HomeMy WebLinkAbout2025-04-02 Utilities Advisory Commission Agenda PacketUTILITIES ADVISORY COMMISSION
Regular Meeting
Wednesday, April 02, 2025
Council Chambers & Hybrid
6:00 PM
Chair Scharff Remote Location: W Hotel, 550 S Spring St.
Aspen, Colorado 81611
Commissioner Gupta Remote Location: Share Lounge,
Tsutaya Bookstore Marunouchi,
3 and 4 Floor, Marunouchi Bld. 2‐4‐1 Marunouchi,
Chiyoda‐ku, Tokyo, 100‐0005, Japan
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. T h e m e e t i n g w i l l b e b r o a d c a s t o n C a b l e T V C h a n n e l 2 6 , l i v e o n
YouTube https://www.youtube.com/c/cityofpaloalto, a n d s t r e a m e d t o M i d p e n M e d i a
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@CityofPaloAlto.org 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@CityofPaloAlto.org 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.
CALL TO ORDER 6:00PM – 6:05PM
AGENDA CHANGES, ADDITIONS AND DELETIONS 6:05PM – 6:10PM
The Chair or Board majority may modify the agenda order to improve meeting management.
PUBLIC COMMENT 6:10PM – 6:25PM
Members of the public may speak to any item NOT on the agenda.
APPROVAL OF MINUTES 6:25PM – 6:30PM
1.Approval of the Minutes of the Utilities Advisory Commission Meeting Held on March 5,
2025
UTILITIES DIRECTOR REPORT 6:30PM – 6:45PM
NEW BUSINESS A 10 Minute Break May Be Imposed During This Section
2.Approval of Chair and Vice Chair to Serve a Short Term of April 2, 2025 through April 1,
2026 ACTION 6:45PM – 6:55PM
3.Staff Recommend the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution Approving the FY 2026 Gas Utility Financial Forecast and Reserve
Transfers, the Natural Gas Cost of Service and Rate Study, and General Fund Transfer;
and Amending Rate Schedules G‐1 (Residential Gas Service), G‐2 (Residential Master‐
Metered and Commercial Gas Service), G‐3 (Large Commercial Gas Service), and G‐10
(Compressed Natural Gas Service) ACTION 6:55PM – 7:55PM
4.Staff Recommends the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution, Approving the FY 2026 Electric Financial Forecast, including
Transfers, Amending Rate Schedules E‐1 (Residential Electric Service), E‐2 (Residential
Master‐Metered and Small Non‐Residential Electric Service), E‐2‐G (Residential Master‐
Metered and Small Non‐Residential Green Power Electric Service), E‐4 (Medium Non‐
Residential Electric Service), E‐4‐G (Medium Non‐Residential Green Power Electric
Service), E‐4 TOU (Medium Non‐Residential Time of Use Electric Service), E‐7 (Large
Non‐Residential Electric Service), E‐7‐G (Large Non‐Residential Green Power Electric
Service), E‐7 TOU (Large Non‐Residential Time of Use Electric Service), E‐14 (Street
Lights), E‐16 (Unmetered Electric Service), E‐EEC‐1 (Export Electricity Compensation),
and E‐NSE‐1 (Net Metering Surplus Electricity Compensation) ACTION 7:55PM – 8:40PM
5.Review and Recommend Utilities Advisory Commission FY 2025 – 2026 Work Plan for
City Council Approval ACTION: 8:40PM – 9:30PM
FUTURE TOPICS FOR UPCOMMING MEETING May 7, 2025
COMMISSIONER COMMENTS AND REPORTS FROM MEETINGS/EVENTS
ADJOURNMENT
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
Information Report: Utilities Quarterly Report for FY25Q2
12‐Month Rolling Calendar
Public Letter(s) to the UAC
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@CityofPaloAlto.org.
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@cityofpaloalto.org. Requests for assistance or
accommodations must be submitted at least 24 hours in advance of the meeting, program, or
service.
rd th
1 Regular Meeting April 02, 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.CityofPaloAlto.org.
UTILITIES ADVISORY COMMISSIONRegular MeetingWednesday, April 02, 2025Council Chambers & Hybrid6:00 PMChair Scharff Remote Location: W Hotel, 550 S Spring St.Aspen, Colorado 81611 Commissioner Gupta Remote Location: Share Lounge,Tsutaya Bookstore Marunouchi,3 and 4 Floor, Marunouchi Bld. 2‐4‐1 Marunouchi,Chiyoda‐ku, Tokyo, 100‐0005, JapanUtilities Advisory Commission meetings will be held as “hybrid” meetings with the option toattend by teleconference/video conference or in person. To maximize public safety while stillmaintaining transparency and public access, members of the public can choose to participatefrom home or attend in person. Information on how the public may observe and participate in themeeting is located at the end of the agenda. Masks are strongly encouraged if attending inperson. T h e m e e t i n g w i l l b e b r o a d c a s t o n C a b l e T V C h a n n e l 2 6 , l i v e o nYouTube https://www.youtube.com/c/cityofpaloalto, a n d s t r e a m e d t o M i d p e n M e d i aCenter https://midpenmedia.org.VIRTUAL PARTICIPATION CLICK HERE TO JOIN (https://cityofpaloalto.zoom.us/j/96691297246)Meeting ID: 966 9129 7246 Phone: 1(669)900‐6833PUBLIC COMMENTSPublic comments will be accepted both in person and via Zoom for up to three minutes or anamount of time determined by the Chair. All requests to speak will be taken until 5 minutesafter the staff’s presentation. Written public comments can be submitted in advance toUAC@CityofPaloAlto.org and will be provided to the Council and available for inspection on theCity’s website. Please clearly indicate which agenda item you are referencing in your subjectline.PowerPoints, videos, or other media to be presented during public comment are accepted onlyby email to UAC@CityofPaloAlto.org 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 strongcybersecurity management practices, USB’s or other physical electronic storage devices are notaccepted.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.
CALL TO ORDER 6:00PM – 6:05PM
AGENDA CHANGES, ADDITIONS AND DELETIONS 6:05PM – 6:10PM
The Chair or Board majority may modify the agenda order to improve meeting management.
PUBLIC COMMENT 6:10PM – 6:25PM
Members of the public may speak to any item NOT on the agenda.
APPROVAL OF MINUTES 6:25PM – 6:30PM
1.Approval of the Minutes of the Utilities Advisory Commission Meeting Held on March 5,
2025
UTILITIES DIRECTOR REPORT 6:30PM – 6:45PM
NEW BUSINESS A 10 Minute Break May Be Imposed During This Section
2.Approval of Chair and Vice Chair to Serve a Short Term of April 2, 2025 through April 1,
2026 ACTION 6:45PM – 6:55PM
3.Staff Recommend the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution Approving the FY 2026 Gas Utility Financial Forecast and Reserve
Transfers, the Natural Gas Cost of Service and Rate Study, and General Fund Transfer;
and Amending Rate Schedules G‐1 (Residential Gas Service), G‐2 (Residential Master‐
Metered and Commercial Gas Service), G‐3 (Large Commercial Gas Service), and G‐10
(Compressed Natural Gas Service) ACTION 6:55PM – 7:55PM
4.Staff Recommends the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution, Approving the FY 2026 Electric Financial Forecast, including
Transfers, Amending Rate Schedules E‐1 (Residential Electric Service), E‐2 (Residential
Master‐Metered and Small Non‐Residential Electric Service), E‐2‐G (Residential Master‐
Metered and Small Non‐Residential Green Power Electric Service), E‐4 (Medium Non‐
Residential Electric Service), E‐4‐G (Medium Non‐Residential Green Power Electric
Service), E‐4 TOU (Medium Non‐Residential Time of Use Electric Service), E‐7 (Large
Non‐Residential Electric Service), E‐7‐G (Large Non‐Residential Green Power Electric
Service), E‐7 TOU (Large Non‐Residential Time of Use Electric Service), E‐14 (Street
Lights), E‐16 (Unmetered Electric Service), E‐EEC‐1 (Export Electricity Compensation),
and E‐NSE‐1 (Net Metering Surplus Electricity Compensation) ACTION 7:55PM – 8:40PM
5.Review and Recommend Utilities Advisory Commission FY 2025 – 2026 Work Plan for
City Council Approval ACTION: 8:40PM – 9:30PM
FUTURE TOPICS FOR UPCOMMING MEETING May 7, 2025
COMMISSIONER COMMENTS AND REPORTS FROM MEETINGS/EVENTS
ADJOURNMENT
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
Information Report: Utilities Quarterly Report for FY25Q2
12‐Month Rolling Calendar
Public Letter(s) to the UAC
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@CityofPaloAlto.org.
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@cityofpaloalto.org. Requests for assistance or
accommodations must be submitted at least 24 hours in advance of the meeting, program, or
service.
rd th
2 Regular Meeting April 02, 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.CityofPaloAlto.org.
UTILITIES ADVISORY COMMISSIONRegular MeetingWednesday, April 02, 2025Council Chambers & Hybrid6:00 PMChair Scharff Remote Location: W Hotel, 550 S Spring St.Aspen, Colorado 81611 Commissioner Gupta Remote Location: Share Lounge,Tsutaya Bookstore Marunouchi,3 and 4 Floor, Marunouchi Bld. 2‐4‐1 Marunouchi,Chiyoda‐ku, Tokyo, 100‐0005, JapanUtilities Advisory Commission meetings will be held as “hybrid” meetings with the option toattend by teleconference/video conference or in person. To maximize public safety while stillmaintaining transparency and public access, members of the public can choose to participatefrom home or attend in person. Information on how the public may observe and participate in themeeting is located at the end of the agenda. Masks are strongly encouraged if attending inperson. T h e m e e t i n g w i l l b e b r o a d c a s t o n C a b l e T V C h a n n e l 2 6 , l i v e o nYouTube https://www.youtube.com/c/cityofpaloalto, a n d s t r e a m e d t o M i d p e n M e d i aCenter https://midpenmedia.org.VIRTUAL PARTICIPATION CLICK HERE TO JOIN (https://cityofpaloalto.zoom.us/j/96691297246)Meeting ID: 966 9129 7246 Phone: 1(669)900‐6833PUBLIC COMMENTSPublic comments will be accepted both in person and via Zoom for up to three minutes or anamount of time determined by the Chair. All requests to speak will be taken until 5 minutesafter the staff’s presentation. Written public comments can be submitted in advance toUAC@CityofPaloAlto.org and will be provided to the Council and available for inspection on theCity’s website. Please clearly indicate which agenda item you are referencing in your subjectline.PowerPoints, videos, or other media to be presented during public comment are accepted onlyby email to UAC@CityofPaloAlto.org 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 strongcybersecurity management practices, USB’s or other physical electronic storage devices are notaccepted.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 notcreate a facility, fire, or safety hazard; and (3) persons with such items remain seated whendisplaying them and must not raise the items above shoulder level, obstruct the view orpassage of other attendees, or otherwise disturb the business of the meeting.TIME ESTIMATESListed 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.
CALL TO ORDER 6:00PM – 6:05PM
AGENDA CHANGES, ADDITIONS AND DELETIONS 6:05PM – 6:10PM
The Chair or Board majority may modify the agenda order to improve meeting management.
PUBLIC COMMENT 6:10PM – 6:25PM
Members of the public may speak to any item NOT on the agenda.
APPROVAL OF MINUTES 6:25PM – 6:30PM
1.Approval of the Minutes of the Utilities Advisory Commission Meeting Held on March 5,
2025
UTILITIES DIRECTOR REPORT 6:30PM – 6:45PM
NEW BUSINESS A 10 Minute Break May Be Imposed During This Section
2.Approval of Chair and Vice Chair to Serve a Short Term of April 2, 2025 through April 1,
2026 ACTION 6:45PM – 6:55PM
3.Staff Recommend the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution Approving the FY 2026 Gas Utility Financial Forecast and Reserve
Transfers, the Natural Gas Cost of Service and Rate Study, and General Fund Transfer;
and Amending Rate Schedules G‐1 (Residential Gas Service), G‐2 (Residential Master‐
Metered and Commercial Gas Service), G‐3 (Large Commercial Gas Service), and G‐10
(Compressed Natural Gas Service) ACTION 6:55PM – 7:55PM
4.Staff Recommends the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution, Approving the FY 2026 Electric Financial Forecast, including
Transfers, Amending Rate Schedules E‐1 (Residential Electric Service), E‐2 (Residential
Master‐Metered and Small Non‐Residential Electric Service), E‐2‐G (Residential Master‐
Metered and Small Non‐Residential Green Power Electric Service), E‐4 (Medium Non‐
Residential Electric Service), E‐4‐G (Medium Non‐Residential Green Power Electric
Service), E‐4 TOU (Medium Non‐Residential Time of Use Electric Service), E‐7 (Large
Non‐Residential Electric Service), E‐7‐G (Large Non‐Residential Green Power Electric
Service), E‐7 TOU (Large Non‐Residential Time of Use Electric Service), E‐14 (Street
Lights), E‐16 (Unmetered Electric Service), E‐EEC‐1 (Export Electricity Compensation),
and E‐NSE‐1 (Net Metering Surplus Electricity Compensation) ACTION 7:55PM – 8:40PM
5.Review and Recommend Utilities Advisory Commission FY 2025 – 2026 Work Plan for
City Council Approval ACTION: 8:40PM – 9:30PM
FUTURE TOPICS FOR UPCOMMING MEETING May 7, 2025
COMMISSIONER COMMENTS AND REPORTS FROM MEETINGS/EVENTS
ADJOURNMENT
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
Information Report: Utilities Quarterly Report for FY25Q2
12‐Month Rolling Calendar
Public Letter(s) to the UAC
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@CityofPaloAlto.org.
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@cityofpaloalto.org. Requests for assistance or
accommodations must be submitted at least 24 hours in advance of the meeting, program, or
service.
rd th
3 Regular Meeting April 02, 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.CityofPaloAlto.org.
UTILITIES ADVISORY COMMISSIONRegular MeetingWednesday, April 02, 2025Council Chambers & Hybrid6:00 PMChair Scharff Remote Location: W Hotel, 550 S Spring St.Aspen, Colorado 81611 Commissioner Gupta Remote Location: Share Lounge,Tsutaya Bookstore Marunouchi,3 and 4 Floor, Marunouchi Bld. 2‐4‐1 Marunouchi,Chiyoda‐ku, Tokyo, 100‐0005, JapanUtilities Advisory Commission meetings will be held as “hybrid” meetings with the option toattend by teleconference/video conference or in person. To maximize public safety while stillmaintaining transparency and public access, members of the public can choose to participatefrom home or attend in person. Information on how the public may observe and participate in themeeting is located at the end of the agenda. Masks are strongly encouraged if attending inperson. T h e m e e t i n g w i l l b e b r o a d c a s t o n C a b l e T V C h a n n e l 2 6 , l i v e o nYouTube https://www.youtube.com/c/cityofpaloalto, a n d s t r e a m e d t o M i d p e n M e d i aCenter https://midpenmedia.org.VIRTUAL PARTICIPATION CLICK HERE TO JOIN (https://cityofpaloalto.zoom.us/j/96691297246)Meeting ID: 966 9129 7246 Phone: 1(669)900‐6833PUBLIC COMMENTSPublic comments will be accepted both in person and via Zoom for up to three minutes or anamount of time determined by the Chair. All requests to speak will be taken until 5 minutesafter the staff’s presentation. Written public comments can be submitted in advance toUAC@CityofPaloAlto.org and will be provided to the Council and available for inspection on theCity’s website. Please clearly indicate which agenda item you are referencing in your subjectline.PowerPoints, videos, or other media to be presented during public comment are accepted onlyby email to UAC@CityofPaloAlto.org 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 strongcybersecurity management practices, USB’s or other physical electronic storage devices are notaccepted.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 notcreate a facility, fire, or safety hazard; and (3) persons with such items remain seated whendisplaying them and must not raise the items above shoulder level, obstruct the view orpassage of other attendees, or otherwise disturb the business of the meeting.TIME ESTIMATESListed times are estimates only and are subject to change at any time, including while themeeting 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 maybe heard before or after the time estimated on the agenda. This may occur in order to bestmanage the time at a meeting to adapt to the participation of the public, or for any other reasonintended to facilitate the meeting.CALL TO ORDER 6:00PM – 6:05PMAGENDA CHANGES, ADDITIONS AND DELETIONS 6:05PM – 6:10PMThe Chair or Board majority may modify the agenda order to improve meeting management.PUBLIC COMMENT 6:10PM – 6:25PMMembers of the public may speak to any item NOT on the agenda.APPROVAL OF MINUTES 6:25PM – 6:30PM1.Approval of the Minutes of the Utilities Advisory Commission Meeting Held on March 5,2025UTILITIES DIRECTOR REPORT 6:30PM – 6:45PMNEW BUSINESS A 10 Minute Break May Be Imposed During This Section2.Approval of Chair and Vice Chair to Serve a Short Term of April 2, 2025 through April 1,2026 ACTION 6:45PM – 6:55PM3.Staff Recommend the Utilities Advisory Commission Recommend that the City CouncilAdopt a Resolution Approving the FY 2026 Gas Utility Financial Forecast and ReserveTransfers, the Natural Gas Cost of Service and Rate Study, and General Fund Transfer;and Amending Rate Schedules G‐1 (Residential Gas Service), G‐2 (Residential Master‐Metered and Commercial Gas Service), G‐3 (Large Commercial Gas Service), and G‐10(Compressed Natural Gas Service) ACTION 6:55PM – 7:55PM4.Staff Recommends the Utilities Advisory Commission Recommend that the City CouncilAdopt a Resolution, Approving the FY 2026 Electric Financial Forecast, includingTransfers, Amending Rate Schedules E‐1 (Residential Electric Service), E‐2 (ResidentialMaster‐Metered and Small Non‐Residential Electric Service), E‐2‐G (Residential Master‐Metered and Small Non‐Residential Green Power Electric Service), E‐4 (Medium Non‐Residential Electric Service), E‐4‐G (Medium Non‐Residential Green Power ElectricService), E‐4 TOU (Medium Non‐Residential Time of Use Electric Service), E‐7 (LargeNon‐Residential Electric Service), E‐7‐G (Large Non‐Residential Green Power ElectricService), E‐7 TOU (Large Non‐Residential Time of Use Electric Service), E‐14 (StreetLights), E‐16 (Unmetered Electric Service), E‐EEC‐1 (Export Electricity Compensation),and E‐NSE‐1 (Net Metering Surplus Electricity Compensation) ACTION 7:55PM – 8:40PM
5.Review and Recommend Utilities Advisory Commission FY 2025 – 2026 Work Plan for
City Council Approval ACTION: 8:40PM – 9:30PM
FUTURE TOPICS FOR UPCOMMING MEETING May 7, 2025
COMMISSIONER COMMENTS AND REPORTS FROM MEETINGS/EVENTS
ADJOURNMENT
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
Information Report: Utilities Quarterly Report for FY25Q2
12‐Month Rolling Calendar
Public Letter(s) to the UAC
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@CityofPaloAlto.org.
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
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identify yourself by name as this will be visible online and will be used to notify you
that it is your turn to speak.
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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
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accommodations must be submitted at least 24 hours in advance of the meeting, program, or
service.
rd th
4 Regular Meeting April 02, 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.CityofPaloAlto.org.
UTILITIES ADVISORY COMMISSIONRegular MeetingWednesday, April 02, 2025Council Chambers & Hybrid6:00 PMChair Scharff Remote Location: W Hotel, 550 S Spring St.Aspen, Colorado 81611 Commissioner Gupta Remote Location: Share Lounge,Tsutaya Bookstore Marunouchi,3 and 4 Floor, Marunouchi Bld. 2‐4‐1 Marunouchi,Chiyoda‐ku, Tokyo, 100‐0005, JapanUtilities Advisory Commission meetings will be held as “hybrid” meetings with the option toattend by teleconference/video conference or in person. To maximize public safety while stillmaintaining transparency and public access, members of the public can choose to participatefrom home or attend in person. Information on how the public may observe and participate in themeeting is located at the end of the agenda. Masks are strongly encouraged if attending inperson. T h e m e e t i n g w i l l b e b r o a d c a s t o n C a b l e T V C h a n n e l 2 6 , l i v e o nYouTube https://www.youtube.com/c/cityofpaloalto, a n d s t r e a m e d t o M i d p e n M e d i aCenter https://midpenmedia.org.VIRTUAL PARTICIPATION CLICK HERE TO JOIN (https://cityofpaloalto.zoom.us/j/96691297246)Meeting ID: 966 9129 7246 Phone: 1(669)900‐6833PUBLIC COMMENTSPublic comments will be accepted both in person and via Zoom for up to three minutes or anamount of time determined by the Chair. All requests to speak will be taken until 5 minutesafter the staff’s presentation. Written public comments can be submitted in advance toUAC@CityofPaloAlto.org and will be provided to the Council and available for inspection on theCity’s website. Please clearly indicate which agenda item you are referencing in your subjectline.PowerPoints, videos, or other media to be presented during public comment are accepted onlyby email to UAC@CityofPaloAlto.org 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 strongcybersecurity management practices, USB’s or other physical electronic storage devices are notaccepted.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 notcreate a facility, fire, or safety hazard; and (3) persons with such items remain seated whendisplaying them and must not raise the items above shoulder level, obstruct the view orpassage of other attendees, or otherwise disturb the business of the meeting.TIME ESTIMATESListed times are estimates only and are subject to change at any time, including while themeeting 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 maybe heard before or after the time estimated on the agenda. This may occur in order to bestmanage the time at a meeting to adapt to the participation of the public, or for any other reasonintended to facilitate the meeting.CALL TO ORDER 6:00PM – 6:05PMAGENDA CHANGES, ADDITIONS AND DELETIONS 6:05PM – 6:10PMThe Chair or Board majority may modify the agenda order to improve meeting management.PUBLIC COMMENT 6:10PM – 6:25PMMembers of the public may speak to any item NOT on the agenda.APPROVAL OF MINUTES 6:25PM – 6:30PM1.Approval of the Minutes of the Utilities Advisory Commission Meeting Held on March 5,2025UTILITIES DIRECTOR REPORT 6:30PM – 6:45PMNEW BUSINESS A 10 Minute Break May Be Imposed During This Section2.Approval of Chair and Vice Chair to Serve a Short Term of April 2, 2025 through April 1,2026 ACTION 6:45PM – 6:55PM3.Staff Recommend the Utilities Advisory Commission Recommend that the City CouncilAdopt a Resolution Approving the FY 2026 Gas Utility Financial Forecast and ReserveTransfers, the Natural Gas Cost of Service and Rate Study, and General Fund Transfer;and Amending Rate Schedules G‐1 (Residential Gas Service), G‐2 (Residential Master‐Metered and Commercial Gas Service), G‐3 (Large Commercial Gas Service), and G‐10(Compressed Natural Gas Service) ACTION 6:55PM – 7:55PM4.Staff Recommends the Utilities Advisory Commission Recommend that the City CouncilAdopt a Resolution, Approving the FY 2026 Electric Financial Forecast, includingTransfers, Amending Rate Schedules E‐1 (Residential Electric Service), E‐2 (ResidentialMaster‐Metered and Small Non‐Residential Electric Service), E‐2‐G (Residential Master‐Metered and Small Non‐Residential Green Power Electric Service), E‐4 (Medium Non‐Residential Electric Service), E‐4‐G (Medium Non‐Residential Green Power ElectricService), E‐4 TOU (Medium Non‐Residential Time of Use Electric Service), E‐7 (LargeNon‐Residential Electric Service), E‐7‐G (Large Non‐Residential Green Power ElectricService), E‐7 TOU (Large Non‐Residential Time of Use Electric Service), E‐14 (StreetLights), E‐16 (Unmetered Electric Service), E‐EEC‐1 (Export Electricity Compensation),and E‐NSE‐1 (Net Metering Surplus Electricity Compensation) ACTION 7:55PM – 8:40PM5.Review and Recommend Utilities Advisory Commission FY 2025 – 2026 Work Plan forCity Council Approval ACTION: 8:40PM – 9:30PMFUTURE TOPICS FOR UPCOMMING MEETING May 7, 2025COMMISSIONER COMMENTS AND REPORTS FROM MEETINGS/EVENTSADJOURNMENTSUPPLEMENTAL INFORMATIONThe materials below are provided for informational purposes, not for action or discussion during UAC Meetings (Govt. CodeSection 54954.2(a)(3)).INFORMATIONAL REPORTS
Information Report: Utilities Quarterly Report for FY25Q2
12‐Month Rolling Calendar
Public Letter(s) to the UAC
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@CityofPaloAlto.org.
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@cityofpaloalto.org. Requests for assistance or
accommodations must be submitted at least 24 hours in advance of the meeting, program, or
service.
rd th
5 Regular Meeting April 02, 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.CityofPaloAlto.org.
Item No. 1. Page 1 of 1
6
2
8
7
Utilities Advisory Commission
Staff Report
From: Kiely Nose, Interim Utilities Director
Lead Department: Utilities
Meeting Date: April 2, 2025
Report #: 2501-3996
TITLE
Approval of the Minutes of the Utilities Advisory Commission Meeting Held on March 5, 2025
RECOMMENDATION
Staff recommends that the UAC consider the following motion:
Commissioner ______ moved to approve the draft minutes of the March 5, 2025 meeting as
submitted/amended.
Commissioner ______ seconded the motion
ATTACHMENTS
Attachment A: 03-05-2025 UAC Minutes
AUTHOR/TITLE:
Kiely Nose, Interim Utilities Director
Staff: Kaylee Burton, Utilities Administrative Assistant
Item #1
Packet Pg. 6
Utilities Advisory Commission Minutes Approved on: Page 1 of 27
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF MARCH 5, 2025 REGULAR MEETING
CALL TO ORDER
Present: Chair Scharff, Vice Chair Mauter, Commissioners Croft, Gupta, Metz, Phillips, and
Tucher
Absent: None
Chair Scharff called the meeting of the Utilities Advisory Commission (UAC) to order at 6:01
p.m.
The clerk called roll and declared seven were present.
AGENDA REVIEW AND REVISIONS
None
ORAL COMMUNICATIONS
There were no public comments.
APPROVAL OF THE MINUTES
ITEM 1: ACTION: Approval of the Minutes of the Utilities Advisory Commission Meeting Held on
February 5, 2025
Chair Scharff invited comments on the February 5, 2025 UAC draft meeting Minutes.
Commissioner Phillips referenced Packet Page 23, the paragraph that read “Commissioner
Phillips asked what the output was,” and he requested that the following be added: “Staff
asked if the outage scenarios presented would provide adequate insight to pre-inform future
consideration of microgrids in Palo Alto. Commissioner Phillips commented it would be more
useful in understanding of the type and duration and possibly number of outages that would
make the microgrid economical.”
Chair Scharff saw no objection and declared that the Minutes would be approved with that
addition.
Item #1
Packet Pg. 7
Utilities Advisory Commission Minutes Approved on: Page 2 of 27
ACTION: Commissioner Phillips moved to approve the draft minutes of the February 5, 2025
meeting as amended.
Vice Chair Mauter seconded the motion.
Motion Carried 7-0
UNFINISHED BUSINESS
None
UTILITIES DIRECTOR REPORT
Kiely Nose, Assistant City Manager, delivered the Director's Report.
Recent City Council Actions Related to Utilities:
•February 3: Authorized the City Manager to execute an agreement with the U.S.
Department of Transportation Pipeline and Hazardous Materials Safety Administration
(PHMSA) for a $16.5 million grant to CPAU for gas capital improvement. Staff have executed
this grant agreement on the City side, but it has not yet been executed by PHMSA due to
federal administrative changes. PHMSA is revising terms and conditions and is expected to
provide guidance for grant recipients in the coming weeks. It is currently unclear whether
the City's grant will ultimately be funded. We are waiting to work with the Federal
administration and will update the Commission as we know more.
•February 10: Approved various contracts for the Commercial and Industrial Energy
Efficiency Program, WaterSmart customer portal, verified emission reductions for calendar
year 2025 through 2034, and on-call field inspection and construction management.
•February 24: Council planned to review the 2025 workplan, priorities and objectives at the
end of the month, but due to timing constraints, this item will be covered in March.
Green v. City of Palo Alto Settlement Update: The Green v. City of Palo Alto settlement
payments were originally scheduled to be paid out to class customers over a three-year period.
The City is accelerating that process. The payment that customers will receive in their bills
between March 10 and April 11 will be a combination of both the second and third installment.
This will complete all settlement actions and administration before the end of the fiscal year.
The City is notifying customers by postcard about the accelerated payments.
Legislative and Regulatory Update: The 2025 legislative year deadline for bills to be introduced
was February 21. Many introduced bills lacked substantive language. However to note, staff are
tracking SB 540 (Becker) to create a regional electricity market, and AB 1207 (Irwin) and SB 840
(Limón) to reauthorize Cap and Trade.
Item #1
Packet Pg. 8
Utilities Advisory Commission Minutes Approved on: Page 3 of 27
The State Fire Marshal released updated Fire Hazard Severity maps for the State of California in
the month of February. For Palo Alto, consistent with past maps, the Foothills region of Palo
Alto is mostly a mixture of high and very high fire hazard zones. With the updated maps, now a
small region including some key account customers are considered in moderate fire hazard
zones. The City has a specific timeline for providing the information to the public for review and
comment, adopting the recommended maps by local ordinance, and submitting the ordinance
and required documents to the Board of Forestry and Fire Protection. The City will also review
and update its Wildfire Mitigation Plan accordingly.
Grid Modernization: The cost of the grid modernization project was discussed at the February
UAC meeting. The current budget for the project is $300 million with the recent resolutions for
debt reimbursement approved by Council reflecting $350 million. The additional $50 million
helps provide flexibility should costs rise. Staff estimate that about half of the project costs are
for equipment replacement that would be necessary in the future regardless of electrification.
The project duration is anticipated to be 6-7 years or longer. In addition to the grid
modernization CIP, there are approximately $60 million in electric utility investments included
in the FY 2025-FY 2029 CIP budget. These projects include investments in system
improvements, substations, security enhancements, routine wooden pole replacement, and
utilities undergrounding.
Gas Main Replacement Project Update: The Gas Main Replacement Project #24B project is
scheduled to be completed at the end of this month. This project involves installing around 3.5
miles of gas main and services from Highway 101 and University to Webster and University,
including the surrounding streets. CPAU also replaced gas pipeline at the Town & Country
Village and on Geng Road. The Contractor (Daleo Inc.) is currently working on Middlefield Road
between Lytton and Hamilton Avenues to install the last section of pipe.
Hydroelectric Update: After an exceptionally dry January, the Northern Sierras saw better than
average conditions in February, while the Central Sierras saw roughly average conditions for the
month. For the water year to date, precipitation and snowpack levels are about 20% above
average levels in Northern California, while they are about 20% below average in Central
California. However, reservoirs across the state remain slightly fuller than average for this time
of year. And overall, the City’s hydroelectric resources are still projected to produce roughly
their long-term average levels of output in fiscal years 2025 and 2026. Federal actions threaten
the operations and efficiency of the Western Area Power Administration (WAPA) and the
Central Valley Project (CVP), largely through suspended federal grant money and staff
reductions. This doesn’t directly impact Palo Alto's ability to provide power, but it could
increase the costs of supplying electricity.
Customer Programs Update: On February 13, the City launched a suite of new program services
to make it easier for residents to electrify their homes. This includes rebates for heat pump
Heating, Ventilation, and Air Conditioning (HVAC) projects and incentives for gas meter
disconnections. A new “Rebate Hub” allows customers to apply for rebates and request quotes
from contractors. Residents can now receive a free online home electrification assessment
Item #1
Packet Pg. 9
Utilities Advisory Commission Minutes Approved on: Page 4 of 27
powered by QuitCarbon and free phone consultation with an electrification expert. More
information can be found at www.cityofpaloalto.org/electrifymyhome.
NEW BUSINESS
ITEM 2: ACTION: Approval of the Fiscal Year 2026 Water Utility Financial Forecast including
reserve Transfers, and Amending Rate Schedules W-1 (General Residential Water Service), W-2
(Water Service From Fire Hydrants), W-3 (Fire Service Connections), W-4 (Residential
Master-Metered and General Non-Residential Water Service), and W-7 (Non-Residential
Irrigation Water Service) 6:45PM – 7:30PM
Item #1
Packet Pg. 10
Utilities Advisory Commission Minutes Approved on: Page 5 of 27
accelerated within the collection system to extend the life of the asset and to do spot repairs.
The same type of technology could not be used on the water and gas side.
Item #1
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Utilities Advisory Commission Minutes Approved on: Page 6 of 27
customers, which was listed as a potential Work Plan item, but alternatively it could be
agendized for the Commission to work out. The other cost savings to consider was a State and
City mandate to purchase EVs, which he explained, and the UAC could explore seeking carb
waivers and perhaps a policy adjustment at the Council level.
Item #1
Packet Pg. 12
Utilities Advisory Commission Minutes Approved on: Page 7 of 27
Commissioner Tucher addressed CapEx and asked how painful it would be to defer roughly $7M
out of the current plan. He discussed the 2.1 percent increase in wholesale rates from SFPUC
and asked if in December they were signaling that it would be zero.
Item #1
Packet Pg. 13
Utilities Advisory Commission Minutes Approved on: Page 8 of 27
Mr. Zucca stated that they were working through the details of the next phase, which would be
to send out mailers notifying folks to get the testing. The third phase would be the City taking
on the entire scope of the testing for those who had not gotten the testing.
Daily Post had a headline “Rate Hike for Leaking
Pipes.” The complaint in the article was that rates were higher because of water leaks. He
noted that part of what was being deferred was leaking pipes to keep rates low, which he found
tricky to resolve. He questioned how much rates were impacted by leaky pipes.
Item #1
Packet Pg. 14
Utilities Advisory Commission Minutes Approved on: Page 9 of 27
represented how much would be recovered for CIP if rates were not increased versus making
the rate change and specifically deferring capital, which would lower the amount of costs
associated with CIP by 5.4 percent.
Item #1
Packet Pg. 15
Utilities Advisory Commission Minutes Approved on: Page 10 of 27
Ms. Nose answered that if bar-napkin math was used that would be correct. As different levers
were moved, it would change reserve levels and many calculations.
Item #1
Packet Pg. 16
Utilities Advisory Commission Minutes Approved on: Page 11 of 27
Ms. Bilir did not see a $4M reduction. The chart showed the year-end reserve balances and the
dark blue bar represented the Rate Stabilization Reserve going from $4M at the end of FY2024,
to $1M at the end of 2025, and then to zero at the end of 2026.
Commissioner Gupta noted that there was mention in the Staff Report that the Finance
Committee had discussed whether they were the appropriate reserve levels or whether they
might be reduced, and he asked if staff was investigating that.
Ms. Nose responded that it was an area that staff was aware of for further study. In terms of
the review between December and now, staff had checked to make sure they were in
compliance with the rate policies. Unfortunately, she suspected that a formal study might show
the reserves to be insufficient. It was under review. Staff agreed that a broader study should be
done, but she did not think it would come back in a cost-reduction manner.
