize the distribution system, rather it is directly connected to the intertie with PG&E. As such, the
City is separately developing a cost-based fee for service administration. Changes in this fee do not materially impact
the COSA results.
Item #4
Packet Pg. 71
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 4
the natural gas utility. The 2026 Report uses a cash-basis method for determining the City’s revenue
requirement based on the City’s financial forecast. The cash-basis revenue requirement is appropriate
because it is consistent with how the City forecasts expenses for the natural gas utility.
FY 2025-2026 natural gas commodity costs are included in City’s financial plan. However, these costs are
adjusted monthly to pass through actual commodity rates charged to the City by its wholesaler. Therefore,
commodity charges are not set based on the 2026 Report; the 2026 Report only evaluates appropriate
distribution charges for the year.
Table 1-3 summarizes the FY 2025-2026 distribution revenue requirement totaling $41.3 million. Rates
were adjusted on July 1, 2025 to meet this requirement using the straight-line inflator approach. Because
the rate levels have been adjusted to collect the FY2026 revenue required from rates, the proposed
rebalancing and rate design changes recommended in the 2026 Report do not require an overall increase
in rate revenue. The 2026 Report recommends rebalancing between rate classes based on the COSA
results, and this rebalancing has rate and bill impacts to individual customers and across rate classes, as
summarized in Table 1-4.
TABLE 1-3: GAS DISTRIBUTION SYSTEM REVENUE REQUIREMENT: FY 2025-2026 Revenue Requirement
Distribution O&M $9,797,408
Customer Accounts and Services $3,208,008
Administration and General $5,002,927
Total Expenses $36,082,566
Total Revenue Required from Rates (Revenue Requirement) $41,268,342
Revenues Based on Rates Currently in Effect $41,268,342
Additional Rate Revenue Needed $0
Total Required Rate Revenue Increase (Decrease) 0%
TABLE 1-4 BILL IMPACTS OF PROPOSED REBALANCING AND RATE DESIGN
Rate Schedule Monthly Usage (Therms)
Current
Rates
Recommended
FY2025-2026 Rate
Bill
Impact
Residential
G-1 Summer: 10; Winter: 30 $50.78 $54.73 8%
Summer: 17; Winter: 51 $73.44 $79.33 8%
Summer: 30; Winter: 80 $127.24 $134.60 6%
Summer: 45; Winter: 150 $247.31 $263.50 7%
Commercial
G-2 Small: 35 $242.74 $103.05 (58%)
Medium: 280 $739.59 $676.33 (9%)
Large: 2,648 $5,558.74 $5,927.83 7%
G-3 20,834 $42,696.69 $44,131.74 3%
1. Includes supply-related costs; assumes 12-month impact.
Item #4
Packet Pg. 72
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 5
1.2.2 Cost of Service Analysis
Cost-of-service is important for the fair allocation of the revenue requirement to the various customer
classes of service. The revenue requirement shown in Table 1-3 for the City was functionalized, classified
and allocated.
Functionalization is the attribution of each cost line-item to one of four different functional parts of
gas service: (1) production (commodity), (2) transportation, (3) distribution, or (4) shared services.
This 2026 Report evaluates only distribution costs and distribution-related overhead (shared services).
Classification is the determination of whether the costs associated with a functionalized line item are
most appropriately allocated based on energy use (therms), demand (maximum system capacity), or
customer (simply having a service).
Allocation is the process of using the classification for each functionalized line item to assign costs to
each customer class. For example, a cost item classified as “energy use” might be allocated based on
annual therm use. This means that the line-item cost is directly correlated to the quantity of energy
used by each customer class annually. This process is described in more detail in the section titled
“Cost of Service Analysis.”
Ultimately, the COSA process requires analysis of how each customer class contributes to the expenses
incurred by the utility to provide service. Table 1-5 shows, by customer class, the revenue requirement
and revenue change needed for FY 2025-2026.
TABLE 1-5: DISTRIBUTION COSA RESULTS: FY 2025-2026
Projected FY 2025-
Revenue
FY 2025-2026
Deficiency/
Revenue
G1 – Residential $17,738,316 $19,210,223 ($1,471,907) 8.3%
$18,006,240 $16,095,484 $1,910,756 (10.6%)
$5,523,787 $5,962,635 ($438,848) 7.9%
Total $41,268,342 $41,268,342 $0 0.0%
1.2.3 Rate Design Recommendations
The final step in the rate study process is to design rates for each class of service. In California, local
governments are subject to Article XIII C of the California Constitution, as amended by Proposition 26,
which requires that gas rates and charges must not exceed the reasonable costs of providing gas service,
and requires that the City’s costs of gas service are allocated to each customer in a manner that bears a
fair or reasonable relationship to the customer’s burdens on, or benefits received from, the gas utility. As
a result, the City sets rates based on COSA results. The goal of rate design is to create rates that recover
costs from customers within each class based on the utility’s cost of providing service. The basis for each
rate design recommendation is provided in this section followed by the recommended rates.
All rate classes are charged a monthly service charge and volumetric charge to recover distribution costs.
EES does not recommend changes to this basic rate design structure, except for a refinement in the
Item #4
Packet Pg. 73
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 6
development of the Monthly Service Charge for G2 customers. The refinement is based on additional
analysis of G2 class usage and costs. Section 1.2.3.2, Commercial provides more details on this change.
1.2.3.1 Residential
The G1 distribution rates consist of a monthly service charge and a 2-tiered volumetric rate: the Tier 1
rate applies to usage up to the baseline quantity and the Tier 2 rate applies to all usage above the baseline.
The G1 rate structure proportionately recovers energy and demand (capacity) costs incurred by the class.
Specifically, individual residential customers have usage characteristics that are similar in both usage
profile and baseline usage. For the purposes of this 2026 Report, “Baseline” usage is defined as average
use and “usage profile” is defined as the shape of energy use over time. Figure 1-1 shows that the daily
usage profiles for residential customers are consistent between individual customers despite different
overall usage level (low, low-medium, medium-high, and high). Second, seasonal baseline usage within
the residential class is relatively uniform across individual customers. As such, a tier threshold can be
applied to customers without being discriminatory toward customers with higher use, because higher-use
customers only pay their proportional fair share of the incremental cost of serving that 2nd tier of use.
FIGURE 1-1: RESIDENTIAL DAILY GAS USE BY USAGE LEVEL:
DAILY SHARE (%) OF ANNUAL USE 4
While the tier rates do not change between seasons, the baseline quantity above which Tier 2 rates apply
does change and is higher in winter than in the summer because natural gas-based heating is used more
in the winter and causes higher gas consumption.5 Therefore, the class average therms are higher in the
winter than in the summer. This tiered structure ensures that all G1 customers pay for their Tier 1 demand,
but that all the costs of Tier 2 service are only borne by the customers that have Tier 2 demand. EES
4 CALMAC Customer Load Shapes - PG&E. https://www.calmac.org/customer_load_shapes_pge.asp
5 Usage above the Tier 1 baseline quantity is charged Tier 2 rate. The current quantity is 20 therms/30-day-billing in
summer and 60 therms/30-day-billing in winter.
Item #4
Packet Pg. 74
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 7
calculated the G1 tiered rates using the Base and Excess method (discussed in more detail in Section 4.1)
and proposes a modest increase of summer baseline from 20 to 23 therms per thirty-day billing period.
Table 1-6 summarizes the costs to be recovered in each rate component for G1.
TABLE 1-6: G1 RATES AND COST RECOVERY
Rate Component Recovers The Following Costs:
Monthly Service Charge Customer-related costs such as customer service, billing, and overhead adders
Tier 1 Volumetric Rate Energy-related costs plus 21% of demand-related distribution unit costs1
Tier 2 Volumetric Rate Energy-related costs plus 79% of demand-related distribution unit costs1
1See calculations in Section 4.1.1. Residential (G1) Rate Design, Table 4-3.
G1 usage patterns are distinguishable from G2 and G3 usage, and that difference in usage patterns is the
cause for a tiered approach to allocate costs among customers in the G1 (residential) class, but not in the
G2 or G3 classes. Average use is much more consistent (less variable) among all individually metered
residential customers in comparison to G2 or G3 customers. As shown in Table 1-7 below, G1 therm
consumption has a small variation between the median (midpoint consumption) and the average, and the
spread across all the data is relatively low compared with G2 and G3. To illustrate the relative variability,
the average is divided by the spread to produce 0.88 for G1. A higher value indicates that data is more
closely centered around the average value. The spread around G2 and G3 average use is much greater
(showing more variability), as indicated by the lower values of 0.33 and 0.41, respectively.
TABLE 1-7: AVERAGE THERMS/MONTH BY SERVICE ACCOUNT
G1
Residential
G2
Small Commercial
G3
Large Commercial
Average 33 462 13,534
Median 27 78 3,530
% Difference between Average and Median 23% 494% 85%
Spread (Standard deviation) 38 1,382 33,362
Average/Spread (coefficient of variation) 0.88 0.33 0.41
When average usage across individual customers in a class is similar, a certain threshold is associated with
a consistent or baseline share of system capacity that is used relatively proportionately by all customers;
usage above that threshold creates additional system capacity costs that are caused by only a small
portion of the customer base. Average use is an equitable threshold in a relatively low-spread
environment because it identifies the average consistent demand placed on the system by all users. Use
that exceeds the average creates a demand for additional capacity used by only a fraction of the
customers. A tiered system then allocates the additional (“excess”) capacity costs only among the
customers that placed the Tier 2 excess demands on the system. By structuring the rate this way, average
users are not forced to subsidize the costs of larger infrastructure they do not use. At the same time, the
initial average increment of usage is charged identically – so all users pay the same rate for usage up to
the baseline.
Natural gas is a service. Customers must pay not only for the commodity (the natural gas itself) that is
served to their property, but also for all of the infrastructure necessary to distribute the natural gas to the
property. For example, when all houses are the same size and have the same end-use systems, customers
Item #4
Packet Pg. 75
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 8
who use an average or below-average amount of natural gas should not only pay proportionally less for
the commodity than high users because they are using proportionally fewer molecules of natural gas; they
should also pay proportionally less of the additional costs incurred by the utility to serve the customers
who use excess energy at peak times (such as the incremental additional cost of a larger pipeline). A tiered
rate ensures that the City’s incremental additional costs to serve Tier 2 demands are charged to the cause
of those costs. Higher users therefore pay a marginally higher rate – but only for the portion of their use
that exceeds the average or baseline threshold.
1.2.3.2 Commercial
EES does not recommend changing the volumetric rate structure for G2 and G3 because the current
structure reasonably recovers individual customer energy and demand components according to how
each customer uses the system. While there are inherent differences in consumption across individual
customers within the G2 and G3 rate classes, the shape of these consumption profiles within each class
are relatively consistent as illustrated in Figure 1-2. Figure 1-2 illustrates the annual usage profiles for
different types of businesses. The differences in average consumption between customers are due
primarily to the type of business operation (end-use of natural gas i.e., refrigeration, heating, etc.) and
building footprint (square footage). Grocery store use averages 8 therms per day during the summer,
whereas government buildings average approximately 2 therms per day in the summer. Winter usage is
also significantly different between these business types, where grocery stores average 14 therms per day
and government buildings average closer to 8 therms per day. These differences in baseline usage mean
that a tiered rate applied to all customers within the class would result in subsidies between customers
with different baseline use. Because customers with higher baseline use would more often exceed the
threshold, those customers would pay more than their fair share of costs.
FIGURE 1-2: COMMERCIAL DAILY GAS USE BY BUILDING TYPE6
6 CALMAC Customer Load Shapes - PG&E. https://www.calmac.org/customer_load_shapes_pge.asp. The above
example profiles are included in G2 and G3 classes according to Table 3-4.
0
2
4
6
8
10
12
14
16
18
20
Th
e
r
m
s
Retail Religious Construction Office Government Grocery Health
Item #4
Packet Pg. 76
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 9
While these customers vary significantly in total gas usage, the usage profiles for commercial and
industrial customers are similar within each class (G2 or G3), as shown in Figure 1-2. Because customers
within each class have similar usage profiles, the cost to serve individual customers within each class is
similar from a volumetric perspective ($/therm). The similar cost of service is determined from the COSA
methodology which allocates costs based on class usage profile. Therefore, a uniform variable charge is
an equitable rate design for both G2 and G3 classes.
This 2026 Report updated input, assumptions, and calculations of fixed charges. The methodology and
supporting assumptions are detailed in Section 3. In addition to the methodology review, the 2026 Report
provides additional analysis for G2 meter capacity-related costs by comparing the average consumption
for various meter capacities. Fixed costs are higher for customers with larger capacity service because of
the larger and more expensive equipment required to provide higher capacity service. Three G2
subclasses are defined based on meter capacity, as shown in Table 1-8. The recommended monthly
service charge is developed based on the COSA methodology which, in part, allocates costs to each
customer class based on meter costs.
With the recommended rates, G2 customers would be charged a Monthly Service Charge based on
maximum meter capacity; customers with lower-capacity meters would pay a lower Monthly Service
Charge than those with higher capacity meters. For example, a customer with a meter capacity of 200
standard cubic feet per hour (scfh) would pay the lowest Monthly Service Charge, at $29.24.
TABLE 1-8: G2 MONTHLY SERVICE CHARGES: FY 2025-2026
CPAU Approved Maximum
7
Number of
Current Monthly
Service Charge
Monthly Service
Charge
1,136 $170.55 $29.24
940 $170.55 $94.56
117 $170.55 $419.08
While Table 1-8 shows the lower Monthly Service Charge for smaller G2 customers (defined as customers
with meter capacity up to 220 scfh), Table 1-9 illustrates that this same group of customers should also
receive an overall rate decrease. The rate decrease is primarily achieved through the lower monthly
service charge. The column “Revenue Requirement” in Table 1-9 presents the total revenue requirement
amounts (including fixed and variable costs) that correspond to the recommended Monthly Service
Charges shown in Table 1-8 above. The recommended rates for G2 are provided in Section 1.2.4.
7 All meters have a manufacturer-rated capacity and an approved for engineering maximum capacity. The CPAU
approved capacity is typically slightly lower than the manufacturer maximum capacity due to connected
characteristics and other variable conditions.
Item #4
Packet Pg. 77
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 10
TABLE 1-9: G2 REVENUES AND REVENUE REQUIREMENT: FY 2025-2026
CPAU Approved Maximum
2026 Revenues
at Current
Monthly Service
Revenue
Projected
FY 2026
Revenue
Change
$3,251,805 $1,740,448 ($1,511,358) (46.5%)
Above 220 but Below 4,000 $8,235,944 $7,630,668 ($605,276) (7.3%)
4,000 and Above $6,518,490 $6,724,368 $205,878 3.2%
Total G2 $18,006,240 $16,095,484 ($1,910,756) (10.6%)
Customers that exceed 250,000 therms per year in consumption are placed on the G3 rate schedule. For
this level of consumption, the service sizes and meter costs are much more uniform within the class
compared with G2. For example, the cost for the smallest meters in G3 is 56% of the cost for the largest
capacity meters. The same comparison for G2 results in the smallest capacity meter cost at less than 2%
of the cost of the largest capacity meter. Meter cost uniformity within a customer class is a factor in
determining a cost-based rate design for each class. Customers with larger meters are charged a higher
monthly Service Charge. Because individual customers within G3 have relatively uniform meter sizes and
costs, it is reasonable to charge the same monthly service charge to all G3 customers.
1.2.4 Rate Change Recommendations
Table 1-10 provides a comparison of current rates and recommended rates for FY 2026, including the
newly developed G2 Monthly Service Charge by meter capacity.
Item #4
Packet Pg. 78
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 11
TABLE 1-10: CURRENT AND RECOMMENDED RATES
Current FY 2025-2026 Percent
$18.40 $19.58 $1.18 6.4%
Distribution Charge ($/therm)
Tier 1
For Winter: first 60 therms/30-day-billing
For Summer: first 20 therms/30-day-billing
(current); first 23 therms/30-day-billing
$0.8944 $1.0456 $0.1512 16.9%
Tier 2
For Winter: over 60 therms/30-day-billing
For Summer: over 20 therms/30-day-billing
(current); over 23 therms/30-day-billing
$2.2873 $2.5203 $0.2330 10.2%
G2: Small Commercial (Total)
Monthly Service Charge $170.55 $78.03 ($92.52) (54.2%)
Distribution Charge ($/therm)
G2: Meter Capacity ≤ 220 scfh
Monthly Service Charge $170.55 $29.24 ($141.31) (82.9%)
Distribution Charge ($/therm) $1.1749 $1.2204 $0.0455 3.9%
G2: Meter Capacity > 220 scfh and < 4,000 scfh
Monthly Service Charge $170.55 $94.56 ($75.99) (44.6%)
Distribution Charge ($/therm) $1.1749 $1.2204 $0.0455 3.9%
G2: Meter Capacity ≥ 4,000 scfh
Monthly Service Charge $170.55 $419.08 $248.53 145.7%
Distribution Charge ($/therm) $1.1749 $1.2204 $0.0455 3.9%
G3 Large Commercial
Monthly Service Charge $780.34 $1,712.36 $932.02 119.4%
Distribution Charge ($/therm)
Item #4
Packet Pg. 79
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 12
2 Revenue Requirement Development
This section presents the development of the natural gas revenue requirement in the 2026 Report. A
revenue requirement analysis compares the overall revenues of the utility to its projected expenses and
determines the overall adjustment to rate levels required for the utility’s revenues to meet those
expenses.
2.1 OVERVIEW OF THE CITY’S REVENUE REQUIREMENT METHODOLOGY
The City utilizes the cash basis approach for determining its revenue requirement. The revenue
requirement for the City’s natural gas utility includes the elements shown in Table 2-1.
TABLE 2-1: ELEMENTS OF A CASH BASIS REVENUE REQUIREMENT
+ Operating Expenses
Natural Gas Supply Expense
Distribution O&M Expense
Customer Accounting Expenses
Administrative and General Expense
+ Capital Improvements Funded from Rates
+ General Fund Transfer
= Total Revenue Requirement
- Transfers from Reserves
- Miscellaneous Revenue Sources
= Net Revenues Required From Rates (or Net Revenue Requirement)
In this basic analytical framework, the first step in determining the revenue requirement is to select a
period over which to review revenues and expenses. This 2026 Report uses a future fiscal year test period
to correspond with the City’s budget year. The revenue requirement in this 2026 Report reflects the City-
provided financial forecast (budget) for FY 2025-2026.
The next step in the analysis was to translate the City-budgeted costs into the system of accounts used by
a natural gas utility.
2.2 SUPPLY COSTS
While this 2026 Report does not include an analysis for gas supply costs, a summary of these costs is
provided here for reference. As with most natural gas utilities, a major expense associated with operating
the utility is the cost of natural gas supply. The City is projecting FY 2025-2026 gas supply costs at $29.2
million or 42 percent of the total FY 2025-2026 revenue requirement. Supply costs are charged to
customers via four pass-through rate components. The following rate components are adjusted monthly
to reflect actual costs:
1. Gas commodity: This represents the cost of buying gas in the market.
2. Gas transportation: This reflects the cost of transporting purchased gas from the delivery points
to Palo Alto.
3. Cap and Trade compliance: This covers the cost of mandated participation in the State’s cap and
trade program.
4. Carbon offset charge: This accounts for the cost of buying offsets needed to comply with the City’s
Carbon Neutral Gas Portfolio Program.
Item #4
Packet Pg. 80
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 13
While the cost of natural gas supply is included in the 2026 Report, it is treated as a separate category
because the cost of natural gas supply is collected through separate rate components. A description of
these separate rates is provided in Section 4.2.
2.3 DISTRIBUTION COSTS
Total FY 2025-2026 revenue requirement for distribution is projected to be $41.3 million. Distribution
operating expenses include the following (other expenses are discussed in Sections 2.4 through 2.7):
Physical system costs of $9.8 million. These costs include the operation and maintenance of
distribution system infrastructure such as distribution mains, regulators, and meters.
Customer service-related costs of $3.2 million. These costs include meter reading, billing, key account
representatives and general customer service.
Administrative and general costs of $5.0 million. These costs include functions like accounting,
purchasing, legal, and other administrative functions provided by the City’s General Fund staff, as well
as Utilities Department administrative overhead, insurance, rent, and transfers to city non-enterprise
funds for items such as utility building improvements and to other enterprise funds for items such as
the gas utility’s share of Geographic Information System project costs.
The customer service category includes $0.5 million in expenses for energy efficiency, conservation
(demand side management), and low-income assistance programs. These expenses are incurred by the
gas enterprise as part of a program established by the City pursuant to California Public Utilities Code
Section 898. By virtue of this program, gas customers are exempted from a state surcharge that would
otherwise be collected on utility bills pursuant to Public Utilities Code Section 890. The City’s energy
efficiency and demand-side management programs reduce customer gas demand and are designed to
reduce the need for capital expenditures that would otherwise be needed to expand the capacity of the
gas distribution system.
2.4 DEBT SERVICE AND RATE-FUNDED CAPITAL IMPROVEMENT PROGRAM (CIP)
The City must cover its capital improvement projects (CIP) through either debt, cash from rates, or
external sources such as grants or loans.
For FY 2025-2026, the City has debt service payments of $0.8 million for past borrowings to fund CIP,
specifically the 2011 Series A Utility Revenue Refunding Bonds. This bond issuance was to refinance the
$18 million principal remaining on the Utility Revenue Bonds, 2002 Series A issued for the Gas and Water
Utilities to finance various improvements to the distribution systems.
The majority of CIP is funded from rate revenues. For FY 2026, the budgeted CIP is $7.5 million. This
amount is partially offset by contributions made by new customers in the form of connection fees. The
$0.7 million in connection fees is included in other revenues, which is further discussed below. Total FY
2025-2026 debt service and rate-funded CIP is $8.3 million before customer contributions.
Item #4
Packet Pg. 81
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 14
2.5 GENERAL FUND TRANSFER
The City calculates the equity transfer from its natural gas utility based on a methodology approved by
voters in November 2022.8 The General Fund Transfer is estimated to be $9.7 million in FY 2025-2026.
2.6 MISCELLANEOUS/OTHER REVENUES
The City receives additional operating and non-operating revenues. These revenues include interest
earned on City reserves, connection fees (customer charges that recover the cost of capital facilities
necessary to accommodate increased demand on the system) and other miscellaneous service revenues.
Miscellaneous revenues include customer discounts and uncollectible bills. These are recovered from non-
rate revenues, including interest income from investments. For FY 2025-2026, the projection for the total
miscellaneous/other revenues is $0.7 million. The miscellaneous/other revenues are separate from fixed
and volumetric charges for natural gas service and are therefore considered an offset to the total revenue
required from retail rates.
2.7 TRANSFERS TO/FROM RESERVES
In its FY 2025-2026 natural gas financial forecast, the City is anticipating that $5.9 million of rate revenues
will need to be added to the reserves in FY 2025-2026 to restore both the operating and CIP reserves. The
operating reserve balance is adjusted to meet future debt service requirements as projected from the
City’s financial plan. Additionally, the City plans to make contributions to the CIP reserve fund to balance
year-to-year fluctuations in CIP expenditures. The use of the reserve fund allows the City to have more
stable and gradual rate increases over time.
2.8 SUMMARY OF REVENUE REQUIREMENT
The City’s Distribution revenue requirement for the FY 2025-2026 test period is summarized in Table 2-2.
No overall rate increase is required to meet projected FY 2025-2026 costs, due to current overall rate
levels.
8 In November 2022, voters approved Measure L, amending the Municipal Code, Section 2.28.185, “Natural Gas
Utility Transfer” states: “Each fiscal year the City Council may transfer from the natural gas utility to the general fund
an amount equal to 18% of the gross revenues of the gas utility received during the fiscal year two fiscal years before
the fiscal year of the transfer. At its discretion, the City Council may decide to transfer a lesser amount. The projected
cost of the transfer shall be included in the City’s retail natural gas rates as part of the cost of providing gas service.”