Commissioner Phillips requested that it be agendized for discussion. It was interesting that the
debt covenants from 2009 and 2011 were on the individual reserve but also the sum of the
reserves for water, gas, and electric. He wondered why they were not jointly managed. He
stated that it made no sense to have individual optimized numbers.
Mr. Kurotori noted that each utility had to be accounted for separately and the loans the City
had taken had to be repaid between the funds, so there must be a separate accounting
structure.
Ms. Nose thought it would be a great item for the Work Plan discussion for the upcoming year.
She felt that there was mixing of apples and oranges. Some things were associated with debt
covenants and some with operating reserves, and each was governed by different regulations.
Commissioner Gupta echoed Chair Scharff’s concerns related to deferring CapEx and that in the
future larger reserves may need to be maintained. He thought the 10 percent rate increase was
reasonable. He asked his colleagues were they stood on the proposed alternative and which
option they would propose.
Chair Scharff stated that staff explained why they were opposed to the alternative option.
Public Comment
There were no requests to speak.
Vice Chair Mauter moved that staff’s recommendation for a 10 percent rate increase be
accepted and that the UAC encourage Council to consider the savings opportunities and that
any savings opportunities be applied toward a reduction in the use of the reserve expenditure.
She wanted the cost savings identified in the proposal to be applied to a reduced spend on the
reserve.
Item #1
Packet Pg. 17
Utilities Advisory Commission Minutes Approved on: Page 12 of 27
Commissioner Croft did not support subsidizing credit cards. She did not know if the UAC could
determine where it should be spent. She stated that the Wastewater Reserve was in great
need.
Chair Scharff voiced that electricity credit card fees had to go to electricity and wastewater
credit card fees to wastewater.
Commissioner Phillips seconded the motion.
Chair Scharff suggested that the motion spell out the cost savings the subcommittee came up
with.
Vice Chair Mauter accepted that.
Motion Carried 7-0
ACTION: The Utilities Advisory Commission Recommend the City Council
1. Approve the Fiscal Year 2026 Water Utility Financial Forecast shown in this staff report and
attachments and approving a reserve transfer of up to $3,000,000 from the Rate
Stabilization Reserve to the Operations Reserve in FY 2025; and
2. Amend the following Rate Schedules (Attachment B) effective July 1, 2025 (FY 2026):
a. W-1 (General Residential Water service)
b. W-2 (Water Service from Fire Hydrants)
c. W-3 (Fire Service Connections)
d. W-4 (Residential Master-Metered and General Non-Residential Water Service)
e. W-7 (Non-Residential Irrigation Water Service)
3. Recommend the Finance Committee and City Council consider the potential cost saving
activities (credit card separate charge, electric vehicle replacement policies) as discussed by
the UAC Subcommittee to control rate increases and to the extent these mitigate costs,
reallocate savings to restore reserves while maintaining the recommended rate increase in
1 and 2 above.
ITEM 3: ACTION: Approval of the Fiscal Year 2026 Wastewater Collection Utility Financial
Forecast, and Amending Rate Schedules S-1 (Residential Wastewater Collection and Disposal),
S-2 (Commercial Wastewater Collection and Disposal), S-6 (Restaurant Wastewater Collection
and Disposal) and S-7 (Commercial Wastewater Collection and Disposal – Industrial Discharger),
and Repealing Rate Schedules S-3 (Industrial Waste Laboratory and Analysis Charges) and S-4
(Hauled Liquid Waste Charges) 7:30PM – 8:00PM
Lisa Bilir, Senior Resource Planner, provided slides and stated that the Wastewater Collection
Utility provided a critically important service to Palo Alto. Palo Alto and neighboring cities sent
wastewater to the RWQCP, and some of the facilities at the plant needed to be rebuilt, so some
Item #1
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Utilities Advisory Commission Minutes Approved on: Page 13 of 27
of the costs were to fund that. She outlined the proposal for the Waste Water Collection Utility.
There was also an alternative proposal, which she discussed. She spoke of the drivers for the
rate increase. The reserves in the Wastewater Collection Utility were depleted, which needed
to be restored to within the guideline range. Compared with the preliminary rates that were
presented in December, there were a couple changes that increased the level from 18 percent
to 20 percent, which she discussed. She shared a slide representing the bill comparison for
residential customer, which they had taken from Silicon Valley Clean Water and the Financial
Plan, and a slide showing the drivers for the rate increase, which she detailed. She also spoke of
the alternative proposal. She supplied charts showing cost and revenue projections and
Operations Reserve projections. Staff recommended that the UAC recommend that Council
adopt a resolution approving the financial forecast. They were recommending to repeal two
rate schedules (S3 and S4), which she stated was a clean-up item.
Item #1
Packet Pg. 19
Utilities Advisory Commission Minutes Approved on: Page 14 of 27
Ms. Bilir responded that they could put that comparison together.
Item #1
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Utilities Advisory Commission Minutes Approved on: Page 15 of 27
Kiely Nose, Assistant City Manager, stated that the proposals were taken seriously. They were
large increases and different from the December rates, and staff needed to proactively work on
communicating with the public the reasons for the increases.
ACTION: The Utilities Advisory Commission Recommend the City Council
S-1 (Residential Wastewater Collection and Disposal),
S-2 (Commercial Wastewater Collection and Disposal),
S-6 (Restaurant Wastewater Collection and Disposal) and
Item #1
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Utilities Advisory Commission Minutes Approved on: Page 16 of 27
d.S-7 (Commercial Wastewater Collection and Disposal – Industrial Discharger),
and
e. Repealing Rate Schedules S-3 (Industrial Waste Laboratory and Analysis Charges)
and S-4 (Hauled Liquid Waste Charges)
3. Recommend the Finance Committee and City Council consider the potential cost saving
activities (credit card separate charge, electric vehicle replacement policies) as discussed
by the UAC Subcommittee to control rate increases and to the extent these mitigate
costs, reallocate savings to restore reserves while maintaining the recommended rate
increase in 1 and 2 above.
ITEM 4: ACTION: Consideration of the Utilities Advisory Subcommittee’s One Water Advocacy
Letter and a Commissioner’s Proposed Bay Area Water Supply & Conservation Agency
(BAWSCA) Advocacy Letter and Potential Recommendation to City Council 8:00PM – 8:30PM
Chair Scharff moved to Item 4, and asked if this pertained to a letter the subcommittee drafted.
He asked who was on the subcommittee.
Commissioner Gupta stated that was an accurate statement for the One Water Advocacy
Letter. The subcommittee included Vice Chair Mauter, Commissioner Phillips, and himself.
Chair Scharff asked Commissioner Tucher if thoughts from this should be integrated into this
letter or if it should be thought of separately.
Commissioner Tucher replied that his letter was very different and had a different audience. His
letter related to recommending to Council that they, through BAWSCA, request more dialogue,
information, and answers from SFPUC.
Chair Scharff declared that the One Water letter would be addressed by the subcommittee first
and then Commissioner Tucher’s item would be discussed.
[The Commission took a break at 7:55 p.m. and resumed at 8:09 p.m.]
Public Comment
Peter Drekmeier, Policy Director for the Tuolumne River Trust, appreciated the transparency of
Items 2 and 3. He shared slides. He spoke about the drought from 2020 to 2022. He noted that
2023 had been an incredibly wet year. He appreciated rationing, but he spoke of it not
benefitting the environment and hurting fiances. He discussed demand projections and water
and wastewater sales recovery by FY2026-2027. He explained that it was vital that Palo Alto get
information from the SFPUC.
Commissioner Tucher asked what information he was referring to.
Item #1
Packet Pg. 22
Utilities Advisory Commission Minutes Approved on: Page 17 of 27
Mr. Drekmeier discussed the One Water letter containing a sentence referencing the return
period for the design drought, the likelihood of occurrence, and he encouraged that the
numbers in the letter be changed, which he outlined. He recommended modeling for water
sales and demand being lower than projected. He suggested getting information from the
SFPUC concerning the what ifs, which he explained.
Item #1
Packet Pg. 23
Utilities Advisory Commission Minutes Approved on: Page 18 of 27
planning or investments decisions at this time. She did not want to discard it. She thought it
could be a resource moving forward. She referenced Page 204, the design drought, and stated
that the City was relying on Peter Drekmeier and Dave Warner’s analysis related to the
probability of a design drought because they had not received an assessment from SFPUC,
which she believed could be addressed in the letter from Commissioner Tucher. She addressed
the sentence that read “found that no drought in 25,000 years of stochastic modeling that
approached the severity the design drought scenario,” and she thought the historical model
should also be mentioned, which she suggested read “the SFPUC found no drought in 25,000
years of stochastic modeling or 1,100 years of historic and paleo-modeling that approach the
severity of the design drought.” She remarked that they had discussed the “several hundred
thousand years fourth probability analysis suggested design drought scenario has an
exceptionally rare return period, potentially one in several hundred thousand years.” She
recommended that be modified to potentially 1 in 8,000 years or that there be a range.
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Karla Dailey, Assistant Director of Utilities Resource Management Division, answered that they
did coordinate and collaborate with fellow cities and that they worked regionally. She discussed
why One Water had been done, which included providing a framework for projects. Other cities
were looking at One Water planning, but not everyone had the same definition of One Water,
and everybody’s territory was slightly different. There may be opportunities in the future to
take what each city had learned to inform decisions being made as regional partners. She did
not know about recouping money.
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also considering preserving the authority of the UAC. He thought some of the concerns were
included in the One Water letter. He did not think sending the letter would accomplish the
SFPUC doing the things that are requested in the letter. He understood that Council Member
Stone had the letter. He felt that sending two letters would take away from the One Water
letter, and he was not sure what would be gained by sending it to Council. He did not support
it.
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Commissioner Croft felt that this letter requesting answers to questions could go with the One
Water letter in the same packet to Council.
Vice Chair Mauter explained why it was not possible to put the letter in the One Letter Plan
letter. The One Water letter was written to respond to the conditions given by SFPUC, and the
second letter questioned the validity of those conditions. She was not sure that the One Water
Plan letter was the correct place to make these distinct requests. She considered it to be more
of a future-looking effort. She would support asking Council to help the UAC get answers to the
questions and to move away from language asking them to pursue one particular route over
another in order to seek the answers.
Commissioner Tucher asked what the one route was. He suggested sending the letter.
Vice Chair Mauter thought Chair Scharff was suggesting that potentially Council Member Stone
raising the questions independently could be more politically effective in eliciting the needed
answers.
Commissioner Tucher wanted Council to decide what should be done.
Vice Chair Mauter felt that a unanimously supported letter would be a stronger letter to
Council. Seeking compromise seemed to be an important path to pursue.
Commissioner Phillips felt that the reasonable compromise would be Chair Scharff’s suggestion
for an alternative letter. He asked how the letter could be drafted.
Chair Scharff thought the letter could be drafted at this meeting. He suggested that staff draft it
and that the questions be succinctly listed for Council.
Commissioner Gupta stated the letter raised very important points that needed to be
addressed by BAWSCA and SFPUC. He liked the approach recommended by Chair Scharff and
Commissioner Phillips. He was concerned that Council may choose to not forward the letter if it
was presented to them, which would be a lost chance to get the questions answered.
Chair Scharff asked staff if they were drafting the letter.
Ms. Nose replied that she had started to recorder type the initial thoughts the Commission had
identified. She felt that the tapes could be viewed to frame that out. She thought staff was
missing the specific questions and that the UAC’s dialogue on that would be helpful.
Commissioner Tucher stated that the questions were in the public. He recommended that the
UAC follow through with Chair Scharff and Commissioner Thomas’ suggestions. He wanted the
questions to be listed and presented with the letter he drafted for Council to use if they
desired. The questions included asking the reasoning for using higher enterprise forecast, which
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he did not want to lead with. He wanted to ask the SFPUC rerun the analysis based on lower
demand projections.
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demand projections using the Finance Bureau numbers and the current numbers and growing
at X rate. 2) SFPUC to publish the likelihood of the design drought occurring, the return period
for the design drought, and to model the likelihood of using a less severe drought using 7½
years. 3) Looking back at the three droughts modeled in the LTVA, what the storage levels
would be if the Bay Delta Plan was in place.
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Commissioner Phillips Seconded the motion.
Peter Drekmeier stated that BAWSCA gave demand projections to the SFPUC, which he
discussed being a problem. He noted that care needed to be taken when addressing demand
projections. He added that giving SFPUC an end-of-year date would result in them waiting that
long. He voiced that it needed to be very specific without any opportunities to fudge. He liked
the direction it was going.
Vice Chair Mauter stated that BAWSCA was doing new demand projection models that
hopefully would be less inflated.
Mr. Drekmeier commented that they would be less inflated and there would be a sensitivity. He
suggested using their 2022 demand study high and low scenarios.
Chair Scharff declared that the Commission accepted that.
Mr. Drekmeier added that they had done a lot of investigative work to understand what was
happening, so they created a water supply calculator. He could crunch the numbers, but unless
they came from the SFPUC, they would be questioned. He explained that the SFPUC had
created a water supply worksheet and that different scenarios could be produced quickly. He
noted that having the low-end and high-end numbers would provide information to have a
discussion. He suggested editing Number 4 to read “at current demand” and to remove
“historic.” He voiced that Number 3 was open ended and that it would be interesting to see
their response. He thought the UAC wanted to know how shortening the design drought using
reasonable, realistic demand projections would impact the water supply deficit that would
need to be made up for with expensive, alternative water supplies.
Vice Chair Mauter confirmed that UAC wanted to know how shortening the design drought
using reasonable, realistic demand projections would impact the water supply deficit that
would need to be made up for with expensive, alternative water supplies.
Mr. Drekmeier thanked the UAC for the time they had put into this.
Motion Carried 7-0
ACTION: Motion Approved
ITEM 5: ACTION: Review and Recommend Utilities Advisory Commission FY 2025 – 2026 Work
Plan for City Council Approval 8:30PM – 9:00PM (Moved to April Agenda)
Chair Scharff asked if Item 5 could be rescheduled.
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Kiely Nose, Assistant City Manager, would reschedule the item for April and address the
tentative accordingly.
ACTION: Moved to April
FUTURE TOPICS FOR UPCOMING MEETINGS ON (DATE) AND REVIEW OF THE 12 MONTH
ROLLING CALENDAR
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and agendize these topics. They had considered drafting a Commissioner’s Memo on the topic
and getting it on the agenda, although they would be happy to go about it in a different way.
COMMISSIONER COMMENTS and REPORTS from MEETINGS/EVENTS
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mod and technologies that should be considered. He hoped the Professor and Jonathan
Abendschein could meet to discuss grid mod, which maybe could be the seed of broader and
more regular collaborations with Stanford.
th. He thought they would pay registration.
ADJOURNMENT
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Item No. 2. Page 1 of 1
Utilities Advisory Commission
Staff Report
From: Kiely Nose, Interim Director of Utilities
Lead Department: Utilities
Meeting Date: April 2, 2025
Report #: 2503-4248
TITLE
Approval of Chair and Vice Chair to Serve a Short Term of April 2, 2025 through April 1, 2026
RECOMMENDATION
Recommended Motion
Commissioner ____ moved to approve Commissioner ____ as Chair.
Motion seconded by Commissioner ___.
Commissioner ___ moved to approve Commissioner ___ as Vice Chair.
Motion seconded by Commissioner ___.
BACKGROUND
Annually the Chair and Vice Chair are selected at the beginning of the new recruitment term for
a period of one year, from the first meeting in April through April of the following year. This
item is included in the agenda for the purpose of Commissioners selecting a Chair and Vice
Chair for a short term, spanning from April 2, 2025 through April 1, 2026.
AUTHOR/TITLE:
Kiely Nose, Interim Director of Utilities
Staff: Kaylee Burton, Utilities Administrative Assistant
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Utilities Advisory Commission
Staff Report
From: Kiely Nose, Interim Director of Utilities
Lead Department: Utilities
Meeting Date: April 2, 2025
Report #: 2411-3751
TITLE
Staff Recommend the Utilities Advisory Commission Recommend that the City Council Adopt a
Resolution Approving the FY 2026 Gas Utility Financial Forecast and Reserve Transfers, the
Natural Gas Cost of Service and Rate Study, and General Fund Transfer; and Amending Rate
Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas
Service), G-3 (Large Commercial Gas Service), and G-10 (Compressed Natural Gas Service)
RECOMMENDATION
Staff recommends the Utilities Advisory Commission recommend that the City Council adopt a
resolution (Attachment A):
1. Approving the Fiscal Year 2026 Gas Utility Financial Forecast shown in this staff report and
attachments; and
2. Approving the transfer of up to $1.5 million from the Gas Utility Operations Reserve to
the Distribution Rate Stabilization Reserve at the end of FY 2025; and
3. Approving the Natural Gas Cost of Service and Rate Study (Attachment F); and
4. Transferring up to 18% of gas utility gross revenues received during FY 2024 to the
General Fund in FY 2026; and
5. Amending Rate Schedules (Attachment B) effective July 1, 2025 (FY2026):
a. G-1 (Residential Gas Service)
b. G-2 (Residential Master-Metered and Commercial Gas Service)
c. G-3 (Large Commercial Gas Service)
d. G-10 (Compressed Natural Gas Service)
EXECUTIVE SUMMARY
The City of Palo Alto Utilities (CPAU) provides electricity, water, wastewater, natural gas, and
fiber optic services to the Palo Alto community. The Public Works Department also provides
refuse collection and processing for recycling, compost and garbage, wastewater treatment and
stormwater management. The City’s primary goals are to manage these services in a way that
ensures continued safe, reliable, environmentally sustainable, and cost-effective operations.
The City is proposing rate increases this year for electric, natural gas, wastewater and water
services. The stormwater management fee increase will occur per the Consumer Price Index
(CPI) as approved by residents in a 2017 ballot measure. The City strives to be transparent with
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utilities customers about the reason for rate changes, including explaining the cost drivers,
benefits to customers, what the City is doing to keep costs low for ratepayers, and the services
and programs provided by the City to help customers keep utility bill costs low. Attachment E
outlines CPAU’s plan for communicating rate changes to customers. Staff are presenting an
overview of the financial forecast and rate change proposal for each utility service to the
Utilities Advisory Commission (UAC) and Finance Committee prior to City Council review and
approval in June 2025.
Table 1: Current Year (FY2025) and Projected Overall Rate Trajectory from FY 2026 to FY 2030
BACKGROUND
ANALYSIS
Past Trends
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driven by higher operating and administrative charges. Total FY 2024 actual expenses were $63
million, compared to the $67 million projected in the FY 2025 Financial Plan. Table 2 summarizes
the variances from forecast.
Table 2: FY 2024 Actuals vs. Prior Year’s Forecast ($000)
Net Cost/
(Benefit)
Variance
Type of Change
Sales revenues lower than forecast, Low Residential
Tier 2 Consumption
5,479 Revenue Decrease
Lower connection fees revenues 358 Revenue Decrease
Supply purchases lower than forecast (4,623)Cost Decrease
Higher distribution costs (without CIP)906 Cost Increase
CIP costs higher than forecasted 1,739 Cost Increase
Net Cost / (Benefit) of Variances 3,859 Net Cost Increase
Projections
Overview
In the current year (FY 2025), sales revenues are projected to be about $6.3 million, or 9% lower
compared to last year’s forecast, primarily due to lower projected gas consumption. On the
expense side, supply purchases are expected to be about $3.9 million, or 15% lower compared
with last year’s forecast, driven by lower than expected consumption and lower market-based
commodity and carbon offset costs. However, operations costs are projected to rise by about $2
million, or 6%, in FY 2025, mainly due to higher allocated charges and salaries and benefits
expenses. Additionally, CIP costs are expected to decrease by about $5 million, or 57%, in FY
2025, reflecting a deferral of a rate-funded Gas Main Replacement project construction (from FY
2025 to FY 2027 and FY 2029), to be replaced by a federally grant-funded project.1
Looking ahead to the five-year forecast period from FY 2026 to FY 2030, supply-related costs are
expected to increase at an average annual rate of 6%, with commodity prices projected to grow
by 3% annually. Furthermore, distribution expenses are forecasted to rise by an average of 7%
annually.
Figure 1 shows the actual overall system average rate percentage change from FY 2018 through
FY 2025 (grey) and the projected overall system average rate change for FY 2026 through FY 2030
(red), excluding supply-related rate changes. The rate increases shown in Figure 6 include the
needed increase for the distribution rate as a percentage of the base Gas Utility sales revenue.
1 Staff Report 2411-3777, February 3, 2025;
https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=83226 Council unanimously voted to
authorize the City Manager or their Designee to Execute an Assistance Agreement with the United States
Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) in the amount of
$16,519,879 through January 31, 2030.
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Figure 1: Gas Utility Expenses, Revenues, Rate Changes Excluding Supply-Related Changes
Actual Costs through FY 2024 and Projections through FY 2030
*FY25 Commitments and Reappropriations reserves balances for Operations and Capital Investment are
anticipated to be utilized in FY 2026 and FY 2027.
Note: Revenues and Expenses exclude Cap-and-Trade auction sales revenue, which goes directly to the Cap-and-
Trade reserve.
Gas usage in Palo Alto declined from FY 2020 to FY 2022, mainly due to the impacts of the COVID-
19 pandemic. However, FY 2023 saw an increase in gas usage, likely driven by a modest recovery
from COVID-19 effects and colder than average winter temperatures. However, similar to
previous declines in gas usage due to economic factors, it is unlikely that consumption will return
to pre-conservation or pre-pandemic levels. Instead, a long-term decline in gas usage is expected.
Further changes, such as the voluntary replacement of gas appliances with electric appliances
and building electrification are also expected to lower long run usage. Staff will conduct strategic
planning and financial analysis separately from this financial forecast to develop a financial and
infrastructure strategy for the Gas Utility as the community electrifies. Any insights from that
analyses will be integrated into future financial forecasts.
Staff worked with a consultant to assist in the development of an updated gas load forecast,
which included statistically adjusted end-use (SAE) modeling, weather-normalized modeling,
economic factors, and an electrification assumption. The result, shown in Figure 2, projects gas
supply load for FY 2026 at 26,172,070 therms, about 5% lower than prior year’s forecast.
Projections for subsequent years have also been adjusted downward by about 5% compared with
last year’s forecast. This reduction reflects decreased consumption in FY 2024, which has slightly
shifted the long-term trend. Over time, declining gas consumption is expected to increase
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pressure on rates, as rising and fixed costs for gas operations and distribution will need to be
allocated across fewer units sold.
Figure 1: Gas Supply Load Forecast
Revenues
. Except where stated
otherwise, these load forecasts are based on normal weather. Weather can vary substantially,
however, and this can affect revenues substantially. Changes in customer behavior,
improvements to gas appliances efficiency, and electrification all impact gas usage. Staff regularly
monitor emerging trends and make updates to forecasts as needed.
Expenses
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Fiscal Year
FY25 Load Forecast FY26 Load Forecast Actual
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Table 3: Gas Utility Costs for FY 2024 to FY 2030 ($000)
Actual ProjectedExpensesFY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030
Supply Costs 22,772 22,395 26,091 27,560 28,607 29,578 30,608
Commodity 11,789 10,087 12,487 12,838 12,640 12,153 11,803
Transportation 4,418 6,836 7,370 7,638 8,106 8,593 9,092
Carbon Offset 2,705 1,616 1,855 2,151 2,343 2,701 2,950
Cap-and-Trade 3,860 3,857 4,380 4,933 5,518 6,131 6,763
Distribution Costs 40,097 38,525 52,467 60,243 50,125 59,270 54,776
Operations 32,873 34,843 36,692 38,123 39,554 41,562 43,597
Capital 7,225 3,682 15,775 22,120 10,571 17,707 11,179
TOTAL 62,869 60,921 78,559 87,803 78,731 88,848 85,384
Supply Costs
Supply costs consist of the commodity cost of natural gas, gas transmission charges, and
environmental compliance costs. These costs are passed directly to customers and are shown as
line items on their utility bills.
Overall, supply expenses are projected to increase by an average of about 6% per year from FY
2025 through FY 2030. Gas commodity costs, which are the most variable component, account
for the largest share of overall costs. Although market forecasts currently indicate that gas prices
will remain relatively steady over the next several years, those forecasts are highly uncertain. The
financial forecast assumes that gas prices increase by an average of about 3% annually during the
forecast period.
Transportation and environmental compliance costs are also expected to rise gradually over the
forecast period. PG&E's local transportation rates, which have experienced steady increases in
recent years, are expected to rise by an average of 6% per year throughout the forecast period2.
Because the Gas Utility is regulated under California’s greenhouse gas (GHG) regulations, the Gas
Utility incurs Cap-and-Trade compliance costs. The regulation requires Palo Alto to purchase
allowances based on actual gas load. Staff estimates that Cap-and-Trade allowance costs will
increase on average by 12% annually over the forecast period.3
The Gas Utility also generates revenue from the sale of free allocated allowances. In FY 2024 and
in accordance with Council-approved Cap-and-Trade revenue uses (Council Resolution 100774)
2 The transportation rates for calendar years 2023-2026 reflect the rates in the December 15, 2021 prepared
testimony (A.21-09-018) regarding PG&E’s 2023 Gas Transmission & Storage (GT&S) Cost Allocation and Rate
Design (CARD), afterward a 3% escalation rate is applied.
3 Based on allowance broker quotes.
4 Council Resolution 10077 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=61567
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and Council’s goal of reducing GHGs 80% by 2030, Palo Alto began allocating Cap-and-Trade
reserves to support programs such as the Full-Service Heat Pump Water Heater Program.
The City also has a Carbon Neutral Natural Gas plan (Staff Report 74415), which involves
purchasing carbon offsets equivalent to the emissions generated by the community's natural gas
use. These high-quality offsets fund projects that reduce GHG emissions, such as forest
conservation or methane capture from dairy farms. While purchasing carbon offsets is an
important initial step in reducing carbon emissions, the long-term goal is to decrease the
community's natural gas usage by maximizing efficiency and transitioning to high-efficiency
electric appliances where feasible. Carbon offset costs are projected to rise by 13% annually
through the forecast period.
In response to the dramatically high natural gas prices that occurred during winter 2022-23 and
to mitigate the impact of short-term price spikes, staff implemented a gas hedging program
effective beginning winter 2023-24. The program currently calls for the inclusion of a gas price
mitigation adder in the gas commodity charge to customers while maintaining the practice of
purchasing gas at market prices. Funds collected from the gas price mitigation adder will accrue
in the Gas Distribution Rate Stabilization Reserve and be used to offset the impact of a potential
gas market price spike above the maximum gas commodity charge to customers.
Operations
Operations costs are projected to increase by about 4% annually on average from FY 2025 to FY
2030, primarily due to higher allocated charges and salary and benefit expenses. The operations
costs in this forecast include $0.7 million for the cross-bore program in FY 2026. The safety
program ensures that gas pipelines have not crossed through sewer laterals, which is rare but
possible during trenchless installation. This "cross-bore" configuration poses a risk of gas leaks as
due to accidental cut by a plumber using a cutting tool to clear a sewer line. While a majority of
sewer laterals have been inspected, staff has come across several services which are unable to
be scoped, due to either infiltration by roots or broken/collapsed pipe segments. Figure 3 shows
the actual operations costs through FY 2024 and projected operations costs for the Gas Utility
from FY 2025 through FY 2030.
5 Staff Report 7441; https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=80132
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Figure 3: Actual and Projected Operations Costs
Capital Improvement Program
Staff anticipates annual capital expenditures will vary during the forecast period due to plans for
larger main replacement projects every other year, instead of smaller projects every year. This
main replacement schedule allows the Gas Utility to meet its main replacement needs while
addressing challenges in the current construction market and optimizing current staffing
resources. Overall CIP costs are expected to increase by around 6% on average annually from FY
2025 through FY 2030.
On May 9, 2024, the Gas Utility received a recommendation letter from the U.S. Department of
Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) for the FY
2023 Natural Gas Distribution Infrastructure Safety and Modernization (NGDISM) Grant. Staff
expects this grant to provide approximately $16.5 million for capital-related work for
replacement of 4.8 miles of leak-prone steel pipe and purchase of leak survey equipment, that is
additional to the utility’s already-planned capital work over the next five-year period. This grant
will replace and provide the full funding for GMR 25 and this replacement will take place in FY
2026 and FY 2027. About $3.7 million that was already reappropriated for this project from FY
2024 will return to the Operations Reserve. The original GMR 25 budget of $9.8 million, initially
scheduled for FY 2025, has been reallocated and split between GMR 26 and GMR 27, with
construction now planned for FY 2027 and FY 2029, respectively. CPAU will continue to look for
other grant opportunities to help fund the replacement of PVC and steel distribution mains in the
gas system.
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This financial forecast also includes transfers of about $1 million and $4 million each year in FY
2027 to FY 2030 from the Operations Reserve to gradually increase the currently depleted CIP
Reserve to within the guideline range by end of FY 2028.
Table 4: Budgeted Gas CIP Spending ($000)
Table 5: Debt Service Coverage Ratio ($000)
FY 2025 FY 2026
Reserves
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and FY 2025, with a plan to return to within the guideline range by the end of FY 2026. The
Operations Reserve is now expected to be above minimum at the end of FY 2025. However, due
to the CIP Reserve contributions starting in FY 2027, the Operations Reserve is expected to
remain close to the minimum guideline levels: it is expected to be at target levels by FY 2030.
Figure 4 shows the actual year-end balance in the Operations Reserve from FY 2018 to FY 2024
and projected from FY 2025 through FY 2030.
Figure 4: Operations Reserve Projection
Table 6: Gas Risk Assessment ($000)
FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030
Total Risk Assessment value 5,364 7,178 8,393 7,838 9,205 9,257
Reserve Maximum
Reserve Target
Reserve Minimum
Risk Assessment
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2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
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Reserve Transfers
Staff estimates that the gas price mitigation adder in the gas commodity charge will collect about
$1.126 million in FY 2025 for the gas hedging program. Although these funds are initially collected
in the Operations Reserve, they should be transferred to the Gas Distribution Rate Stabilization
Reserve to be available to mitigate the impact of potential gas market price spikes exceeding the
maximum gas commodity charge to customers. To support this objective, staff proposes
transferring up to $1.5 million from the Gas Utility Operations Reserve to the Gas Distribution
Rate Stabilization Reserve at the end of FY 2025. The exact transfer amount will be determined
at year end based on calculations aligned with the gas hedging program.
Figure 5 shows the CIP Reserve balances from FY 2018 through FY 2030. The CIP Reserve is
currently depleted; however, planned transfers in FY 2027 through FY 2030 will replenish the CIP
Reserve to within guideline range. With these transfers, the CIP Reserve would reach the
minimum guideline level by FY 2028. Per the Reserves Management Practices (Attachment D),
Section 6, any rate plan that does not return CIP reserves above minimum levels within one year
requires Council approval.
Figure 6 shows year-end reserve balance levels for each reserve from FY 2018 through FY 2030.
Table 7 shows reserve starting and ending balances, revenues, transfers expenses, capital
program contribution and operations reserve guideline levels from FY 2025 to FY 2030.
Reserve Minimum
Reserve Maximum
$0
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2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
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Figure 6: Gas Utility Reserves; Actual Reserve Levels for FY 2018 through FY 2024 and
Projections FY 2025 through FY 2030
$0
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2018 2019 2020 2021 2022 2024 2025 2026 2027 2028 2029 2030
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Rate Stabilization
Commitments &
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Operations Reserve
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Table 7: Operations, CIP, Cap-and-Trade, and Debt Service Reserve Starting and Ending
Balances, Revenues, Transfers To/(From) Reserves, Capital Program Contribution To/(From)
Reserves, and Reserve Guideline Levels for FY 2025 to FY 2030 ($000)
*Operations Reserve represents the Gas Supply Fund Rate Stabilization Reserve and the Gas Distribution Fund
Operations Reserve combined.
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)
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for FY 2026.6 A copy of the FY 2026 COS study titled “City of Palo Alto Natural Gas Cost of Service
and Rate Study,” (Natural Gas Cost of Service and Rate Study), February 2025 is included as
Attachment F 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. This financial forecast is based on staff’s assessment
of the financial position of the Gas Utility using the methodology from the Natural Gas Cost of
Service and Rate Study described above.
Refinement of G-2 (Residential Master-Metered and Commercial Gas Service) Rate Schedule
Table 8: G-2 Service by Maximum Meter Capacity7
G-2 Service by Maximum
Meter Capacity Range # of
Services
≤ 220 scfh
≥ 4,000 scfh
Distribution Revenue Requirement
6 Since FY 2021, the City has adjusted its distribution rates annually based on the COS study for FY 2020, which was
also conducted by EES.
7 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).
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of Service and Rate Study allocates these asset and expense estimates using updated
classification and allocation factors to ensure that the Gas Utility’s costs are properly assigned to
each rate class.
8 – the amount to be recovered through distribution rates via G-1, G-2 and
G-3 rate schedules. Current distribution rates (effective beginning July 1, 2024) at the same FY
2026 sales forecast would generate only $38.0 million in revenue and result in a $3.3 million
revenue shortfall. Thus, an 8.7% overall increase in distribution rates is needed to generate
sufficient revenue to cover FY 2026 distribution revenue requirement.
9 result in a revenue requirement
distribution (among the rate schedules) that differs from the prior cost study. Thus, the
percentage of revenue increase needed varies by rate schedule—ranging from 0% for G-2 to
15.6% for G-1. Tables 11 and 12 in the Proposed Rates section of this report present the current
and proposed rates associated with the following COS revenue requirement estimates.
Table 9: COS Revenue Requirement and Revenue Increase
8 This includes distribution costs, certain supply costs that are not paid for by pass-through supply charges (such as
administrative charges allocated to gas supply), and additional amounts required to restore the gas utility’s
operations reserve to within the guideline range in FY 2026.
9 For example: update in meter costs; adjustment to factor used to allocate General Fund Transfer to rate classes.
See Natural Gas Cost of Service and Rate Study (Attachment F of this report) for more details.
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Table 10: COS Revenue Requirement and Revenue Increase, G-2
Table 11 shows the current and proposed monthly service charges, while Table 12 shows the
volumetric charges related to distribution for all rate schedules. As previously noted, supply-
related charges are pass-through charges that update periodically. The latest charges are
shown in the City’s Rates website10. The proposed rates reflect the Natural Gas Cost of Service
and Rate Study adjustments conducted this year, which recommends a refinement of the G-2
rate schedule by establishing three meter capacity groupings.
10 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
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Table 11: Current and Proposed Monthly Service Charges
G-1 (Residential)$ 16.93 $ 19.52 $ 2.59 15.3%
G-2 (Small Commercial)
G-2 (≤ 220 scfh)156.90 29.06 (127.84)(81.5%)
G-2 (> 220 and < 4,000 scfh)156.90 94.94 (61.96)(39.5%)
G-2 (≥ 4,000 scfh)156.90 417.62 260.72 166.2%
G-3 (Large Commercial)717.89 1,731.67 995.78 138.7%
G-10 (CNG)106.11 115.34 9.23 8.7%
(Residential)
Tier 1 Rates $ 0.8229 $ 1.2274 $ 0.4045 49.2%
Tier 2 Rates 2.1043 1.8972 (0.2071) (9.8%)
(Residential Master-Metered and Small Commercial)
Uniform Rate $ 1.0809 $ 1.2616 $ 0.1807 16.7%
(Large Commercial)
Uniform Rate $ 1.0702 $ 1.1616 $ 0.0914 8.5%
(Compressed Natural Gas)
Uniform Rate $ 0.0175 $ 0.0190 $ 0.0015 8.6%
Table 13 shows the impact of the proposed July 1, 2025 rate changes on the median monthly
residential bill for representative average winter and summer bills, excluding supply-related
cost changes. The annual gas bill for the median residential customer is projected to be 21%
higher in FY 2026 than FY 2025. This increase is due to the overall 5% revenue increase needed
system-wide together with the cost of service adjustments. The actual impact may be different
because customer gas usage varies and commodity price changes monthly. Table 13 shows a
representative winter period (November thru March) and summer period (April through
October) bill comparison.
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Table 13: Impact on Residential Monthly Bill due to Proposed Gas Rate Changes11
ChangeUsage
(Therms/month)
Bill Amount
(Current Rates)
Bill Amount
(Proposed Rates)$/mo.%
Summer
10 $ 33.75 $ 40.38 $ 6.64 19.7%
17 (median) 45.52 54.99 9.47 20.8%
30 79.70 86.50 6.80 8.5%
45 124.15 127.84 3.69 3.0%
Winter
30 $ 68.69 $ 83.41 $ 14.73 21.4%
51 (median) 104.92 128.14 23.22 22.1%
80 180.07 203.03 22.96 12.8%
150 390.54 399.00 8.47 2.2%
Annual Median $ 70.27 $ 85.47 $ 15.20 21.6%
Table 14 shows the impact of the proposed rate changes, effective July 1, 2025, on
representative commercial customer bills, excluding supply-related cost changes. The G-2 usage
levels listed below represent the median usage for the three G-2 rate class groupings, as
recommended by the Natural Gas Cost of Service and Rate Study. G-2 customers with meter
capacity within the lowest (proposed) capacity range and corresponding lower usage would see
a significant reduction in monthly bill because of the proposed change in Monthly Service
Charge (e.g., representative bill at 35 therms/month in Table 14 below reflects a reduction of
$127.84 in Monthly Service Charge, partially offset by the volumetric rate increase). For the G-3
rate class, the usage reflects a sample large commercial customer with an annual consumption
of approximately 250,000 therms.
11 Current rates are derived from actual commodity prices up to January 2025 and forecasted prices until June
2025. Proposed rates, while based on the same supply-related rates as current rates, incorporate adjustments
solely in the increase of distribution rates.
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Table 14: Impact on Commercial Monthly Bill due to Proposed Gas Rate Changes12
ChangeUsage
(Therms/month)
Bill Amount
(Current Rates)
Bill Amount
(Proposed Rates)$/mo %
G-2 (Residential Master-Metered and Small Commercial)
35 $ 226.51 $ 105.07 $ (121.44)-54%
280 706.04 694.62 (11.42)-2%
2,648 5,356.93 6,096.22 739.29 14%
G-3 (Large Commercial)
20,834 $ 41,287.45 $ 44,187.46 $ 2,900.01 7%
Bill Comparisons/Competitiveness
Table 15 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 2023, the annual gas bill for the median Palo Alto residential customer was about $892, or
6% higher compared to a PG&E customer with equivalent consumption. This is attributed to the
gas price spike during the winter of 2022/2023, which impacted all California utilities except
PG&E, which avoided exceptionally high gas prices.
In FY 2025, the estimated annual gas bill for the median Palo Alto residential customer is
projected to be about 16% lower than that of a PG&E customer with equivalent consumption.
With the implementation of the Natural Gas Cost of Service and Rate Study adjustment and the
proposed rate increases, Palo Alto median residential bills are expected to be about 3% lower
than PG&E bills in FY 2026. It is important to note that this 3% difference is likely understated,
as this projection assumes PG&E does not implement additional rate increases between now
and July 2026.
Table 15: Residential Annual Natural Gas Bill Comparison ($/year)
Time Period Median Usage Palo Alto PG&E Zone X % Difference
FY 2022 $ 657.83 $ 724.24 (9%)
FY 2023 891.89 845.03 6%
FY 2024 753.28 764.70 (1%)
FY 2025* 843.26 1,008.72 (16%)
FY 2026 **
Annual
(374 Therms)
1,025.62 1,052.11 (3%)
*Calculated based on actual and projected rates
**Calculated based on projected rates
12 Current rates are derived from actual commodity prices up to January 2025 and forecasted prices until June
2025. Proposed rates, while based on the same supply-related rates as current rates, incorporate adjustments
solely in the increase of distribution rates.
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Table 16 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 this COS adjustment, 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 COS adjustment and the proposed rate increases,
Palo Alto median commercial bills are expected to be about 24% higher than PG&E bills in FY
2026, assuming PG&E does not implement additional rate increases.
Table 16: Commercial Annual Natural Gas Bill Comparison ($/year)
Time Period Median Usage*** Palo Alto PG&E Zone X % Difference
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* 8,472.51 6,523.21 30%
FY 2026**
Annual G-2
(3,356 Therms)
8,335.42 6,727.68 24%
*Calculated based on actual and projected rates
**Calculated based on projected rates
***Calculated based on G-2 with meter capacity of >220 and <4,000 scfh
Climate Credit Option
As shown in Table 13 above, median residential gas bills are expected to increase by about 21.6%
(approximately $15.20 per month or $182.40 per year) in FY 2026, compared with FY 2025. The
Gas Utility is a covered entity under California’s Cap-and-Trade program. CARB’s Cap-and-Trade
regulations authorize utilities to distribute Cap-and-Trade auction proceeds to some or all
ratepayers in a non-volumetric manner. Thus, Council may authorize staff to distribute
approximately $1.6 million in Cap-and-Trade reserve funds to provide a one-time flat $73.20
climate credit to each residential gas customer in FY 2026,13 lessening the rate increase impact
to the median residential customer from approximately $182.40 to $109.20 for FY 2026. While
the credit only applies to gas customers, the $73.20 credit would be the equivalent of reducing
an overall utility median bill increase for electric, gas, water, wastewater, refuse, and stormwater
from 11% to 9% for FY 2026. Cap-and-Trade revenues are earmarked for the benefit of retail
natural gas ratepayers and for GHG emission reduction activities, and subject to any limitations
imposed by Council. For context, $1.6 million is approximately the cost to fully electrify 182
homes.
Cap-and-Trade Reserve Transfer
In accordance with Section 11 of the Gas Reserve Management Practices and Council-approved
13 In accordance with the California Cap-and-Trade Program, specifically California Code of Regulations, Title 17,
Section 95893(d)(3)(C) https://ww2.arb.ca.gov/sites/default/files/2021-02/ct_reg_unofficial.pdf, utilities are
authorized to distribute Cap-and-Trade auction proceeds to some or all ratepayers in a non-volumetric manner.
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Cap-and-Trade revenue uses (Council Resolution 1007714), staff is authorized to transfer
revenues from allocated allowance auction proceeds to the Cap-and-Trade Reserve at the end of
each fiscal year. Additionally, staff may utilize funds from the Cap-and-Trade Reserve to support
greenhouse gas (GHG) reduction programs by transferring funds from the Cap-and-Trade Reserve
to the Operations Reserve.
Under the Cap-and-Trade Regulation, interest earned on allocated allowance auction proceeds
is considered value derived from the allocation of allowances and is subject to the same
distribution requirements. Staff has determined that the accumulated interest amounts to
$1,092,855.17 from Calendar Year (CY) 2015 to CY 2024. Therefore, staff will transfer this amount
from the Operations Reserve to the Cap-and-Trade Reserve in addition to the annual transfers of
allocated allowance revenue and program expenses. Going forward this calculation and transfer
will be done annually.
General Fund Transfer
The Gas Utility's transfer to the City’s General Fund is a component of the City’s gas rates. This
transfer was first authorized by voters in 1950 and reaffirmed in November 2022 with the
passage of Measure L which authorizes a transfer amount up to 18% of the gross revenues of the
Gas Utility. This financial forecast proposes a transfer of $9.735 million in FY 2026, 18% of FY 2024
gross revenues. This transfer of 18% is in alignment with the assumptions in the FY 2025 Adopted
Budget process.
Next Steps
The City Council will consider adopting this Financial Forecast and rate adjustments as part of the
FY 2026 budget review and adoption process in June 2025. If Council approves the proposed rate
changes, the rates will become effective July 1, 2025.
FISCAL/RESOURCE IMPACT
The resource impact of the recommendations summarized in this report is the continued
financial solvency of the Gas Utility and, as the City is a ratepayer, an increase to General Fund
expenses (due to the rate increases) and revenues (due to the General Fund transfer).
Based on the proposed rates increase as shown, the estimated revenue impacts in FY 2026 would
be an increase of $3.3 million in the Gas Fund, not including fluctuations in commodity
revenue/cost. Utility rate increases impact the general fund because the City is a customer of the
Gas Utility. The impact to the general fund from the proposed rate increases is a $0.17 million
expense increase. Additionally, the change in General Fund revenues from FY 2025 to FY 2026
would decrease from $10.917 million in FY 2025 to $9.735 million in FY 2026, a decrease of about
14 Council Resolution 10077 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=61567
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$1.183 million. The FY 2025 transfer was unusually high because it was based on FY 2023 revenue,
which was elevated due to the gas price spike during the winter of 2022-23.
POLICY IMPLICATIONS
The proposed Gas Utility rate adjustments are consistent with Council-adopted Reserve
Management Practices (Attachment D) and were developed using a cost-of-service study and
methodology consistent with the California constitution and industry-accepted cost of service
principles. If reserves fall below the minimum guidelines, Council approval is required for a rate
plan that requires more than one year to return reserves to within guideline levels. This staff
report serves as the required plan.
STAKEHOLDER ENGAGEMENT
Staff presented preliminary rate proposals to the Finance Committee on December 3, 202415 for
discussion only. One Committee member asked about the impact of population changes and one
Committee member said that demographic changes should be included. Staff explained that the
projection assumes lower gas sales due to electrification and we are considering population and
factoring in electrification.
Staff presented preliminary rate proposals to the UAC on December 4, 202416 for discussion only.
One Commissioner asked about how electrification was incorporated in the forecast and staff
explained that an outside consultant performed a regression with an electrification scenario that
was used for the gas purchase forecast. Commissioners asked about reserve guidelines and
reserve levels. One Commissioner expressed interest in the true cost of gas, considering the
environmental externalities.
Additional feedback from the UAC and Finance Committee meetings in 2025 will be incorporated
in the financial forecast and included in the proposal presented to City Council in June 2025
during the budget adoption process.
Attachment E contains examples of CPAU’s communication and outreach methods including the
use of the utilities website, utility bill inserts, messaging on utility bills, and MyCPAU online
account management platform, email newsletters, print and digital ads in local publications,
social media, and community messaging platforms.
ENVIRONMENTAL REVIEW
15 December 3, 2024 Finance Committee Meeting, Staff Report
https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=64761 , Minutes
https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=39017 , Video
https://www.youtube.com/watch?v=-tshOdaDA3A%3Ffeature%3Dshare
16 December 4, 2024 Utilities Advisory Commission, Staff Report
https://cityofpaloalto.primegov.com/Portal/viewer?id=0&type=7&uid=d7cd6030-1d05-412e-a96b-cabd33557bc1,
Minutes https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=41244 , Video
https://www.youtube.com/watch?v=tfznidSYXiU%3Ffeature%3Dshare
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The UAC’s review and recommendation to the Finance Committee on the FY 2026 Gas Utility
financial forecast and rate adjustments does not meet the California Environmental Quality Act’s
definition of a project, pursuant to Public Resources Code Section 21065, thus no environmental
review is required.
ATTACHMENTS:
APPROVED BY:
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Attachment A
NOT YET APPROVED
Resolution No.
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2026 Gas Utility Financial Forecast and Reserve Transfers, the
Natural Gas Cost of Service and Rate Study and General Fund
Transfer, and Amending Rate Schedules G-1 (Residential Gas
Service), G-2 (Residential Master-Metered and Commercial Gas
Service), G-3 (Large Commercial Gas Service), and G- 10 (Compressed
Natural Gas Service)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations, including reserves.
This includes making long-term projections of market conditions, the physical condition of the
system, and other factors that could affect utility costs, and setting rates adequate to recover
these costs. It does this with the goal of providing safe, reliable, and sustainable utility services
at competitive rates. The City adopts Financial Forecasts or Plans to summarize these
projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Forecasts or Plans.
C. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
D. On June 9, 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 adopts the fiscal year (“FY”) 2026 Gas Utility Financial
Forecast and Cost of Service Study attached to and made a part of the staff report presented to
the City Council;
SECTION 2. The Council hereby approves the transfer of up to 18% of gas utility
gross revenues received during FY 2024 to the general fund in FY 2026;
SECTION 3. 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
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Attachment A
NOT YET APPROVED
incorporated. Utility Rate Schedule G-1, as amended, shall become effective July 1, 2025
(Attachment B);
SECTION 4. 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 July 1, 2025 (Attachment B);
SECTION 5. 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 July 1, 2025
(Attachment B);
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-10 (Compressed Natural Gas Service Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule G-10, as amended, shall become effective
July 1, 2025 (Attachment B);
SECTION 7. The City Council finds that revenues derived from the gas rates approved
by this resolution do not exceed the funds required to provide gas service and shall not be used
for any purpose other than providing gas service, and the purposes set forth in Article VII,
Section 2, of the Charter of the City of Palo Alto.
SECTION 8. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
SECTION 9. The Council finds that approving the FY 2026 Gas Utility Financial
Forecast does not meet the California Environmental Quality Act’s (CEQA) definition of a
project under Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(5),
because it is an administrative governmental activity which will not cause a direct or indirect
physical change in the environment, and therefore, no environmental assessment is required.
The Council finds that changing gas rates to meet operating expenses, purchase supplies and
materials, meet financial reserve needs and obtain funds for capital improvements necessary to
maintain service is not subject to the California Environmental Quality Act (CEQA), pursuant to
California Public Resources Code Sec. 21080(b)(8) and Title 14 of the California Code of
Regulations Sec. 15273(a). After reviewing the staff report and all attachments presented to
/ /
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Attachment A
NOT YET APPROVED
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
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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 7-1-2025Sheet No G-1-1
dated 117-1-2024 Sheet No G-1-1Effective 11-1-2024
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 everanywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES:Per Service
Monthly Service Charge: ................................................................................................$ 19.526.93
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:....................................................................................... $
1.20930.8229
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 ................................................................. Pass-
through$0.00-$0.30
4.Carbon Offset Charge .................................................................. $0.00-$0.10
Attachment B Item #3
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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 7-1-2025Sheet No G-1-2
dated 117-1-2024 Sheet No G-1-2Effective 11-1-2024
Distribution Charge:............................................................................................. $
2.10431.8792
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 discount 1 and $0.055 per therm for mitigating the impact of short-term natural
gas market price spikes 2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s
compliance obligations. The Cap and Trade Compliance Charge will changes in
response to changing market conditions, retail sales volumes and the quantity of
allowances required, . The Cap and Trade Compliance Chargeand is a pass-through
charge and itis calculated based on the Cap-and-Trade Pprogram’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 will changes in response
to changing market conditions, changing 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.
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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 7-1-2025Sheet No G-1-3
dated 117-1-2024 Sheet No G-1-3Effective 11-1-2024
The Transportation Charge is a pass-through charge , and it is based on the current PG&E
G-WSL 3 (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 shall beis calculated and billed based upon a level of 23 therms
per 30 day billing period during the Summer period, and 60 therms per 30 day billing period
during the Winter period, based on meter reading days of service, and rounded to the
nearest whole therm. As an example, Tier 1 natural gas usage would beis calculated at
0.767667 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) months,. 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.cityofpaloalto.org/files/assets/public/utilities/rates-schedules-for-utilities/residential-utility-rates/monthly-gas-
volumetric-and-service-charges-residential.pdf
Attachment B Item #3
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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 711-1-20254
dated 117-1-2024 Sheet No G-2-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use less than 250,000 therms per year at one site;
2. Master-metered residential Customers in multi-family residential facilities.
B. TERRITORY:
This schedule applies everanywhere 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)
..................................................................................................................................$ 29.06
2. Above 220 scfh butand less than 4,000 scfh ............................................................$ 94.94
3. 4,000 scfh and above ................................................................................$ 417.62$ 156.90
..............................................................................................................................................
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 .................................................................................. Pass-
through$0.00-$0.30
4. Carbon Offset Charge ................................................................................... $0.00-$0.10
Distribution Charge: .................................................................................................. $1.26160809
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.
Attachment B Item #3
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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 711-1-20254
dated 117-1-2024 Sheet No G-2-2
The meter’s maximum capacity used to determine the applicable Monthly Service Charge
for G-2 Gas Service is the installed meter’s City of Palo Alto-approved maximum
capacity in standard cubic feet per hour (scfh), measured at 7 inches of water column or
equivalent to 0.25 pounds per square inch.
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 discount 1 and $0.055 per therm for mitigating the impact of short-term natural
gas market price spikes 2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge will 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 will changes in response to
changing market conditions, changing sales volumes and the quantity of offsets purchased
within the Council-approved per therm cap.
The Transportation Charge is a pass-through chargeis based on the current PG&E G-
WSL 3 (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
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.cityofpaloalto.org/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-
Attachment B Item #3
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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-2-3 Effective 711-1-20254
dated 117-1-2024 Sheet No G-2-3
{End}
charges-commercial.pdf
Attachment B Item #3
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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 711-1-20254
dated 711-1-2024 Sheet No G-3-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use at least 250,000 therms per year at one site;
2. Customers at City-owned generation facilities including the City’s Natural Gas fueling
station at the Municipal Services Center.
B. TERRITORY:
This schedule applies everyanywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: $ 1,731.67717.89
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges ................................ Pass-through$0.00-$0.25
3. Transportation Charge .......................................................................... Pass-
through$0.00-$0.30
4. Carbon Offset Charge ........................................................................... $0.00-$0.10
Distribution Charge: ............................................................................................................$ 1.0702
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
Attachment B Item #3
Packet Pg. 67
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 711-1-20254
dated 711-1-2024 Sheet No G-3-2
purchase discount 1 and $0.055 per therm for mitigating the impact of short-term natural
gas market price spikes 2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge will 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 will changes in response to
changing market conditions, changing sales volumes and the quantity of offsets purchased
within the Council-approved per therm cap.
The Transportation Charge is a pass-through chargeis based on the current PG&E G-
WSL 3 (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
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.cityofpaloalto.org/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-
charges-commercial.pdf
Attachment B Item #3
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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 711-1-20254
dated 711-1-2024 Sheet No G-3-3
{End}
Attachment B Item #3
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COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-1 Effective 711-1-20254
dated 117-1-2024 Sheet No. G-10-1
A. APPLICABILITY:
This schedule applies to the sale of Gas to the City-owned compressed natural gas (CNG) fueling
station at the Municipal Service Center in Palo Alto.
B. TERRITORY:
Applies to the City’s CNG fueling station located at the Municipal Service Center in City of Palo Alto.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ..........................................................................................$ 115.34106.11
Per Therm
Supply Charges:
Commodity (Monthly Market Based) ................................................................ $0.10-$4.00
Cap and Trade Compliance Charges ............................................. $0.00-$0.25Pass-through
Transportation Charge .................................................................. Pass-through$0.00-$0.30
Carbon Offset Charge ........................................................................................ $0.00-$0.10
Distribution Charge ........................................................................................................$ 0.0190175
D. SPECIAL CONDITIONS
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 spikes 2.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
Attachment B Item #3
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COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-2 Effective 711-1-20254
dated 117-1-2024 Sheet No. G-10-2
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s cost of
regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring
compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The
Cap and Trade Compliance Charge will 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 will changes in response to changing
market conditions, changing sales volumes and the quantity of offsets purchased within the
Council-approved per therm cap.
The Transportation Charge is a pass-through chargeis based on the current PG&E G-WSL 3 (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}
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.cityofpaloalto.org/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-
charges-commercial.pdf
Attachment B Item #3
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Attachment C
Item #3
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Attachment C
Gas Utility Capital Improvement Program (CIP) Financial Details
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Attachment D
6
7
5
7
GAS UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Gas Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015
to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets
as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Gas Utility’s Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
Section 3. Distribution Fund Reserves
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Gas Utility’s Capital
Improvement Program (CIP), as described in Section 6 (CIP Reserve)
d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 8 (Operations Reserve)
f) For tracking unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the gas utility under the State’s Cap and
Trade Program, as described in Section 11 (Cap and Trade Program Reserve)
g) Any funds not included in the other reserves will be considered Unassigned Reserves and
shall be returned to ratepayers or assigned a specific purpose as described in Section 9
(Unassigned Reserves)
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Attachment D
6
7
5
7
Section 4. Reserve for Commitments
1. These guideline levels are
calculated for each fiscal year of the Financial Planning Period and approved by Council
resolution.
1 The guideline levels were corrected to match the Council-approved language updated from the
FY 2021 Financial Plan.
2 Each month is calculated based upon 1/12 of the annual budget.
3 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual
average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use to
derive the annual average would be FY 2022 through FY 2025 etc.
Minimum Level 20% of the maximum CIP Reserve guideline level l
Maximum Level Average annual (12 month)2 CIP budget, for 48 months of
budgeted CIP expenses3
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Attachment D
6
7
5
7
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds may
be added to this reserve. If there are funds in this reserve in excess of the maximum level
staff must propose to transfer these funds to another reserve or return them to
ratepayers in the next Financial Plan. Staff may also seek Council approval to hold funds
in this reserve in excess of the maximum level, if they are held for a specific future purpose
related to the CIP.
Section 7. Rate Stabilization Reserve
The Rate Stabilization Reserve is used to manage the trajectory of future Funds may be added
to the Rate Stabilization Reserve by action of the City Council and held to manage the
trajectory of future year rate increases. Withdrawal of funds from the Rate Stabilization
Reserve requires Council action. If there are funds in the Rate Stabilization Reserve at the end
of any fiscal year, any subsequent Gas Utility Financial Plan must result in the withdrawal of
all funds from this Reserve by the end of the Financial Planning Period.
Section 8. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves
described in Section 4-Section 7 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for that
year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months of
the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
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Attachment D
6
7
5
7
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Gas Utility’s Fund Balance
shall be automatically included in the Unassigned Reserve described in Section 9, below.
Section 9. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas Utility’s
Fund Balance will be held in the Unassigned Reserve. If there are any funds in the Unassigned
Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council
must include a plan to assign them to a specific purpose or return them to the Gas Utility
ratepayers by the end of the first fiscal year of the next Financial Planning Period. For
example, if there were funds in the Unassigned Reserves at the end of FY 2015, and the next
Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a plan
to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff may
present an alternative plan that retains these funds or returns them over a longer period of
time.
Section 10. Intra-Utility Transfers Between Supply and Distribution Funds
The Gas Utility records costs in two separate funds: the Gas Supply Fund and the Gas
Distribution Fund. At the end of each fiscal year staff is authorized to transfer funds between
the Gas Supply Fund and Gas Distribution Fund if consistent with the purposes of the two
reserves involved in the transfer and in order to balance gas utility reserves to avoid negative
balances. For example, Gas Distribution revenues are needed to pay for certain supply-
related costs such as administration of the Gas Supply Fund. Such transfers shall be included
in the ordinance closing the budget for the fiscal year.
Section 11. Cap and Trade Program Reserve
This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the gas utility, under the State’s Cap and
Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy on the
Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the Policy),
adopted by Council Resolution 9487 in January 2015. At the end of each fiscal year, the Cap
and Trade Program Reserve will be adjusted by the net of revenues and expenses associated
with the Cap and Trade program.
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ATTACHMENT E
COMMUNICATIONS PLAN AND OUTREACH EX AMPLES
The fiscal year (FY) 2026 gas utility communications strategy addresses cost drivers for rate increases
including the need to rebuild financial reserves and ongoing capital investment in the natural gas
distribution system. Financial reserves need to be replenished following a drawdown during the
pandemic to keep customer rate changes at a minimal level. Additionally, the City used financial reserves
to protect customers from surging gas prices in the winter of 2022-2023. Maintaining healthy financial
reserves also ensures that the City of Palo Alto Utilities (CPAU) can continue to invest in capital
improvement of the natural gas distribution system for safe and reliable service delivery.
CPAU continues to explore cost-containment measures for each utility fund, consistent with the Utilities
Strategic Plan. CPAU was recently awarded a $16.5 million grant by the U.S. Department of
Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) which was intended to
provide financial assistance for capital-related work that is additional to the utility’s already planned
capital work over the next five-year period. CPAU is awaiting an update from the federal administration
about the ultimate issuance of this grant.
CPAU purchases gas as a commodity on the market, thus monthly gas rates can fluctuate due to external
factors. Staff post the monthly rates online at www.cityofpaloalto.org/RatesOverview and provide
updates on the rate setting process so members of the public can be informed and get involved in the
public process. CPAU promotes gas use efficiency year-round, but most heavily during winter months to
impact heating activities. Messaging emphasizes the importance of saving energy to keep utility costs
low even if gas prices are high or utility rates are increasing. Programs such as advisor services for energy
efficiency and electrification offer residents assistance for home upgrades. CPAU provides free
consulting services and rebates for commercial energy efficiency upgrades. Throughout the year, CPAU
hosts free educational workshops to help residents and businesses better understand energy usage and
learn ways to improve efficiency to keep utility costs low. The MyCPAU online account management
portal provides customers with direct access and more information about utility account and
consumption data.
CPAU communicates about safety for all utility services year-round including the need to call USA (811)
before digging to check for underground utility lines. Staff also emphasize the importance of contacting
CPAU to check for potential sewer and gas line cross-bores prior to clearing a sewer line. Every year,
CPAU publishes a gas safety awareness brochure and mails it to all customers in Palo Alto as well as other
stakeholders. Staff talk with business customers at special facilities meetings and attend neighborhood
safety and emergency preparedness fairs. While print materials and webpages still feature prominently,
CPAU is increasing use of other outreach channels such as email newsletters, social media and online
videos. The Gas Safety Public Awareness Plan contains saved copies of all outreach materials and activity
logs. Additional CPAU communication methods include the utilities webpages, utility bill inserts,
messaging on bills and envelopes, informational fliers and brochures, email newsletters, social media,
print and digital ads in local publications, and participation in community outreach events.
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ATTACHMENT E
Item #3
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Natural Gas Cost of Service and
Rate Study
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
February 202 5
Attachment F Item #3
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16701 NE 80th Street Suite 102 Redmond, WA 98052 425-889-2700 Fax 866-611-3791 www.eesconsulting.com
G e o r g i a T e x a s A l a b a m a N e w H a m p s h i r e W i s c o n s i n M a i n e W a 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
cell 360-319-7946
February 2025
Lisa Bilir
Senior Resource Planner
City of Palo Alto
250 Hamilton Avenue
Palo Alto, CA 94301
SUBJECT: Natural Gas Cost of Service and Rate Study
Dear Lisa:
Attached please find the Natural Gas Cost of Service and Rate Study 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 upon industry practice and
accepted rate setting principles. The assumptions are consistent with the financial and metering data
provided for revenue requirement, customer, and system data and costs.
EES developed the study with mutual aid of the City’s staff and appreciate the internal effort to refine the
study. The findings, conclusions and recommendations of this report supply the basis for the development
of fair and equitable rates for the City.
Very truly yours,
Amber Gschwend
Director, EES Consulting
amber.gschwend@gdsassociates.com
Russ Schneider
Senior Project Manager, EES Consulting
russ.schneider@gdsassociates.com
Attachment F Item #3
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING i
TABLE OF CONTENTS
1 EXECUTIVE SUMMARY ................................................................................................... 1
1.1 System Description ............................................................................................................................................. 1
1.2 Rate Study Overview .......................................................................................................................................... 3
1.2.1 Revenue Requirement ................................................................................................................ 3
1.2.2 Cost of Service Analysis ............................................................................................................. 4
1.2.3 Rate Design Recommendations ................................................................................................ 5
1.2.4 Rate Change Recommendations ............................................................................................... 8
2 REVENUE REQUIREMENT DEVELOPMENT ................................................................... 9
2.1 Overview of the City’s Revenue Requirement Methodology ............................................................. 9
2.2 Supply Costs .......................................................................................................................................................... 9
2.3 Distribution Costs ............................................................................................................................................. 10
2.4 Debt Service and Rate-Funded Capital Improvement Program (CIP) .......................................... 10
2.5 General Fund Transfer .................................................................................................................................... 11
2.6 Miscellaneous/Other Revenues .................................................................................................................. 11
2.7 Transfers to/from Reserves ........................................................................................................................... 11
2.8 Summary of Revenue Requirement........................................................................................................... 11
3 COST OF SERVICE ANALYSIS ....................................................................................... 13
3.1 COSA Definition and General Principles .................................................................................................. 13
3.2 City Natural GAs Distribution COSA Methodology ............................................................................. 14
3.2.1 Functionalization ..................................................................................................................... 14
3.2.2 Classification and Allocation of Costs .................................................................................... 14
3.3 Average & Excess (A&E) ................................................................................................................................ 19
3.3.1 Revised Average & Excess Calculation ................................................................................... 20
3.4 Customer Classes of Service ......................................................................................................................... 21
3.5 Cost of Service Results ................................................................................................................................... 21
4 RATE DESIGN ................................................................................................................ 25
4.1 Recommended Rate Design: Distribution ............................................................................................... 25
4.1.1 Residential (G1) ........................................................................................................................ 25
4.1.2 Small Commercial and Residential Master-Metered and (G2) ............................................. 28
4.1.3 Large Commercial (G3) ............................................................................................................ 30
4.2 Supply Charges ................................................................................................................................................. 31
Attachment F Item #3
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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 as part of its
ongoing efforts to maintain fiscally prudent, fair, cost-based rates for its natural gas customers. The
natural gas COSA is primarily concerned with the development of distribution rates.
In addition to the distribution rates that are the subject of this Study, the City charges four additional rates
to customers that pass on 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 Study.
The starting point for the current study was the COSA that EES performed for FY 2019-2020 (COSA 2020).
The City updated that COSA model for FY 2020-2021 (COSA 2021), with some assistance by EES. Since
then, the City has implemented distribution rate adjustments by uniformly adjusting distribution rates
using the percent change in distribution revenue requirement; thus, distribution rates since 2021 have
reflected the COSA 2020 analysis framework.
This Study is a comprehensive update to the 2020 COSA. All Study assumptions and inputs have been
updated and new rate designs incorporated into the recommendations. EES also modernized and
streamlined the COSA model to facilitate future updates.
EES worked closely with the City’s technical staff and management to refine data inputs for gas sales and
updated 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 23,500 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 of its gas from outside suppliers. Total gas consumption in the City forecasted for FY
2025-2026 is 25.8 million therms. EES expects 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.
1 July 2025 through June 2026.
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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 21,255 9,762,524
G2 Residential Master Metered and Commercial 2,193 11,506,051
G3 Large Commercial 30 4,510,914
Total 23,477 25,779,489
Gas utility rate schedules consist of a fixed monthly service charge and volumetric rates. The Monthly
Service Charge ($/meter/month) and Distribution Charges ($/therm) vary by rate class. Volumetric
charges are used for both commodity purchases and recovery of variable distribution costs.
Table 1-2 summarizes the rate classes and current rate design for the distribution portion of the rate
schedule. It does not include volumetric supply charges: Commodity Charge (Monthly Market Based), Cap
and Trade Compliance Charge, Transportation Charge and Carbon Offset Charge.
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
2
Volumetric Charge, $/therm
1. Summer rates effective April 1 through October 31. Winter rates effective November 1 through March 31.
2 In addition to these standard rate classes, CPAU provides CNG service under the G10 rate schedule. The CNG
customer receives service using specific facilities. The service provided has not changed since the previous cost of
service study, and the cost to serve the G10 customer has increased at the same rate as for the distribution expenses
overall. For this reason, the G10 rate should be adjusted by the average system increases. For FY 2025-2026, the G10
rate should be increased 8.7%.
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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
examination.
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 (revenue
requirement). A revenue requirement analysis compares the overall revenues of the utility to its expenses
and helps determine the need for an overall adjustment to rate levels. 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
the natural gas utility. For this COSA, EES maintained a cash-basis method for determining the City’s
revenue requirement based on the City’s financial forecast.
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 COSA; the COSA focuses narrowly on setting appropriate
distribution charges for the year.
Table 1-3 summarizes the FY 2025-2026 distribution revenue requirement totaling $41.3 million. At
current rates, there is a revenue shortfall of $3.3 million. A rate increase of 8.7% to the distribution rate
would collect the required revenue to meet distribution costs.
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TABLE 1-3: DISTRIBUTION 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
Debt Service & CIP from Rates $8,339,643
General Fund Transfer $9,734,580
Total Expenses $36,082,566
Total Revenue Required from Rates (Revenue Requirement) $41,268,342
Revenues Based on Rates Currently in Effect $37,957,863
Total Required Rate Revenue Increase (Decrease) 8.7%
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 production (commodity), transportation,
distribution, or shared services. This COSA evaluates only Distribution costs and distribution-related
overhead.
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 1-4 shows, by customer class, the revenue requirement
and revenue change needed for FY 2025-2026.
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TABLE 1-4: DISTRIBUTION COSA RESULTS: FY 2025-2026
Projected FY 2025-
Revenue
FY 2025-2026
Deficiency/
Revenue
G1 – Residential $16,311,063 $18,853,368 $2,542,305 15.59%
$16,565,086 $16,568,614 $3,527 0.02%
$5,081,713 $5,846,360 $764,647 15.05%
Total $37,957,863 $41,268,342 $3,310,479 8.7%
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. 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 according to the utility’s respective 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 is not recommending changes to this basic rate design structure, except for a refinement in the
development of the Monthly Service Charge for G2 based on additional analysis of that class’s 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 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.
EES recommends no change to the G1 rate structure because it effectively recovers energy and demand
or capacity costs incurred by the class.
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 heat is more prevalent in the
winter and causes higher consumption.3 This ensures that those customers contributing to higher
seasonal demand are paying appropriately for their share of the demand-related cost in a tiered rate. EES
evaluated the G1 tier rates using the Average and Excess (A&E) method (discussed in more detail in
Section 3.4) and proposes a modest adjustment to the summer baseline from 20 to 23 therms per thirty-
day billing period.
3 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.
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Table 1-5 summarizes the costs to be recovered in each rate component for G1.
TABLE 1-5: 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 54% of demand-related distribution unit costs*
Tier 2 Volumetric Rate Energy-related costs plus 46% of demand-related distribution unit costs*
*See calculations in Section 4.1.1. Residential (G1) Rate Design, Table 4-5.
1.2.3.2 Commercial
EES recommends no change to the volumetric charge structure for the two commercial classes (G2 and
G3). Within the commercial rate class, there are inherent size differences, in terms of physical space and
energy use, related to the types of business.