Item #4
Packet Pg. 82
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 15
TABLE 2-2: SUMMARY OF NATURAL GAS DISTRIBUTION REVENUE REQUIREMENT: FY 2025-2026 Revenue Requirement
Distribution O&M $9,797,408
Total Expenses $36,082,566
$5,874,887
Total Revenue Required from Rates (Revenue Requirement) $41,268,342
Additional Rate Revenue Needed without Gas Supply $0
Item #4
Packet Pg. 83
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 16
3 Cost of Service Analysis
The objective of the cost-of-service analysis (COSA) is to allocate the costs in the revenue requirement to
each customer class of service to determine the cost to serve those customers. An essential principle of
cost allocation is the concept of cost-causation. Cost-causation evaluates which customer or group of
customers causes the utility to incur certain costs by linking system facility investments and the operating
costs to serve certain facilities to the way customers use those facilities and services. This section of the
report discusses the general approach used to allocate the City’s costs and presents a summary of the
results.
3.1 COSA DEFINITION AND GENERAL PRINCIPLES
A COSA study allocates the costs of providing utility service to the various customer classes served by the
utility based upon the cost-causal relationship associated with specific expense items. This approach is
taken to develop a fair and equitable designation of costs to each class of service. The COSA allocates joint
and common costs among the various classes using factors appropriate to each type of expense. The COSA
is the second step in a traditional three-step process for developing natural gas service rates, after
development of the revenue requirement but before designing rates.
This COSA study is an embedded cost analysis. Embedded costs generally reflect the actual costs incurred
by the utility and closely track the costs kept in its accounting records.
There are three basic steps to follow in developing a COSA: functionalization; classification; and allocation.
Functionalization separates costs into major categories that reflect the different services provided to
customers and the types of assets used to provide those services. The primary functional categories for
the City’s natural gas utility are supply and distribution.
Classification determines the portion of each cost that is related to specific cost-causal factors, or
“classifiers.” These classifiers might be demand-related (related to the class of service’s peak energy usage
over a given period), energy-related (related to the total energy used by the class of service over a given
period), or customer-related (costs incurred as a result of receiving service, regardless of the energy use
or peak demand). Natural gas supply or commodity costs are related to the amount of natural gas
purchased and are therefore considered energy-related. The distribution system is designed to extend
service to all customers attached to the system and to meet both the peak day demand and the annual
energy requirement of each customer, meaning that costs are both demand-related and energy-related.
Some operational costs, such as billing, are generally customer-related. Costs can also be classified based
on whether they are system-wide or specifically assigned to a customer or group of customers, if
appropriate.
Allocation of costs to specific classes of service happens after those costs have been classified. Allocation
factors are chosen to allocate the costs assigned to each classification, and the share of costs allocated to
each class of service are based on the class’s contribution to the specific allocation factor selected. For
example, certain distribution costs might be classified as partially demand-related and partially energy-
related. The demand-related costs could be allocated to the classes of service using each class’s
contribution to the annual system peak day demand (the highest day for the system as a whole at any
time during the year), while the energy-related costs would be allocated to classes based on their annual
energy usage. In this example, the allocation factors are 1) each class of service’s contribution to the
Item #4
Packet Pg. 84
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 17
annual system peak day demand, and 2) the annual energy usage of each class of service. An analysis of
customer requirements and usage characteristics is completed to develop allocation factors reflecting
each of the classifiers employed within the COSA.
3.2 CITY NATURAL GAS DISTRIBUTION COSA METHODOLOGY
3.2.1 Functionalization
As mentioned previously, this rate study addresses only the distribution portion of the City’s gas utility.
As such, all costs included in the revenue requirement have already been functionalized as Distribution.
Distribution costs include are allocated based on the depreciated value of all the physical assets (“rate
base”) and all operating costs required to transport the natural gas commodity from the point of
interconnection across the City’s distribution system to customers at their meters.
3.2.2 Classification and Allocation of Costs
The classification and allocation factors used for each component of the rate base and revenue
requirement are shown in Table 3-1 and Table 3-2 and are discussed in more detail below. The purpose
of looking at the rate base in the COSA is to set the cost causation associated with the physical assets,
which are then used to guide the allocation of the annual expenses. The rate base for the City’s natural
gas utility consists of the net value of its physical assets – both the distribution system itself (“Distribution
Plant”) and the natural gas utility’s fair share of general City facilities, equipment, and other capital such
as software that provide for the administration and general costs of the utility (“General Plant”). The rate
base is taken from audited fiscal 2025 physical asset/plant values. The revenue requirement is a
forecasted future year.
Descriptions of each factor are included in Table 3-3. In general, this COSA employs the same methodology
used in the 2020 Study but with changes to allocation factors based on updated cost-causation..
Specifically, the distribution rate base classification was updated as discussed in Section 4.3 below.
Distribution costs are classified into the following components: demand, energy, customer, and direct
assignments. The demand component reflects the portion of costs driven by peak demand for natural gas.
The energy component is related to costs incurred to provide the annual amount of gas to customers or
groups of customers. The customer component covers the facility and operating costs that vary with the
number of customers, such as meters and billing. Directly assigned costs are costs that can be attributed
to just one or more rate classes. The following are the specific classifiers used for the City’s distribution
function:
Demand. Demand-related costs are those that vary with the peak demand or the maximum rates of
natural gas supply to classes of service. Customer and system demands for this analysis are measured
in peak day therms. Demand costs are generally related to the size of facilities needed to meet a
customer’s maximum daily demand. Generally, the rate base is allocated based on the Average &
Excess method which involves a demand component (see Section 3.3). The allocated rate base is then
used to allocate certain revenue requirement expenses.
Energy. Energy-related costs are those that vary with the total amount of natural gas consumed by
customer class. Usage measured in therms is used in this portion of the analysis. Energy costs are the
costs of consumption over a specified period, such as a month or year. Reserve fund contributions are
an example of a cost item that is allocated to customer classes based on therms used. This ensures
that each customer contributes to the reserve fund based on their proportional use of the system.
Item #4
Packet Pg. 85
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 18
Customer. Customer-related costs are those that vary with the number of customers. Customer costs
are weighted to account for differences in the cost of providing services to those customers. For
example, the service line and metering associated with serving a large commercial customer is larger
and more costly and requires substantially more work and material than the service line and meter
for a small residential customer. Customer service expenses are typically allocated to customers based
on some measure of number of customers or weighted customer service factors based on the amount
of time and complexity to provide service to different types of customers.
Direct Assignment. Some costs are directly assigned to specific classes of service. For example, costs
associated with specific account representatives to large commercial customers are allocated directly
to the G3 rate class. In exchange, G3 does not share in other customer service costs incurred by the
other classes.
The methodology for classification and allocation of the City’s rate base is summarized in Table 3-1. All
line items in this table are functionalized as Distribution.
Note that the rate base does not reflect the annual expenses associated with running the utility but
instead reflects the capital investments made by the utility for the physical assets in the distribution
system or that are part of the general administration of the utility. The purpose of looking at the rate base
in the COSA is to set the cost causation associated with the physical assets, which are then used to guide
the allocation of the annual expenses.
Working capital is traditionally added to cover the cash on hand needed to run the utility. An estimate of
1/8th of operating costs is typically used to reflect the lag time between revenue collections and accounts
payable. This metric, 1/8th of annual expenses, or 45 days,9 is common because it accounts for the
operating expenses that need to be paid prior to the collection of revenues after metering and billing.
9 One eighth of 365 days is 45.
Item #4
Packet Pg. 86
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 19
TABLE 3-1: DISTRIBUTION RATE BASE
Asset Description
Asset Value
FY 2021-2022 10
and Allocation
Equipment-Meters
$12,334,716 CUSTM Weighted by Meters and
Total Distribution Plant $155,578,873
General Plant
$1,910,425 GPLT Plant
$2,911,310 GPLT Plant
Total General Plant $4,821,735
Total Gross Plant in Service $160,400,608
Less: Accumulated Depreciation
Total Accumulated Depreciation
Total Net Plant
Working Capital: 1/8 Operating Costs
$2,251,043 OMWOP Expense
TOTAL RATE BASE
Constructions Working in Progress
(CWIP)
Total CWIP
TOTAL RATE BASE plus CWIP $117,034,679
Next, the methodology for classification and allocation for the City’s Natural Gas Distribution revenue
requirement can be found in Table 3-2. More detail on the classification and allocation factor codes used
in the classification and allocation process can be found in Table 3-3. Two changes were made to the
allocation factor assumptions since the prior study:
10 Fiscal year ending June 30, 2022 was the audited asset values available for the study period.
Item #4
Packet Pg. 87
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 20
1. The general fund transfer allocation was updated from net plant to revenue. This update reflects
a policy change approved by the voters via Measure L, approved in 2022 where the transfer is
calculated as a share of rate revenue.
2. Reserves contributions or transfers are allocated based on therms. The reserves are used to
stabilize supply costs. Supply costs are 100% energy related; therefore, this line item should be
classified and allocated based on energy.
TABLE 3-2: DISTRIBUTION REVENUE REQUIREMENT
FY 2025-2026
Classification
and Allocation
Engineering Support 768,861 RBD Distribution Rate Base
Operations & Maintenance 9,028,547 RBD Distribution Rate Base
9,797,408
Admin - Customer & Marketing
$227,967 CUSTW Weighted for
$485,915 CUSTM
$543,152 CUSTW Weighted for
$9,850 CUSTW Weighted for
$155,106 DA1
$1,266,689 CUSTW2 Weighted for
Total Customer Service, Accounts &
Sales $3,208,008
Administrative & General
Administrative & General Salaries 11 $1,451,715 OMAG
11 Administrative and General Salaries includes salaries and benefits for staff assigned directly to Gas Utility
Administration.
Item #4
Packet Pg. 88
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 21
FY 2025-2026
Classification
and Allocation
Allocated Charges 12 $2,735,638 OMAG
Rents $574,830 OMAG
Transfers to Non-Enterprise Funds $59,411 OMAG
Transfers to Enterprise Funds $181,333 OMAG
Administrative & General Salaries
Total Costs with A&G
Interest and Debt Service Expense
Total Debt Service /Capital
Improvement $8,339,643
Revenue Requirement Before Other
Revenues $41,957,453
Other (Revenues) & Expenses
$449,823 NETPLT
($625,693) NETPLT
Total Other Revenues
REVENUE REQUIREMENT for COST
ALLOCATION $41,268,342
Table 3-3 shows how each factor code classifies then allocates the costs to classes of service. The Average
& Excess (AE) allocator is described in greater detail below the table.
12 Allocated charges are general costs incurred on behalf of all of the City’s utilities (water, wastewater, fiber, electric
and gas) that are individually determined and allocated to each business line, as well as salaries and benefits
allocated based on Capital Improvement Project cost centers.
13 This includes uncollectible accounts for bad debt, low-income rate assistance discounts, and pre-1970s retired
employee discounts on utility bills at a primary residence. These are funded through non-rate revenues and Public
Utilities Code 890 revenues.
Item #4
Packet Pg. 89
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 22
TABLE 3-3: NATURAL GAS DISTRIBUTION REVENUE REQUIREMENT
Factor Code Factor Name Classification Allocation Basis
AE Average and Excess 63% Demand
37% Energy and Above Average (Excess) coincident
peak demand. Energy portion is remaining
share of A&E attributed to average
Accounting/Metering w/o G3 accounting and metering but excluding G3
Rate Base 34% Energy
8% Customer
based on the net book value of all shared
services assets and other capital assets
Gas Supply and A&G) 30% Energy Gas Supply and A&G expenses
Rate Base 34% Energy based on the book value of all general plant
(w/o General Plant & 34% Energy value of all capital assets (initial cost)
34% Energy
8% Customer
value of all capital assets (initial cost less
accumulated depreciation) assigned to
Purchased Gas Supply) 30% Energy the cost of Purchased Gas Supply
3.3 AVERAGE & EXCESS (A&E)
The classification and allocation of several rate base line items in Table 3-1 are based on the Average &
Excess (A&E) method. This 2026 Report improves the A&E methodology to better align with how the
distribution system is designed and built for reliable service. The 2020 Study classified A&E costs as 100%
demand-related and then used each customer’s share of demand to allocate those distribution costs
across customer classes. In this study, A&E is classified as both energy and demand to more accurately
reflect how the City’s distribution system is designed and built. The previous A&E method primarily
attributed system costs entirely to demand, which is an appropriate option for systems experiencing
growth. Now that the system is expected to exhibit declining use, and because capacity sizing is
determined based on both energy and demand, the revised A&E method is recommended. The system
planning criteria and the associated recommended A&E method are described below.