It is not appropriate to charge larger-usage businesses more through a volumetric tiered rate structure
because the larger sized customers have sufficient minimum monthly consumption to account for
variances in distribution costs on a per therm basis. For example, when comparing the minimum level of
monthly consumption to the annual consumption, all commercial classes have minimum consumption
over 59%, whereas residential minimum consumption by the same measure is only 36%. Therefore, tiered
volumetric Distribution Charges for commercial classes are not necessary, but do have a place for the
residential class. There is not a sufficient under-recovery of demand-related distribution costs from
minimum volumes to warrant a tiered rate for commercial classes.
This Study updated input, assumptions and calculations of fixed charges. The resulting changes proposed
to the Monthly Service Charge for G2 are based on a refinement of cost functionalization developed in
the study. This methodology and assumptions are detailed in Section 3. In addition to the methodology
review, EES performed additional analysis on G2 meter capacity related costs by comparing the average
consumption for various meter capacities. Fixed costs are generally higher for customers with larger
capacity service because of the larger and more expensive equipment required to provide higher volume
service.
Based on the findings of this analysis, EES determined customer-related costs for three categories defined
by meter capacity. Table 1-6 illustrates the recommended rate for the G2 class and the number of services
within each G2 subgroup. 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 $29.06.
For G3, the meter capacity of services is much more uniform within the rate class. Also, importantly, the
meter costs associated with G3 consumption levels are similar.
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TABLE 1-6: G2 MONTHLY SERVICE CHARGES: FY 2025-2026
CPAU Approved Maximum Meter Capacity (scfh 4
Number
of
Monthly Service
Charge
Monthly Service
Charge
1,134 $156.90 $29.06
942 $156.90 $94.94
116 $156.90 $417.62
While Table 1-6 shows the lower Monthly Service Charge for smaller G2 customers (defined as customers
with meter capacity up to 220 scfh), Table 1-7 illustrates that this same group of customers should also
receive an overall rate decrease. The column “Revenue Requirement” in Table 1-7 presents the total
revenue requirement amounts (including fixed and variable costs) that correspond to the recommended
Monthly Service Charges shown in Table 1-6 above. The recommended rates for G2 are provided in
Section 1.2.4.
TABLE 1-7: G2 REVENUES AND REVENUE REQUIREMENT: FY 2025-2026
CPAU Approved Maximum
2026 Revenues
at Current
Monthly Service
Revenue
Projected
FY 2026
Revenue
Change
$2,948,824 $1,713,540 ($1,235,283) -41.9%
Above 220 but Below 4,000 $7,685,399 $7,987,841 $302,442 3.9%
4,000 and Above $5,930,863 $6,867,232 $936,369 15.8%
Total G2 $16,565,086 $16,568,614 $3,527 0.0%
4 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. CPAU approved maximum 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).
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1.2.4 Rate Change Recommendations
Table 1-8 provides a comparison of current rates and recommended rates for FY 2026, including the newly
developed G2 Monthly Service Charge by meter capacity.
TABLE 1-8: CURRENT AND RECOMMENDED RATES
Current FY 2025-2026 Percent
$16.93 $19.52 $2.59 15.3%
For Winter: first 60 therms/30-day-billing
For Summer: first 20 therms/30-day-billing
(current); first 23 therms/30-day-billing
$0.8229 $1.2274 $0.4045 49.2%
For Winter: over 60 therms/30-day-billing
For Summer: over 20 therms/30-day-billing
(current); over 23 therms/30-day-billing
$2.1043 $1.8972 -$0.2071 -9.8%
$156.90 $78.00 -$78.90 -50.3%
$1.0809 $1.2616 $0.1807 16.7%
≤
$156.90 $29.06 -$127.84 -81.5%
$1.0809 $1.2616 $0.1807 16.7%
$156.90 $94.94 -$61.96 -39.5%
$1.0809 $1.2616 $0.1807 16.7%
≥
$156.90 $417.62 $260.72 166.2%
$1.0809 $1.2616 $0.1807 16.7%
$717.89 $1,713.67 $995.78 138.7%
$1.0702 $1.1616 $0.0914 8.5%
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2 Revenue Requirement Development
This section presents the development of the natural gas revenue requirement in the COSA study. Simply
stated, a revenue requirement analysis compares the overall revenues of the utility to its expenses and
determines the overall adjustment to rate levels required.
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 COSA uses a future fiscal year test period to
correspond with the City’s budget year. The revenue requirement in this COSA 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 Study 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 $25.8 million or
38 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.
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While the cost of natural gas supply is included in the COSA, it is treated as a separate category as 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 operations 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 or cash from rates or
through 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 in effect, 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.
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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 2022.5 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 and contributions. These come in the
form of interest revenues, connection fees and other miscellaneous service revenues. Interest revenues
are interest earned on the utility’s reserves. Connection fees are contributions paid by customers to cover
the cost of new facilities built on their behalf. For FY 2025-2026, the projection for these revenues and
contributions is $0.7 million.6 These 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.
A rate increase of 8.7% is required to meet projected FY 2025-2026 costs.
5 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.”
6 Misc. Revenues also includes customer discounts and uncollectible bills. These items reduce the amount of funds
needed to be collected from retail gas rate revenues because they are recovered from non-rate revenues including
interest income from investments. Therefore, the total Misc. Revenues is the total non-rate revenue net of these
expenses.
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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
Other Revenues -$689,111
Total Revenue Required from Rates (Revenue Requirement) $41,268,342
Revenues Based on Rates Currently in Effect $37,957,863
Additional Rate Revenue Needed without Gas Supply $3,310,479
Total Required Rate Revenue Increase (Decrease) 8.7%
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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, namely: functionalization; classification;
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 system revenues or directly 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
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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 services include all services required to transport the natural gas commodity from the point
of interconnection across the City’s distribution system to end-users 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. (Rate base for
the City’s natural gas utility consists of investment of physical assets. It includes general plant and
distribution plant investment and is net of accumulated depreciation. EES typically relies on an audited
fiscal year for rate base amounts, whereas 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 COSA but with a few changes to allocation factors based on updated cost-causation
themes.
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 of time, such as a month or year. Reserve
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 use of the
system.
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
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is more costly and requires substantially more work and material than that 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. 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.
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TABLE 3-1: DISTRIBUTION RATE BASE
Asset Description
Asset Value
FY 2021-2022 7
and Allocation
Equip-Meters
$12,334,716 Weighted by Meters and
Total Distribution Plant $155,578,873
General Plant
$1,910,425 Plant
$2,911,310 Plant
Total General Plant $4,821,735
Total Gross Plant in Service $160,400,608
Less: Accumulated Depreciation
Total Accumulated Depreciation $53,646,292
Total Net Plant
Working Capital: 1/8 Operating Costs
$2,251,043
OMWOP Operation & Maintenance
Expense
TOTAL RATE BASE
Constructions Working in Progress
(CWIP)
Total CWIP
TOTAL RATE BASE plus CWIP
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.
7 Fiscal year ending June 30, 2022 was the audited asset values available for the study period.
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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 Number of Services
Weighted for
Weighted for
Weighted for
Weighted for
Total Customer Service, Accounts &
Sales
Administrative & General
Administrative & General Salaries 8
Allocated Charges 9
Rents
Transfers to Non-Enterprise Funds
Transfers to Enterprise Funds
8 Administrative and General Salaries includes salaries and benefits for staff assigned directly to Gas Utility
Administration.
9 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.
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FY 2025-2026
Classification
and Allocation
$5,002,927
$18,008,343
Interest on Long-Term Debt $23,348 NETPLT Net Plant
Principal on Long-Term Debt $778,250 NETPLT Net Plant
System Improvement $7,538,046 NETPLT Net Plant
$8,339,643
General Fund Transfer $9,734,580 REV Current Rate Revenues
Reserves Contribution $5,874,887 therm Annual Energy (therms)
$41,957,453
Customer Discounts 10 -$318,105 NETPLT Net Plant
Connection Fees $700,000 NETPLT Net Plant
Misc. Revenue and other
contributions (Other) -$449,823
$625,693
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.
10 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. The low-income rate assistance discounts and pre-1970s
retired employee discounts on utility bills at a primary residence are funded through non-rate revenues including
interest income from investments.
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TABLE 3-3: NATURAL GAS DISTRIBUTION REVENUE REQUIREMENT
Factor Code Factor Name Classification Allocation Basis
AE Average and Excess 100% Demand An allocation of demand costs that
calculates the difference between the peak
demand and average demand – A more
detailed explanation of the Average and
Excess allocation framework is later in the
Accounting/Metering w/o G3 accounting and metering but excluding G3
Rate Base 50% Energy
8% Customer
based on the net book value of all shared
services assets and other capital assets
Gas Supply and A&G) 42% Energy Gas Supply and A&G expenses
Rate Base 50% Energy based on the book value of all general plant
(w/o General Plant & 50% Energy value of all capital assets (initial cost)
50% Energy
8% Customer
value of all capital assets (initial cost less
accumulated depreciation) assigned to
Purchased Gas Supply) 42% Energy the cost of Purchased Gas Supply
3.3 AVERAGE & EXCESS (A&E)
The Average and Excess method (A&E method) compares the baseline capacity and energy used (the
“average,” or “baseline”) against the maximum capacity and energy used on a seasonal basis (the
“excess”). This captures the level of system capacity required to serve the customer during peak times as
opposed to average times. The previous COSA study functionalized and classified distribution system costs
as 100% demand related, and then used each customer’s share of non-coincident peak demand to allocate
those distribution costs across customer classes.
As part of this study, EES revised the A&E method calculations because it recognizes that part of the
system is built to serve the customer/energy use and part of the system was built to serve the demand
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component whereas the previous method primarily attributed system sizing entirely to demand. The
revised A&E method classifies distribution system costs to demand and energy. Then costs are allocated
to customer classes based on an estimate of average demand and maximum (excess) demand for each
class. This current A&E method provides the basis for calculating fixed and variable unit costs. It also
equitably determines residential Tier 1 and Tier 2 rates (described later).
Based on monthly sales by customer class, the A&E method used in this Study makes the following
assumptions:
1. Average demand represents the 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 minimum use year-round.11
The current A&E method assumes that the marginal costs of the distribution system do not decrease as
capacity increases. The method also provides cost allocation across customer classes consistent with the
average use of each class while still maintaining a cost obligation for classes where excess use varies
significantly from average use.
3.3.1 Average & Excess Calculation
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
minimal use (energy). In addition, another portion of the distribution system investment is needed to
meet customer maximum use (demand). In order to apportion the system between minimum use
characteristics and maximum demand characteristics, we approximate this share of the system using the
classification split as described below.
Table 3-4 demonstrates the classification using a minimum average use and excess use method (the A&E
method). Minimum average use is defined as annual use calculated assuming customer use is equal to the
lowest monthly use year-round (this lowest therms/month/customer occurs in October for residential
and November for commercial). As noted above, the minimum average use is used to approximate the
share of distribution system needed to serve a customer within each class at their minimum level of
consumption. Using this method, the relevant costs are then split between the share of the minimum
average use (energy-related in row d) and share of excess demand (demand-related in row e).
11 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 (shared) compared with services needed to serve
a single family home (not shared).
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TABLE 3-4: AVERAGE & EXCESS CLASSIFICATION
Formula Total
Annual Sales, Therms a 25,779,489
Minimum Average Use, Therms b 13,936,088
Excess Use, Therms c 11,843,401
Energy-Related d = b ÷ a 54%
Demand-Related e = c ÷ a 46%
Once classified as energy and demand costs, distribution system costs are allocated to customer classes.
For the energy-related costs, the cost allocation is based on the customer class’ average use of the system.
Average use is appropriate since it reflects annual usage characteristics while the minimum would reflect
only the low season usage (summer). For demand-related, the cost allocation is based on customer class’
share of maximum use. The result is that all customers using the system will pay for their share of fixed
distribution costs based on their usage level, and customers with higher variation in use (demand) will
also pay their fair share of demand-related system costs. The recommended rate design within each class
determines how these costs are recovered.
3.4 CUSTOMER CLASSES OF SERVICE
Customer classes of service refer to the arrangement of customers into groups that reflect common usage
characteristics or facility requirements.12 The classes of service used within this Study were as follows:
Residential (G1); Small Commercial (G2); and Large Commercial (G3). The City also serves one Compressed
Natural Gas (CNG) customer whose costs are paid by the City’s Public Works department; the costs and
revenues for this City-owned service are part of the overall revenue requirement. These rates should
continue to increase at system average rates as they have been over recent periods because the nature
of service has not changed. Thus, it is reasonable that the CNG customer’s cost of service has increased
at the same rate as the distribution expenses overall.
3.5 COST OF SERVICE RESULTS
Given the key assumptions and updates discussed above, the COSA was completed. Tables 3-5 and 3-6
provide a summary of the Rate Base and Revenue Requirement amounts allocated to the various
customer classes.13 These schedules are calculated by multiplying the applicable classification and
allocation factors to each cost in the rate base and revenue requirement.
12 Breakpoints between or within rate classes are sometimes referred to as segmentation in rate making.
13 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.
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TABLE 3-5: DISTRIBUTION RATE BASE ALLOCATION RESULTS: FY 2025-2026
Asset Description Total
G1
G2 Small
G3 Large
$12,334,716 $9,135,516 $2,878,448 $320,752
$59,109,371 $24,674,393 $25,111,143 $9,323,835
$2,729,148 $1,139,245 $1,159,411 $430,492
$976,067 $407,446 $414,658 $153,963
$77,559,779 $32,376,261 $32,949,339 $12,234,179
$2,869,793 $1,197,956 $1,219,160 $452,677
$155,578,873 $68,930,816 $63,732,158 $22,915,899
$1,910,425 $846,434 $782,597 $281,395
$2,911,310 $1,289,886 $1,192,604 $428,820
$4,821,735 $2,136,319 $1,975,201 $710,215
$160,400,608 $71,067,135 $65,707,359 $23,626,113
$49,833,503 $22,079,245 $20,414,062 $7,340,197
$3,812,789 $1,689,295 $1,561,891 $561,602
$53,646,292 $23,768,540 $21,975,953 $7,901,799
$106,754,316 $47,298,595 $43,731,406 $15,724,314
$2,251,043 $1,131,981 $820,532 $298,530
TOTAL RATE BASE
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TABLE 3-6: DISTRIBUTION REVENUE REQUIREMENT ALLOCATION RESULTS: FY 2025-2026
Plant Description FY 2026 Total G1 Residential
G2 Small
G3 Large
Engineering Support 768,861 340,652 314,960 113,249
Operations & Maintenance 9,028,547 4,000,190 3,698,502 1,329,855
Total Distribution 9,797,408 4,340,842 4,013,463 1,443,104
Customer Service, Accounts, & Sales
Admin - Customer & Marketing $227,967 $179,500 $41,741 $6,727
$465,537 $176,296 $207,781 $81,460
Total Customer Service $3,208,008 $2,199,184 $727,166 $281,658
$1,451,715 $730,023 $529,167 $192,525
Transfers to Non-Enterprise Funds
Total Costs with A&G
Interest and Debt Service Expense
$23,348 $10,344 $9,564 $3,439
$778,250 $344,812 $318,806 $114,632
Total Debt Service /CIP Expense
General Fund Transfer
Reserves Contribution
Revenue Requirement Before Other
Revenues $41,957,453 $19,158,686 $16,850,905 $5,947,862
Customer Discounts -$318,105 -$140,940 -$130,310 -$46,855
Connection Fees $700,000 $310,142 $286,752 $103,106
-$449,823 -$199,299 -$184,268 -$66,256
$131,346 $58,194 $53,805 $19,347
$625,693 $277,220 $256,312 $92,161
Total Other Revenues
NET REVENUE REQUIREMENT
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Table 3-7 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 3-7: DISTRIBUTION COSA RESULTS: FY 2025-2026
Projected FY 2026 Revenues
Revenue
2026
Change
$16,311,063 $18,853,368 $2,542,305 15.59%
G2 – Small Commercial $16,565,086 $16,568,614 $3,527 0.02%
G3 – Large Commercial $5,081,713 $5,846,360 $764,647 15.05%
Total $37,957,863 $41,268,342 $3,310,479 8.7%
Residential and Large Commercial classes require higher rate increases compared to the G2 class. 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 fund contributions.
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.
3. The Rate Base Allocation of Distribution assets was updated to reflect updated Average & Excess
calculations. This change moved some asset value from G2 to G1 due to the greater variability in
seasonal use by G1 customers. This allocation flows through to expense items allocated based on
the same version of rate base, and it results in a larger share of expenses being allocated to G1
compared to the 2020 study and less cost being allocated to G2.
4. Customer allocators such as meters and services, and weighed customers, were updated to reflect
current meter cost and billing cost information. These updates resulted in larger shares of
expenses allocated to G1 and G3.
5. Average use for G1 and G3 are lower in FY 2025-2026 compared with FY 2019-2020. When
average use is lower, fixed costs are spread across a smaller number of therms impacting the
overall rate adjustment needed.
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.
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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). As a result, the City has set rates to match the COSA results for each customer class.
It is important to note that 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 forecast. For this Study, 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
•
service unit costs
• Calculate tiered rates based on A&E cost allocation
•
Small Commercial G2
•
service
• Implement three separate fixed monthly charges
Large Commercial G3
•
service unit costs
Table 1-8 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 heat is more prevalent in the winter. This ensures that
those customers contributing to higher seasonal demand are paying appropriately for their share of the
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demand-related cost.
EES evaluated the current G1 Tier breakpoints using sales data for several test periods, based on the
current rate design. EES confirmed that the winter baseline of 60 therms/30-day-billing still reflects of the
winter average at 60 therms/30-day-billing: EES recommends continuing to set the winter baseline to 60
therms/30-day-billing. However, the data, more than not, suggest that the summer baseline should be
increased from 20 to 23 therms/30-day-billing. Table 4-2 below shows the current baseline and average
consumption values supporting EES recommendation.
TABLE 4-2: BASELINE CALCULATIONS 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
Further, considering the costs that should be collected in Tier 1 vs. Tier 2 rates, EES used the same Average
and Excess calculations applied to distribution rate base or plant to determine the amount the current
rate design should collect at each rate. The excess calculation compares the difference between the
minimum and maximum use to produce the excess portion of average and excess. Using the excess
calculations, EES can determine how much Tier 1 baseline consumption is above minimum use and assign
that portion of excess demand costs to the Tier 1 rate. The result includes 54% of demand costs in the Tier
1 rate and the remainder of demand costs assigned to the Tier 2 rate.
Table 4-3 summarizes the costs to be recovered in each rate component for G1.
TABLE 4-3: 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 54% of demand-related distribution unit costs
Tier 2 Volumetric Rate Energy-related costs plus 46% of demand-related distribution unit costs
This result indicates that the rate design, if appropriately balanced as proposed, collects distribution
system costs between the tiers based on how those costs are classified and allocated in the COSA and the
seasonal Tier 1 baseline quantities.
The recommended volumetric rates for Residential are based on the volume of therms in each tier and
the relative share of demand-related distribution costs. Based on the baseline usage, or Tier 1 allocation,
54% of G1 consumption is within the Tier 1 (6.9 million therms). This volume is compared with the
minimum average use volume of 3.6 million therms. Minimum Average Use is the average volume of
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therms across all Residential customers per day multiplied by the number of days in a year (Table 4-4).
TABLE 4-4: G1 MINIMUM AVERAGE USE
Minimum Average Use/30-Day-Billing 14 therms
Annual Minimum Average Use 14 therms × 12 30-day-billings x 21,255 meters = 3.6
million therms
The current average Tier 1 volume on an annual basis is equal to 26 therm/30-day-billing which is
significantly higher than the minimum of 14 therms/30-day-billing calculated for minimum use. Therefore,
the Tier 1 volume also exceeds the annual minimum average use, and EES determined that a share of
demand-related costs should be allocated to the Tier 1 rate.
The share of demand-related costs to be collected in the Tier 1 rate is calculated by taking the share of
Tier 1 consumption in excess of the Minimum Average Use, as shown in Table 4-5.14
TABLE 4-5: G1 TIER 1 DEMAND-RELATED COSTS
Formula Total
Annual G-1 Sales, Therms A 9,762,524
Minimum Average Use, Therms B 3,558,936
Tier 1 Use, Therms as proposed C 6,935,563
Tier 1 Use Exceeding Minimum Average Use, Therms d = c - b 3,376,628
Excess Use (Demand-Related), Therms f = a - b
Share of Demand-Related Costs in Tier 1 Baseline g = d÷ f
This methodology helps to align the tiered rates more closely to the cost of service for each block of service
volume. If the Tier 1 baseline seasonal quantities are adjusted in the future, this analysis should be
updated to reflect the new quantities.
Table 4-6 shows the bill impacts for average customer use in summer and winter.
14 It is necessary to evaluate the minimum average use and compare those quantities to the Tier 1 quantities. If the
Tier 1 quantity were equal to the minimum use, 100% of demand-related distribution costs should be collected
through the Tier 2 rate. However, because the baseline Tier 1 quantity is approximately equal to average seasonal
use, that average use includes some component of demand cost. Therefore, a portion of demand-related costs
should be collected from the Tier 1 rate.
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TABLE 4-6: G1 BILL IMPACTS AT AVERAGE CUSTOMER USE, DISTRIBUTION ONLY
At Current Recommended Therms/30-
$43.83 $51.09 $7.26 16.6% 22.0
$92.54 $107.75 $15.21 16.4% 61.1
Table 4-7 shows the impacts for a range of customer bills under various low, median and high usage levels.
TABLE 4-7: G1 BILL IMPACTS AT VARIOUS USAGE LEVELS, DISTRIBUTION ONLY
Season
Usage At
Current FY 25 Rates
At
Recommended Bill Impact
$/Month
Bill Impact
$33.75 $40.38 $6.64 19.7%
$45.52 $54.99 $9.47 20.8%
$79.70 $86.50 $6.80 8.5%
$124.15 $127.84 $3.69 3.0%
$68.69 $83.41 $14.73 21.4%
$104.92 $128.14 $23.22 22.1%
$180.07 $203.03 $22.96 12.8%
$390.54 $399.00 $8.47 2.2%
$70.27 $85.47 $15.20 21.6%
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. As described in Section 1.2, Rate Study Overview, EES performed a detailed analysis of G2 usage
and costs and recommends a refinement in the development of the Monthly Service Charge for G2.
Figures 4-1 and 4-2 show examples of usage and cost characteristic analysis.
The fixed monthly service charge for a given rate schedule (customer class) is set to recover the customer-
related costs allocated to that schedule. Weighted meter cost is a major factor used to allocate customer-
related fixed costs to various rate schedules. This COSA uses updated meter costs that reflect latest
available data on meter cost and associated capacity of installed meters.
G2 is different from G1 and G3 in that its approximately 2,100 services have a much wider range of usage,
as well as meter types and capacities. EES examined G2 meter types and corresponding average usage
data to determine whether and how it can inform the development of G2 monthly service charge to better
reflect customer-related fixed costs.
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Figure 4-1 shows how G2 meter capacity and associated average consumption. Size correlates to usage;
as expected, larger meters have larger average usage.15 Larger meters require larger service lines
(connecting the meter to the distribution system) and generally impose greater demand on the system.
FIGURE 4-1: AVERAGE MONTHLY USAGE BY METER CAPACITY
Moreover, EES observes distinct patterns and separations in average usage levels that support three 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)
15 This is expected because meter capacity is sized to match the customer’s usage demand. City of Palo Alto, Utility
Rule and Regulation 15, Section B.6: Meter Installations, Capacity of Meters, April 2023.pdf.
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FIGURE 4-2: G2 – AVERAGE MONTHLY USAGE BY METER CATEGORY
Thus, EES recommends implementing a Monthly Service Charge based on the G2 service’s maximum
meter capacity and calculates these charges using allocated costs that are based on each grouping’s
weighted meter costs.
The above three G2 meter ranges were chosen as a result of detailed examination of the distribution of
usage across different meter types and capacities, according to summary data in Figures 4-1 and 4-2. The
calculation for the volumetric charge applicable to all G2 usage remains unchanged. See Table 1-6, G2
Monthly Service Charges: FY 2025-2026, and Table 1-8, Current and Recommended Rates.
Table 4-8 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 4-8: G2 BILL IMPACTS
At Current
FY 2024-2025
FY 2025-2026
Average
# of
$629.59 $629.72 $0.13 0.0% 437 2,193
≤ 1,134
Average Use $216.71 $98.87 -$117.84 -54.4% 55
50% of Average Use $186.81 $63.96 -$122.84 -65.8% 28
˂ 942
Average Use $679.70 $705.15 $25.45 3.7% 484
50% of Average Use $418.30 $400.05 -$18.26 -4.4% 242
≥ 116
Average Use $4,245.43 $5,189.76 $944.33 22.2% 3,783
50% of Average Use $2,201.16 $2,803.69 $602.53 27.4% 1,891
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
Attachment F Item #3
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 31
rate schedule applies to commercial customers who use at least 250,000 therms per year at one site.16
This threshold, which defines the rate class, results in a group of customers with similar services, sizing
requirements and usage characteristics. Therefore, it is not necessary to develop tiered rates or fixed
charge variances within this class. No change is recommended in the overall design of these charges.
For illustrative purposes, Table 4-9 presents the G3 bill impact at 20,833 therms, which is 1/12 of the
annual threshold level for G3 service.
TABLE 4-9: G3 BILL IMPACTS
At Current FY FY 2025-2026
G3 Large Commercial $41,287.45 $44,186.73 $2,899.28 7.0%
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 4-10 shows the current ranges.
TABLE 4-10: 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 with a range or not.
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 10187, August 19, 2024). The
Commodity charge range, therefore, is consistent with the Council-approved strategy.
16 Utility Rate Schedule G-3.
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 32
The City’s gas utility is a covered entity under the California Air Resources Board (CARB) Cap-and-Trade
program, in this programthe 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’s
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).17
Recently, the Transportation Charge exceeded the published range and the Council increased the upper
limit on the Transportation Charge.18 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.19
EES does not recommend changes to the Carbon Offset Charge range. In December 7, 2020 Council
adopted Resolution 9930 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, 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.
17 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
18 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.
19 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
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 33
Attachment F Item #3
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 34
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)
= $/Therm
Where:
Number of Allowances Required (%) =
(Projected Emissions for Current Year - Palo Alto’s Allocated Allowances for Current
Year)
÷ Projected Emissions for Current Year
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 35
3. Transportation Charge The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to Customer Meters. The current rates are shown in
this tariff https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-
WSL.pdf, provided by PG&E. Additionally, there is a distribution loss factor (updated
annually), which is calculated by the variances of gas supply purchases and gas retail
sales for the past three fiscal years.
The Transportation Charge calculation formula is:
PG&E G-WSL Transportation Charges ($/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)
÷ Annual Gas Sales (therms)
= Carbon Offset Charge ($/therm)
Where:
Purchase Price of Carbon Offset ≤ $19/MT CO2e
Attachment F Item #3
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April 2, 2025 www.cityofpaloalto.org
FY 2026 Gas Rate Proposal
Utilities Advisory Commission
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2
Residential Median Bill Projections (Bill $ and % change from prior year)
1)FY 2025 incorporates results of cost-of-service analysis
2)Gas rate in FY 2026 based on General Fund transfer of 18% of gross revenue in FY 2024; changes shown with commodity rates held constant; actual gas
commodity rates vary monthly; FY 2026 incorporates results of cost-of-service analysis
3)Stormwater fees increase by CPI index annually per approved 2017 ballot measure (2.6% in FY 2025)
4)Based on projected FY 2025 monthly residential bill of $404
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3
Residential Median Bill Projections w/ Climate Credit (Bill $ and % change from prior year)
1)FY 2025 incorporates results of cost-of-service analysis
2)Gas rate in FY 2026 based on General Fund transfer of 18% of gross revenue in FY 2024; changes shown with commodity rates held constant; actual gas
commodity rates vary monthly; FY 2026 incorporates results of cost-of-service analysis
3)Stormwater fees increase by CPI index annually per approved 2017 ballot measure (2.6% in FY 2025)
4)Based on projected FY 2025 monthly residential bill of $404
Climate Credit:
One-time flat $73.20
credit to residential
G-1 customers only.
The total cost is
about $1.6M from
the Cap-and-Trade
Reserve, enough to
fund whole home
electrification
incentives for about
182 homes.
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4
Proposal
•5% overall rate increase in FY 2026, assuming no change in supply costs;
•Cost of Service Analysis completed February 2025 – requires rate changes varying by
customer class to match the cost to serve
•22% ($15.20/month) increase for median residential customer
Drivers
•Reserve replenishment, labor, allocated charges, cross-bore program
•Federal grant of $16.5 million expected to fund CIP work including main replacement
•Gas General Fund Transfer in FY 2026 estimated at $9.735M, (18% of FY 2024 gross
revenue)
Compared with Preliminary Rates
•Lowered overall revenue increase from 6% to 5%
•Cost of Service Analysis results incorporated, residential and large commercial are
expected to see increases
Gas Rate Proposal
Note: excludes supply-related rate changes
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5
FY 2026 Rate Increase Drivers
Calculation Notes:
•Rate increases based on projected FY 2026 revenues
apportioned by 4 -year average of actual costs
•Rate increases apply to sales revenue; Revenue includes some
non-rate revenue.
This chart explains the rate increase drivers for the
overall rate increase. Additional cost of service
adjustments by customer class are required.
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6
Gas Cost and Revenue Projections
*FY25 Commitments and Reappropriations
reserves balances for Operations and
Capital Investment are anticipated to be
utilized in FY26 and FY27
**Revenues and Expenses excludes Cap-
and-Trade auction sales revenue, which
goes directly to the Cap-and-Trade reserve
***The grant-funded $16.5M CIP project is
anticipated to be under construction in
FY26 and FY27
6
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7
Gas Operations Reserve Projections Item #3
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8
Basic Cost of Service Methodology
•First establish how much revenue you need
•Then use consumption patterns to allocate costs among
customer classes according to how they incur utility costs
•CPA classes: G-1 (residential), G-2 (small commercial and multi-
family master-metered), G-3 (large commercial) and G-10 (CNG
Station)
•Costs allocators include things like therms used, number of
customers in class
•Then design rates that provide prices that allocate costs to
customers who consume in different ways.
•Examples include tiered rates, seasonal rates, fixed charges, etc.
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9
Prop 26 Considerations
•Prop 26 (2010): State ballot initiative that amended the State
Constitution
•Gas and electric rates must represent the cost of service
absent voter/ratepayer approval
•Cost of service analysis is the record demonstrating that the
rates are cost-based
•Only applies to fees/charges imposed by local agencies
(including gas/electric utility rates) – investor-owned utilities
have all the latitude the CPUC will give them
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10
Gas Bill Comparisons Proposed Rates FY 2026 ($/Mo.)
Residential
Commercial and Multi-Family Master-Metered
Note:
•FY 2026 rates calculated assuming
no change to supply-related rates;
PG&E transportation rates as of
January 1, 2025
•FY 2025 rates calculated based on
actuals and projected rates
•PG&E bills are calculated using
Climate Zone X
•PG&E bills include a climate credit
for residential
•G-2 bills are calculated based on
the median usages for each meter
capacity group
FY 2025
(Current)
FY 2025
(Current)
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11
Communication and Outreach
Key Messages
•Reasons for rate increases and benefits to customers
•Competitive rates to other utilities and neighboring cities
•What the City is doing to keep costs down
•City programs and services to help customers keep utility bill
costs low
Outreach Strategies
•Public Meetings: UAC, Finance, City Council
•Digital Communication:website, social media,
email newsletters, City blog, videos
•Direct Mail: utility bill inserts,Proposition 218 notice,
SFPUC rates postcard
•Local Media Engagement: articles, interviews
Utility bill insert about gas safety
Installing new gas pipe for the Gas Main
Replacement Project #24B
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12
Recommendation
The Utilities Advisory Commission recommends that the City Council adopt a
resolution:
1. Approving the Fiscal Year 2026 Gas Utility Financial Forecast
2. Approving the transfer of up to $1.5 million from the Gas Utility Operations
Reserve to the Distribution Rate Stabilization Reserve at the end of FY 2025
3. Approving the Natural Gas Cost of Service and Rate Study
4. Transferring up to 18% of gas utility gross revenues received during FY 2024
to the General Fund in FY 2026
5. Increasing distribution rates by 8.7% (for an estimated 5.4% increase to
overall rates) for FY 2026 by amending Rate Schedules;
a. G-1 Residential Gas Service,
b. G-2 Residential Master-Metered and Commercial Gas Service,
c. G-3 Large Commercial Gas Service, and
d. G-10 Compressed Natural Gas Service
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Utilities Advisory Commission
Staff Report
From: Kiely Nose, Interim Director of Utilities
Lead Department: Utilities
Meeting Date: April 2, 2025
Report #: 2411-3753
TITLE
Staff Recommends the Utilities Advisory Commission Recommend that the City Council Adopt a
Resolution, Approving the FY 2026 Electric Financial Forecast, including Transfers, Amending
Rate Schedules E-1 (Residential Electric Service), E-2 (Residential Master-Metered and Small
Non-Residential Electric Service), E-2-G (Residential Master-Metered and Small Non-
Residential Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-
4-G (Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-
Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-7-G
(Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-Residential Time
of Use Electric Service), E-14 (Street Lights), E-16 (Unmetered Electric Service), E-EEC-1 (Export
Electricity Compensation), and E-NSE-1 (Net Metering Surplus Electricity Compensation)
RECOMMENDATION
Staff recommends the Utilities Advisory Commission recommend that the City Council adopt a
resolution (Attachment A):
1. Approving the Fiscal Year 2026 Electric Utility Financial Forecast shown in this staff report
and attachments; and
2. Approving the transfer at the end of FY 2025 of up to $5 million from the Electric Utility
Supply Operations Reserve to the Distribution Operations Reserve;
3. Amending Rate Schedules (Attachment B) effective July 1, 2025 (FY 2026):
a. E-1 (Residential Electric Service)
b. E-2 (Small Non-Residential Electric Service)
c. E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service
d. E-4 (Medium Non-Residential Electric Service)
e. E-4-G (Medium Non-Residential Green Power Electric Service)
f. E-4 TOU (Medium Non-Residential Time of Use Electric Service)
g. E-7 (Large Non-Residential Electric Service)
h. E-7-G (Large Non-Residential Green Power Electric Service)
i. E-7 TOU (Large Non-Residential Time of Use Electric Service)
j. E-14 (Street Lights)
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k. E-16 (Unmetered Electric Service) to recover capital and maintenance costs for
utility pole attachments and telecom conduit
l. E-EEC-1 (Export Electricity Compensation) to reflect 2024 avoided cost, and
m. E-NSE-1 (Net Surplus Electricity Compensation) to reflect current projections of FY
2026 avoided cost.
EXECUTIVE SUMMARY
The City of Palo Alto Utilities (CPAU) provides electricity, water, wastewater, natural gas, and
fiber optic services to the Palo Alto community. The Public Works Department also provides
refuse collection and processing for recycling, compost and garbage, wastewater treatment and
stormwater management. The City’s primary goals are to manage these services in a way that
ensures continued safe, reliable, environmentally sustainable, and cost-effective operations. The
City is proposing rate increases this year for electric, natural gas, wastewater and water services.