Item #4
Packet Pg. 90
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 23
The natural gas utility’s capital plan is primarily focused on upgrading and maintaining aging infrastructure
rather than expanding the system for growth. When evaluating the sizing of mains, City engineers model
the annual maximum demand (i.e., highest gas consumption during a January cold spell) to determine the
optimal system size to meet customers’ peak demand. The modeling also incorporates an analysis of
energy usage depending on the physical structure of the distribution system. The energy component is
particularly important to analyze when a network of mains result in endogenous impacts when one or
more of the pipes is replaced or resized. For example, the City’s engineers evaluate main sizing when
planning for replacement projects. In areas where a portion of the system has more than one main
providing service, engineers model the sizing of the main being replaced based on locational energy use
and available capacity of adjacent mains. Depending on the capacity and energy available from the other
mains, the replacement main can be resized to minimize cost on the system. This is particularly important
where usage has declined (or expected to decline) since the system was originally put into service.
Because both demand and energy use are important factors in considering current and future capacity
investments in the system, the distribution rate base is classified as both demand and energy under the
revised A&E method. Demand-related costs are then allocated to customer classes based on each class’s
contribution to peak demand. Energy-related costs are allocated to customer classes based on therms.
The revised A&E classification to demand and energy is based on a comparison of the energy used (the
“average”) against the maximum demand (the “excess”). Maximum demand is equal to the highest daily
usage for the class in each month or the non-coincident peak (NCP). The NCP is the sum of individual
customer peaks within the class independent of the system peak timing.
Overall, the A&E method makes the following assumptions:
1. Average energy represents the capital investment needed to serve the average customer in each class;
2. Excess use is the additional investment needed to serve customers with demands that vary by season.
Those customers with higher excess use require a larger investment in the system compared with
customers whose usage remains close to the average use year-round.14 Allocating excess use costs only to
excess users reasonably places those increased costs on only the customers that created the need for
capacity above their average use; otherwise, customers with lower use would arguably be subsidizing
customers higher use.
3.3.1 Average & Excess Calculation
As explained above, the A&E method classifies (splits) distribution costs between energy and demand
components. This classification recognizes that a portion of the distribution system is engineered to serve
a customer with average energy. In addition, another portion of the distribution system investment is
needed to meet customer maximum use (excess demand).
14 A good example of this type of customer is an individually metered multi-family unit. These customers have low
average use and the services needed for each unit are lower in cost compared with services needed to serve a single
family home (not shared).
Item #4
Packet Pg. 91
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 24
In order to develop the A&E calculation, daily or hourly load profile data is needed to calculate class load
factors. A load factor is the ratio of average use to peak use over a given time period. A low load factor
(for example 30%) indicates that average natural gas usage for that customer is relatively low compared
to that customer’s peak usage. A low load factor customer is more costly to serve on a $/therm basis since
there are fewer therms over which to spread system capacity costs. Due to the relationship between load
factors and cost of service, these factors are key components of the recommended cost allocation
methodology from the COSA.
The City does not yet have hourly or daily meter data from which to calculate load factors. In lieu of specific
Palo Alto data, daily load profiles were developed using public data available from California Management
Advisory Council (CALMAC).15 These load profiles are a good approximation for Palo Alto customers
because they are developed by a neighboring utility for the portion of its service area that has similar
weather conditions to Palo Alto as well as similar building attributes (based on California building codes
for example).
The overall method applies Palo Alto monthly usage data by class to the daily curves from CALMAC. The
CALMAC data is based on PG&E load research data for calendar year 2024 and specifically for the coastal
region. This data is applied to the City’s FY2026 load data. Next, maximum day demands are calculated
for each rate class and for the system as a whole.
For the G1 class, several residential load shapes were aggregated to produce a class load curve. Figure 3-
1 illustrates the sample daily load curves for 4 usage groups ranging from low annual use (less than 235.4
therms) to high annual use (above 575.7 therms). The curves are similar in shape and differ primarily in
magnitude.
15 CALMAC Customer Load Shapes - PG&E. https://www.calmac.org/customer_load_shapes_pge.asp
Item #4
Packet Pg. 92
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 25
FIGURE 3-1: PG&E AVERAGE RESIDENTIAL DAILY LOAD BY HOME TYPE
Commercial building load shapes were aggregated to develop G2 and G3 class load shapes. In many cases,
building/business types can range in usage level; therefore, profiles may be included in more than one
class. Table 3-4 details the building segments included for each class.
TABLE 3-4: COMMERCIAL INDUSTRY SEGMENT ASSIGNMENT TO CLASSES
Segment
G2 –
Small
G2 –
Medium
G2 –
Large
G3 –
Large Commercial
Multifamily Included Included Included
Automotive and Repair Included Included Included Included
Construction Included Included Included Included
Education Included Included Included Included
Full Service Restaurants Included Included
Gas Station & Convenience Stores Included Included
Government (Institutional) Included Included Included Included
Grocery Included Included Included Included
Health Included Included Included Included
Limited Service Restaurants Included Included
Lodging Included Included Included Included
Manufacturing Included
Office Included Included Included Included
Personal Care Services Included Included
Religious Included Included Included Included
Retail Included Included Included Included
Transportation & Utilities Included Included Included Included
Warehouse Included
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
Th
e
r
m
s
0 - 235.37 therms 235.37 - 378.83 therms 378.83 - 575.72 therms > 575.72 therms
Item #4
Packet Pg. 93
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 26
Figure 3-2 compares the resulting daily therm usage by class after the class profiles are applied to monthly
Palo Alto use. Notably, the G1 profile is characterized by a much larger increase in peak winter demand
compared with G2 and G3 classes. This relationship is observed even after adjusting for relative load sizes
across classes.
FIGURE 3-2: PALO ALTO CLASS LOAD
3.3.1.1 Load Factor Calculations
Monthly class load factors were calculated from monthly usage, each month’s individual maximum day
usage (demand or non-coincident peak) and the number of days per month. Load factors are calculated
for each month according to the equation below where usage is the total therms per month, demand is
the maximum daily therms in that month, and days is the number of days in the month. So, a residential
customer who uses 60 therms in January, and has a maximum daily use of 2.74 therms, has a load factor
of 70.6% for January.16
𝑳𝑳𝑳𝑳𝑳𝑳𝑳𝑳 𝑭𝑭𝑳𝑳𝑭𝑭𝑭𝑭𝑳𝑳𝑭𝑭= 𝑼𝑼𝑼𝑼𝑳𝑳𝑼𝑼𝑼𝑼(𝑫𝑫𝑼𝑼𝑫𝑫𝑳𝑳𝑫𝑫𝑳𝑳∗𝑫𝑫𝑳𝑳𝑫𝑫𝑼𝑼)
Table 3-5 contains the monthly load factor results by class. A lower load factor indicates that peak daily
use is relatively high compared to the average use over the same period. These customers typically have
16 Load factor = 60 therms divided by (31 days x 2.74 therms) = 70.6%.
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
7 8 9 10 11 12 1 2 3 4 5 6
Th
e
r
m
s
/
d
a
y
Month
G1 G2 Small G2 Medium G2 Large G3 Total System
Item #4
Packet Pg. 94
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 27
a higher cost to serve because more capacity is needed to serve them, but energy use is relatively lower,
all else equal. The G1 rate class has the lowest average monthly load factor. The lower load factor is also
illustrated in Figure 3-2 where there is a larger difference in winter use compared with summer use. Lower
load factors result in higher volumetric rates because costs associated with the required system capacity
are spread over a lower number of therms. For example, two customers groups with the same maximum
consumption but different load factors will have different $/therm rates. Both groups use the same share
of system capacity; however, the customer group with lower energy use will have a higher rate in $/therm.
TABLE 3-5: LOAD FACTOR BY CLASS
CY Month G1 G2 – Small G2 – Medium G2 – Large G3
2025 7 70.6% 89.8% 90.0% 87.9% 87.6%
2025 8 73.8% 89.0% 89.1% 86.1% 90.6%
2025 9 74.8% 82.1% 82.1% 79.0% 83.2%
2025 10 55.7% 68.5% 68.3% 60.5% 68.8%
2025 11 59.5% 72.6% 72.4% 67.7% 72.1%
2025 12 65.1% 74.8% 74.5% 70.1% 74.0%
2026 1 75.4% 81.8% 81.8% 79.1% 81.9%
2026 2 59.7% 72.4% 72.2% 68.5% 71.7%
2026 3 63.2% 72.4% 72.3% 69.4% 71.8%
2026 4 58.7% 75.9% 75.6% 70.8% 75.5%
2026 5 65.0% 78.2% 78.2% 74.3% 78.7%
2026 6 75.5% 86.8% 86.8% 83.2% 87.1%
The load factors are used to calculate each class’s NCP (sum of individual customer peaks). The NCP is
used to measure the “excess” demand portion in the A&E calculation. The NCP is appropriate because the
system sizing is based on the sum of individual customer peaks regardless of when the peaks occur.
3.4 CUSTOMER WEIGHTING FOR METER COSTS
The number of customers weighted by meter costs is used in the study to allocate meter asset value in
the rate base. Weighted meter costs are appropriate for allocating meter asset values in the rate base
because they represent the relative cost of replacing meters for each class as infrastructure ages. “Meter
costs” for each customer class are equal to the current replacement cost of the meters (equipment) plus
labor costs for installation. Utilities typically do not record original meter and installation costs by
customer or location; therefore, the next best measure for service cost is the current replacement cost.
Table 3-6 compares the resulting meter costs. This 2026 Report uses an average of meter replacement
costs based on the count of all meter types currently in service within each class. This weighted average
cost is most appropriate because it considers all of the meter types and requisite costs used by each class
of service.
TABLE 3-6: CUSTOMER WEIGHTING FOR METER COSTS: FY2026 G1 G2 G3
Meter Costs1 $414 $1,262 $10,473
Weighting $8,761,310 $2,772,869 $308,954
1. Meter Costs include both the cost of the assets and labor costs for installation. Costs are based on current
replacement costs and labor rates.
Item #4
Packet Pg. 95
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 28
The meter cost weighting from Table 3-6 results in a larger share of meter values from the rate base being
allocated to G1 and a relatively smaller share of meter rate base allocated to G2 compared with the 2020
Study. This update is one of the primary drivers for the rate rebalancing recommended in this study. Note
that the G2 class is later disaggregated into 3 subgroups based on meter size and usage. Meter costs for
G2 small, medium, and large are $313, $1,709, and $6,935, respectively. Taken together, the average is
G2 meter cost is $1,262 as shown in Table 3-7.
3.5 CUSTOMER CLASSES OF SERVICE
Customer classes of service refer to the arrangement of customers into groups that reflect common usage
characteristics or facility requirements.17 The classes of service used within this 2026 Report were as
follows: Residential (G1); Small Commercial (G2); and Large Commercial (G3). The City also serves its own
Compressed Natural Gas (CNG) meter. The costs for the CNG service are paid by the City’s Public Works
department. The City is developing a cost-based fee to recover the CNG service’s fair share of metering
costs, service administration, and directly assigned costs. The estimated fee revenue is small (0.01% of
the total revenue requirement), and changes do not materially impact the results of this study.
3.6 COST OF SERVICE RESULTS
Given the key assumptions and updates discussed above, the COSA was completed. Tables 3-7 and 3-8
provide a summary of the Rate Base and Revenue Requirement amounts allocated to the various
customer classes.18 These schedules are calculated by multiplying the applicable classification and
allocation factors to each cost in the rate base and revenue requirement.
17 Breakpoints between or within rate classes are sometimes referred to as segmentation in rate making.
18 The rate base and revenue requirement tabs of the COSA model also show the rate base and revenue requirement
allocated to each class of service.