The stormwater management fee increase will occur per the Consumer Price Index (CPI) as
approved by residents in a 2017 ballot measure. The City strives to be transparent with utilities
customers about the reason for rate changes, including explaining the cost drivers, benefits to
customers, what the City is doing to keep costs low for ratepayers, and the services and programs
provided by the City to help customers keep utility bill costs low. Attachment E outlines CPAU’s
plan for communicating rate changes to customers. Staff are presenting an overview of the
financial forecast and rate change proposal for each utility service to the Utilities Advisory
Commission (UAC) and Finance Committee prior to City Council review and approval in June
2025.
The Electric Utility rate forecast proposes a 5.1% rate increase for FY 2026. Last year’s forecast
projected 5% annual rate increases from FY 2027 to FY 2029. The updated forecast now projects
a 6% increase in FY 2027, 8% increases in FY 2028 and FY 2029, and a 6% increase in FY 2030.
Table 1 shows the proposed rate increases for FY 2026 through FY 2030. The drivers for this
increase relative to last year’s forecast include a new warehouse and laydown yard for grid
modernization, replacement of emergency generators, and an update to the General Fund
Transfer forecast from $15.6 million to $17.4 million beginning in FY 2026. The General Fund
Transfer increase is a result of the estimated grid modernization asset value increase (capital
assets are an input to the Council-adopted General Fund Transfer methodology and when capital
assets increase, General Fund Transfer also increases). Although the General Fund Transfer is
funded by non-rate revenue, less non-rate revenue is projected to be available to pay for other
costs with a larger General Fund Transfer and so a larger rate increase is necessary. The rate
increases in the outer years of the forecast could change as the Council finalizes plans for debt
financing grid modernization costs.
In the current year, FY 2025, power supply costs are expected to be slightly lower than forecasted
a year ago; the main driver for this shift is extremely high market prices for resource adequacy
capacity and renewable energy credits, which have yielded higher wholesale revenues for the
City. The City’s load (consumption) for the current year is projected to be about 10% higher than
previously forecasted, but is then expected to be relatively flat over the next several years.
Meanwhile, output from the City’s hydroelectric resources is projected to be roughly equal to
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long-term average levels over the next few years. Hydroelectric revenue continues to be a large
source of uncertainty in the City’s supply cost projections. In the next five years, staff expects
increasing transmission access charges, rising renewable portfolio standard requirements, and
tightening resource adequacy requirements to steadily increase electric supply costs. Capital
spending and distribution system maintenance spending is rising due to grid modernization,
fiber-related investments and an upgrade to the Hanover Substation which will benefit all electric
rate payers. Staff expects grid modernization and related capital costs to be offset with a series
of debt financing with the first bond issuance in FY 2026.
Table 1: Current Year (FY 2025) and Projected Overall Rate Trajectory from FY 2026 to FY 2030
BACKGROUND
ANALYSIS
Past Trends
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the electric system, and the cost of contract field crews to cover operational work due to
challenges with filling vacancies and multi-year construction projects such as Foothills
undergrounding and grid modernization.
Table 2: FY 2024 Actuals vs. Prior Year’s Forecast ($000)
Net Cost/(Benefit) Variance Type of change
Higher revenues from higher load (5,083)Revenue increase
Lower electric supply costs (7,897)Cost decrease
Higher operational costs 8,799 Cost increase
Lower than forecasted capital investment (28,074)Cost decrease
Net Cost / (Benefit) of Variances (33,156)
Projections
Overview
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Operations costs in FY 2025, other than public benefits and Low Carbon Fuel Standards (LCFS)
expenses, are projected to be $5 million, or 7% higher than FY 2024 actuals. Allocated charges
from other City departments are projected to increase 9% based on adopted FY 2025 budget
numbers.
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Figure 1: Electric Utility Revenues, Expenses, and Rate Changes:
Staff conducted an updated load forecast for FY 2026, with forecast methodologies that
incorporated weather patterns, economic factors, and historical trends. This forecast projected
energy demand at 893,052 MWh and a peak load of 163 MW in FY 2026. This forecast also
included a revised FY 2025 energy demand about 8% higher than last year’s forecast, at 902,133
MWh and 164 MW, driven largely by higher-than-expected sales in FY 2024. The main
contributors of the increased demand include 10% growth in the E-7 rate class, driven primarily
by a customer’s data center expansion, which added nearly 30 GWh to the load. This customer’s
formalized capacity reservation agreement further adds 60 GWh annually and is included in this
forecast. However, long-term trends show a gradual 1% annual decline over the last 20 years in
load due to energy efficiency measures, rooftop solar adoption, and the loss of industrial users,
partially offset by growth in building electrification and EV charging.
Figure 2 shows the forecast of electricity consumption through FY 2044. Electricity consumption,
which was depressed due to the economic effects of the pandemic, is assumed to recover to a
level slightly above the long-term trend line (shown in the FY 2026 Forecast line). Potential factors
that may offset declining sales include another potential data center project and Figure 2 shows
a range of forecasts up to the FY 26 Forecast (high range) line. Building and vehicle electrification
at a business-as-usual level is included in the FY 2026 forecast, but large increases in the pace of
building and vehicle electrification could increase sales further as well. Demand forecasts are
14%6%8%0%
0%
35%
5%6%8%
8%6%
0
50
100
150
200
250
300
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
$
M
i
l
l
i
o
n
s
Fiscal Year
Capital Investment
Electric Commodity
Operations
Transfers
Grid Modernization Debt
Debt Service
Revenue
-5%
Notes:
1)The 35% increase includes April
2022 activation of the Hydroelectric
Rate Adjuster (HRA), a 5% base rate
increase, and the January 1, 2023
increase of the HRA from
$0.013/kWh to $0.048/kWh.
2) The 5% decrease include July 1,
2023 deactivation of the HRA and a
21% increase to the base rates to
align with long-term expenses.
3) COS Study Adjustment of -6% to
9% Rate Change depending on
usage levels
-6% to 9%
(2)(1)
(3)
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updated every year taking into account fundamental changes. Staff updates the forecast annually
based on the most updated information for financial forecast purposes.
Figure 2: Forecasted Electricity Consumption
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Figure 3: Forecasted Electricity Peak Demand
The Electric Utility receives most of its revenues from sales of electricity to Palo Alto customers,
but about 20 to 25% comes from other non-rate revenue sources. Of these non-rate revenue
sources, about 50% to 75% represents wholesale revenues – from surplus energy sales, surplus
RA sales, and sales of RECs that are in excess of the City’s renewable portfolio standard (RPS)
requirements. These revenues may offset electric supply purchase costs, smooth rate increases,
or fund reserves or costs including the Electric General Fund Transfer and local decarbonization
programs of the remaining revenues, the largest sources are interest income, customer
connection fees for new or replacement electric services, and carbon allowance sales revenues
associated with the State’s cap-and-trade program.
Staff expects Cap-and-Trade allowance revenues to stabilize through the forecast period, but this
revenue source is uncertain as the current regulations are set to sunset in 2030 unless
reauthorized by the State. The California Air Resources Board (CARB) is in the process of updating
Cap-and-Trade regulations to increase the stringency of the program and allowable uses by
lowering the target emissions levels. A revised regulation is expected to be adopted in 2025, with
implementation anticipated in 2026. Staff will update Cap-and-Trade related revenues
projections when more information becomes available.
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The forecast for interest income assumes current interest rates continue, and there are no major
reserve reductions aside from what is anticipated in this forecast. If interest rates rise, interest
income could increase, and if reserves decrease (due to drought or a withdrawal from the Electric
Special Projects (ESP) reserve for a major project), interest income would decrease.
Expenses
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Figure 4: Electricity Supply by Source
Figure 5 and Table 3 show the actual and projected costs for the electric supply portfolio,1 and
Figure 5 also shows average and actual hydroelectric generation.2 FY 2021 and FY 2022 had lower
than average hydroelectric generation, while FY2024 had higher than forecasted generation.
Starting in FY 2023 (in the FY 2024 Electric Utility Financial Plan) staff lowered its projection of an
average hydroelectric year to more closely align with the past 10 years of historical averages.
Renewable energy costs have stayed relatively flat as one renewable energy contract ended while
another renewable project came online to fulfill the City’s carbon neutral and RPS goals. The
current market outlook is uncertain for newer renewables projects because of headwinds from
supply chain issues and interconnection delays, along with the potential for new trade tariffs and
reduced federal subsidies. CAISO transmission access charges are projected to continue to
increase as transmission lines are built throughout California to accommodate new renewable
projects. In total, staff projects net electric supply costs to increase from an average of about $86
million from FY 2022 through FY 2025 to about $117 million by FY 2030.
1 Costs are shown net of wholesale revenues and cannot be directly compared with the electric supply purchase
figures shown in Attachment C: Electric Utility Financial Forecast Table.
2 Average hydroelectric generation based on the currently inactive E-HRA rate schedule.
-40%
-20%
0%
20%
40%
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80%
100%
120%
140%
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
%
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Net Market
Purchases/Sales
Hydroelectric
Renewable
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Figure 5: Electric Supply Portfolio Costs
FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030
Net Market Purchases /
(Sales)(20,417)(9,146)(12,684)410 1,632 6,116 10,141
Renewables 33,794 36,196 37,489 38,805 40,283 38,078 35,402
Hydroelectric Costs 18,690 18,819 20,686 21,089 20,434 20,208 20,818
Transmission 30,093 28,559 29,120 30,768 32,844 35,042 37,137
Other Costs 6,349 10,000 17,070 6,111 8,668 12,518 13,529
68,509 84,430 91,682 97,182 103,861 111,961 117,028
0
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700
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2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
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Renewables
Hydroelectric Cost
Transmission
Average Hydro
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Actual/Projected
Hydro Generation
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Operations
•Administration, including financial management of charges allocated to the Electric Utility
for administrative services provided by the General Fund and for Utilities Department
administration, as well as debt service and other transfers (for example, transfers to
General Fund to pay for communications dispatch, fire training, graffiti removal from
poles and boxes, and Office of Emergency Services emergency response). Additional
detail on Electric Utility debt service is provided in the Debt Service section below
•Customer Service
•Engineering work for maintenance activities (as opposed to capital activities)
•Operations and Maintenance of the distribution system;
•Resource Management and Demand Side Management; and
•Transfers including the General Fund Transfer, transfers to the City’s capital project fund,
and technology fund.
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Figure 6: Electric Utility Operational Costs
0
20
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2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
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Resource Management
Demand Side Management
Administration
Operations & Maintenance
(including Engineering)
Customer Service
Transfers
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Capital Improvement Program
Table 4: Electric Utility CIP Spending ($000)
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applied to those FY 2025 actual capital costs for grid modernization and related projects (see
Council staff report 2411-3805,3 December 16, 2024 for a detailed discussion and accompanying
Resolution 102094).
Figure 7: Projected Funding Plan for Grid Modernization Project
The Electric Utility has previously pledged reserves and net revenue as security for non-electric
bond issuances listed in Table 5 even though the Electric Utility is not responsible for the debt
service payments. The Electric Utility’s reserves or net revenues would only be called upon if the
responsible utilities are unable to make their debt service payments. Staff does not anticipate
that this will occur. These pledges have not impacted electric rates. Staff projects that the Electric
Utility’s net revenues in each future year will exceed 125% of debt service (see Attachment C,
Utility Financial Table, line 71).
3 Staff report 2411-3805 “Adoption of a Resolution of Intention to Reimburse Expenditures for the Grid
Modernization and Related Projects of the Electric Utility System Infrastructure from the Proceeds of the Tax-
Exempt Utility Revenue Bonds.” https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=83165
4 Council Resolution 10209 (Dec. 16, 2024) https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62094
-30
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70
90
2025 2026 2027 2028 2029 2030
Projection
$
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Fiscal Year
Debt-Funded Rate/Reserve-Funded
Budgeted Project Expense Annual Debt Service
$86M
Issuance $100M
Issuance
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Table 5: Other Issuances Secured by Electric Utility’s Revenues or Reserves
2009 Water Revenue Bonds
(Build America Bonds)Water $1,977*No Yes
2011 Utility Revenue
Refunding Bonds, Series A
Gas
Water
$1,457 No Yes
*Net of Federal interest subsidy
The Electric Utility currently has two primary contingency reserves, the Supply Operations
Reserve and the Distribution Operations Reserve. In addition, the Electric Utility has a Hydro
Stabilization Reserve, an Electric Special Projects (ESP) Reserve, and a Capital Reserve. Reserve
funds may be utilized with Council approval.
There are a variety of risks associated with the Supply Fund related to resource generation
variability, market price volatility, transmission cost increases, and regulatory changes to market
rules. Because of the high range of uncertainty in energy price predictions more than three years
into the future, this risk assessment is only performed for the first two fiscal years of the forecast
period. It is important to note that the likelihood of all these adverse scenarios occurring
simultaneously, and to the degree described in Table 6, is very low.
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Table 6: Electric Supply Fund Risk Assessment
Of the risks faced by the Electric Utility’s Supply Fund for FY 2027, the largest risk would be facing
a dry year with very low hydroelectric output, accounting for one third ($7.6 million) of all the
adverse cost uncertainty. Since the utility’s costs for its hydroelectric resources are almost
entirely fixed, costs do not decline when the output of those resources are low, but the utility
needs to buy power to replace the lost output. The converse happens when hydroelectric output
is higher than average.
Of the remaining risks for FY 2027, $5.2 million or 20% is related to potential transmission cost
increases above staff’s current forecast. $4.4 million or 17% is related to the potential that total
load (and the associated retail sales revenue) may be lower than projected. Other risks are
related to production from the City’s renewable contracts and market prices for purchases and
sales of energy and resource adequacy (Items 3, 4, 5, 6, and 7 above), totaling $5.6 million or
22%.
As shown in Figure 8, staff anticipates the Supply Operations Reserve will remain within
guideline levels throughout the five year forecast period. Note that the high reserve level in FY
E
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2023 is related to one-time revenues including a $24M refund from the successful litigation
against the Bureau of Reclamation for overcharges related to power purchases from the Central
Valley Project. These funds were redistributed to other purposes in FY 2024, with those
transfers resulting in a reduction in the Supply Operations Reserve.
Figure 8: Electric Supply Operations Reserve Adequacy
Reserve Maximum
Reserve Target
Reserve Minimum
0
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2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
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Table 7: Electric Distribution Fund Risk Assessment ($000)
Total non-commodity revenue 77,592 85,849 88,142 88,744 92,892 94,459
Max. revenue variance, previous 10 yrs 8%8%8%8%8%8%
Risk of revenue loss 6,124 6,776 6,957 7,004 7,331 7,455
CIP Budget 21,066 - 15,297 23,796 19,172 15,804
CIP Contingency @10% 2,107 - 1,530 2,380 1,917 1,580
8,231 6,776 8,486 9,384 9,249 9,036
In last year’s Financial Plan, staff proposed various reserve transfers to manage a one-year cash
flow issue related to the grid modernization project. Council approved certain transfers
recommended in last year’s Financial Plan in FY 2024 and FY 2025. At year end FY 2024, staff
evaluated the reserve levels based upon actual FY 2024 results and completed necessary
transfers within the Council approved levels. Following is a list of each of the transfers Council
approved for FY 2024 followed by a discussion of the actual transfers completed in FY 2024.
No transfer was necessary from the Electric Special Projects Reserves to the Supply Operations
Reserve. Furthermore, the Electric Utility Supply Operations Reserve was able to repay $2.5
Reserve Maximum
Reserve Target
Reserve Minimum
Risk Assessment
-10
-5
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5
10
15
20
25
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2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
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million of an earlier $10 million loan from the Electric Special Projects Reserve in FY 2024. The
current balance of the Electric Special Projects Reserve is $22.6 million. This Financial Forecast
proposes the Electric Utility Supply Operations Reserve to repay the Electric Special Projects
Reserve the remaining $7.5 million of the internal loan in FY 2025. Council also approved a
transfer of up to $30 million from the Supply Operations Reserve to the Electric Special Projects
Reserve in FY 2025 so no further Council action is necessary for staff to complete this transfer
(Resolution 101785). Additionally, this forecast reflects repayments of $1 million per year from
FY 2026 through FY 2030 to the Electric Special Projects Reserve for loans to the water and gas
utilities for AMI investments.
2)Up to $17 million from the Supply Operations Reserve to the Hydroelectric
Stabilization Reserve
Staff completed the $17 million transfer from the Supply Operations Reserve to the Hydroelectric
Stabilization Reserve in FY 2024. The Hydroelectric Stabilization Reserve balance is $17.4 million,
approaching the reserve’s target level of $19 million. This level will allow the City to avoid
activating the hydroelectric rate adjuster if upcoming winters are drier than average. The Electric
Utility was in a position to make this transfer because of one-time sales revenues and supply cost
savings in FY 2024 related to high hydroelectric generation resulting from the rainy winter of
2022/2023. In addition, market conditions enabled the utility to realize higher than usual sales
revenue related to favorable hydrological conditions and high resource adequacy market prices.
3)Up to $58 million from the Supply Operations Reserve to the Distribution
Operations Reserve
Staff completed a $42 million transfer from the Supply Operations Reserve to the Distribution
Operations Reserve. Attachment C, Electric Utility Financial Details table shows the FY 2024 year-
end Electric Operations Reserve (Supply and Distribution combined) is $32.2 million, which is
approximately equal to the minimum guideline range. Figures 8 and 9 show the actual and
projected reserve balances for each of these reserves. In FY 2025, staff proposes a transfer of up
to $5 million from the Supply Operations Reserve to the Distribution Operations Reserve. The
purpose of this transfer is to manage the Distribution Operations Reserve level given the short-
term cash flow issue related to the grid modernization project. The debt issuance is not scheduled
until FY 2026 while some of the CIP work will occur in FY 2025 and will temporarily be funded by
the Electric Utility Distribution Operations Reserve.
Additionally, in accordance with the Electric Utility Reserve Management Practices (Attachment
D), staff transferred $1.9 million from the Supply Operations Reserve to the Cap and Trade
Reserve based upon actual Cap and Trade costs and revenues. The City maintains a Cap and Trade
Program Reserve within the Electric fund to hold any revenues from the sale of carbon allowances
freely allocated by CARB to the Electric Utility that are not spent within the fiscal year. Cap and
Trade Program revenues are provided to the Electric Utility to support a wide variety of carbon
reducing activities. Until the establishment of the REC Exchange program, adopted by Council in
5 Resolution 10178, June 17, 2024, https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62050
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August 2020 (Staff Report #11556),6 all of this Cap and Trade Program revenue was spent on
purchasing renewable energy and none was held in reserve.
In accordance with Council’s August 2020 direction, the City began selling City-owned renewable
energy (Category 1 RECs, which mostly represent in-state renewable energy) and replacing them
with purchased Category 3 RECs, which represent mostly out-of-state electricity. This exchange
takes advantage of market conditions to reduce supply costs, fund electric utility programs and
capital investment, and raise funds for local emissions reduction. On December 12, 20227 Council
approved continuation of the program with 100% of revenue going to local emissions reduction.
In accordance with Council policy, staff will fund the Cap and Trade Program Reserve with
unspent revenues from the sale of carbon allowances freely allocated to the electric utility in an
amount equal to 100% of each FY’s Renewable Energy Credit (REC) Exchange program revenues,
currently estimated to be between $0.7 million and $1.7 million going forward, for future local
decarbonization projects.
Last year’s financial plan amended the Electric Utility Reserve Management Practices to direct
staff to transfer any unspent CIP budget that is not reappropriated or encumbered at the end of
each fiscal year to the CIP Reserve. These represent ratepayer funds already collected for the
purpose of CIP investment, and retaining them in the CIP Reserve allows the City to use them to
fund future unanticipated CIP expenses (such as mid-year budget adjustments due to increased
costs for specific projects) that were not included in a financial forecast. Last year’s financial plan
also recommended, and Council approved, a transfer of up to $5 million from the Electric
Distribution Operations Reserve to the CIP Reserve in FY 2025. The Capital Reserve balance is
$0.9 million, which is below the minimum guideline range. Staff will evaluate the year-end results
in FY 2025 and complete a transfer to the Capital Reserve to bring it up to the minimum guideline
if this is feasible.
Reserve Balance
The Electric Utility also has a CIP Reserve for short term capital contingencies and as a place to
set aside funds for large, one-time projects that the Utilities would otherwise need to debt-fund.
Figure 10 below reflects the maximum and minimum CIP Reserve guideline levels, starting in FY
2018 through FY 2030. Because of the fluctuating annual dollar amounts and timing of CIP
projects budgeted to occur during the forecast period, as well as the potential for new ongoing
projects to be included in the CIP plan in later years, four years of budgeted CIP are used to
calculate the reserve maximum levels. The minimum CIP Reserve level is 20% of the maximum
CIP Reserve guideline level.
Last year’s Financial Plan recommended to fund the CIP Reserve to its minimum level by the end
of FY 2025, and Council approved a $5 million transfer in FY 2025 for this purpose. Staff will
6Staff Report 11556 https://www.cityofpaloalto.org/civicax/filebank/documents/78046
7December 12, 2022 Staff Report #14375 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=82045
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complete the transfer based on FY 2025 actual results, however, this forecast does not include
funds for this transfer based upon current projections.
Figure 10: Electric CIP Reserve Adequacy
Reserve Minimum
Reserve Maximum
-5
0
5
10
15
20
25
30
35
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
$
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CIP Reserve (Year-End)
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Figure 11: Electric Utility Reserves (Supply Fund):
Table 13 shows the projected balance of each of the Electric Utility reserves for the period
covered by this Financial Forecast. See also: Attachment C: Electric Utility Financial Table
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Table 12: Electric Utility Reserves Starting and Ending Balances, Revenues, Transfers
To/(From) Reserves, and Reserve Guideline Levels for FY 2025 to FY 2030 ($000)
*Includes funds of $43.895 million from the CIP Reappropriations and Commitments Reserves
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Cost of Service Supplement - Unmetered Electric Service (E-16) Rate
8). EES recommends increasing this fee (also adopted by the Federal
Communications Commission as a “safe harbor” rate in 2018) by the annual Consumer Price
Index for All Urban Consumers in the San Francisco-Oakland-Hayward area since 2018. The
recommended updated license fee is $329.44 per year per pole.
8 Staff Report #3133 https://www.cityofpaloalto.org/files/assets/public/v/1/agendas-minutes-reports/reports/city-
manager-reports-cmrs/year-archive/2012/final-staff-report-id-3133_amendments-to-util-rate-schedule-e-16.pdf
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Proposed Rates
Bill Impacts
The City adopted its current electric rates effective July 1, 2024. At that time, the City did not
increase the overall revenue but did implement a series of rate adjustments by customer class
in accordance with the City of Palo Alto Electric Cost of Service and Rate Study, completed by
EES Consulting in April 2024.9 The current and proposed FY 2026 rates are reflected in Table 14
below:
9 Palo Alto Electric Cost of Service and Rate Study https://www.cityofpaloalto.org/files/assets/public/v/3/agendas-
minutes-reports/reports/city-manager-reports-cmrs/attachments/2024-rates/electric-cosa.pdf
TABLE 13: PROPOSED E-16 RATES
Service Current Rate
FY 2025
Proposed Rate
FY 2026
C. Unmetered Electric Service
1.Customer Charge, $/month $9.00 $10.96
2.Energy Charge, $/kWh Same as E-2 Same as E-2
E. Misc Rates
1. Conduit License Fee, $/foot/year $1.94 $1.94
2. Processing Fee for Electric Conduit Usage Actual Cost Actual Cost
3.Pole Attachment License Fee, $/Foot/Year $29.511 $47.60
4.Processing Fee for Utility Pole Attachments, $/pole $55.00 $152.00
5.License Fee for mounting communication
equipment including distributed antenna systems on
utility poles, $/pole
$270.00 $329.44
1.The current rate includes a small incremental increase of $2.80/year for each additional foot of
leased space up to 4 feet.
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Table 14: Current and Proposed Electric Rates
E-1 (Residential)
Tier 1 Energy ($/kWh)0.19461 0.20570 0.01109 5.7%
Tier 2 Energy ($/kWh)0.21868 0.22944 0.01076 4.9%
Customer Charge ($/month)4.64 5.15 0.51 11.0%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh)0.25210 0.26485 0.01275 5.1%
Winter Energy ($/kWh)0.16414 0.17290 0.00876 5.3%
Customer Charge ($/month)5.60 6.22 0.62 11.1%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh)0.15387 0.16171 0.00784 5.1%
Winter Energy ($/kWh)0.11018 0.11579 0.00561 5.1%
Summer Demand ($/kW)45.29 47.59 2.30 5.1%
Winter Demand ($/kW)23.73 24.94 1.21 5.1%
Customer Charge ($/month)113.73 119.53 5.80 5.1%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh)0.13570 0.14262 0.00692 5.1%
Winter Energy ($/kWh)0.08797 0.09245 0.00448 5.1%
Summer Demand ($/kW)40.36 42.41 2.05 5.1%
Winter Demand ($/kW)27.79 29.20 1.41 5.1%
Customer Charge ($/month)520.80 547.36 26.56 5.1%
Table 15 shows the impact of the proposed July 1, 2025 rate changes on the residential and non-
residential bills for various consumption levels. The increase for all rate classes is about 5.1%.
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Table 15: Impact of Proposed Electric Rate Changes on Customer Bills in FY 2026
Net Energy Metering Compensation Rates
The City operates two Net Energy Metering (NEM) programs. Solar customers served by the City
of Palo Alto's (CPAU) original NEM program, also called NEM 1, are compensated at retail rates
for electricity they export to the grid, and solar customers served by the NEM successor program,
or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are compensated at
the Export Electricity Compensation (EEC) rate for exported electricity.
Customers on the NEM 1 program who have chosen to have the value of any annual net
generation they produced over the past 12 months credited back to their account do so under
the Net Metering Net Surplus Electricity Compensation (E-NSE-1) rate. The Net Surplus Electricity
Compensation rate represents the value of the City’s avoided cost or value of customer-
generated electricity in Palo Alto, including compensation for the energy, avoided capacity
charges, avoided transmission and ancillary service charges, avoided transmission and
distribution (T&D) losses, and renewable energy credits (RECs), or environmental attributes. Staff
proposes decreasing the E-NSE-1 rate to $0.1012/kWh based on updated avoided cost
calculations reflecting declines in long-term electricity market prices expected to continue into
the future.
Under the City’s NEM successor program, participating solar customers in Palo Alto are billed at
the current retail rate for electricity drawn from the grid, and receive a credit for electricity they
export to the grid at the EEC rate. This compensation rate also reflects the avoided cost or value
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of customer-generated electricity in Palo Alto, calculated on a forward-looking basis for the
upcoming fiscal year. As shown in the table below, the current avoided cost for solar generation
in Palo Alto is $0.1420/kWh, which is higher than the City’s projected avoided cost, which
requires the proposed NEM compensation rate (E-EEC-1) to decrease to $0.1206/kWh. This
decrease in the overall avoided cost is driven by changes in electricity market prices. Table 16
shows the current and proposed NEM Buyback rates effective July 1, 2025.
Table 16: NEM Buyback Rates – Current vs. Proposed
Bill Comparisons/Competitiveness
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Santa Clara’s electrical system benefits from a higher load factor with a significantly larger
commercial load compared to Palo Alto’s, resulting in a more efficient distribution system and
lower rates. However, unlike Palo Alto, Santa Clara’s system is not 100% carbon neutral, as part
of its electricity is generated from natural gas.
Table 17: Residential Monthly Electric Bill Comparison (Effective 3/1/2025, $/mo.)
Table 18: Commercial Monthly Electric Bill Comparison (Effective 3/1/2025, $/mo.)
General Fund Transfer
10 Each year it is
calculated according to the 2009 Council-adopted methodology and does not require additional
Council action.
Next Steps
10 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to the General Fund Transfer methodology.
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The City Council will consider adopting this Financial Forecast and rate adjustments as part of the
FY 2026 budget review and adoption process in June 2025. If Council approves the proposed rate
changes, the rates will become effective July 1, 2025.
FISCAL/RESOURCE IMPACT
POLICY IMPLICATIONS
STAKEHOLDER ENGAGEMENT
ENVIRONMENTAL REVIEW
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The UAC’s review and recommendation to the Council on the FY 2026 Electric Financial Forecast
and rate adjustments does not meet the California Environmental Quality Act’s definition of a
project, pursuant to Public Resources Code Section 21065, thus no environmental review is
required.
ATTACHMENTS
APPROVED BY:
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* NOT YET APPROVED *
Attachment A
1
027032125
Resolution No. ____
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2026 Electric Utility Financial Forecast, and Amending Utility Rate
Schedules E-1 (Residential Electric Service), E-2 (Residential Master-Metered
and Small Non-Residential Electric Service), E-2-G (Residential Master-
Metered and Small Non-Residential Green Power Electric Service), E-4
(Medium Non-Residential Electric Service), E-4-G (Medium Non-Residential Green
Power Electric Service), E-4 TOU (Medium Non-Residential Electric Time of
Use Service), E-7 (Large Non-Residential Electric Service), E-7-G
(Large Non- Residential Green Power Electric Service), E-7 TOU (Large Non-
Residential Electric Time of Use Service), E-14 (Street Lights), E-16 (Unmetered
Electric Service), E-EEC-1 (Export Electricity Compensation), and E-NSE-1 (Net
Metering Surplus Electricity Compensation)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of its
utilities with the goal of ensuring adequate revenue to fund operations. This includes making
long-term projections of market conditions, the physical condition of the system, and other
factors that could affect utility costs, and setting rates adequate to recover these costs. It does
this with the goal of providing safe, reliable, and sustainable utility services at competitive rates.
The City adopts Financial Forecasts or Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Forecasts or Plans.
C. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of the
City of Palo Alto may by resolution adopt rules and regulations governing utility services, fees and
charges.
D. On June 16, 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 fiscal year (“FY”) 2026 Electric Utility
Financial Forecast attached to and made a part of the staff report presented to the City
Council;
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* NOT YET APPROVED *
Attachment A
2
027032125
SECTION 2. The Council hereby approves a transfer of up to $5 million from the
Electric Utility Supply Operations Reserve to the Distribution Operations Reserve by the end of
FY 2025, as described in the FY 2026 Electric Utility Financial Forecast;
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2025;
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-2 (Residential Master-Metered and Small Non-Residential Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-2, as amended, shall
become effective July 1, 2025;
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-2-G (Residential Master-Metered and Small Non-Residential Green Power Electric
Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-2-G,
as amended, shall become effective July 1, 2025;
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2025;
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-4-G (Medium Non-Residential Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall become
effective July 1, 2025;
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-4 TOU (Medium Non-Residential Time of Use Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended, shall become
effective July 1, 2025;
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective July
1, 2025;
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended to read
Item #4
Packet Pg. 163
* NOT YET APPROVED *
Attachment A
3
027032125
as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become effective
July 1, 2025;
SECTION 11. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-7 TOU (Large Non-Residential Time of Use Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become
effective July 1, 2025;
SECTION 12. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated. Utility
Rate Schedule E-14, as amended, shall become effective July 1, 2025;
SECTION 13. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-16 (Unmetered Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-16, as amended, shall become effective July 1, 2025;
SECTION 14. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-EEC-1 (Export Electricity Compensation) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-EEC-1, as amended, shall become effective July 1, 2025;
SECTION 15. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-NSE-1 (Net Surplus Electricity Compensation Rate) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-NSE-1, as amended, shall become effective
July 1, 2025;
SECTION 16. The Council finds that the revenue derived from the adoption of this
resolution shall be used only for the purpose set forth in Article VII, Section 2, of the Charter of
the City of Palo Alto.
SECTION 17. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor that
are not provided to those not charged, and do not exceed the reasonable costs to the City of
providing the service or product.
//
//
//
Item #4
Packet Pg. 164
* NOT YET APPROVED *
Attachment A
4
027032125
SECTION 18. The Council finds that approving the Electric Financial Forecast and Reserve
transfers 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 electric rates to meet operating expenses, purchase supplies and materials, meet
financial reserve needs and obtain funds for capital improvements necessary to maintain service
is not subject to the California Environmental Quality Act (CEQA), pursuant to California Public
Resources Code Sec. 21080(b)(8) and CEQA Guidelines Sec. 15273(a). After reviewing the staff
report and all attachments presented to Council, the Council incorporates these documents
herein and finds that sufficient evidence has been presented setting forth with specificity the
basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
Assistant City Attorney
Director of Administrative Services
Item #4
Packet Pg. 165
RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-1-1 Supersedes Sheet No E-1-1
Effective 7-1-20254 dated 7-1-20234
A. APPLICABILITY:
This Rate Schedule applies to separately metered single-family residential dwellings receiving
Electric Service from the City of Palo Alto Utilities.
B.TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh)Commodity Distribution Public Benefits Total
Tier 1 usage $
0.103730.102 0.095930.086 0.006040.00549 0.205700.194
Any usage over Tier 1 40 79 68
D.SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
2. Calculation of Usage Tiers
Tier 1 Electricity usage shall be calculated and billed based upon a level of 15 kWh per
day, prorated by Meter reading days of Service. As an example, for a 30-day bill, the Tier
1 level would be 450 kWh. For further discussion of bill calculation and proration, refer
to Rule and Regulation 11.
{End}
Attachment B Item #4
Packet Pg. 166
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-1 Supersedes Sheet No E-2-1
Effective 7-1-20254 dated 7-1-20243
A. APPLICABILITY:
This Rate Schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities:
1. Non-residential Customers receiving Non-Demand metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities receiving Non-
Demand metered Electric Service.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period
$
0.150750.149
$
0.108060.097
$
0.264850.2
0.093340.092 0.073520.066 0.172900.1
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
Attachment B Item #4
Packet Pg. 167
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-2 Supersedes Sheet No E-2-2
Effective 7-1-20254 dated 7-1-20243
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh
for twelve consecutive months, whereupon, at the option of the City, it may be removed.
{End}
Attachment B Item #4
Packet Pg. 168
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-G-1 Supersedes Sheet No E-2-G-1
Effective 7-1-20245 dated 7-1-20243
A. APPLICABILITY:
This Rate Schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities who qualify for E-2 Service and choose to participate in the Palo Alto Green
Program:
1. Non-residential Customers receiving Non-Demand metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities receiving Non-Demand
metered Electric Service.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public Green
$
0.150750.14
$
0.108060.09
$
0.006040.
$
0.272350.
0.093340.09
0.073520.06
0.006040.
$
0.1716480
Customer Charge 6.225.60
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$
0.150750.14
$
0.108060.09
$
0.006040.
$
0.2521026
Attachment B Item #4
Packet Pg. 169
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-G-2 Supersedes Sheet No E-2-G-2
Effective 7-1-20245 dated 7-1-20243
Customer Charge 6.225.60
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation
Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities
Department of enough renewable energy credits (RECs) to match 100% of the metered
energy usage at the Customer’s facility each month. Any Customer may alternately request
that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs.
CPAU will charge the Customer the Palo Alto Green Charge for each such requested block.