Item #4
Packet Pg. 96
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 29
TABLE 3-7: DISTRIBUTION RATE BASE ALLOCATION RESULTS: FY 2025-2026
Asset Description Total G1 Residential
G2 Small
G3 Large
Equipment-Meters $12,334,716 $9,124,973 $2,364,799 $844,943
Equipment-Services $59,109,371 $25,762,073 $22,504,632 $10,842,665
Equipment-Misc. $2,729,148 $1,189,465 $1,039,065 $500,618
Equipment-Regulators $976,067 $425,406 $371,617 $179,044
Equipment-Distribution Mains $77,559,779 $33,803,451 $29,529,232 $14,227,096
Equipment-Measuring $2,869,793 $1,250,763 $1,092,612 $526,417
Building $1,910,425 $878,671 $698,726 $333,029
Equipment $2,911,310 $1,339,013 $1,064,793 $507,505
($49,833,503) ($22,920,160) ($18,226,279) ($8,687,064)
($3,812,789) ($1,753,634) ($1,394,503) ($664,652)
$2,251,043 $1,160,297 $761,319 $329,427
TOTAL RATE BASE
$8,029,320 $3,692,963 $2,936,671 $1,399,685
Item #4
Packet Pg. 97
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 30
TABLE 3-8: DISTRIBUTION REVENUE REQUIREMENT ALLOCATION RESULTS: FY 2025-2026
Plant Description FY 2026 Total G1 Residential
G2 Small
G3 Large
Engineering Support $768,861 $353,626 $297,780 $117,455
Operations & Maintenance $9,028,547 $4,152,543 $3,496,760 $1,379,245
Total Distribution $9,797,408 $4,506,169 $3,794,540 $1,496,700
$465,537 $176,305 $207,750 $81,482
Total Customer Service $3,208,008 $2,197,456 $728,749 $281,803
Transfers to Non-Enterprise Funds
Total Administrative & General $5,002,927 $2,578,752 $1,740,020 $684,155
Total Costs with A&G $18,008,343 $9,282,376 $6,263,309 $2,462,658
Interest and Debt Service Expense
$23,348 $10,738 $9,042 $3,567
$778,250 $357,944 $301,417 $118,889
Total Debt Service /CIP Expense $8,339,643 $3,835,692 $3,229,947 $1,274,004
General Fund Transfer
Reserves Contribution
Revenue Requirement Before Other
Revenues $41,957,453 $19,527,169 $16,362,377 $6,067,907
Customer Discounts $318,105 $146,308 $123,202 $48,595
Connection Fees ($700,000) ($321,954) ($271,110) ($106,935)
$449,823 $206,889 $174,217 $68,717
($131,346) ($60,411) ($50,870) ($20,065)
Total Other Revenues ($689,111) ($316,946) ($266,893) ($105,272)
NET REVENUE REQUIREMENT $41,268,342 $19,210,223 $16,095,484 $5,962,635
Item #4
Packet Pg. 98
C I T Y O F P A L O A L T O Natural Gas Cost of Service Analysis
prepared by E E S C O N S U L T I N G 31
Table 3-9 provides a summary of the COSA results with the recommended revenue changes. These results
are the basis for the recommended distribution charges provided in the next section.
TABLE 3-9: DISTRIBUTION COSA RESULTS: FY 2025-2026
Projected FY 2026
Revenues
Revenue
Requirement
Projected FY
2026 Deficiency
Revenue
Change
Needed
G1 – Residential $17,738,316 $19,210,223 ($1,471,907) 8.3%
G2 – Small Commercial $18,006,240 $16,095,484 $1,910,756 (10.6%)
G3 – Large Commercial $5,523,787 $5,962,635 ($438,848) 7.9%
Total $41,268,342 $41,268,342 $0 0.0%
Residential and Large Commercial classes require rate increases and the Small Commercial class requires
a rate decrease. EES compared this study with the previous analysis (FY 2019-2020) and found the
following significant drivers for these results:
1. Overall, the FY 2025-2026 Distribution revenue requirement is 171% of the FY 2019-2020 revenue
requirement. The increase is due to multiple years of significant inflationary pressures and
planned reserve fund contributions.19 However, because the rate was adjusted on July 1, 2025,
the overall revenue level does not need to be increased at this time.
2. The allocation of the General Fund Transfer was updated from Net Plant to Revenue. As a result,
G1 is being allocated a larger share of the General Fund Transfer. Despite the adverse impact on
G1 rates, this update better aligns the expense item with cost since the General Fund Transfer is
calculated based on gross revenues.20
3. Customer allocators, such as customers weighted for meter costs, were updated to reflect current
meter cost and billing cost information. More detail on this analysis can be found in Section 3.3.2.
Further, the method for calculating the meter costs for each class was changed from using a
representative meter to using a weighted average for all meters in each class. These updates
resulted in larger shares of expenses allocated to G1 and G3. The development of these allocators
included a detailed analysis of the average cost of the average capacity meter for each rate class
and rate class grouping.
4. Previous studies relied on Average & Excess for some aspects of Distribution System Allocation,
and that is maintained in the current revision. However, the Rate Base Allocation of Distribution
19 Resolution 10232 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62153 approving the
Reserves Management Practices (Exhibit 3 to Resolution 10232)
https://www.paloalto.gov/files/assets/public/v/3/agendas-minutes-reports/agendas-minutes/city-council-
agendas-minutes/2025/june-16/rates-attachments/finalized-attachment-c-exhibit-3-fy26-gas-reserve-
management-practices.pdf)
20 In November 2022, voters approved Measure L, amending the Municipal Code, Section 2.28.185, “Natural Gas
Utility Transfer” states: “Each fiscal year the City Council may transfer from the natural gas utility to the general fund
an amount equal to 18% of the gross revenues of the gas utility received during the fiscal year two fiscal years before
the fiscal year of the transfer. At its discretion, the City Council may decide to transfer a lesser amount. The projected
cost of the transfer shall be included in the City’s retail natural gas rates as part of the cost of providing gas service.”
Item #4
Packet Pg. 99
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 32
assets was updated to reflect updated Average & Excess calculations. This change moved some
asset value from G1 to G2 and G3 based on the classes relative share of total sales. The
classification to both energy and demand better reflects how the system is planned and its current
operation, as discussed previously in the report. More detail on this update can be found in
Section 3.3.1.
5. Total use for all classes is lower in FY 2025-2026 compared with FY 2019-2020. Total G1 use
declined from 10.3 million therms to 9.8 million therms, G2 usage declined from 12.5 million
therms to 11.5 million therms, and G3 use declined from 5.6 million to 4.5 million therms. When
total use declines, fixed costs are spread across a smaller number of therms impacting the
$/therm rate.
In addition, all rate change aspects in this report are for distribution charges only and do not include
changes to supply. When considering overall rate impacts, it is important to note that most of these rate
changes are forecasted to be less than a 10% impact when considering combined commodity and
distribution charges.
Item #4
Packet Pg. 100
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 33
4 Rate Design
The final step in the rate study process is to design rates for each class of service or customer class. In
California, local governments are subject to Article XIII C of the California Constitution, amended by
Proposition 26 (2010), which requires gas rates and charges to not exceed the reasonable costs of
providing gas service, and requires that the City’s costs of gas service are allocated to each customer in a
manner that bears a fair or reasonable relationship to the customer’s burdens on, or benefits received
from, the gas utility. As a result, the City has set rates to match the COSA results for each customer class.
The results of the revenue requirement and COSA study are based on forecasted load data estimates and
usage pattern assumptions. Actual load and usage patterns may differ from the forecast. For this 2026
Report, rates are developed based on the forecast loads and observed historical usage patterns for each
customer class.
The rates for the Residential and Commercial customers are designed to reflect the differences in costs
among the various customer classes. The costs per customer class differ based on the seasonal shape of
consumption (referred to as energy use) as well as the daily peak demand for each customer class.
Differences in energy use by season and the level of peak demand have an impact on the utility’s need for
distribution facilities and the costs to operate and maintain those facilities.
4.1 RECOMMENDED RATE DESIGN: DISTRIBUTION
This section of the report reviews the present rate structures for the City and provides a comparison with
the recommended rates based on this cost of service study. Table 4-1 summarizes the current rate design
for each rate schedule and recommended rate design updates. As mentioned previously, the
recommended rate design is the same as the current rate design with the exception of some updates and
refinement as described below.
TABLE 4-1: NATURAL GAS DISTRIBUTION RATE DESIGN RECOMMENDATION OVERVIEW
Rate Schedule Current Rate Design Recommended Rate Design
Residential G1 Fixed Monthly Charge
Seasonal Tiered Rate with
Inclining Blocks
Update fixed and volumetric charges to cost of service unit costs
Calculate tiered rates based on Base and Excess methodology
Update Tier 1 summer baseline quantity
Small Commercial G2 Fixed Monthly Charge
Volumetric Charge
Update fixed and volumetric charges to cost of service
Implement three separate fixed monthly charges based on
Large Commercial G3 Update fixed and volumetric charges to cost of service unit costs
Table 1-10 in Section 1.2.3, Rate Recommendations, summarizes the current and FY 2025-2026
recommended rates for each class. The rate recommendations and bill impacts by rate class are provided
below.
4.1.1 Residential (G1)
The G1 distribution rates consist of a monthly service charge and volumetric tier rates: The Tier 1 rate
applies to usage up to the baseline quantity and the Tier 2 rate applies to all usage above the baseline.
While the tier rates do not change between seasons, the baseline quantity varies by season and is higher
in winter than in the summer because natural gas-based heating is used more in the winter. Therefore,
the class average therms are higher in the winter than in the summer. The tiered rate structure ensures
Item #4
Packet Pg. 101
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 34
that those customers contributing to higher seasonal demand are paying appropriately for their share of
the demand-related cost.
The current G1 Tier breakpoints (baselines) were evaluated using sales data for several test periods. Based
on average winter monthly use for 2022-2024, the winter baseline of 60 therms/30-day-billing is
appropriate. However, the most recent data supports increasing the summer baseline from 20 to 23
therms/30-day-billing. Table 4-2 shows the current baseline and average consumption values supporting
the recommendation.
TABLE 4-2: BASELINE QUANTITY ASSESSMENT
Tier 1 Baseline Assessment Therms/30-Day-Billing
Summer Winter
Current Baseline 20 60
Average Consumption
FY 2022 Actual 22 60
FY 2023 Actual 24 70
FY 2024 Actual 21 53
Gas Forecast FY 2026 24 56
Average of 3 Historical Years and 1 Forecast Year 23 60
Summer Winter
Recommended Baseline 23 60
The recommended baselines are used in the tiered rate calculations. The tiered rates recover all energy-
related distribution costs plus a share of demand-related distribution costs from each tier. The Base and
Excess capacity methodology is used to determine the portion of distribution demand costs collected from
each tier.21 The Base and Excess method first calculates G1 maximum annual use by applying G1 peak day
usage over the entire year. This assumes that the full capacity of the system is utilized year-round, which
is the basis for apportioning annual system capacity costs to Base use (Tier 1) and Excess use (Tier 2). If all
customers used this maximum amount of therms per day for the entire year, then the $/therm rate would
be a uniform rate. Because customers do not use the full capacity of the system year-round, the portion
of system capacity costs needed to serve demands above the base use level, are apportioned to the Tier
2 rate. Base level demand is thus collected in the Tier 1 rate by dividing distribution demand costs by the
annual use calculated at full capacity. The resulting $/therm is included in the Tier 1 rate. All excess
(remaining) demand costs are included in the Tier 2 rate. Table 4-3 illustrates the calculation of first tier
rate. Table 4-4 illustrates the calculation of the Tier 2 rate.
21 The Average & Excess methodology is used to apportion system costs to each rate class. The Base & Excess is used
only in the G1 tiered rate design.
Item #4
Packet Pg. 102
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 35
TABLE 4-3: G1 RATE CLASS TIER 1 RATE CALCULATION: BASE & EXCESS CAPACITY
Formula/Line Value Cost Share
Tier 1 Therms A 7,029,018
Distribution Demand Costs B $5,742,961 100%
Class Peak, therms/day C 89,733
Annualized Usage based on Peak
Demand, Therms
d = 365 × c 32,752,486
Tier 1 Demand Component, $/therm e = b ÷ d $0.1753
Tier 1 Demand Cost f = a × e $1,237,498 21%
Distribution Energy Costs g $8,495,630
Total Therms h 9,762,524
Energy, $/therm i = g ÷ h $0.8702
Tier 1 Total, $/therm j = e + i $1.0456
TABLE 4-4: TIER 2 RATE CALCULATION: BASE & EXCESS CAPACITY Formula/Line Value Cost Share
Tier 2 Therms k 2,733,507
Excess Demand Costs l = b – f (Table 4-3) $4,510,463 79%
Tier 2 Demand
Component, $/therm
m =l ÷ k $1.6501
Energy, $/therm i (Table 4-3) $0.8702
Tier 2 Total, $/therm n = m + i $2.5203
Table 4-5 shows the distribution bill impacts for average customer use in summer and winter.