These REC purchases support the production of renewable energy, increase the financial
value of power from renewable sources, and create a transparent and sustainable market
that encourages new development of wind and solar power.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
Attachment B Item #4
Packet Pg. 170
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-G-3 Supersedes Sheet No E-2-G-3
Effective 7-1-20245 dated 7-1-20243
application provided by the Customer Service Center. Customers may request at any time,
in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program.
4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh
for twelve consecutive months, whereupon, at the option of the City, it may be removed.
{End}
Attachment B Item #4
Packet Pg. 171
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-1 Supersedes Sheet No E-4-1
Effective 7-1-20254 dated 7-1-20243
A. APPLICABILITY:
This Rate Schedule applies to Demand metered Secondary Electric Service for Customers with
a maximum Demand below 1,000 kilowatts. This Rate Schedule may include Service to master-
metered multi-family facilities or other facilities requiring Demand metered Service, as
determined by the City.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $ 11.0910.98 $ 38.0834.31 $ 49.1745.29
Energy Charge (per kWh)
0.124410.123 0.027970.025 0.006040.00 0.158420.1538
0.080280.079 0.027970.025 0.006040.00 0.114290.1101
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.
Attachment B Item #4
Packet Pg. 172
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-2 Supersedes Sheet No E-4-2
Effective 7-1-20254 dated 7-1-20243
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a Maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh
for twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type
Demand Meter which does not reset after a definite time interval may be used at the City's
option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 pm on weekdays.
4. Changing Rate Schedules
Customers may request a rate schedule change at any time to any City of Palo Alto full-
service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage
profile.
5. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
Attachment B Item #4
Packet Pg. 173
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-3 Supersedes Sheet No E-4-3
Effective 7-1-20254 dated 7-1-20243
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change his system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
6. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3)
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
Attachment B Item #4
Packet Pg. 174
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-4 Supersedes Sheet No E-4-4
Effective 7-1-20254 dated 7-1-20243
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
Attachment B Item #4
Packet Pg. 175
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-1 Supersedes Sheet No E-4-G-1
Effective 7-1-20254 dated 7-1-20234
A. APPLICABILITY:
This Rate Schedule applies to Customers who qualify for E-4 Service and who choose to
participate in the Palo Alto Green Program.
B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Public Green
$ 49.1745.2
0.124410.12 0.027970.025 0.006040.0.165920.
$ 26.0923.7
0.080280.07 0.027970.025 0.006040.
Attachment B Item #4
Packet Pg. 176
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-2 Supersedes Sheet No E-4-G-2
Effective 7-1-20254 dated 7-1-20234
2. 1000 kWh Block Purchase Option:
$ 49.1745.2
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted
for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill
amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has dropped
Attachment B Item #4
Packet Pg. 177
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-3 Supersedes Sheet No E-4-G-3
Effective 7-1-20254 dated 7-1-20234
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the
City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type
Demand Meter, which does not reset after a definite time interval, may be used at the City's
option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays.
4. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full-service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
5. Palo Alto Green Program Description and Participation
Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities
Department of enough renewable energy credits (RECs) to match 100% of the metered
energy usage at the customer’s facility each month. Any Customer may alternately request
that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs.
CPAU will charge the Customer the Palo Alto Green Charge for each such requested block.
These REC purchases support the production of renewable energy, increase the financial
value of power from renewal sources, and creates a transparent and sustainable market that
encourages new development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any time,
in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
Attachment B Item #4
Packet Pg. 178
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-4 Supersedes Sheet No E-4-G-4
Effective 7-1-20254 dated 7-1-20234
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change the system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue Meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3)
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue Meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
Attachment B Item #4
Packet Pg. 179
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-5 Supersedes Sheet No E-4-G-5
Effective 7-1-20254 dated 7-1-20234
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
Attachment B Item #4
Packet Pg. 180
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-1 Supersedes Sheet No E-4-TOU-1
Effective 7-1-20254 dated 7-1-20243
A. APPLICABILITY:
This voluntary Rate Schedule applies to Demand metered Secondary Electric Service for
Customers with Demand between 500 and 1,000 kilowatts per month and who have sustained
this level of usage for at least three consecutive months during the most recent 12 month period.
This Rate Schedule may include Service to Master-Metered multi-family facilities or other
facilities requiring Demand metered Service, as determined by the City.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
0.172080.170 0.028170.025 $ 0.206290.201
Attachment B Item #4
Packet Pg. 181
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-2 Supersedes Sheet No E-4-TOU-2
Effective 7-1-20254 dated 7-1-20243
0.120960.119 $ 0.02775 $ 0.154750.150
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted
for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill
amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Energy
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 2:00 p.m. to 4:00 p.m. Monday through Friday (except holidays)
9:00 p.m. to 11:00 p.m.
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
WINTER PERIOD (Service from November 1 to April 30):
Attachment B Item #4
Packet Pg. 182
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-3 Supersedes Sheet No E-4-TOU-3
Effective 7-1-20254 dated 7-1-20243
Energy
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 9:00 a.m. to 2:00 p.m. Monday through Friday (except holidays)
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
TYPES OF DEMAND CHARGES: The Peak Demand Charge per Kilowatt applies to the
maximum peak-period Demand during the time periods noted above. The Maximum (Max)
Demand charge per Kilowatt applies to the maximum Demand at any time during the month. Both
Demand charges apply in each Billing Period, and the maximum peak-period Demand and
maximum Demand may occur at different times in the Billing Period depending on Customer
usage patterns.
SEASONAL RATE CHANGES: When the Billing Period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal period,
and the Charges based on the applicable rates therein. For further discussion of bill calculation
and proration, refer to Rule and Regulation 11.
3. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive
months, a Demand Meter will be installed as promptly as is practicable and thereafter continued
in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve
consecutive months, whereupon, at the option of the City, it may be removed.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time
periods as defined under Section D.2.
4. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said Rate Schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer
may request a Rate Schedule change to any applicable City of Palo Alto full-service Rate
Attachment B Item #4
Packet Pg. 183
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-4 Supersedes Sheet No E-4-TOU-4
Effective 7-1-20254 dated 7-1-20243
Schedule as is suitable to their kilowatt Demand and kilowatt-hour usage.
5. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be offered,
but the City is not required to supply Service at a particular line voltage where it has, or will
install, ample facilities for supplying at another voltage equally or better suited to the Customer's
electrical requirements, as determined in the City’s sole discretion. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any Customer
receiving the discount in this section. The Customer then has the option to change his system so
as to receive Service at the new line voltage or to accept Service (without voltage discount)
through transformers to be supplied by the City subject to a maximum kilovolt-ampere size
limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue Meter are not operating,
the Maximum Demand will be reduced by the sum of the Maximum Generation of those
non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced
below zero.
Attachment B Item #4
Packet Pg. 184
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-5 Supersedes Sheet No E-4-TOU-5
Effective 7-1-20254 dated 7-1-20243
(2) If the non-utility generation source does not operate for an entire billing cycle, the
standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible
Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as
amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
Attachment B Item #4
Packet Pg. 185
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-1 Supersedes Sheet No E-7-1
Effective 7-1-20254 dated 7-1-20243
A. APPLICABILITY:
This Rate Schedule applies to Demand metered Service for large non-residential Customers with
a Maximum Demand of at least 1,000KW per month per site, who have sustained this Demand
level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Customer Charge
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
Attachment B Item #4
Packet Pg. 186
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-2 Supersedes Sheet No E-7-2
Effective 7-1-20254 dated 7-1-20243
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account
or one Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule,
consists of one or more Accounts which cover contiguous parcels of land with no
intervening public right-of-ways (e.g. streets) and which have a common billing address.
4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the
City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-
type Demand Meter which does not reset after a definite time interval may be used at the
City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 pm on weekdays.
Attachment B Item #4
Packet Pg. 187
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-3 Supersedes Sheet No E-7-3
Effective 7-1-20254 dated 7-1-20243
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.8 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change his system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kVA size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue Meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
Attachment B Item #4
Packet Pg. 188
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-4 Supersedes Sheet No E-7-4
Effective 7-1-20254 dated 7-1-20243
(1) In the event the Customer’s Maximum Demand (as defined in Section D.4)
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue Meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
Attachment B Item #4
Packet Pg. 189
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-1 Supersedes Sheet No E-7-G-1
Effective 7-1-20254 dated 7-1-20243
A. APPLICABILITY:
This Rate Schedule applies to Customers who qualify for E-7 Service and who choose to
participate in the Palo Alto Green Program.
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Public Green
$ 43.6140.
30.5727.
Attachment B Item #4
Packet Pg. 190
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-2 Supersedes Sheet No E-7-G-2
Effective 7-1-20254 dated 7-1-20243
2. 1000 kWh Block Purchase Option:
$ 43.6140.
30.5727.
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
Attachment B Item #4
Packet Pg. 191
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-3 Supersedes Sheet No E-7-G-3
Effective 7-1-20254 dated 7-1-20243
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has dropped
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the
City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type
Demand Meter which does not reset after a definite time interval may be used at the City's
option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays.
4. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account
or one Meter if the Accounts are at one site. A site, for the purposes of this Rate Schedule,
consists of one or more Accounts which cover contiguous parcels of land with no
intervening public right-of-ways (e.g. streets) and which have a common billing address.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile
6. Palo Alto Green Program Description and Participation
Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities
Department of enough renewable energy credits (RECs) to match 100% of the metered
energy usage at the Customer’s facility each month. Any Customer may alternately request
that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs.
CPAU will charge the Customer the Palo Alto Green Charge for each such requested block.
These REC purchases support the production of renewable energy, increase the financial
value of power from renewal sources, and creates a transparent and sustainable market that
encourages new development of wind and solar.
Attachment B Item #4
Packet Pg. 192
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-4 Supersedes Sheet No E-7-G-4
Effective 7-1-20254 dated 7-1-20243
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any time,
in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.8 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a qualified line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's Electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change the system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
9. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue Meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
Reserved Capacity)
Summer Period 9.259.16 $ 31.5428.41 $ 40.7937.57
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
Attachment B Item #4
Packet Pg. 193
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-5 Supersedes Sheet No E-7-G-5
Effective 7-1-20254 dated 7-1-20243
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3)
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue Meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
Attachment B Item #4
Packet Pg. 194
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-1 Supersedes Sheet No E-7-TOU-1
Effective 7-1-20254 dated 7-1-20243
A. APPLICABILITY:
This voluntary Rate Schedule applies to Demand metered Service for non-residential Customers
with a Maximum Demand of at least 1,000KW per month per site, who have sustained this
Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
0.181990.18 $ $ $
0.122250.12 $ $ $
Attachment B Item #4
Packet Pg. 195
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-2 Supersedes Sheet No E-7-TOU-2
Effective 7-1-20254 dated 7-1-20243
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted
for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill
amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Energy
Peak: 4:00 pm to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 2:00 p.m. to 4:00 p.m. Monday through Friday (except holidays)
9:00 p.m. to 11:00 p.m.
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
WINTER PERIOD (Service from November 1 to April 30):
Energy
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 9:00 a.m. to 2:00 p.m. Monday through Friday (except holidays)
Attachment B Item #4
Packet Pg. 196
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-3 Supersedes Sheet No E-7-TOU-3
Effective 7-1-20254 dated 7-1-20243
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
TYPES OF DEMAND CHARGES: The Peak Demand Charge per Kilowatt applies to the
maximum peak-period Demand during the time periods noted above. The Maximum (Max)
Demand charge per Kilowatt applies to the maximum Demand at any time during the month. Both
Demand Charges apply in each Billing Period, and the maximum peak-period Demand and
maximum Demand may occur at different times in the Billing Period depending on Customer
usage patterns.
SEASONAL RATE CHANGES: When the Billing Period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal period,
and the Charges based on the applicable rates therein. For further discussion of bill calculation
and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account or one
Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule, consists of
one or more Accounts which cover contiguous parcels of land with no intervening public right-of-
ways (e.g. streets) and which have a common billing address. 4. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive
months, a Demand Meter will be installed as promptly as is practicable and thereafter continued
in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve
consecutive months, whereupon, at the option of the City, it may be removed.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time
periods as defined under Section D.2.
Attachment B Item #4
Packet Pg. 197
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-4 Supersedes Sheet No E-7-TOU-4
Effective 7-1-20254 dated 7-1-20243
5. Changing Rate Schedules
Customers electing to be served under E-7 TOU must remain on said Rate Schedule for a minimum
of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request
a Rate Schedule change to any applicable City of Palo Alto full-service Rate Schedule as is suitable
to their kilowatt Demand and kilowatt-hour usage.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is supplied,
a discount of 2.8 percent for available line voltages above 2 kilovolts will be offered, but the City
is not required to supply Service at a particular line voltage where it has, or will install, ample
facilities for supplying at another voltage equally or better suited to the Customer's electrical
requirements, as determined in the City’s sole discretion. The City retains the right to change its
line voltage at any time after providing reasonable advance notice to any Customer receiving the
discount in this section. The Customer then has the option to change his system so as to receive
Service at the new line voltage or to accept Service (without voltage discount) through
transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
Attachment B Item #4
Packet Pg. 198
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-5 Supersedes Sheet No E-7-TOU-5
Effective 7-1-20254 dated 7-1-20243
non-utility generators on the Customer’s side of the City’s revenue Meter are not operating,
the Maximum Demand will be reduced by the sum of the Maximum Generation of those
non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced
below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the
standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible
Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4) , as
amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
Attachment B Item #4
Packet Pg. 199
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No. E-14-1 Supersedes Sheet No. E-14-1
Effective 7-1-20254 dated 7-1-20242
A. APPLICABILITY:
This Rate Schedule applies to all street and highway lighting installations ranging in voltages from
120 to 480 which CPAU elects to operate and maintain.
B. TERRITORY:
Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City.
C. RATES: $ Per Lamp Per Month –
Attachment B Item #4
Packet Pg. 200
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No. E-14-2 Supersedes Sheet No. E-14-2
Effective 7-1-20254 dated 7-1-20242
$ Per Lamp Per Month –
CPAU supplies electricity and
switching and maintains lighting
system, including lamps and glassware.
Lamp Rating:
Street Lights
Mercury-Vapor Lamps
400 watts 53.5348.29
High Pressure Sodium Vapor Lamps
70 watts 35.37 31.90
100 watts 45.35 40.92
150 watts 62.00 55.94
250 watts 95.30 85.99
Light Emitting Diode (LED) Lamps
70 watts-equivalent 13.27 11.96
100 watts-equivalent 20.83 18.79
150 watts-equivalent 27.80 25.07
175 watts-equivalent 31.43 28.35
250 watts 46.87 42.28
Traffic Signals
12” Head Total (Red Yellow Green) 27.12 24.45
8” Head Total (RYG) 23.55 21.22
12” Arrow Total (RYG) 25.49 22.97
12” Beacon 10.19 9.19
Pedestrian Head 9.36 8.44
Controller 20.05 18.10
Speed Signs 92.73 83.74
Attachment B Item #4
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STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No. E-14-3 Supersedes Sheet No. E-14-3
Effective 7-1-20254 dated 7-1-20242
D. SPECIAL CONDITIONS:
1. Point of Delivery: Delivery will be made to the Customer's system at a Service point or at points
designated by CPAU. CPAU will furnish the Service connection to one point for each lamp or group
of lamps, provided the Customer has designed the system to include the minimum number of delivery
points. CPAU will make all underground connections to CPAU’s system at the Customer's expense.
2. Switching: CPAU will perform switching (on CPAU's side of the points of delivery) at no Charge,
provided there are at least 10 kilowatts of lamp load on each circuit separately switched, including all
lamps on the circuit whether served under this Rate Schedule or not. An extra charge of $2.50 per month
will be made for each circuit separately switched unless such switching installation is made for CPAU's
convenience.
3. Annual Burning Schedule: The rates in this Rate Schedule apply to lamps which will be turned on
and off once each night in accordance with a regular burning schedule approved by CPAU and not
exceeding 4,100 hours per year.
4. Maintenance: The rates in this Rate Schedule include all labor necessary for replacement of
glassware, including inspection and cleaning. Maintenance of glassware by CPAU is limited to standard
glassware that is commonly used and manufactured in reasonably large quantities, as determined by
CPAU in its sole discretion. The rates include maintenance of circuits between lamp posts and of circuits
and equipment in and on the posts, provided these are all of good standard construction as determined
by CPAU. CPAU in its sole discretion may decline to grant rates for maintenance of systems with non-
standard glassware, or inadequate circuitry and equipment. Rates applied to any agency other than the
City of Palo Alto also include painting of posts with one coat of good ordinary paint, as determined by
CPAU to be needed to maintain good appearance. Maintenance does not include replacement of posts
damaged by third parties or acts of nature.
5. Rates For Lamps Not on this Rate Schedule: In the event a Customer installs a lamp which is not
represented on this Rate Schedule, CPAU will prepare an interim rate reflecting CPAU's estimated costs
associated with the specific lamp. This interim rate will serve as the effective rate for billing purposes
until the new lamp rating is added to Rate Schedule E-14.
{End}
Attachment B Item #4
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UNMETERED ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-16
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No. E-16-1 Supersedes Sheet No. E-16-1
Effective 7-1-202516 dated 07-01-2016
A. APPLICABILITY:
This rate schedule is applicable under the terms and conditions of the City of Palo Alto Utilities
Department to Customers who contract with the City for unmetered electric service for
billboards, unmetered telephone services, telephone booths, railroad signals, cathodic protection
units, traffic cameras, wireless antenna and related equipment, community antenna television and
video systems, cable TV power supplies, and automatic irrigation systems and also applies to
other miscellaneous Electric Utility fees to various public agencies and private entities.
B. TERRITORY:
Within the incorporated limits of the City of Palo Alto and land owned or leased by the City.
C. NET MONTHLY BILL:
1. Customer Charge using annual SEIU salary schedule: $9.007.31 per
month
2. Energy Charge:
(for all kWh supplied) using Electric Rate Schedule E2 plus all applicable riders
3. Minimum Charge:
Minimum monthly charge will be the Customer Charge.
D. DETERMINATION OF ENERGY REQUIREMENTS:
a. Initial Inventory
Customer shall enter into a contract for service under this Schedule and provide a written
inventory of all equipment at each of service requested, including the type and nameplate
rating for each piece of equipment. The billing energy for each point of service will be
determined by the Utilities Electric Engineering Division estimation of the kWh usage
based on the type, rating and quantity of the equipment provided by the Customer.
Monthly bill will be based on the following calculations:
1. Total Wattage.
2. Total Wattage times estimated annual operating hours as set in the contract equals
annual watt hours.
3. Annual watt hours divided by 1000 hours equals annual kilowatt hours (kWh)
Attachment B Item #4
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UNMETERED ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-16
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No. E-16-2 Supersedes Sheet No. E-16-2
Effective 7-1-202516 dated 07-01-2016
4. Annual kWh divided by twelve (12) months equal monthly kWh.
5. Monthly kWh times current rate per kWh = monthly bill for each unmetered service
location or equipment.
b. Updating Inventory
Customer will update its inventory by informing the Utilities Electric Engineering Division
in writing of changes in type, rating and/or quantity of equipment as such changes occur,
and billings will be adjusted accordingly. Upon Utilities Electric Engineering Division
request, but no later than the one year anniversary of the date on which Customer first takes
service, Customer shall provide an updated inventory of all equipment at each point of
service.
c. Test Metering
The Utilities Electric Engineering Division may, at its discretion, test meter the load at
various types and ratings of the Customer’s equipment to the extent necessary to verify the
estimated kWh usage used for billing purpose and, where dictated by such test metering,
Utilities Electric Engineering Division will make prospective adjustments in estimated
usage for subsequent billing purposes; however, Utilities shall be under no obligation to
test meter- the load of Customer’s equipment. Utilities’ decision not to test meter the load
of Customer’s equipment shall not release Customer from the obligation to provide to
Utilities Electric Engineering Division, and to update, annually as provided in section b,
an accurate inventory of the types, rating and quantities of equipment upon which billing
is based.
d. Inspection
The Utilities Electric Engineering Division shall endeavor to inspect the equipment at each
point of service annually as close to the anniversary date of the contract as is practical, and
make prospective adjustments in billing as indicated by such inspections; however,
Utilities shall be under no obligation to conduct such inspections for the purpose of
determining accuracy of billing or otherwise. Utilities decisions not to conduct such
inspections shall not release Customer from the obligation to provide to Utilities Electric
Engineering Division, and to update, an accurate inventory of the types, rating and
quantities of equipment upon which billing is based.
e. Billing for Service
As the service described in this schedule is unmetered, Customer agrees to pay amounts
billed in accordance with the current inventory, regardless of whether any of the
installations of the Customer’s equipment were electrically operable during the period in
Attachment B Item #4
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UNMETERED ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-16
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No. E-16-3 Supersedes Sheet No. E-16-3
Effective 7-1-202516 dated 07-01-2016
question and regardless of the cause of such equipment failure to operate.
E. MISCELLANEOUS RATES:
Service Description Rate *
1. License Fee for Electric Conduit Usage
(A) Exclusive use $ 1.94/ft/yr
(B) Non-Exclusive use 0.97/ft/yr
2. Processing Fee for Electric Conduit Usage Actual Cost
3. License Fee for Utility Pole Attachments
(A) 1 ft. of usable space $ 29.5947.60/pole/yr
(B) 2 ft. of usable space 32.3995.20/pole/yr
(C) 3 ft. of usable space 35.18142.80/pole/yr
4 ft. of usable space $37.98/pole/yr
4. Processing Fee for Utility Pole Attachments $1525.00/pole
5. License Fee for mounting communication equipment
including distributed antenna systems on utility poles
$329.44270.00/pole/yr
* Rates are monthly unless otherwise indicated.
F. NOTES:
The fees set forth in Section E.1 through E.5, inclusive, are subject to adjustment annually in
accordance with fluctuations in the Consumer Price Index (CPI), if any. The base for computing
the adjustment is the Consumer Price Index for All Urban Consumers (CPI-U) for the San
Francisco-Oakland-San Jose MSA, which is published by the U.S. Department of Labor,
Bureau of Labor Statistics for the month of December of a base year, which falls within the
year in which a master license agreement is signed by the City and the licensee. The adjustment
shall be calculated, if there is an increase or decrease between December of a base year (when
the rate(s) is/are first applicable) and December of any subsequent base year.
{End}
Attachment B Item #4
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EXPORT ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-EEC-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-EEC-1 Sheet No.E-EEC-1
dated 7-1-20243 Effective 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies in conjunction with the otherwise applicable Rate Schedules for each
Customer class. This Rate Schedule may not apply in conjunction with any time-of-use Rate Schedule.
This Rate Schedule applies to Customer-Generators as defined in Rule and Regulation 2 who are either
not eligible for Net Energy Metering or who are eligible for Net Energy metering but elect to take
Service under this Rate Schedule.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. RATE:
The following compensation rate shall apply to all electricity exported to the grid.
Per kWh
Export electricity compensation rate $ 0.1243 0.1420
D. SPECIAL CONDITIONS
1. Metering equipment: Electricity delivered by CPAU to the Customer-Generator or received by
CPAU from the Customer-Generator shall be measured using a Meter capable of registering the
flow of electricity in two directions (aka “bidirectional meter”). The electrical power
measurements will be used for billing the Customer-Generator. CPAU shall furnish, install and
own the appropriate Meter.
2. Billing:
a. CPAU shall measure during the billing period, in kilowatt-hours, the electricity delivered
and received after the Customer-Generator serves its own instantaneous load.
b. CPAU shall bill the Customer-Generator consumption charges for the electricity delivered
by CPAU to the Customer-Generator based on the Customer-Generator’s applicable Rate
Schedule.
c. In the event the electricity generated exceeds the electricity consumed and therefore is
received by CPAU, the Customer will receive a credit for all electricity received by CPAU
at the buyback Rate designated in section C above.
{End}
Attachment B Item #4
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NET METERING NET SURPLUS ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-NSE-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-NSE-1 Sheet No. E-NSE-1
dated 07-01-20243 Effective 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to eligible residential and small commercial Net Energy Metering Election
A Customers who, at the end of an annual settlement period, as described in Rule 29, are Net Surplus
Customer-Generators of electricity who elect to receive monetary compensation as such preference is
indicated on the net surplus electricity election form. This Rate Schedule only applies to Customers
who participate in Net Energy Metering, and does not apply to Customers that take service under the
City’s Net Energy Metering Successor Rate, as each of these terms are defined in Rule and Regulation
2.
B.TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. RATES:
Per kWh
Net Surplus Electricity Compensation rate $ 0.1273 0.1427
D. SPECIAL CONDITIONS
1.Net Surplus Electricity Compensation Rate eligibility shall be determined as specified in Rule 29.
Net surplus electricity, as specified in Rule 29, if applicable, will be multiplied by the above
compensation rate to determine the Customer’s annual net surplus electricity compensation stated
in dollars.
2. Additional terms, conditions and definitions govern Net Energy Metering Service and
Interconnection, as described in Rule 29.
{End}
Attachment B Item #4
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Attachment C
Electric Utility Financial Details
Item #4
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Attachment C
Electric Utility Capital Improvement Program (CIP) Financial Details
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Attachment D
6
8
5
9
APPENDIX A: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
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Attachment D
6
8
5
9
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 11 (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) For tracking revenues earned via the sale of Low Carbon Fuel Credits allocated by the
California Air Resources Board to the City, as well as expenses incurred, in accordance
with California’s Low Caron Fuel Standard program, as described in Section 15 (Low
Carbon Fuel Standard Reserve)
i) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves
for Commitments will be set to an amount equal to the total remaining spending authority
for all contracts in force for the Electric Supply Fund and Electric Distribution Fund,
respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves
for Reappropriations will be set to an amount equal to the amount of all remaining capital
and non-capital budgets that will be reappropriated to the following fiscal year for each Fund
in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies set forth in Resolution 9206 (Resolution of the Council of the City of Palo Alto
Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve and
Adoption of Electric Special Project Reserve Guidelines). These policies are included from
Resolution 9206 as amended to refer to the reserves structure set forth in these Reserves
Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2025;
f) Any uncommitted funds remaining at the end of FY 2030 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
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Attachment D
6
8
5
9
Section 7. Hydroelectric Stabilization Reserve
after the
transfers described above shall be the basis for staff’s determination, with Council
approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-HRA) for
the following fiscal year.
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Attachment D
6
8
5
9
Maximum Level Average annual (12 month)1 CIP budget, for
48 months of budgeted CIP expenses2
b) Changes in Reserves: At the end of each fiscal year staff will transfer from the Distribution
Operations Reserve to the CIP Reserve an amount equal to the amount of electric utility
unspent CIP budget at the end of the fiscal year reduced by the amount of any contractual
commitments and reappropriations. Any other additions to or withdrawals from the CIP
reserve require Council action.
c) Minimum Level:
i) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve reaching
its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is
below its minimum level at the end of FY 2017, staff must present a plan by June 30,
2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff
may present, and the Council may adopt, an alternative plan that takes longer than
one year to replenish the reserve, or that does so in a shorter period of time.
d) Maximum Level: If there are funds in this reserve in excess of the maximum level staff
must propose in the next Financial Plan to transfer these funds to another reserve or
return them to ratepayers in the funds to ratepayers, or designate a specific use of funds
for CIP investments that will be made by the end of the next Financial Planning period.
Staff may also seek City Council to approve holding funds in this reserve in excess of the
maximum level if they are held for a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period. The Council may approve exceptions
to this requirement, when proposed by staff to provide greater rate stabilization to
customers.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to 11 above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
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Attachment D
6
8
5
9
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were funds
in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning Period is
FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign the funds
in the Unassigned Reserve by the end of FY 2017. Staff may present an alternative plan that
retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
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Attachment D
6
8
5
9
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
Section 15. Low Carbon Fuel Standard (LCFS) Reserve
This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the
California Air Resources Board to the City, as well as expenses incurred, in accordance with
California’s Low Caron Fuel Standard program. At the end of each fiscal year, the LCFS
Reserve will be adjusted by the net of revenues and expenses associated with California’s
LCFS program.
Section 16. Cap and Trade Program Reserve
This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the electric utility, under the State’s Cap
and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy
on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the
Policy), adopted by Council Resolution 9487 in January 2015. At the end of each fiscal year,
the Cap and Trade Program Reserve will be adjusted by the net of revenues and expenses
associated with the Cap and Trade program.
Section 17. Electrification Reserve
This reserve is used to track funding of City buildings, appliance and vehicle electrification
projects and programs, including development and implementation costs and associated
financial incentives, loans and rebates for participating customers. The reserve may be
funded by any lawful source of funds available for such programs, including new or ongoing
utility revenues derived from customer participation. The reserve balance shall be annually
adjusted based on the net of revenues and expenses associated with the City’s building
appliance and vehicle electrification projects and programs using this reserve.
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Attachment E
COMMUNICATIONS PLAN AND OUT REACH EXAMPLES
The fiscal year (FY) 2026 electric utility communications strategy addresses the cost drivers for a rate
increase including the City’s significant investment in electric grid infrastructure, rising costs for
transmission access charges, increasing renewable energy portfolio standards, tightening resource
adequacy requirements, and financial reserve recovery. One of the larger capital improvement projects
in progress now is the electric grid modernization, which was developed to expand capacity and enhance
reliability for increased electric load. Thus the equity transfer to the General Fund has increased along
with the grid modernization asset value and will be reassessed as the utility issues debt.
Staff will inform customers of the need to recover funds to bring electric supply operations reserves
above the minimum guidelines following the reserve drawdowns during the pandemic, drought, and
high winter energy prices during 2022-2023. It is also important to educate customers about the cost to
buy and transport electricity to Palo Alto, and distribute it within Palo Alto. Critical components of CPAU’s
expenses include maintaining and replacing infrastructure, customer service, billing, and administration.
Long-term cost trends show supply and distribution costs increasing over time. Despite raising rates,
electric costs to customers still remain lower than the comparator regional investor-owned utility, PG&E.
City of Palo Alto Utilities (CPAU) communication methods include utilities webpages, utility bill inserts,
messaging on utility bills and MyCPAU online account management platform, email newsletters, print
and digital ads, social media, and business and neighborhood customer presentations. CPAU promotes
energy efficiency programs to help customers keep utility bill costs low even as market prices increase
or CPAU raises utility rates. Programs such as GoGreen Financing and advisor services for energy
efficiency and electrification offer residents assistance for home upgrades. CPAU provides free
consulting services and rebates for commercial energy efficiency upgrades and programs for electric
vehicle (EV) charging infrastructure to assist in the switch from fossil fueled transportation to clean,
electric driving. Throughout the year, CPAU hosts free educational workshops to help residents and
businesses better understand energy usage and learn ways to improve efficiency to keep utility costs
low. The MyCPAU online account management portal provides customers with direct access and more
information about utility account and consumption data.
CPAU customers benefit from local control and policy setting, and community values-driven programs
and services, including the decision to go carbon neutral in 2013. Palo Alto’s renewable energy purchase
agreements contribute to our utility’s long-term energy security and commitment to sustainability. The
City’s Sustainability and Climate Action Plan (S/CAP) focuses on electrification as a primary way to reduce
greenhouse gas emissions. CPAU recently launched several new rebate programs in partnership with the
State and other industry entities to offer rebates for customers to switch from natural gas appliances to
electric. CPAU will highlight these resources and reinforce how community-driven policies, such as for
beneficial electrification, factor into our utility rates, and reflect the value provided by CPAU as a
municipal utility.
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Attachment E
Item #4
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MEMORANDUM
Unmetered Electric Service Rate Methodology
1
16701 NE 80th Street Suite 102 Redmond, WA 98052 425-889-2700 Fax 866-611-3791 www.gdsassociates.com
Georgia Texas Alabama New Hampshire Wisconsin Florida Maine Washington California
MEMORANDUM
TO Jim Fleming
FROM Amber Gschwend
DATE February 11, 2025
RE Unmetered Electric Service Rate Technical Memo
INTRODUCTION
This memo summarizes the methodology and assumptions used to develop rates for the City of Palo Alto’s
Unmetered Electric Service Rate Schedule (E-16). This schedule includes the following services:
1.Unmetered Electric Service
2.License Fee for Electric Conduit Use
3.License Fee for Utility Pole Attachments
4.License Fee for mounting communications equipment on utility poles (including antenna systems)
This memo provides the rate calculations for each of the above fees. The appendix contains a rate survey of
local utilities providing the same services.
UNMETERED ELECTRIC SERVICE
The current rate for Unmetered Electric service is $9/month plus estimated energy use billed at the E-2 energy
rate. The fixed charge is based only on the staffing cost to calculate bills for unmetered customers. At the
current rate for Program Assistant I, the staff who performs the annual billing, it requires on average two hours
to recalculate, invoice, and track each unmetered customer bill on an annual basis. At a current fully loaded
labor rate of $65.78/hour for a Program Assistant I,1 the annual cost is $131.55, or $10.96/month. This rate
should be updated when the City of Palo Alto Labor Agreements Salary Schedule is updated. The energy charges
are equal to E-2 rates.
POLE ATTACHMENT RATE
To provide electric service, CPAU owns 5,888 utility poles. Communication providers and PG&E have
attachments on CPAU’s poles and share the maintenance costs.
This memo describes the assumptions and methodologies used to calculate an appropriate pole
attachment rate for potential new attachments. The recommended pole attachment rates are based on
the AB1027 (2011) framework for calculating pole attachment rates, codified at Public Utilities Code (PUC)
section 9510 et seq.; with the goal that adopted pole attachment rates do not either subsidize or over-
charge communication providers. PUC section 9512(c) exempts poles that are under joint ownership
including Northern California Joint Pole Association. This memo applies to attachments that are not part
of the joint ownership agreement.
1 Labor rate of $43.85/hour plus 50% for benefits.
Attachment F Item #4
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MEMORANDUM
Unmetered Electric Service Rate Methodology
2
Input Assumptions and Methodology
Assembly Bill 1027 2 allows utilities to recover the annual ownership cost of associated utility poles
including ongoing maintenance costs and annual capital costs (depreciation). Costs are based on a utility’s
current asset values and maintenance costs. The annual cost is calculated based on the attachment’s share
of the utility pole’s capacity. In addition to the annual fee, a one-time fee may also be charged for new
pole attachments.
Key inputs to the pole attachment rate are summarized in Table 1.
TABLE 1: POLE ATTACHMENT RATE METHODOLOGY
Usable Space Measured in feet, the space
available for attachments
• PUC 9512(a)(1) dictates 13.5 feet,
subject to factual rebuttal
Space Occupied by
Attachment
Measured in feet, space required for
each attachment
1 ft is standard
Usable Space Share Measured as a percentage equal to
the space occupied by the
•
13.5 feet of usable space
•
•
•
•
•
average age from CPAU pole database
• Useful life of a pole is 80 years based
on CPAU replacement schedule
• Estimated values as described later in
•
•
adjusted by 15% to remove value of
appurtenances used only for electric
•
• Based on FY2023 actual costs
Depreciation Annual cost of capital Annual depreciation expense is 1.3%
based on 80-year asset life
The net book value for poles is an important input for calculating the cost share for overhead
maintenance, depreciation, and administration cost adders. The net book value must be adjusted for
capital contributions. The City does not have a long-standing record for capital contributions for the
history of its current pole population. However, the current agreements indicate that pole costs are often
2Now part of the California Public Utilities Code (PUC) section 9510 et seq
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MEMORANDUM
Unmetered Electric Service Rate Methodology
3
shared 50% between the City and communications providers. Therefore, it is conservatively assumed that
50% of the net book value for poles is contributed capital. This amount is removed from the bare cost of
the poles.