TABLE 4-5: G1 BILL IMPACTS AT AVERAGE CUSTOMER USE, DISTRIBUTION ONLY
At Current Recommended Average Use
$40.86 $42.58 $1.72 4.2% 22.0
$74.58 $85.08 $10.50 14.1% 61.1
Item #4
Packet Pg. 103
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 36
Table 4-6 shows the impacts for a range of customer bills under various low, median and high usage levels.
TABLE 4-6: G1 BILL IMPACTS AT VARIOUS USAGE LEVELS, DISTRIBUTION ONLY
Season
Usage At
Current FY 26 Rates
At
Recommended
Distribution
Bill Impact
$/Month
Distribution
Bill Impact
$27.34 $30.03 $2.69 9.8%
$33.60 $37.35 $3.75 11.2%
30
45 $89.29 $99.07 $9.78 11.0%
Winter 30
(Median) 51 $64.01 $72.90 $8.89 13.9%
80
150 $277.92 $309.14 $31.22 11.2%
Annual (Median) 31
4.1.2 Small Commercial and Residential Master-Metered (G2)
The current G2 distribution rate design is composed of a fixed monthly service charge and a volumetric
charge. The fixed monthly service charge for a given rate schedule (customer class) is set to recover the
customer-related costs allocated to that schedule. As described in Section 1.2, Rate Study Overview, EES
recommends refinement in the development of the Monthly Service Charge for G2. Due to the diversity
in G2 meters and service sizes, and the methodology in the COSA that allocates fixed customer costs based
on meter costs, it is recommended to implement three separate Monthly Service Charges for G2 based
on service size. These service charges more precisely reflect the different services provided and the
associated costs for each of the three subclasses.
The creation of G2 subclasses (Small, Medium, and Large – defined below) is necessary to avoid intra-class
subsidies that exist from a single monthly service charge applied to customers that range in size from 36
therms per month to over 11,000 therms per month. G2 is unique in that the types of meters (and meter
costs) and customer usage represents a much wider range. To address the potential subsidies within the
class, G2 meter types and corresponding usage data is analyzed to determine G2 monthly service charges
that more precisely reflect customer-related fixed costs among differentiated subclasses within the class.
Figure 4-1 shows G2 meter capacity and associated average consumption. Meter size is positively
correlated with average use. This finding is expected and indicates that larger meters have higher average
use.22 Larger capacity meters also require larger service lines (connecting the meter to the distribution
system) and generally impose greater demand on the system. Recall that usage for commercial buildings
are uniform in shape but differ in relative size (Figure 1-3).
22 This is expected because meter capacity is sized to match the customer’s demand. City of Palo Alto, Utility Rule
and Regulation 15, Section B.6: Meter Installations, Capacity of Meters, April 2023.pdf
https://www.cityofpaloalto.org/files/assets/public/v/2/utilities/rules-and-regulations/rule-15-metering-april-
2023.pdf
Item #4
Packet Pg. 104
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 37
FIGURE 4-1: AVERAGE MONTHLY USAGE BY METER CAPACITY
Figure 4-1 shows distinct patterns and separations in average usage levels that support 3 G2 meter
groupings based on maximum meter capacity. Figure 4-2 shows the distinct average usage levels
associated with the following three groupings by maximum meter capacity (in standard cubic feet per
hour or scfh).
1. Up to 220 scfh (≤ 220 scfh)
2. Above 220 scfh and below 4,000 scfh (> 200 scfh and < 4,000 scfh)
3. 4,000 scfh and above (≥ 4,000 scfh)
Item #4
Packet Pg. 105
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 38
FIGURE 4-2: G2 – AVERAGE MONTHLY USAGE BY METER CATEGORY
The above G2 meter ranges were chosen based on a detailed examination of the use across different
meter types and capacities, according to summary data in Figures 4-1 and 4-2. This same rigor was also
applied to determine appropriate meter costs for G1 and G3.
The calculation for the G2 volumetric charge remains unchanged. As mentioned previously, the uniform
shape in G2 usage profiles supports a uniform volumetric rate. Recommended rates for G2 can be found
in Table 1-6, G2 Monthly Service Charges: FY 2025-2026, and Table 1-10, Current and Recommended
Rates.
Table 4-7 shows the G2 bill impacts for representative accounts in each G2 subgroup. Impacts for average
use and for 50% of average use are provided.
TABLE 4-7: G2 BILL IMPACTS, DISTRIBUTION ONLY
At Current
FY 2026-2027
FY 2025-2026
Average
# of
$684.29 $628.21 -$56.08 -8.2% 437 2,193
≤ 1,136
Average Use $235.17 $96.36 -$138.81 -59.0% 55
50% of Average Use $202.86 $62.80 -$140.06 -69.0% 28
˂ 940
Average Use $739.20 $685.24 -$53.96 -7.3% 484
50% of Average Use $454.88 $389.90 -$64.97 -14.3% 242
≥ 117
Average Use $4,615.20 $5,035.93 $420.74 9.1% 3,783
50% of Average Use $2,392.87 $2,727.51 $334.63 14.0% 1,892
Item #4
Packet Pg. 106
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 39
4.1.3 Large Commercial (G3)
The present G3 rate design is composed of a monthly service charge and a volumetric charge. As noted
earlier, this class generally has large capacity meters and a high consumption threshold for service. G3
rate schedule applies to commercial customers who use at least 250,000 therms per year at one site.23
This threshold, which defines the rate class, results in a group of customers with similar services and usage
characteristics, but very different usage levels. The service size and service cost uniformity means that
fixed customer-related costs are also uniform within the rate class. Therefore, as a single charge fairly
recovers the fixed customer-related charges from each customer. And, for tiered rates to be
nondiscriminatory, the class would need to be both uniform in usage profile and average use. Individual
customer baseline use is not uniform within this rate class. Therefore, tiered rates are not appropriate as
they would result in higher-use customers subsidizing lower-use customers. No change is recommended
in the overall design of these charges.
For illustrative purposes, Table 4-8 presents the G3 bill impact at 20,833 therms, which is 1/12 of the
annual threshold level for G3 service.
TABLE 4-8: G3 BILL IMPACTS, DISTRIBUTION ONLY
At Current FY FY 2025-2026
G3 Large Commercial $25,015.37 $26,450.39 $1,435.02 5.7%
4.2 SUPPLY CHARGES
The primary focus of the rate study was the distribution charges which vary based on budgets and
operating needs. The City also must pass through costs that vary based on external factors and market
conditions. These appear in rate schedules as Supply Charges. Supply charges include the Commodity, Cap
and Trade Compliance, Carbon Offset, and Transportation Charges. These charges are on a $/therm basis
and require frequent updates due to the variable nature of the underlying costs.
Currently, the City has a range included in the rate schedules. Table 4-9 shows the current ranges.
TABLE 4-9: SUPPLY CHARGES
Supply Charges $/therm
1. Commodity (Monthly Market Based) $0.10-$4.00
2. Cap and Trade Compliance Charges $0.00-$0.25
3. Transportation Charge $0.00-$0.30
4. Carbon Offset Charge $0.00-$0.10
EES examined both the current calculation of each charge and the basis for that calculation, as well as
whether the charge should remain a pass-through and whether or not a range of values is appropriate.
23 Utility Rate Schedule G-3.
Item #4
Packet Pg. 107
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 40
EES does not recommend any changes to the Commodity charge range. For the Commodity supply charge,
Council amended the Gas Utility Long-term Plan (GULP) Objectives, Strategies and Implementation Plan
including collecting funds via a gas price mitigation adder to manage potential future short-term natural
gas price spikes above the $4.00 per therm maximum charge (Resolution 101187, August 9, 2024). The
Commodity charge range, therefore, is consistent with the Council-approved strategy.
The City’s gas utility is a covered entity under the California Air Resources Board (CARB) Cap-and-Trade
program, under which the City is obligated to purchase allowances to cover all greenhouse gas emissions
resulting from natural gas use within Palo Alto’s service territory. EES recommends eliminating the ranges
for the Cap and Trade Compliance charge and instead converting this charge to a pass-through of the
City’s actual costs because the City has little to no control over them, and they are largely non-
discretionary. The Cap and Trade Compliance Charge is calculated based on the Cap-and-Trade program
quarterly auction allowance closing prices.
Likewise, EES recommends eliminating the ranges for the Transportation Charge and passing through
these charges. The Transportation charge is the rate the City pays Pacific Gas and Electric Company (PG&E)
to transport gas from the PG&E Citygate to the City of Palo Alto distribution system. PG&E is regulated by
the California Public Utilities Commission. Palo Alto has no control over these charges and no alternatives
for transporting gas to its distribution system. The Transportation Charge is based on PG&E’s wholesale
tariff (G-WSL)24.
Recently, the transportation charge exceeded the published range and the Council increased the upper
limit on the Transportation Charge.25 This is likely to occur for both the Transportation Charge and the
Cap and Trade Compliance Charges in the future. Because the true costs can vary outside of the ranges
provided, the ranges do not appear to provide material value to customers. If the costs vary outside the
upper limit of the range the costs above the limit are paid for by the gas utility’s reserves unless the Council
increased the upper limit. Updating the ranges with a wider spread would also provide less practical
information to customers. Therefore, EES recommends eliminating the ranges for the Cap and Trade
Compliance and Transportation charges. Two years of historical monthly values for the Transportation
Charge and Cap and Trade Compliance Charge are posted publicly on the City’s website for reference.26
EES does not recommend changes to the Carbon Offset Charge range. In December 2020 Council adopted
Resolution 99303, amending the Carbon Neutral Gas Plan. This program is voluntary in the sense that it is
a local program approved by the City Council rather than a compliance obligation imposed by the state or
another governing body. The amended plan limited the purchase price of offsets to $19 per ton CO2e,
24 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
25 On October 7, 2024, Council adopted resolution 10190 increasing the upper limit on the Transportation Charge on
all of the City’s gas rate schedules from $0.25 per therm to $0.30 per therm effective November 1, 2024.
26 Residential: 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 and
Non-Residential and Residential Master-Metered:
https://www.cityofpaloalto.org/files/assets/public/v/24/utilities/business/business-rates/monthly-gas-volumetric-
and-service-charges-commercial-3.pdf
Item #4
Packet Pg. 108
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 41
consistent with the original maximum 10 cents per therm rate impact, therefore the range is consistent
with the Council-approved program.
Second, EES recommends providing more detailed information on the source costs and calculation for all
four of the supply charges. Recommended additions include language in Table 4-10.
Item #4
Packet Pg. 109
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 42
TABLE 4-10: SUPPLY LANGUAGE
Supply Charges Description
1. Commodity (Monthly Market Based) This 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
discount (Adopted via Resolution 9451, on September 15, 2014), and $0.055 per therm
for mitigating the impact of short-term natural gas market price spikes.
The Commodity Charge calculation formula is:
PG&E Citygate Monthly Bidweek Price ($/MMBtu)
+ Gas Supplier Adder ($/MMBtu)
– Municipal Gas Discount ($/MMBtu)
× (1+ Distribution Loss Multiplier)
+ Gas Price Spike Mitigation Charge ($/MMBtu)
÷ 10 (conversion from MMBtu to therm) (MMBtu/therm)
= Commodity Rate ($/therm)
Where :
PG&E Citygate Monthly Bidweek Price is the monthly price for PG&E Citygate as
reported in the first issue of the month of Natural Gas Intelligence’s Bidweek Survey
as published by Intelligence Press Inc.
The Gas Supplier Adder is the premium or discount applied to the Bidweek Price Index,
based on the City's actual transactions with its natural gas suppliers.
The Distribution Loss Multiplier, updated annually, is calculated by the variances of gas
supply purchases and gas retail sales for the past three fiscal years.
2. Cap and Trade Compliance Charge
with the State’s Cap and Trade Program, including the cost of acquiring compliance
instruments sufficient to cover the Gas Utility’s compliance obligations. The Cap and
Trade Compliance Charge is adjusted in response to market conditions, retail sales
volumes, and the quantity of allowances required. The calculation formula is based on
carbon allowance auction prices and allowances needed to comply with state law. One
allowance is equal to 1 metric ton (MT) of CO2.