POLE ATTACHMENT RATE
Figure 1 illustrates the pole attachment rate methodology. Table 2 details the resulting pole attachment
rate using the methodology and inputs described. The resulting annual fee is $47.60/ attachment. CPAU
is planning for significant pole replacements in the next 5-10 years and should revisit this calculation with
updates, as the net book value of the poles is expected to increase over time with the capital expenses
planned.
FIGURE 1: POLE ATTACHMENT LEASE METHODOLOGY
Lease Rate
($/Attachment/Year)
Bare Pole
Net Book
Value
($/Pole)
Annual
Operating Costs
($/Pole)
Depreciation +
G&A +Annual
O&M
Annual
Operating Costs
($/Pole)
Net Book
Value
Ownership
($/Pole)
Ownership
($/Pole)
Usable Space
Factor
(%)
Attachment F Item #4
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MEMORANDUM
Unmetered Electric Service Rate Methodology
4
TABLE 2: POLE ATTACHMENT RATE CALCULATION
Line Formula/Source
O & M Adder
1 Maintenance Expense FY2024 Prelim. Actual $3,690,146
2 Net Investment (Accumulated Depreciation) Line 8 - Line 9 $10,757,928
3 Line 1/Line 2
G & A Adder
4 Total General & Administrative Expense FY2023 Actual $6,090,703
5 Net Book Value (All Plant in Service) As of Ending FY2023 $215,968,770
6 Line 4/Line 5
Capital Cost Adder
7 Annual Depreciation Rate 1/80 years 1.3%
8 Capital Cost Original Cost $21,622,546
9 Net Book Value Original Cost less Depreciation $10,864,618
10 Line 8/Line 9 × Line 7
11 Net Book Value Line 9 $10,864,618
12 Number of Poles Pole Database 5,888
13 Net Cost of Bare Pole (Line 11/Line 12) × (1-15%) $1,568.43
14 Average Height of Pole (ft) From CPAU Pole Database 46
15 Space Occupied by Attachment Number of Feet Required 1
16 Usable Space (ft) PUC section 9510 et seq 13.5
17 Usable Space Share of Pole Height (%) Line 16/Line 14 29.3%
18 Net Cost of Bare Pole Line 13 $1,568.43
19 Carrying Cost Percentage Sum lines 3, 6, 10 39.6%
20 Annual Operation Cost per pole Line 18 × Line 19 $621.25
21 Cost of Ownership Line 18+ Line 20 $2,189.68
22 Cost of Ownership (Based on Usable Space) Line 17× Line 21 $642.62
23 Usable Space Factor (%) Line 15/ Line 16 7.4%
24 Line 22 × Line 23
In addition to the attachment fee, a processing fee is charged per pole to cover engineering and field review.
This processing fee is calculated based on the current labor rate of $152/hour and the hours required (1.0
hours). This hourly rate includes benefits and administrative overhead. The resulting fee is $152 per pole. This
Attachment F Item #4
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MEMORANDUM
Unmetered Electric Service Rate Methodology
5
is the same charge from URS C-1 Utility Miscellaneous Charge. The rate schedule could reference URS C-1
rather than providing the rate in URS-16.
TABLE 3: POLE ATTACHMENT PROCESSING FEE
0.5 $152.00 $76.00
0.5 $152.00 $76.00
LICENSE FEE FOR SMALL CELL ATTACHMENTS
In 2018, the Federal Communications Commission (FCC) established new rules around small cell attachments
to utility poles. The order intended to make more available the deployment of 5G networks. Utilities may
recover the annual cost of service to small cell attachments as long as those costs are deemed reasonable. The
FCC further states that reasonable annual costs are typically limited to $270 per pole per year for small cell
attachments. The current annual fee for small cell attachments is set at the 2018 value of $270. The
recommended annual fee updates this value using the Consumer Price Index for All Urban Consumers in the
San Francisco-Oakland-Hayward area. The recommended updated license fee is $329.44 per year per pole.
CONDUIT LEASE RATE
The lease fee for electric conduit use is calculated much the same way as the pole attachment rate. The
conduit lease is for exclusive use only since conduit is not shared. The City tracks O&M costs for
underground conduit separately. Annual O&M costs are $300,000. General and administrative costs plus
depreciation expense is calculated at 4.9% of the net book value for conduit. These costs plus direct
conduit O&M costs total to produce an annual rate of $1.94/foot. Figure 2 illustrates the general
methodology while Table 4 provides the detailed calculations.
FIGURE 2: CONDUIT LEASE FEE METHODOLOGY
Conduit
Lease Rate,
($/ft/year)
Conduit Net
Book Value
($/ft)
Direct Annual
Operating
Costs
($/ft/year)
Adder for
Depreciation
and G&A
(%)
Attachment F Item #4
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MEMORANDUM
Unmetered Electric Service Rate Methodology
6
TABLE 4: CONDUIT LEASE RATE CALCULATION
line Formula/Source
1 CPAU Records Feet of Conduit 575,264
2 Account 366 Fixed Assets Capital Cost $34,186,622
3 Net Book Account 366 Depreciation $17,403,632
4 Line 2 - Line 3 Net Book Value $16,782,990
5 Line 4 / Line 1 Net Book Value per Foot of Conduit, $/ft $29.17
6 CPAU Records Annual O&M Costs $300,000
7 Line 6 / Line 1
8 Actual FY23 Expenses Total General & Administrative Expense $6,090,703
9 Fixed Assets Net Book Value (All Plant in Service) $215,968,770
10 Line 8 / Line 9 Administrative Expense Adder 2.8%
11 1/100 years Annual Depreciation Rate 1.0%
12 (Line 2/Line 4) × Line 11 Depreciation Adder 2.0%
13 Line 10 + Line 12 Total Carrying Cost Adder 4.9%
14 Line 13 × Line 5
15 Line 7 + Line 14
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MEMORANDUM
Unmetered Electric Service Rate Methodology
7
SUMMARY
Table 5 compares the current and recommended rates for Unmetered Utility Service:
TABLE 5: RECOMMENDED RATES
FY2026 Rate
1.Customer Charge, $/month $9.00 $10.96
2.Energy Charge, $/kWh Same as E-2 Same as E-2
1.Conduit License Fee, $/foot/year $1.94 $1.94
2.Processing Fee for Electric Conduit Usage Actual Cost Actual Cost
3.Pole Attachment License Fee, $/Foot/Year $29.511 $47.60
4.Processing Fee for Utility Pole Attachments, $/pole $55.00 $152.00
5.License Fee for mounting communication
equipment including distributed antenna systems
on utility poles, $/pole
1.The current rate includes a small incremental increase of $2.80/year for each additional foot of
leased space up to 4 feet.
The recommended unmetered service rate aligns closely with the FY2025 E-2 rate and excludes costs
related to meter reading since Utility Rate Schedule E-16 provides the process for determining energy
requirements based on equipment specifications. For pole attachments, it is recommended that CPAU
charge the same fee for each foot of usable space licensed for communications use. This recommendation
is consistent with PUC 9510(a)(1). The Appendix shows that the calculated pole attachment rate is higher
than the rates published by other utilities surveyed. The sampling of utilities for pole attachment rates is
difficult since many participate in the Northern California Joint Pole Association that manages standard
pole attachments for member agencies. Pole attachment rates in other states are commonly in the $30-
$40/attachment range. The rate level is mostly impacted by the net book value of the pole attachment
and the depreciation schedule.
Attachment F Item #4
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MEMORANDUM
Unmetered Electric Service Rate Methodology
8
APPENDIX
TABLE 6: POLE ATTACHMENT RATE COMPARISON
$47.60
$18.50
$21.94
TABLE 7: SMALL CELL ATTACHMENT RATE COMPARISON
$329.44
$1,475 deposit
$94.08 increased 2.5% annually
$303.41 increased 3% annually
$270 increased 3% annually each
effective date
TABLE 8: UNMETERED SCHEDULE
$10.961
Summer (May 1-Oct 31) (E-2)$0.26485
Winter (Nov 1- Apr 30) (E-2)$0.17290
$15.75 $0.20113
$5.06
First 800 kWh $0.24377
Above 800 kWh $0.22130
$13.28 $0.15700
$20.75 $0.27180
1. Updates according to hourly rate of Program Assistant I at 2 hours per year.
https://www.cityofpaloalto.org/Departments/Human-Resources/Labor-
Agreements-and-Salary-Schedules
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April 2, 2025 www.cityofpaloalto.org
FY 2026 Electric Rate Proposal
Utilities Advisory Commission
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Proposal
•5.1% overall rate increase in FY 2026 (11% increase in distribution rates, combined with 1% increase in supply rates)
Drivers
•Significant investment in grid modernization funded by revenues and bond financing; first bond issuance in FY 2026
•Reserves recovering from 2020-2022 drawdown
•In current year, power supply costs lower than budget
•Longer-term transmission costs & renewable energy targets are rising and Resource Adequacy requirements are
tightening; Resource Adequacy costs are expected to increase while Resource Adequacy sales revenue declines
Compared with Preliminary Rates
•Cost increases including: new warehouse and laydown yard for grid modernization , replacement of emergency
generators, General Fund Transfer increase to reflect grid modernization asset value
•Reflects climate action budget
•Supply forecast update
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Electric Bill Comparisons
Note: PG&E Rates Effective March 1, 2025; Santa Clara Rates Effective January 1, 2025; Palo Alto Rates Effective July 1, 2024
**calculated using the "average" bundled total rates, and Climate Zone X, which includes most nearby comparison communities
*Includes the annual climate credit, and Climate Zone X, which includes most nearby comparison communities
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Electric Cost and Revenue Projections Item #4
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5
Electric Supply Operating Reserve Projections
Received $24M Overcharges Refund
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Electric Distribution Operating Reserve Projections
Maintained rates with no
increases in FY2021 and FY2022,
and utilized the operating
reserve to cover expenses
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Electric Bill Impact Item #4
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Communication and Outreach
Key Messages
•Reasons for rate increases and benefits to customers
•Competitive rates to other utilities and neighboring cities
•What the City is doing to keep costs down
•City programs and services to help customers keep utility bill costs low
Outreach Strategies
•Public Meetings: UAC, Finance, City Council
•Digital Communication:website, social media,
email newsletters, City blog, videos
•Direct Mail: utility bill inserts,Proposition 218
notice,SFPUC rates postcard
•Local Media Engagement: articles, interviews
Sample utility bill insert
about energy efficiency
Replacing a utility pole as
part of the Electric Grid
Modernization Project
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Electric Recommendation
U
1.Approving the Fiscal Year 2026 Electric Utility Financial Forecast shown in this staff report and
attachments; and
2.Approving the transfer at the end of FY 2025 of up to $5 million from the Electric Utility Supply Operations
Reserve to the Distribution Operations Reserve.
3.Amending Rate Schedules (Attachment B) effective July 1, 2025 (FY 2026): E -1 (Residential Electric Service),
E-2 (Residential Master-Metered and Small Non-Residential Electric Service), E -2-G (Residential Master-
Metered and Small Non-Residential Green Power Electric Service), E-4 (Medium Non-Residential Electric
Service), E-4-G (Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-Residential
Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-7-G (Large Non-Residential
Green Power Electric Service), E -7 TOU (Large Non-Residential Time of Use Electric Service), E-14 (Street
Lights), E-16 (Unmetered Electric Service), E-EEC-1 (Export Electricity Compensation), and E-NSE-1 (Net
Metering Surplus Electricity Compensation)
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Item No. 5. Page 1 of 1
Utilities Advisory Commission
Staff Report
From: Kiely Nose, Interim Director of Utilities
Lead Department: Utilities
Meeting Date: April 2, 2025
Report #: 2503-4375
TITLE
Review and Recommend Utilities Advisory Commission FY 2025 – 2026 Work Plan for City
Council Approval
RECOMMENDATION
Staff recommends the Utilities Advisory Commission (UAC) to review, provide feedback, and
recommend City Council approval of the FY 2025 - 2026 Annual Work Plan.
BACKGROUND
This item was brought to the March 5, 2025 Utilities Advisory Commission meeting and was not
heard. This item is being brought back to the Commission.
ATTACHMENTS
Attachment A: Staff Report 2501-4002 from March 5, 2025 Meeting
Attachment B: Utilities Advisory Commission Draft FY 2025-2026 Workplan
Attachment C: Supplemental Staff Report
Attachment D: Proposed Topics from UAC Commissioners
AUTHOR/TITLE:
Kiely Nose, Interim Director of Utilities
Staff: Kaylee Burton, Utilities Administrative Assistant
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Item No. 5. Page 1 of 2
Utilities Advisory Commission
Staff Report
From: Kiely Nose, Interim Utilities Director
Lead Department: Utilities
Meeting Date: March 5, 2025
Report #: 2501-4002
TITLE
Review and Recommend Utilities Advisory Commission FY 2025 – 2026 Work Plan for City
Council Approval
RECOMMENDATION
Staff recommends the Utilities Advisory Commission (UAC) to review, provide feedback, and
recommend City Council approval of the FY 2025 - 2026 Annual Work Plan.
BACKGROUND
In accordance with the 2020 City Boards, Commissions, and Committees Handbook, each Board
and Commission should prepare an annual work plan for proposal to the City Council by the
second quarter of the calendar year. The Council will review the work plan and provide
feedback annually at a dedicated City Council meeting. The annual report should include the
results of the prior year’s plan. When applicable, the City Council would like to see metrics of
community involvement and participation in meetings and activities included in the work plan.
Council expects Boards and Commissions to work on items in the approved workplan. In
addition, Council may refer additional items to the Boards and Commissions in response to new
developments. Boards and Commissions should refrain from expending their time and that of
the staff liaison on items that have not been approved by the City Council. If the Board or
Commission would like to add an issue for review after an annual workplan has been approved
by the City Council, a prompt request by the Board or Commission Chair to the City Council is
required and the item will then be addressed by the City Council as a whole.
ANALYSIS
Staff prepared attachment A, a draft UAC workplan for FY 2025-2026 based on standing items
for the Commission. In addition, Utilities Advisory Commissioners were surveyed for proposed
FY 2025-2026 priorities for the UAC to consider. Below are the responses received at the
publishing of this report, in no specific order. Upon development and approval of the UAC
workplan by the Commission, it will be brough forward to the City Council for review and
approval to ensure alignment of priorities and resources in Spring 2025.
Potential UAC Workplan Items received to date:
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Item No. 5. Page 2 of 2
•Emergency Preparedness: Examples that may be covered could include long term
power outages and wildfire mitigation plan
•Advocacy Letters: Examples that have been previously discussed: One Water Advocacy
Letter and Bay Area Water Supply & Conservation Agency Advocacy Letter [currently
agendized for March 2025 commission meeting]
Staff will issue an additional supplemental item with any additional feedback from
Commissioners by March 3, 2025 to support the UAC discussion and development of the
workplan.
City Council Priority Setting Process Status: On January 25, 2025, the City Council adopted its
priorities for 2025:
•Economic Development & Retail Vibrancy
•Climate Action and Adaptation & the Natural Environment Protection
•Implementing Housing Strategies for Social and Economic Balance
•Public Safety, Wellness & Belonging
As has been the City’s practice for the past few years, staff has followed the City Council
approval of its priorities by developing and recommending for City Council approval a set of
objectives to advance each priority throughout the calendar year. The City Council is scheduled
to review these objectives (68 recommended) and City Council workplans for 2025 at its
February 24, 2025 meeting, guiding and prioritizing resource allocation for 20251.
RESOURCE IMPACT
The UAC recommended workplan does not have an immediate fiscal impact; however,
resources may be needed to be allocated to implement workplan items the Commission wishes
to recommend. Opportunities to allocate resources to projects include the FY 2026 annual
budget process, with adoption scheduled for June 2025. In addition, the City Council may
amend the budget throughout the year.
ATTACHMENTS
Attachment A: DRAFT Utilities Advisory Commission FY 2025 – 2026 Workplan
AUTHOR/TITLE:
Kiely Nose, Interim Director of Utilities
Staff: Kaylee Burton, Utilities Administrative Assistant
1 City Council, February 24, 2025, Agenda Item #10;
https://cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=7064&meetingTemplateType=2&comp
iledMeetingDocumentId=13223
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Utilities Advisory Commission
2025-2026 Workplan
Staff Liaison: Kiely Nose, Interim Director of Utilities
Lead Department: Utilities
About the Commission The Utilities Advisory Commission (UAC) is charged with providing advice on long range planning and policy matters, acquisition,
development, and financial review of electric, gas and water resources; joint action projects with other public or private entities
which involve electric, gas or water resources; environmental implications of proposed electric, gas or water utility projects; and
conservation and demand management. Additionally, the UAC is charged with providing advice on the acquisition, development
and financial review of the dark fiber network and wastewater collection utilities. As a highly regulated industry, there may be
matters not listed below that will be presented to the UAC in accordance with current or future (local, state, or federal) legislative
requirements.
The Commission is composed of 7 members.
Terms are for 3 years and commence on the first meeting in April.
See Palo Alto Municipal Code (PAMC) Sections 2.23.010 (Membership), 2.23.030 (Term of Office), 2.23.040 (Officers),
2.23.050 (Purpose and Duties), and 2.23.060 (Meetings).
Current Commissioners •Greg Scharff (Chair)
•Meagan Mauter (Vice Chair)
•Phil Metz
•Rachael Croft
•Robert Phillips
•Utsav Gupta
•Chis Tucher
Mission Statement The purpose of the Utilities Advisory Commission shall be to advise the City Council on present and prospective
long-range planning, policy. major program, and project matters relating to the electric, gas, water, wastewater
collection, fiber optics utilities, and recycled water matters, excluding daily operations.
The Utilities Advisory Commission shall have the following duties:
•Advise the City Council on long-range planning and policy matters pertaining to:
Joint action projects with other public or private entities which involve, affect or impact the utilities;
Environmental aspects and attributes of the utilities;
•Water and energy conservation, energy efficiency, and demand side management; and Recycled water matters not
otherwise addressed in the preceding subparagraphs;
•Review and make recommendations to the City Council on the consistency with adopted and approved plans, policies, and
programs of any major utilities;
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•Formulate and review legislative proposals regarding the utilities, to which the city is a party, in which the city
has an interest, or by which the city may be affected;
•Review the utilities capital improvement programs, operating budgets and related reserves, rates, and the
recycled water program, budget, rate, and thereafter forward any comments and recommendations to the
finance committee or its successor;
•Provide advice upon such other matters as the City Council may from time to time assign.
The Utilities Advisory Commission shall not have the power or authority to cause the expenditure of city funds or to
bind the city to any written, oral, or implied contract.
The Utilities Advisory Commission may, subject to its City Council-approved bylaws and at the discretion of the City
Council, foster and facilitate engagement with the general public, not excluding representatives of commerce and
industry, in regard to the utility matters referred to in subsections above.
Prior Year
Accomplishments
Advanced Heat Pump Water Heater (HPWH) Pilot Program:
-Over 500 customers have installed a heat pump water heater using the City’s rebate, full service, or emergency replacement
program to-date, and the pace of installations is approximately 20% of annual water heater replacements.
Advanced Meter Infrastructure (AMI)
-21,492 gas customers have had completed installs
-18,035 water customers have had completed installs
-21,411 electric customers have had completed installs
Renewable Energy Credit (REC) Exchange Program
-Approved by Council on 12/12/2022 to continue the program and return to the UAC and Council in 2025
-Sold 161,900 PCC1 RECs and purchased 160,000 PCC3 RECs, yielding $10.86 million in net revenue for 2024
Fiber-to-the-Premises (FTTP)
-Began coordinating grid mod project with FTTP
-Identified and began addressing key challenges
-Pilot to align grid mod project with FTTP
-CEQA Initial Study for FTTP
Electric Grid Modernization (Grid Mod)
An Electrification Study was performed by a consultant with the goal of identifying any electric system upgrades needed
across the electric distribution system. The focus of the Study resulted recommendations for upgrades to line transformers,
feeder capacity, increasing the number of switches and connections on the system between feeders and substations, and
upgrading substation equipment.
Staff prepared plans and construction drawings to a Pilot area selected within the Phase 1 boundary, Construction on the
first modernization project is started in Q2 2024 in a 1200-home neighborhood pilot area bounded by Louis, Amarillo, 101,
and Embarcadero. The modernization projects will be coordinated with fiber to the premise (FTTP) construction. To
capitalize on synergies between GridMod and FTTP, a Pilot area combining both GridMod and FTTP project was identified,
and the joint Pilot project boundary was fixed. The GridMod design was contracted with consultant Entrust, and the
construction of the Pilot was started in Q3 of 2024, and completion of the construction work is anticipated at the end of Q2
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2025.As of January 9, 2025, , 60 of 74 poles have been replaced, 51 new transformers have been installed, and the service
to over 500 households in the Pilot area have been prepared and are ready for electrification. Engineering staff has started
the planning and design work for the remainder of the Phase 1 area, which Staff expects the construction of to be
completed by Q4 of 2025.
Sewer System Replacement 31 (SSR31)
-Conducted successful outreach meeting with Barron Square HOA residents who have been impacted by the activity at the
project’s laydown yard. The on-going communication has been effective to keep the Barron Square residents informed.
-The portion of the work requiring 2-lane closure on El Camino Real was performed at night. No more nighttime work is
anticipated on this project, unless unexpected condition dictates.
-Continue with daytime work. The remaining work will be performed on El Camino Real between Fernando and Sheridan and
on Page Mill Road between El Camino Real and Ramons Way.
-Project is currently on track to be completed in May 2024, before Caltrans and County of Santa Clara’s paving projects start.
Water main replacements
9,893 Feet of water main replaced
252 services replaced
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STANDING TOPIC 1:Annual Budget - Rate changes to Water, Gas, Electric, Wastewater collection, and Fiber services.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED / LOCAL LAW /
COUNCIL-APPROVED
The community will have a better
understanding of the rates and why they
are being charged.
Rates are reviewed annually and each rate
change is determined by the COSA reports.
UAC review is in March, FCM review is in
April and CCM approval is in June
Staff time, Legal team review time,
Consultant time to create the COSA report.
Council approval of budget N/A
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
Rates are always a high priority. The change has an impact on the community and economy.N/A N/A
STANDING TOPIC 2:Water Supply: Consider potential future sources of water supply. This includes recycled water, demand management programs, grey water, treatment efforts, and
use of effluent.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED / LOCAL LAW /
COUNCIL-APPROVED
The benefit to the community is to have
ample water source and supply when
needed in the event of a drought or for
basic uses
This is not a single effort or project;
however, a year-round effort
Staff time, Legal team review time,
Consultant time for development of the One
Water Plan which is a holistic 20-year water
portfolio
Council approval of the One Water Plan
which includes adaptable, dynamic, water
supply portfolios.
N/A
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
Having knowledge of where the City's water supply is coming from and how we maintain
that supply is a maintained priority..
N/A N/A
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STANDING TOPIC 3:Electric Supply: Consider updates to the electric supply portfolio and issues relating there to.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED / LOCAL LAW /
COUNCIL-APPROVED
Reliability for customers, health benefits,
and clean energy responsible for the vast
carbon reduction the City has achieved
over the past decade
This is an ongoing regularly monitored
effort and does not have a start or
completion time
Approved budget, staff time, legal review
time, consultants as needed, and
technology
Release of RFP for more renewable
energy supply options in the Integrated
Resource Plan (IRP). Have the IRP near
completion to present to the UAC for
review and approval. Maintaining and
expanding the zero emissions portion of
the portfolio and carbon neutral plan.
N/A
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
The health and well being of the community is a high priority for Council and Utilities N/A N/A
STANDING TOPIC 4:Gas Supply: Consider aspects of the gas supply portfolio and issues relating thereto
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED / LOCAL LAW /
COUNCIL-APPROVED
Gas is a type of energy used to provide
some residences and businesses in Palo
Alto with heat for their facilities and some
cooking appliances.
This is not a single effort or project;
however, a year-round effort
Staff time, Legal team review time,
Consultant time when necessary
Utilities on average are 10% below
PG&E's rates year round
N/A
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
The health and well being of the community is a high priority for Council and Utilities N/A N/A
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STANDING TOPIC 5:Utilities CIP's: Discuss CIP projects.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED / LOCAL LAW /
COUNCIL-APPROVED
There are multiple CIP's throughout the
Utilities, each with their own benefits to the
City and the community from rebuilding
the water reservoirs, repairing and
replacing sewer lines or water mains,
maintaining street lights, building out the
fiber backbone, upgrading the meter
system to upgrading the outage
management system
Utilities has multiple projects in their Council
approved CIP budget. Most of these
projects are multi year based.
Staff time, Legal review time, Procurement
time for setting up contracts, contractors for
work completion
Utilities CIP success is completion of the
project within the timeline and budget that
was approved by Council.
N/A
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
Maintaining quality of life for the community creates the priority for Utilities projects N/A N/A
STANDING TOPIC 6:Reliability, Resiliency and adaptation: Ongoing discussions regarding the reliability and resiliency of the utilities.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED / LOCAL LAW /
COUNCIL-APPROVED
This matter encompasses a number of
situations including but not limited to the
S/CAP program. The benefit of any of the
reliability or resiliency projects is to
support the City and community now and
into the future with reliable, safe
connections, water, electricity, fiber and
natural gas
These programs and projects are year
round and do not have a beginning or an
end. For example the S/CAP is set to
accomplish the goal by 2030
Budget approval, staff time, additional staff,
and some use of consultants
Maintaining a high level of efficient, safe,
economic, and reliable services.
YES
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
The S/CAP is a Council priority and therefore a High priority for the Utilities Advisory
Commission to focus on
N/A N/A
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STANDING TOPIC 7:Legislative Initiatives: The Utility tracks many local, state and federal bills that touch on utilities. Should any new laws, regulations, or ordinances pass during the
year, the UAC may need to discuss the changes.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED / LOCAL LAW /
COUNCIL-APPROVED
Staff tracks the possible changes in laws
and regulations and presents the
proposed changes to the UAC for review
and consideration to the Council.
Legislature meets throughout the year and
possible changes can occur at any point
that effect utilities
Staff time, travel, and legal review time This is a non-measurable project State Mandated
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
N/A The level of priority is based on the particular legislation being proposed and how it
effects the regulated utilities
N/A
STANDING TOPIC 8:Council Driven Initiatives: The UAC will address any matter assigned by the City Council.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED / LOCAL LAW /
COUNCIL-APPROVED
The UAC is made up of a diverse group
with insight of the innerworkings of and
vast knowledge in the utilities arena.
Timeline will be addressed once assigned UAC, Staff and legal review time Council approval of completed task YES
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
Typically when Council requests a review of an item it is considered a priority N/A N/A
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7
1
0
0
Standing Topic 9:
S/CAP Support: Discuss community engagement, technology (current & emerging), finance, and community scaling of S/CAP plans to meet the City’s goals for
sustainability and climate action. This includes electrification efforts, possible code modifications, potential full or partial retirement of the gas distribution system,
and electrification of gas appliances. It also includes permitting and inspection processes for customers wishing to upgrade panels, electrify appliances, or install
solar PV, energy storage, and/or EV charging systems.
BENEFICIAL IMPACTS TIMELINE BENEFICIAL IMPACTS TIMELINE BENEFICIAL IMPACTS
UAC expertise will help the Council S/CAP
Committee make progress on achieving
S/CAP goals with benefits to reducing the
impacts of climate change.
In these areas:
Ongoing support to the S/CAP Committee UAC expertise will help the Council
S/CAP Committee make progress on
achieving S/CAP goals with benefits to
reducing the impacts of climate change.
In these areas:
Ongoing support to the S/CAP
Committee
UAC expertise will help the
Council S/CAP Committee
make progress on achieving
S/CAP goals with benefits to
reducing the impacts of
climate change.
In these areas:
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
Support S/CAP Committee goals to develop plans and improve processes for building
electrification
Discussions of other forms of emissions reduction besides building electrification Support S/CAP Committee
goals to develop plans and
improve processes for building
electrification
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Item No. 5. Page 1 of 5
Utilities Advisory Commission
Supplemental Report
From: Kiely Nose, Interim Director of Utilities
Meeting Date: March 5, 2025
Item Number: 5
Report #:2502-4220
TITLE
Supplemental Information: Review and Recommend Utilities Advisory Commission FY 2025 –
2026 Work Plan for City Council Approval
RECOMMENDATION
Staff recommends the Utilities Advisory Commission (UAC) to review, provide feedback, and
recommend City Council approval of the FY 2025 - 2026 Annual Work Plan.
This supplemental report transmits proposed workplan items submitted by UAC commissioners
subsequent to the release of the original staff report to assist in facilitation of the UAC
discussion and recommended workplan for Council consideration.
BACKGROUND
In accordance with the 2020 City Boards, Commissions, and Committees Handbook, each Board
and Commission should prepare an annual work plan for proposal to the City Council by the
second quarter of the calendar year. The purpose and duty of the UAC is outlined in the City of
Palo Alto Municipal Code Chapter 2.23.050.
“The purpose of the utilities advisory commission shall be to advise the city council on
present and prospective long-range planning and policy and major program and project
matters relating to the electric utility, gas utility, water utility, wastewater collection
utility, fiber optics utility and recycled water matters, excluding daily operations.”
ANALYSIS
The Commission is recommended to consider its purpose as defined in the Palo Alto Municipal
Code, the City Council Priorities, the City Council Priority objectives, and Council approved
workplans and strategic plans as some of the variables when deciding on recommended
workplan items to the work of the Commission for 2025. This will ensure alignment with the
City Council activities and resource allocation. The UAC may add a workplan topic, amend an
existing topic on the draft workplan to address a desired topic more explicitly, and may choose
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Item No. 5. Page 2 of 5
to consider items for future years. As a reminder, the workplan is intended to reflect activities
to be completed in a 12-month period, specifically identifying the UAC role and actions. This
workplan will be forwarded for City Council review and approval by recommendation of the
UAC.
UAC Commissioner Workplan Feedback
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Item No. 5. Page 3 of 5
13. Emergency Preparedness: Prepare CPAU and the Palo Alto community it serves for
emergencies, such as earthquakes, cyber-attacks, wildfires, and floods, in coordination
with Palo Alto’s Office of Emergency Services (OES).
14. Grid Modernization Strategy: successfully address the key issues that will affect the
design and cost of CPAU’s future distribution Grid. Annual update on project.
Proposed Topics and Current Status:
To assist the UAC in finalizing it’s recommended workplan, staff have provided the following
information to assist in identifying any existing alignment with standing UAC workplan topics
and or the current status or schedule of items suggested by various Commissioners.
Title
UAC Standing
Topic Current Status / Schedule
1. Long-Term
Strategy for
CPAU’s Natural
Gas Utility
Topics
8 & 9
Decommissioning of the CPAU natural gas utility is an action
item both in the Council 2025 priority objective and S/CAP
approved workplan and falls under these two standing
topics. Specifically, ‘Share preliminary analysis of strategies
for a physical and financial transition of the gas utility to
relevant policymakers and stakeholders’ is the expected
work for 2025.
2. Feasibility of
Purple Pipe
Expansion &
Establishment of
a Recycled
Water Utility
N/A New Workplan Item
Purple pipe has previously been explored in the Northwest
County Recycled Water Strategic Plan which included a
business plan for a system expansion1 with discussion at the
UAC2 and City Council3 in 2018. Information from this study
was recently updated for use in the One Water Plan. Current
Regional Water Quality Control Plant improvements are
focused on rehabilitation of the over 50-year-old regular
sewage treatment functions.
3. Universal Access N/A New Workplan Item
4. Regional
Collaboration on
Water Supply
N/A Advocacy letters both discussing the One Water Plan
framework and engagement with SFPUC and BAWSCA are
agendized for the March 2025 UAC meeting for
recommendation to City Council.
5. Credit Card Fees N/A New Workplan Item
This topic relates to Standing Topic 1, review of the annual
budget and rate changes for utility services though can be
considered off cycle by the Commission from the typical rate
setting process.
1 Northwest County Recycled Water Strategic Plan https://www.cityofpaloalto.org/files/assets/public/v/1/public-
works/water-quality-control-plant/recycled-water/2021/tm-6.5_30dec2020.pdf
2 UAC October 2018; https://cityofpaloalto.org/civicax/filebank/blobdload.aspx?t=72210.49&BlobID=68055
3 City Council November 2018;
https://cityofpaloalto.org/civicax/filebank/blobdload.aspx?t=72210.49&BlobID=68054
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Item No. 5. Page 4 of 5
Title
UAC Standing
Topic Current Status / Schedule
6. Fiber to the
Premises (FTTP)
Pilot & Phase 1
Topic 1 FTTP is an action item in the Council 2025 priority objectives
‘Complete build-out of fiber-to-the-premises (FTTP) pilot
Phase 1 with grid modernization…and work to establish
internet service provider operations’ in 3rd quarter (Q) of CY
2025. In alignment with the Standing Topic 1, rates for fiber
services are scheduled for UAC review in Q2 of CY 2025.
7. Federal Issues
and
Collaboration
Topic 7 Standing Topic 7 addresses legislative initiatives, tracking
local state and deferral bills that impact utilities operation
and regulations and review of changes needed with the UAC
to the extent needed. These actions support the real time
tracking of issues a recognize alignment with existing
legislative guidelines for City operations as adopted by the
City Council annually. Considering the recent federal
administrative actions, the City Council has taken action to
create a Council ad hoc committee to draft a resolution that
‘underscores the Council’s Commitment to Sustaining Palo
Alto Values and Interests’ in the face of the federal
administration.
8. Data Center
Competitiveness
N/A New Workplan Item
9. Microplastics
and Forever
Chemicals in
Water Supply
and Wastewater
N/A New Workplan Item
As part of the City’s operating activities, testing of
wastewater and water occur in accordance with state and
federal laws and regulations as well as with applicable
permits issued by regulatory agencies. During 2023, the City
tested for PFAS and all results were below reporting limits
and were presented in the City’s 2023 Water Quality
Report.4 During 2022, the State Water Board issued an
order for certain agencies to begin testing for microplastics.5
SFPUC is one of initial agencies required to monitor surface
water for microplastics and staff are waiting for the results
of the state’s investigation.
10.Time of Use
Rates
(Electricity)
Topic 1 In alignment with the Standing Topic 1, rates for electric
utility service pilot time of use rates are scheduled for UAC
review in 2025 including implementation plans and the rates
recommended for feedback and recommendation to the
Finance Committee and City Council.