The Cap and Trade Compliance Charge calculation formula is:
Most Recent Auction Price ($/MT CO2)
x Number of Allowances Required (%)
x (conversion from MT CO2 to therm) (MT CO2/therm)
= $/Therm
Where:
Number of Allowances Required (%) =
(Projected Emissions for Current Year- Palo Alto’s Allocated Allowances for Current
Year)
÷ Projected Emissions for Current Year
Item #4
Packet Pg. 110
CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 43
3. Transportation Charge The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to Customer Meters. The current rates are shown in
this tariff https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-
WSL.pdf, provided by PG&E. Additionally, there is a distribution loss factor (updated
annually), which is calculated by the variances of gas supply purchases and gas retail
sales for the past three fiscal years.
The Transportation Charge calculation formula is:
PG&E G-WSL Transportation Charges ($/therm)
- Cap and Trade Cost Exemption ($/therm)
× (1+ Distribution Losses Multiplier)
= Transportation Charge ($/therm)
Where:
The Distribution Loss Multiplier, updated annually, is calculated by the variances of gas
supply purchases and gas retail sales for the past three fiscal years.
4. Carbon Offset Charge
gases produced when Gas is burned. The Carbon Offset Charge will change in response
to market conditions, sales volumes, and the quantity of offsets purchased within the
Council-approved cap of $19 per MT CO2e, calculated annually.
The Carbon Offset Charge calculation formula is:
Weighted Average Cost of Carbon Offset ($/MT CO2)
x (conversion from MT CO2 to therms) (MT CO2/therms)
= Carbon Offset Charge ($/therm)
Where:
Purchase Price of Carbon Offset ≤ $19/MT CO2e
Item #4
Packet Pg. 111
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-1 Effective 27-1-20265
dated 0711-1-20254 Sheet No G-1-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from City of Palo Alto
Utilities:
1. Separately-metered single-family residential Customers;
2. Separately-metered multi-family residential Customers in multi-family residential
facilities.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ..............................................................................................$ 19.5818.40
Tier 1 Rates: Per Therm
Supply Charges:
1. Commodity (Monthly Market-Based) ......................................... $0.10-$4.00
2. Cap and Trade Compliance Charge ............................................ $0.00-
$0.25Pass-through
3. Transportation Charge ................................................................. Pass-
through$0.00-$0.30
4. Carbon Offset Charge .................................................................. $0.00-$0.10
Distribution Charge:....................................................................................... $
1.04560.8944
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 ............................................. $0.00-
$0.25Pass-through
3. Transportation Charge ................................................................. $0.00-
$0.30Pass-through
4. Carbon Offset Charge .................................................................. $0.00-$0.10
Item #4
Packet Pg. 112
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 27-1-20265
dated 0711-1-20254 Sheet No G-1-2
Distribution Charge:............................................................................................. $
2.52032.2873
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.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
Item #4
Packet Pg. 113
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 27-1-20265
dated 0711-1-20254 Sheet No G-1-3
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, Cap and Trade Compliance, Carbon Offset and Transportation
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 0.667 therms per
day23 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). ,
rounded to the nearest whole therm, based on meter reading days of service. As an
example, for a 30 day bill, the Tier 1 level would be 20 therms during the Summer period
and 60 therms during the Winter period months. For further discussion of bill calculation
and proration, refer to Rule and Regulation 11.
{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/rates-schedules-for-utilities/residential-utility-rates/monthly-gas-
volumetric-and-service-charges-residential.pdf
Item #4
Packet Pg. 114
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 27-1-20265
dated 711-1-20245 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-Mmetered 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) .......................................................$ 29.24
2. Above 220 scfh and less than 4,000 scfh ................................................................$ 94.56
3. 4,000 scfh and above ...................................................................................$ 419.08170.55
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) ......................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges ........................................................... $0.00-
$0.25Pass-through
3. Transportation Charge .................................................................................. $0.00-
$0.30Pass-through
4. Carbon Offset Charge ................................................................................... $0.00-$0.10
Distribution Charge: .................................................................................................. $
1.17491.2204
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 Mmeter’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
Item #4
Packet Pg. 115
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 27-1-20265
dated 711-1-20245 Sheet No G-2-2
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.
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, Cap and Trade Compliance, and Carbon Offset and Transportation
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
Item #4
Packet Pg. 116
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 27-1-20265
dated 711-1-20254 Sheet No G-3-1
A. APPLICABILITY:
This schedule applies to the following Customers Commercial Customers receiving Gas Service
from the City of Palo Alto Utilities, who use at least 250,000 therms per year at one site:
2. Commercial Customers who use at least 250,000 therms per year at one site;
3. Customers at City-owned generation facilities including the City’s Natural Gas fueling
station at the Municipal Services Center.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: $ 780.341,712.36
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges ................................ $0.00-$0.25Pass-through
3. Transportation Charge .......................................................................... $0.00-
$0.30Pass-through
4. Carbon Offset Charge ........................................................................... $0.00-$0.10
Distribution Charge: .................................................................................................$ 1.16331.1874
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
Item #4
Packet Pg. 117
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 27-1-20265
dated 711-1-20254 Sheet No G-3-2
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 , Cap and Trade Compliance, Carbon Offset and Transportation
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.
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
Item #4
Packet Pg. 118
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-3 Effective 27-1-20265
dated 711-1-20254 Sheet No G-3-3
{End}
Item #4
Packet Pg. 119
Item No. 5. Page 1 of 12
6
8
0
4
Utilities Advisory Commission
Staff Report
From: Alan Kurotori, Utilities Director
Lead Department: Utilities
Meeting Date: November 5, 2025
Report #: 2503-4364
TITLE
Discussion and Update on the Fiscal Year 2027 Preliminary Utilities Financial Forecast and Rate
Projections
RECOMMENDATION
This item is for discussion, and no action is requested. These preliminary calculations reflect an
initial estimate for review and feedback by the Finance Committee and Utilities Advisory
Commission (UAC) on key assumptions for the Electric, Gas, Water, and Wastewater Collection
Utilities to inform recommended Fiscal Year (FY) 2027 financial forecasts and proposed rate
changes for each utility.
EXECUTIVE SUMMARY
The City of Palo Alto Utilities provides electricity, water, wastewater, natural gas, and fiber
optics. The City’s Public Works Department also provides refuse collection and processing for
recycling, compost and garbage, wastewater treatment and stormwater management services.
Customers benefit from the continued safe, reliable, environmentally sustainable, and cost-
effective operations of each of these utilities. FY 2027 preliminary calculations model necessary
rate increases to support upkeep, infrastructure replacements, and replenishment of reserves
to allow the City to continue to provide high quality utility services to the community.
All of the preliminary rate forecasts presented here are unchanged from the forecasts
presented to the City Council in June1, except for the Gas Utility. Last year’s Financial Forecast
projected a 6% increase for the Gas Utility in FY 2027 while staff now propose an 8% overall
revenue increase in FY 2027, which is equivalent to a 9% median impact to the residential
customer’s gas bill. Preliminary forecasts reflect a need for an overall 9% or $37.80 monthly
rate increase in FY 2027 for the median residential utility bill, encompassing six services
1 Staff Report 2411-3776, June 16, 2025
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=35104f
06-6925-4fe3-89c7-b0e53e6eec42
Item #5
Packet Pg. 120
Item No. 5. Page 2 of 12
6
8
0
4
(electric, gas, water, sewer, refuse, and stormwater). A Gas Utility cost-of-service study is on a
parallel process timeline for Council consideration. This preliminary financial forecast assumes
the gas utility cost allocations in the study are approved by Council and implemented in early
2026. The Refuse Utility is in the process of conducting a cost-of-service study and staff
anticipates the study results will be ready for review in early 2026.
BACKGROUND
Item #5
Packet Pg. 121
Item No. 5. Page 3 of 12
6
8
0
4
adjustments similar to those discussed last year are necessary to restore reserves to within
guideline ranges with the five-year planning period. For the Electric, Water and Wastewater
Collection Utilities, the proposed rate increases are the same as presented to the Council in
June 2025. However, for the gas utility due to declining sales revenues and increasing costs,
additional increases are necessary as described in more detail below.
ANALYSIS
1) Gas rate in FY 2027 based on General Fund transfer of 18% of gross revenue in FY 2025; changes
shown with commodity rates held constant; actual gas commodity rates vary monthly.
2) A rate increase is not included in Table 1 for Refuse in FY 2027 because the Cost of Service study
results are not yet available.
3) Stormwater management fees increase by Consumer Price Index (CPI) annually per approved 2017
ballot measure (2.6% in FY 2025).
4) Based on projected average monthly residential bill over FY 2026 of $442.60; includes proposed cost
of service adjustments for the Gas Utility in FY 2026 which are being presented to the UAC
concurrent to this report. This approach shows the proposed FY 2027 gas rate increase impacts
discussed in this preliminary rate proposal.
5) Bill dollar changes are rounded to the nearest $0.10, and bill percentage changes are rounded to the
nearest whole percent.
Item #5
Packet Pg. 122
Item No. 5. Page 4 of 12
6
8
0
4
Electric
The FY 2027 preliminary rate projections in the Electric Utility Financial Forecast are unchanged
from the FY 2026 Financial Forecast presented to the Council on June 16, 2025 of 6% for FY
2027.
At the end of FY 2025 the Electric Utility’s combined Operations Reserves for Distribution and
Supply totaled $46.6 million, which is close to the target level of $49.5 million.3 At the end of FY
2025 the following transfers were completed:
1) 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.4 These funds covered higher costs
during the pandemic, lower hydroelectric generation during the drought, and high
winter energy prices during 2022-2023.
2) 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 in FY 2025, bringing the hydro reserve balance to
$18.7 million, which is within the target hydro reserve amount of $19.0 million.5
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
3 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
4 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://www.cityofpaloalto.org/files/assets/public/v/1/agendas-minutes-reports/reports/city-manager-reports-
cmrs/year-archive/2017/8186.pdf. $5 million was repaid in FY 2020; See Staff Report 11341
https://www.paloalto.gov/files/assets/public/v/1/agendas-minutes-reports/reports/city-manager-reports-
cmrs/year-archive/2020/id-11341-mini-packet-062220.pdf. 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 13361,
June 13, 2022) https://www.cityofpaloalto.org/files/assets/public/v/6/agendas-minutes-reports/agendas-
minutes/city-council-agendas-minutes/2022/20220613/20220613pccsm-final-amended-linked.pdf#page=102. 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).
5 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 #5
Packet Pg. 123
Item No. 5. Page 5 of 12
6
8
0
4
recover higher supply costs.
Staff expects that debt will be issued later in FY 2026 to cover the grid modernization costs
already spent and planned in FY 2026. The Electric Distribution Operations Reserve is currently
low because it reflects grid modernization costs, commitments, and reappropriations planned
to be reimbursed through the debt issuance (an estimated total of $3.5 million in FY 2025 and
$6 million in FY 2026). As mentioned above, on a combined basis, the Electric Distribution and
Supply Operations Reserves are within the guideline range.
Staff updated the preliminary forecast for the electric supply purchase costs in FY 2027. Net
electric supply purchase costs are anticipated to be 3% higher than the FY 2026 Financial
Forecast. Revenues from selling surplus system Resource Adequacy and Renewable Energy
Certificates provide additional supply revenues.9 The demand forecast for FY 2027 is 8% higher
than that in the FY 2026 Financial Forecast. Transmission costs continue to rise, and capital
spending and distribution system maintenance spending is rising due to grid modernization and
other substation upgrades to increase capacity and enhance reliability, which will benefit all
electric ratepayers.
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://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment
/?historyId=cdf2cce3-a2be-45f3-9acf-9b073bb01196
Changes made after the Finance Committee Staff Report are described in the City Council
Report 2411-3776:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment
/?historyId=35104f06-6925-4fe3-89c7-b0e53e6eec42
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
Gas
Last year’s Financial Forecast (FY 2026) projected a 6% increase for the Gas Utility in FY 202710.
9 Resolution 9913 https://www.paloalto.gov/files/assets/public/v/1/city-clerk/resolutions/reso-
9913.pdf?t=40151.26, Staff Report 11556 https://www.paloalto.gov/files/assets/public/v/1/agendas-minutes-
reports/reports/city-manager-reports-cmrs/year-archive/2020-2/id-11566.pdf,
10 Staff Report 2412-3868
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=8bb9e
844-77c1-448d-b9f3-77514c21a64b
Item #5
Packet Pg. 124
Item No. 5. Page 6 of 12
6
8
0
4
In FY 2025, gas utility sales revenues were about $4.7 million (8%) lower than forecasted due to
lower-than-expected gas usage. Although supply purchases were $3.2 million (14%) below
forecast, the cost savings were insufficient to offset the revenue shortfall. Distribution expenses
were approximately $0.6 million (-4%) lower than projected, while CIP expenses exceeded
projections by about $6.8 million, most of which were funded through the CIP reappropriation
and commitments reserve. Also approximately $700,000 in additional funds will be needed in
FY 2027 for gas line repairs at Arastradero Creek. To offset these costs, the City received grant
funding of approximately $300,000 of Federal Energy Management Agency (FEMA) funding and
$95,000 in California Governor’s Office of Emergency Services (CalOES) funding that will be
shared among the Water, Wastewater Collection, and Gas Utilities in GS-25001 (the capital
project completing the emergency repairs at Arastradero Creek).
13 The Finance
Committee voted unanimously to recommend the City Council revise the proposed FY 2026
rates to retain the FY 2025 rate structure, with a rate increase to meet the revenue
requirement for FY 2026 in the gas utility, and to refer staff to return to the UAC to further
review the cost-of-service study assumptions and principles. On June 16, 2025 the City Council
agreed that the UAC should review the updated COSA.14
13 May 7, 2025 Finance Committee Meeting
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=530a4f
25-5455-4cec-a95c-5190d95d9a4f; Video: https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Item
2.a., 3.b. Supplemental Report https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Video
14 During the UAC, Finance Committee and Council meetings, various proposals were also discussed regarding one-
time credits using Cap and Trade auction revenues and ultimately the Council returned the issue of a one-time
credit to the UAC at the time they review the updated COSA. However, currently no credits are being proposed.
For a full history of those proposals, see UAC Staff Report 2411-3751 from April 2, 2025:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=29fcc1
53-3f31-44d8-9b96-ec5349e043c2; and Finance Committee Staff Report 2412-3868, April 15, 2025
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=8bb9e
844-77c1-448d-b9f3-77514c21a64b; and May 7, 2025 Finance Committee Meeting:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=530a4f
25-5455-4cec-a95c-5190d95d9a4f; Video: https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Item
2.a., 3.b. Supplemental Report https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Video; and Council
Staff Report 2411-3776 June 16, 2025:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=35104f
06-6925-4fe3-89c7-b0e53e6eec42
Item #5
Packet Pg. 125
Item No. 5. Page 7 of 12
6
8
0
4
UAC. 17 On September 15, 2025 the Council directed staff to follow the reasonable-cost analysis
required by Proposition 26 and to collaborate with the UAC to develop revised gas rates
effective January 2026 based on five design principles.18
Staff met with the UAC subcommittee four times from August through October, followed the
reasonable-cost analysis required by Proposition 26 and developed revised gas rates based on
the five design principles approved by the City Council. The implementation of the Gas Utility
rates resulting from the cost-of-service study on February 1, 2026 enables the utility to take a
stepwise approach to rate adjustments. This approach distinguishes the cost-of-service-based
rate changes, effective in early 2026, from the general gas utility rate increases proposed in this
report to take effect in July 2026 for FY 2027.
During the pandemic, the City kept overall Gas Utility rate increases at 2% to 3% annually and
utilized reserve funding to cover costs. In the winter of 2022-23, surging gas commodity prices
depleted the Gas Utility reserves, which covered the gap between actual gas commodity costs
and the Council-approved maximum gas commodity charge. Reserves need to be replenished
to provide a target of 90 days of operations and maintenance and commodity expenses.19
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. The preliminary forecast assumes a transfer based on 18% of estimated gross
revenues from FY 2025, to be $10.7 million in FY 2027, an increase of $1.0 million from FY 2026.
As a result of lower sales revenues in FY 2025, as well as additional projected capital costs, and
rising operating costs, staff now propose an 8% overall revenue increase in FY 2027 which is
equivalent to a 9% median impact to the residential customer’s gas bill. The FY 2027
preliminary Gas Utility Financial Forecast reflects a distribution rate increase of 14.5%, which is
equivalent to an 8% overall system average increase when combined with supply related
charges, assuming supply charges remain unchanged.
17 July 9, 2025, UAC voted 6-1 with Gupta voting no; see action minutes
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=40dc6
4ea-7e0c-4dca-9235-61e1a6516b07
18 Staff Report 2507-4958, September 15, 2025:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=043ab
d5a-f59f-4702-ad04-845541a8133f; see action minutes:
https://cityofpaloalto.primegov.com/Public/CompiledDocument?meetingTemplateId=16223&compileOutputType
=1
19 Staff Report 2411-3776, Attachment C, Exhibit 3, Section 8, Operations Reserve, June 16, 2025:
https://www.paloalto.gov/files/assets/public/v/3/agendas-minutes-reports/agendas-minutes/city-council-
agendas-minutes/2025/june-16/rates-attachments/finalized-attachment-c-exhibit-3-fy26-gas-reserve-
management-practices.pdf
Item #5
Packet Pg. 126
Item No. 5. Page 8 of 12
6
8
0
4
The current year (FY 2026) Financial Forecast for the Gas Utility (approved June 16, 2025) is
described in the Finance Committee Staff Report 2412-3868:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment
/?historyId=8bb9e844-77c1-448d-b9f3-77514c21a64b
Water
23; however, these funds were not
transferred at year-end because the Operations Reserve balance was already within the reserve
policy guideline range (see Table 2). The Rate Stabilization Reserve has $4 million remaining as
of FY 2025 year-end, which may be used to cover costs in FY 2026 or beyond, as determined by
City Council.
23 City Council June 16, 2025, Attachment B – Resolution for the FY 2026 Water Utility
Item #5
Packet Pg. 127
Item No. 5. Page 9 of 12
6
8
0
4
Table 2. Actual and Projected Reserve Balances and Guidelines ($000)*
25. Projected reserve guideline amounts for FY 2026 and FY 2027 reflect the FY27
Preliminary Forecast’s projected expenses.
26, the San Francisco Public Utilities
Commission (SFPUC), estimated a 1% increase to its wholesale water rate in FY 2027. Consistent
with this rate notice, the City’s preliminary forecast assumes that in FY 2027 SFPUC increases
the wholesale water rate from its current level of $5.80/CCF to $5.86/CCF. Table 2 shows rate
projections through 2030 as stated in the SFPUC’s May 8, 2025 wholesale water rate notice.
SFPUC’s wholesale rate projection is subject to change and highly uncertain.
25 Water Utility Reserve Management Practices; Section 5 (CIP Reserve), Section 7 (Operations Reserve):
https://www.paloalto.gov/files/assets/public/v/1/agendas-minutes-reports/agendas-minutes/city-council-
agendas-minutes/2025/june-16/rates-attachments/attachment-b-exhibit-3-fy26-water-reserve-management-
practices.pdf
26 San Francisco Public Utilities Commission Fiscal Year 2025-2026 Wholesale Water Rates, May 13, 2025,
https://sfpuc.sharefile.com/share/view/se9a42370c51345bd9d2b495f8b885fc0
Actual
FY 2025 FY 2026 FY 2027
Operations Reserve Balance 16,351$ 9,946$ 10,880$
Mininum Reserve Guideline (60 days of O&M and commodity expense) 8,353$ 9,451$ 9,589$
Maximum Reserve Guideline (120 days of O&M and commodity expense) 16,706$ 18,903$ 19,178$
CIP Reserve Balance 3,500$ 4,472$ 7,272$
Mininum Reserve Guideline (20% of the maximum CIP Reserve guideline
level)2,226$ 3,083$ 3,639$
Maximum Reserve Guideline (Average annual (12 month) CIP budget,
for 48 months of budgeted CIP expenses)11,129$ 15,416$ 18,197$
Rate Stabilization Reserve Balance 4,000$ 4,000$ 4,000$
Projected
Item #5
Packet Pg. 128
Item No. 5. Page 10 of 12
6
8
0
4
Table 3: SFPUC Commodity Rate Projection as of May 2025
The projected FY 2027 rate increase is necessary to pay for inflationary cost increases and to
comply with reserve guidelines while funding the necessary maintenance and replacement
activities that contribute to the safe and reliable provision of high-quality water to Palo Alto
residents and businesses. Absent sufficient and timely rate increases, the Water Utility is at risk
of further delaying capital maintenance projects, which increases costs long-term because of
construction inflation and potentially increasing maintenance costs and emergency repairs of
older water mains. Moreover, it puts the system at risk of further depleting reserves, which
reduces the financial flexibility to address unexpected costs.
The current year (FY 2026) Financial Forecast for the Water Utility (approved June 16, 2025) is
described in the Finance Committee Staff Report 2412-3869 from April 1, 2025:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment
/?historyId=8bb9e844-77c1-448d-b9f3-77514c21a64b
Changes made after the Finance Committee Staff Report are described in the City Council
Report 2411-3776:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment
/?historyId=35104f06-6925-4fe3-89c7-b0e53e6eec42
Attachment B, Exhibit 1 to City Council Report 2411-3776 includes financial and 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-
b-exhibit-1-fy26-water-utility-financial-forecast-and-cip-detail.pdf
Wastewater Collection
The FY 2027 preliminary rate projections in the Wastewater Collection Utility Financial Forecast
are unchanged from the FY 2026 Financial Forecast presented to the Council on June 16, 2025
of 16% for FY 2027.
In FY 2025, the Wastewater Collection Utility received approximately $2.7 million in grant
revenue from Valley Water. This funding was used to offset the Wastewater Treatment costs,
which is a direct benefit to the residents and businesses in Palo Alto.
At year end FY 2025, the Wastewater Collection Utility had approximately $0.9 million in cash
available, which is lower than staff’s projection. There is a possibility that the Wastewater
Collection Utility will not be able to fully repay the loan (Reso 10173)29 from the Fiber Utility
29 Resolution 10173: https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62043
Fiscal Year 2027 2028 2029 2030 2031
SFPUC Commod ity Rate Projection (as o f May '25)1%1%5%8%3%
Item #5
Packet Pg. 129
Item No. 5. Page 11 of 12
6
8
0
4
that is due to be repaid with interest in FY 2026. The loan may need to be extended to keep a
positive cash balance. Extension of the loan will not impact activities in the Fiber Utility.
Item #5
Packet Pg. 130
Item No. 5. Page 12 of 12
6
8
0
4
FISCAL/RESOURCE IMPACT
Based on the preliminary rate increases as shown, the estimated revenue impacts in FY 2027
represent an increase of $5.0 million in the Water Fund, $4.9 million in the Wastewater
Collection Fund, $5.5 million in the Gas Fund, and an increase of $12 million in the Electric
Fund. Utility rate increases impact the General Fund because the City is a utilities customer.
The impact to the General Fund of these preliminary rate increases is a $0.5 million expense
increase.
STAKEHOLDER ENGAGEMENT
Staff plan to present the preliminary rate information to the Finance Committee on
November 18, 2025. An excerpt of the minutes from the Finance Committee’s November 18,
2025 meeting will be located at the City’s Agenda’s and Minutes website
(paloalto.gov/councilagendas).
The UAC is scheduled to review the long-term Financial Forecasts and proposed rate
adjustments for the Electric, Water, Wastewater and Gas Utilities in March 2026. The Finance
Committee is tentatively scheduled to review the long-term Financial Forecasts and proposed
rate adjustments in Spring 2026. In late April or early May, notification of any recommended
Water and Wastewater Collection rate adjustments will be sent to customers, giving them the
opportunity to protest the proposed changes as required by Article XIIID of the State
Constitution (added by Proposition 218). The Financial Forecasts and proposed new rate
schedules will be considered by the City Council with the FY 2027 budget, at which time the
Public Hearing required by Article XIIID of the State Constitution will be held.
ENVIRONMENTAL REVIEW
The UAC’s review of the preliminary financial projections does not meet the definition of a
project, pursuant to Section 21065 of the California Environmental Quality Act, thus no
environmental review is required.
AUTHOR/TITLE:
Alan Kurotori, Director Utilities
Item #5
Packet Pg. 131