11.Demand side
management
(DSM)
Topics 2, 3,
4, & 9
Standing Topics 2-4 facilitate discussion of demand side
management of utility commodities. Annually as part of the
2nd quarter Utilities Quarterly Report, the annual DSM report
is prepared and transmitted for the UAC review. In addition,
4 City’s 2023 Water Quality Report https://www.cityofpaloalto.org/files/assets/public/v/1/utilities/water-
quality/pal108cpauwaterannual2023.pdf
5 Water State Board Begin Testing for Microplastics
https://www.waterboards.ca.gov/drinking_water/certlic/drinkingwater/documents/microplastics/rs2022-
0032.pdf
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Item No. 5. Page 5 of 5
Title
UAC Standing
Topic Current Status / Schedule
the 10-year Energy Efficiency goals are scheduled to be
reviewed by the UAC in spring 2025. Discussion of
technologies to advance demand management are included
as part of the Reliability and Resiliency Strategic Plan
reviewed by UAC and approved by Council and part of the
approved S/CAP plan outlined in Standing Topic 9.
12.Stanford
Interconnection
N/A New Workplan Item
The City and Stanford have explored interconnection
between the agencies as recently as January 2021, however,
discussions concluded due to parties unable to reach
agreement on price and terms. Resources were refocused
and have continued to work on establishing a second
transmission corridor with PG&E.
13.Emergency
Preparedness
N/A New Workplan Item
The Office of Emergency Services is updating the City’s
Emergency Operations Plan (EOP) in 2025. The EOP will be
in alignment with the 2023 Santa Clara County
Multijurisdictional Hazard Mitigation Plan. Additionally, two
work initiatives are underway relating to this topic, an audit
by the City Auditor (as provided by Baker Tilly) regarding
wildfire preparedness and the recent wildfire maps as
released by the State of California Fire Marshall. Both are
scheduled to be reviewed by the Policy & Services
Committee and City Council by the conclusion of FY 2025.
14. Grid
Modernization
Strategy
Topics 5 & 6 The significant investments for Grid Modernization capital
improvements - in alignment with activities under Standing
Committee topics 5 and 6, Utilities Capital Improvement
Program and reliability and resiliency activities respectively -
are next scheduled to be reviewed by the UAC in early FY
2026 to support review of financing authorization for
issuance of debt including a project update. Studies recently
reviewed by UAC inform future implementation of grid
management systems to improve situational awareness,
operational efficiency and Distributed Energy Resources (e.g.
rooftop solar, battery storage, and electric vehicles).
ATTACHMENTS
Attachment B: Proposed Topics Submitted by UAC Commissioners
APPROVED BY:
Kiely Nose, Interim Director of Utilities
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Proposed Topic 1:
Long-Term Strategy for CPAU’s Natural Gas Utility - Develop a comprehensive 5–20 year plan to align the gas utility with climate
goals, financial stability, and regulatory changes, while evaluating options for electrification, biogas integration, and long-term
infrastructure strategy.
BENEFICIAL
IMPACTS
TIMELINE RESOURCES
NEEDED
MEASURE OF SUCCESS STATE MANDATED / LOCAL LAW /
COUNCIL-APPROVED
Provides a comprehensive,
future-focused plan for CPAU’s
natural gas utility over the next 5,
10, and 20 years.
Integrates climate impact,
regulatory environment, and
evolving market conditions (e.g.,
supply, building electrification
trends).
Ensures financial stability by
addressing costs, procurement
strategies, tariffs, revenues, and
the utility’s contribution to the
City.
Identifies how best to align the
gas utility with Palo Alto’s
sustainability goals and
community expectations over the
long term.
Short‐Term (6–12 mo.)
Define scope and objectives of the long‐term gas utility strategy.
Gather data and costs on externalities (supply constraints,
regulatory changes, climate impacts, cost of compliance).
Engage stakeholders (residents, businesses, environmental
groups) to identify concerns/goals.
Medium‐Term (12–24 mo.)
Develop draft plan outlining potential pathways (e.g., maintaining
gas utility with partial electrification incentives, exploring advanced
biogas/hydrogen blends, pricing in true cost of gas and its
externalities, or phasing down distribution).
Conduct financial analyses (cost, revenue, rates, capital
investment, utility payment to City) and regulatory feasibility.
Long‐Term (24+ mo.)
Finalize and adopt a formal strategy for the next 5–20 years.
Begin implementing policy, infrastructure, and rate changes as
approved by Council.
Staff analysis
(Utilities, Finance,
Sustainability) and
potential consultants
for policy,
engineering, and
market assessments.
Legal counsel for
evolving regulations
and potential litigation
(e.g., building
electrification
mandates).
Stakeholder outreach
resources for public
engagement.
Completion and Council adoption of
a 5–20 year gas utility strategy.
Clear articulation of how
externalities and climate goals are
addressed (e.g., cost of carbon,
supply reliability, how pricing of gas
rates should be adjusted to reflect
externalities).
Stable or well‐managed utility
finances, including City payment,
without undermining broader climate
goals.
Positive feedback from community
stakeholders on transparency and
alignment with City values.
Gas regulation intersects
with state and federal laws
(CPUC, etc.).
Local ordinances or
building codes may require
revision (Council approval).
Council likely to be
involved if new rate
structures, code changes,
or litigation decisions arise.
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
High Priority, but not urgent—designed for a 2–3 year planning horizon. N/A Likely, if changes to local
ordinances, building codes,
or rate structures are
proposed.
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Proposed Topic 2:Feasibility Study of Purple Pipe Expansion & Establishment of a Recycled Water Utility - Assess the potential for expanding Palo Alto’s
recycled water system
BENEFICIAL
IMPACTS
TIMELINE RESOURCES
NEEDED
MEASURE OF
SUCCESS
STATE MANDATED / LOCAL LAW
/ COUNCIL-APPROVED
Maximizes the City’s
significant capital
investment in the
wastewater
treatment/recycling plant.
Reduces reliance on potable
water by expanding the
purple pipe system and
usage within Palo Alto.
Creates potential for a
Recycled Water Utility to
govern, finance, and
manage distribution
effectively.
Enhances sustainability,
resilience to drought, and
local water independence.
Short‐Term (6–12 mo.)
Map and assess the existing purple pipe infrastructure, including the small system
running down East Bayshore to the golf course and Greer Park.
Quantify the volume of recycled water currently sent to Mountain View vs. local
use.
Initiate a feasibility study addressing technical, regulatory, and financial aspects of
expanding the purple pipe system within Palo Alto.
Medium‐Term (12–24 mo.)
Evaluate costs/benefits of expansion scenarios, including potential revenue
models or cost-sharing agreements.
Benchmark other cities’ successful recycled water programs to explore best
practices and potential governance structures.
Engage stakeholders (residents, businesses, other agencies) on feasible
expansion routes and priorities.
Long‐Term (24+ mo.)
If recommended, establish a formal Recycled Water Utility to govern distribution,
set rates, and manage infrastructure.
Begin phased construction of new pipelines or retrofits based on study findings
and Council approval.
Engineering/Consulting
services for
infrastructure
assessment and
expansion design
Financial analysis to
assess cost recovery,
potential rate
structures, or grants
Legal/regulatory review
to align with state
requirements on
recycled water
Stakeholder outreach
resources for
community
engagement
Completion of feasibility
study with clear
recommendations for
expansion
Increased local recycled
water usage within Palo
Alto, reducing reliance on
potable supply
Viable business model
for a Recycled Water
Utility (if pursued) that
covers O&M costs
Positive feedback from
City Council,
stakeholders, and
regulatory bodies on the
expansion plan
Council approval for capital
investments and new utility
formation.
Subject to state and regional
regulations.
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
High priority due to current, substantial capital investment in recycling plant, to ensure City
maximizes use of its investment. In addition, aligns with City’s sustainability goals. N/A Yes, major capital
expansions may require
formal Council action.
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Proposed Topic 3:Universal Access - Enhance CPAU accessibility beyond ADA compliance to ensure equitable service for all customers.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED / LOCAL
LAW / COUNCIL-
APPROVED
Ensures customers with
disabilities can fully access CPAU
services (billing portal,
communications, facilities).
Goes beyond minimum ADA
compliance to adopt best
practices in universal design.
Builds equity and trust among all
community members.
Short‐Term (3–6 mo.)
Conduct accessibility audit of
CPAU platforms (e.g., billing
portal, website, physical sites).
Launch customer surveys & focus
groups specifically for disabled
customers.
Medium‐Term (6–12 mo.)
Implement identified
improvements (e.g., user interface
changes, alternative format
billing).
Provide staff training on universal
design & inclusive communication.
Long‐Term (12+ mo.)
Ongoing monitoring & periodic
re‐evaluation via user feedback
surveys.
Internal staff time
Possible budget for any identified
changes
Higher user satisfaction among
disabled customers ADA compliance is
federally mandated but
these efforts go beyond to
provide universal access.
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
High priority given equity considerations. N/A May require council policy
changes (e.g., new design
standards).
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Proposed Topic4:Regional Collaboration on Water Supply - Advocate for accurate drought planning, strengthen regional partnerships, and
explore alternative water supply solutions to enhance resiliency, cost efficiency, and long-term water security.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED /
LOCAL LAW /
COUNCIL-
APPROVED
Enhanced drought resiliency &
diversified water supply.
Accurate design drought and cut
back scenarios to advise current
and future planning.
Stronger position in regional
decision‐making.
Potential cost savings via joint
projects.
Short‐Term (6–12 months):
Advocate for regional partners, e.g. BAWSCA and
SFPUC, to provide accurate design drought and
cut back scenarios. Seek to bolster BAWSCA to
advocate for accurate drought planning.
Work with regional partners to identify and study
feasibility of alternative water supplies.
Medium‐Term (12–24 months):
Work with regional partners to communicate to
public potential planning around alternative water
supply.
Staff time for
interagency
coordination
Possible consulting
studies (supply
forecasting, demand
modeling)
Incorporation of Palo Alto’s
interests in regional water
plans.
Tangible progress on
shared infrastructure or
alternative supply
solutions.
Improved drought planning
data.
N/A
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
High priority. BAWSCA has a new CEO/General Manager that the City and UAC
should work with. SFPUC has just begun its own alternative water supply planning
process, with a primary focus on purified water projects. Its recently approved 10-year
capital improvement plan allocates $260 million toward alternative water supply
programs within its $3.16 billion total budget, but much of this planning remains in the
early stages. The UAC recently considered and did not proceed with the city’s One
Water Plan, advising focusing on regional partnership to enhance our understanding
of the drought planning scenarios for future regional and local planning and to seek a
comprehensive regional strategy to alternative water supply.
N/A N/A
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Proposed Topic 5:Credit Card Fees - Implement a fee pass-through to reduce City costs, improve transparency, and allow larger credit card
payments while monitoring customer impact.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED /
LOCAL LAW /
COUNCIL-
APPROVED
Potential $1.2M/year savings for
the Utilities budget by shifting
transaction fees to customers
who choose credit cards.
Encourages cost transparency
and may incentivize lower‐fee
payment methods.
Allow for customers to charge
larger bill amounts (>$5,000) to
their credit cards, as fees are
transparently passed on.
Short‐Term (3–6 months):
Implement updated fee pass-
through structure and billing
system changes.
Develop communication plan for
customers.
Medium‐Term (6–12 months):
Monitor and review impact on
customer satisfaction and
payment behavior.
Billing software updates & staff
training
Customer
communication/outreach
Reduction in City’s
transaction‐fee costs (targeting
$1.2M savings).
Customer acceptance measured
by complaint levels or payment
method shifts.
Minimal negative impact on
delinquency rates.
N/A
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
N/A Lower priority but also low-hanging fruit that can save $1.2 million annually. May require policy
update.
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Proposed Topic 6:Fiber to the Premises (FTTP) – Pilot and Phase 1 - Review and evaluate pilot results, recommend to Council ISP rates, refine
business and operations plan for Phase 1 rollout, and inform decision on further investment after Phase 1.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED /
LOCAL LAW /
COUNCIL-
APPROVED
Enhances high‐speed internet
access for residents &
businesses.
Ensure equitable access to high-
speed and high-quality internet
across the City, its
neighborhoods, and its residents.
Future‐proofs City’s
communications infrastructure.
Short‐Term (6–12 mo.):
Complete pilot, begin marketing,
gather data on take‐rate.
- Medium‐Term (12–24 mo.):
Evaluate pilot results, refine
business and operations plan for
Phase 1 rollout.
Capital investment for fiber
deployment
Marketing budget
Ongoing operations &
maintenance funding
Demonstration of operational
success from pilot.
Meeting or exceeding pilot and
phase 1 goals
Positive customer feedback and
subscription growth.
Sustainable model to
cost‐recovery or revenue.
Likely needs Council
approval for budget
allocations, rate
structures, or bond
financing
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
High priority. The Council has approved a FTTP pilot and phase 1 to
study eventual build-out to the city. In the coming year, the pilot will
be started and studied.
N/A N/A
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Proposed Topic 7:Federal Issues and Collaboration - Monitor federal policy changes, informational item regarding impact, secure critical funding,
advocate for beneficial legislative or regulatory actions to protect City resources, and strengthen federal partnerships.
BENEFICIAL IMPACTS TIMELINE RESOURCES
NEEDED
MEASURE OF SUCCESS STATE MANDATED /
LOCAL LAW /
COUNCIL-
APPROVED
Helps the City mitigate negative
effects from federal policy
changes (e.g., budget cuts,
shifting regulations).
Identifies resources (e.g., federal
grants) that City utilities rely on,
ensuring continuity of funding &
compliance.
Positions the City to advocate
effectively for beneficial regulatory
or legislative changes.
Strengthens relationships with
federal representatives and
agencies.
Short‐Term (3–6 mo.)
Inventory federal resources/programs used by the
City (funding, permits, land, etc.).
Develop risk assessment of potential federal
cost‐cutting impacts.
Identify immediate federal legislative or regulatory
priorities for City advocacy.
Medium‐Term (6–12 mo.)
Engage regularly with federal representatives (e.g.,
staff briefings, letters, visits).
Develop strategies to safeguard critical grants or
programs.
Long‐Term (12+ mo.)
Propose any desired federal law/regulation
changes for long‐term City benefit.
Formalize ongoing mechanism for monitoring and
responding to federal actions.
Staff time to compile
inventories and
coordinate advocacy
Possible outside
lobbyist or legal
counsel for federal
issues
Budget for
travel/meetings in
Washington, D.C. or
regionally
Timely identification of potential
federal funding shortfalls or
policy changes.
Number of successful federal
grants retained or newly secured
despite cost‐cutting.
Positive engagement/feedback
from federal reps on City’s
positions.
Incorporation of City concerns
into relevant legislative
proposals or regulatory
rulemaking.
Council approval might
be required for formal
policy positions or
lobbying expenditures.
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
High priority given the potential budget or regulatory impacts. N/A May require council
policy changes,
including city resolutions
or official stances on
federal issues.
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Proposed Topic 8:Data Center Competitiveness - Review and recommend policies and incentives to attract data centers to Palo Alto
BENEFICIAL IMPACTS TIMELINE RESOURCES
NEEDED
MEASURE OF
SUCCESS
STATE MANDATED /
LOCAL LAW /
COUNCIL-
APPROVED
Potential to attract new data
center developments or
expansions, boosting local
economic activity and job
creation.
Leverages Palo Alto’s carbon-free
energy to market a more
sustainable data center
environment versus competitors.
Increases City revenue streams
(utility sales, property taxes, etc.)
Increased sales may lead to
reduced rates for our customers.
Builds on existing tech reputation
of Palo Alto/Silicon Valley.
Short‐Term (1–3 mo.)
Conduct market analysis comparing Palo Alto’s electricity
rates, real estate availability, permitting processes, and
data center–friendly policies to those of neighboring cities
(e.g., Santa Clara).
Identify key barriers or advantages (e.g., cost
competitiveness, clean energy, land use constraints).
Medium‐Term (3–9 mo.)
Develop targeted policy or rate options to attract data
centers (e.g., special electricity rate packages, expedited
permitting zones).
Collaborate with real estate developers and property
owners to address space constraints or lease structures.
Long‐Term (9+ mo.)
Implement pilot incentive programs or updated rates if
Council-approved.
Monitor outcomes, refine strategies, and continue
marketing Palo Alto’s advantages.
Staff time (economic
development, utilities,
planning) for market
research and policy
review.
Potentially consultant
to assess market if
needed.
Legal counsel if
changes to rates or
zoning require new
ordinances.
Budget for
outreach/marketing
materials.
Clear, data-driven
competitiveness report
identifying Palo Alto’s
position vs. neighbors.
If implemented, new or
expanded data center
developments within city
limits.
Revenue growth from
increased utility sales.
Favorable feedback from
the tech community
regarding Palo Alto’s data
center environment.
Council approval for new
electricity rates or zoning
changes.
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
High priority due to opportunity to compete in exploding data center market due to the
rise of artificial intelligence. N/A Yes, if altering utility rate
structures or
zoning/permitting
processes for data
centers.
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Proposed Topic 9:Microplastics and Forever Chemicals in Water Supply and Wastewater - Assess and mitigate forever chemical (PFAS etc.)
and microplastic contamination in drinking water and wastewater.
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED /
LOCAL LAW /
COUNCIL-
APPROVED
Improved public health and
environmental protection by
studying and reducing PFAS (and
other forever chemicals) and
microplastics in drinking water
and discharged wastewater.
Compliance with California and
federal regulations (keeps the
City ahead of regulatory curves).
Potentially reduced long‐term
infrastructure costs by addressing
contaminants early.
Builds community trust in water
quality.
Short‐Term (6–12 months):
Initiate sampling of wastewater
and water distribution system to
quantify microplastics and PFAS.
Conduct feasibility for solutions,
such as for installing filters on
residential/commercial laundry
machines.
Medium‐Term (12–24 months):
Evaluate pilot programs for
retrofitting or upgrading treatment
processes.
Assess whether plastic-based
service lines and mains contribute
microplastics to the water/soil, and
study alternative pipe materials.
Staff time for feasibility studies &
sampling
Funding for pilot mitigation
projects
Reduction in PFAS/microplastic
levels to target thresholds.
Subject to CA and
potential future federal
regulations on
PFAS/microplastics
May need Council
approval if new local
ordinances or major
capital investments are
required.
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
High priority in determining baseline microplastic and forever
chemical contamination and studying mitigation given increased
awareness of extent of contamination and detrimental health effects.
N/A May require policy
update (e.g., if requiring
certain filters or changing
procurement standards).
Item #5
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Proposed Topic 10:
Time of Use Rates - bring TOU to UAC early to give us a chance to discuss and advise on options before they are rolled out.
Then, once TOU rates are in place, report out on how it is going at least once a year
BENEFICIAL IMPACTS TIMELINE RESOURCES
NEEDED
MEASURE OF SUCCESS STATE MANDATED / LOCAL
LAW / COUNCIL-
APPROVED
•Discuss what are our goals as
a city? Reduce GHG use within
PA? Minimize cost of
electricity? Reduce stress on
grid from vehicle charging?
•How many and what rate
structures would we consider?
•What rate structures are in use
in other comparable areas and
how are they performing?
Staff, Legal, •Suggestions for top level KPIs:
o Fraction or bar chart incorporating all
customer classes: __ signups / __
customers in customer class
o chart: % of customers uptake (cumulative
by quarter by customer class)- this would
reflect performance over time
o chart: % of total PA electricity on TOU
rates (cumulative by quarter)- this would
reflect performance over time
o Measures of GHG reduced / cost saved
(depending on what the goal was)
Cost-of-service
requirements set
forth in the California
Constitution and
applicable statutory
law
HIGH PRIORITY LOWER PRIORITY COUNCIL-
DIRECTED
POLICY
UPDATE
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Proposed Topic 11:Demand side management: annual update and discussion on programs and performance
BENEFICIAL IMPACTS TIMELINE RESOURCES
NEEDED
MEASURE OF SUCCESS STATE MANDATED / LOCAL
LAW / COUNCIL-
APPROVED
•What are the city's goals of demand side
management? Reducing load / water use?
Electrification? Load shifting?
•What are our strategies / programs and
how are they performing? (beyond TOU
rates)
•(this part may overlap with grid mod /
SCAP projects): What technologies does
CPAU recommend to customers to help
with these changes? What are the steps to
determine what these recommendations
will be? How will we communicate them?
(Examples: circuit sharing panels,
batteries, management of vehicle charging,
vehicle to grid)
Staff and Legal •Create KPIs and report against them (in a numeric
form, not in a paragraph description)
•Suggestions for top level KPIs
o Annual electric, gas, and water savings as a
percent of total load
o Pie charts breaking down annual electric and gas
savings by end use as a percent of total energy
savings
o Charts showing historical electric, gas, and water
savings over time
o Charts showing historical adoption of EVs, solar,
and storage over time
HIGH PRIORITY LOWER PRIORITY COUNCIL-
DIRECTED
POLICY
UPDATE
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Proposed Topic 12:CPAU – Stanford Interconnection
BENEFICIAL IMPACTS TIMELINE RESOURCES NEEDED MEASURE OF SUCCESS STATE MANDATED /
LOCAL LAW /
COUNCIL-
APPROVED
Greater grid reliability/resilience if
either Palo Alto’s or Stanford’s
system fails.
Integrated emergency planning
for critical services.
Short‐Term (6–12 mo.):
Feasibility/engineering study on
interconnection points, cost
sharing.
Medium‐Term (12–24 mo.):
Implementation planning,
permitting, construction approach.
Joint technical consultants
Infrastructure investment funding
Coordination team (City &
Stanford)
Successful interconnection or
backup capability in actual or
simulated emergency.
Minimal downtime and rapid
recovery in a crisis.
Positive cost‐benefit compared
to not having interconnection.
Likely requires formal
agreement or MOU
between City and
Stanford.
Council approval for
major infrastructure
investments or
cost‐sharing
arrangements.
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
Stanford and CPAU each currently have only one transmission line.
CPAU has expressed concern over long-term power loss in the event
of an accident at this transmission line (e.g., airplane crash), or
upstream power loss due to disaster. CPAU power supports
residences, businesses, and three major hospitals, including Stanford
Hospital. Stanford has experienced power-loss events due to impacts
to their PG&E transmission line, most recently in March 21, 2023. An
interconnection between the grids will allow for greater grid reliability
and resilience if either Palo Alto’s or Stanford’s system fails.
N/A Possibly (for final
agreements, budget
approvals)
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Proposed Topic 13:CPAU Electrical Emergency Preparedness
BENEFICIAL IMPACTS TIMELINE RESOURCES
NEEDED
MEASURE OF SUCCESS STATE MANDATED /
LOCAL LAW /
COUNCIL-
APPROVED
CPAU emergency preparedness is essential
for the preparedness of the entire Palo Alto
community and a key aspect of CPAU’s
reliability / resilience activities.
This initiative is geared to prepare CPAU
and the Palo Alto community it serves for
emergencies, such as earthquakes, cyber-
attacks, wildfires, and floods, in coordination
with Palo Alto’s Office of Emergency
Services (OES).
2025-2026: Initial
assessment and
coordination with OES. (See
“Measures of Success”)
2027 & ongoing:
Implementation and regular
updating.
2025-2025: CPAU
staff time for
establishing initial
objectives and
planning with OES.
OES staff to work with
CPAU.
1. Determination of the “design emergencies”
to be used as the basis for CPAU
emergency preparedness.
2. Establishment of CPAU’s risk assessment
framework in coordination with OES.
3. Determination of CPAU’s roles and specific
actions in each such emergency.
4. Completion of action planning and
implementation in coordination with OES.
N/A
HIGH PRIORITY LOWER PRIORITY COUNCIL-DIRECTED
POLICY UPDATE
Highly important and urgent.
CPAU emergency preparedness is essential for the preparedness of
the entire Palo Alto community.
CPAU has invested to reinforce water system operation during an
emergency, for example water main upgrading and wells with
emergency power. But CPAU has focused its electrical reliability
efforts only on short-term interruptions. With the risk of earthquakes
and other events that could cause long-term disruption to CPAU’s
electricity delivery, it is essential that we develop equivalent plans for
electrical resilience and CPAU responsibility during a severe
emergency. CPAU needs to develop its emergency preparedness
consistent with the OES “design emergency” in collaboration with
OES.
N/A N/A
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Proposed Topic 14:
CPAU Grid Mod Strategy
BENEFICIAL IMPACTS TIMELINE RESOURCES
NEEDED
MEASURE OF SUCCESS STATE MANDATED
/ LOCAL LAW
/ COUNCIL-
APPROVED
Grid Mod represents an expenditure of $300M+.
Multiple technologies and other exogenous factors
will impact distribution grid design and
implementation in major ways. To address those
issues, the Grid Mod plan needs to include:
1. The goals that grid modernization is
intended to achieve and the strategy for
achieving those goals.
2. A detailed plan and roadmap articulating
what will be done, and when: Anticipated
“external environment” impacts over the
life of the plan; key milestones and
decision points for actions and
expenditures; which technologies will be
accommodated and when; estimated
capital and operating costs; and
opportunities to mitigate, reduce, or delay
expenditures.
With major Grid Mod
expenditures already
underway, CPAU
needs an intensive
strategic planning
focus starting
immediately and
continuing from 2025
through 2027.
2025-2027: CPAU
staff time and
external experts to
map out the CPAU
distribution grid
evolution and
impacts of key
exogenous factors.
(See “Measures of
Success.)
To succeed, Grid Mod must successfully address the key
issues that will affect the design and cost of CPAU’s future
distribution Grid:
1.New technologies: Technological advances mean
that the future grid will not be an incremental
extension of today’s grid. So, Grid Mod needs to
anticipate and incorporate those changes, for
example, local distributed energy resources (DER)
such as solar + storage; microgrids; active demand
side management (DSM); electric vehicles (EVs), and
advanced metering (AMI).
2.SCAP: How will the grid deliver the electricity called
for by the City’s SCAP plan?
3.Resilience: When the grid is operating (reliability, up
time, repairability) and during emergencies (as CPAU
does for water).
4.Other exogenous factors: Especially energy
supply, future regulations, and shifts in demand, such
as proliferation of large data centers.
N/A
HIGH PRIORITY LOWER PRIORITY COUNCIL-
DIRECTED
POLICY
UPDATE
Highly important and urgent.
With a planned expenditure of $300M+ Grid Mod is CPAU’s largest
capital investment. To succeed and employ this capital effectively
the Grid Mod plan and implementation must explicitly address and
incorporate key technological and other exogenous factors.
N/A N/A
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Staff Report: 2411- 4066 – Page 1 of 51
Utilities Advisory Commission
Staff Report
From: Kiely Nose, Interim Director of Utilities
Lead Department: Utilities
Meeting Date: April 2, 2025
Staff Report: 2411- 4066
TITLE
Information Report: Utilities Quarterly Report for FY25-Q2
RECOMMENDATION
This is an informational report, and no action is requested.
EXECUTIVE SUMMARY
This report has been prepared to keep the Utilities Advisory Commission (UAC) apprised of the major issues that are facing
the water, gas, electric, wastewater collection and fiber utilities including legislative/regulatory issues, utility-related
capital improvement programs, operations, reliability impact measures and a utility financial summary. This updated
report includes the annual Demand Side Management Report as an attachment. The UAC will be provided copies of a
separate quarterly climate report containing information about greenhouse gas reduction programs such as electric
vehicle charger installations and heat pump water heater replacements. Items of special interest in this report are
summarized below:
Vacancies and Staffing – Appendix B
The Utilities Department has 51 vacant positions out of 269 authorized positions or a 19% vacancy rate at the end
of December 2024 compared to 48 vacancies or 18% in September 2024.
Utilities is training two new HR Liaisons and is receiving additional support from the Human Resources Department
to fill the vacancies. Forty of the 51 positions are in active phases of recruitment (planning, job posting, skills
assessment, interviews, and offers).
Electric Utility:
Supply cost for FY 2025 is currently projected to be $76.7 M, which is in line with the budgeted amount. (Section
1.1.1)
Hydroelectric generation is expected to be at average levels this year. (Section 1.1.2)
Utilities staff has tentatively expressed an interest in one standalone battery energy storage system (BESS) and
one standalone solar project. (Section 1.1.3)
Electric sales volumes through Q2 were 8.6% higher than forecasted, driven by new data center load and increased
summer cooling. (Section 1.4.1)
Gas Utility:
Gas prices have remained low and stable. (Section 2.2)
One gas main replacement project is in progress, and one is in the design stage. (Section 2.2)
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Staff Report: 2411- 4066 – Page 2 of 51
Gas sales through Q2 were 18.4% lower than forecasted due to a late start to the heating season. (Section 2.4.1)
Water Utility:
As of December 1, precipitation at the Hetch Hetchy weather station was about 114% of median. (Section 3.1)
Water sales through Q2 were close to the forecast. (Section 3.4.1)
Wastewater Utility:
The City is in the process of developing an invitation for bids to contract for a three-year program to inspect sanitary
sewer mains using cameras and another for rehabilitating or replacing the sewer lines that run from homes or
businesses to the sewer mains. (Section 4.2).
Actual wastewater sales revenues through Q2 are tracking with the budget. (Section 4.3.1)
Fiber Utility:
The build of the fiber hut is completed. The City expects delivery of the hut to the Colorado power station in April,
after approval of the building permit and preparation of the hut site including pouring of the padmount,
substructure work for power and fiber, and final inspection.
The contract for the operating support system and business support system (OSS/BSS) software is in progress.
The OSS/BSS is the customer portal and utility operating system for customer sign-up, billing, scheduling, and Palo
Alto Fiber internet provisioning.
The City is recruiting for a Fiber Systems Manager to lead the fiber network expansion by integrating the existing
dark fiber backbone (where necessary) with the building of fiber-to-the-premises and new fiber backbone.
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Staff Report: 2411- 4066 – Page 3 of 51
OVERVIEW
Utilities Quarterly Report
FY 2025-Q2
Fiscal Year 2023
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1 ELECTRIC UTILITY.....................................................................................................................................................................8
1.1 ELECTRICITY SUPPLY AND TRANSMISSION ...........................................................................................................................................8
1.1.1 Forecasted Supply Costs...................................................................................................................................................8
1.1.2 Hydroelectric Conditions..................................................................................................................................................9
1.1.3 Renewable Energy Procurement......................................................................................................................................9
1.2 CAPITAL IMPROVEMENT PLAN STATUS ...............................................................................................................................................9
1.3 RELIABILITY ................................................................................................................................................................................10
1.4 FINANCIAL HEALTH ......................................................................................................................................................................11
1.4.1 Sales Forecasts vs. Actuals.............................................................................................................................................11
1.4.2 Financial Position...........................................................................................................................................................12
2.1 GAS SUPPLY AND TRANSMISSION ....................................................................................................................................................13
2.1.1 Actual and Forecasted Supply Costs ..............................................................................................................................14
2.2 CAPITAL IMPROVEMENT PLAN STATUS .............................................................................................................................................14
2.3 RELIABILITY ................................................................................................................................................................................14
2.4 FINANCIAL HEALTH ......................................................................................................................................................................15
2.4.1 Sales Forecasts vs. Actuals.............................................................................................................................................15
2.4.2 Financial Position...........................................................................................................................................................16
3.1 WATER SUPPLY AND TRANSMISSION ...............................................................................................................................................17
3.2 CAPITAL IMPROVEMENT PLAN STATUS .............................................................................................................................................19
3.3 RELIABILITY ................................................................................................................................................................................19
3.4 FINANCIAL HEALTH ......................................................................................................................................................................19
3.4.1 Sales Forecasts vs. Actuals.............................................................................................................................................19
3.4.2 Financial Position...........................................................................................................................................................20
4.1 WASTEWATER TREATMENT UPDATES AND CAPITAL PLANNING STATUS ..................................................................................................21
4.1.1 Treatment Cost Trends...................................................................................................................................................21
4.1.2 Regional Water Quality Control Plant Capital Planning Status .....................................................................................23
4.2 COLLECTION SYSTEM CAPITAL IMPROVEMENT PLAN STATUS ................................................................................................................23
4.3 FINANCIAL HEALTH ......................................................................................................................................................................24
4.3.1 Sales Forecasts vs. Actuals.............................................................................................................................................24
4.3.2 Financial Position...........................................................................................................................................................25
5.1 FIBER UTILITY STRATEGIC PLANNING ...............................................................................................................................................26
5.2 CAPITAL IMPROVEMENT PLAN STATUS .............................................................................................................................................26
5.3 RELIABILITY ................................................................................................................................................................................27
5.4 FINANCIAL HEALTH ......................................................................................................................................................................27
5.4.1 Fiber Sales......................................................................................................................................................................27
5.4.2 Financial Position...........................................................................................................................................................27
7.1 STATE LEGISLATIVE ACTIVITY ..........................................................................................................................................................30
7.2 STATE REGULATORY ACTIVITY ........................................................................................................................................................30
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Staff Report: 2411- 4066 – Page 5 of 51
8.1 OVERVIEW OF HEDGING PROGRAMS ...............................................................................................................................................32
8.2 OVERVIEW OF ENERGY RISK MANAGEMENT PROGRAM.......................................................................................................................32
8.3 FORWARD DEALS.........................................................................................................................................................................32
8.4 ELECTRIC MARKET EXPOSURE ........................................................................................................................................................33
8.5 TRANSACTION COMPLIANCE ..........................................................................................................................................................33
APPENDIX C: PALOALTOGREEN GAS PROGRAM.............................................................................................................................34
9 APPENDIX B: STAFFING AND VACANCIES...............................................................................................................................36
10 APPENDIX D: WASTEWATER UTILITY ANNUAL INFRASTRUCTURE MAINTENANCE AND REPLACEMENT REPORT ................37
11 APPENDIX E: FISCAL YEAR 2024 DEMAND SIDE MANAGEMENT REPORT............................................................................42
11.1 EXECUTIVE SUMMARY ..................................................................................................................................................................42
11.1.1 Summary Goals and Achievements................................................................................................................................42
11.2 ELECTRIC EFFICIENCY ....................................................................................................................................................................43
11.3 GAS EFFICIENCY AND ELECTRIFICATION ............................................................................................................................................45
11.4 WATER EFFICIENCY ......................................................................................................................................................................47
11.5 ELECTRIC VEHICLES ......................................................................................................................................................................48
11.6 SOLAR AND STORAGE ...................................................................................................................................................................50
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Figures
FIGURE 1: FY 2025 Q2 FINANCIAL PLAN SUPPLY COST FORECAST VS. ACTUALS .........................................................................................................7
FIGURE 2: HYDRO GENERATION: FY 2025-2027 ACTUALS & PROJECTIONS (GWH)...................................................................................................8
FIGURE 3: ELECTRIC OUTAGE RELIABILITY, FY 2018 TO FY 2022............................................................................................................................9
FIGURE 4: ELECTRIC OUTAGE RELIABILITY, FY 2023 TO FY 2025..........................................................................................................................10
FIGURE 5: ELECTRIC SALES VOLUME (KWH), UP TO FY 2025-Q2..........................................................................................................................10
FIGURE 6: ELECTRIC SALES REVENUE ($), UP TO FY 2025-Q2 ..............................................................................................................................11
FIGURE 7: PALO ALTO GAS COMMODITY RATES .................................................................................................................................................12
FIGURE 8: GAS SUPPLY COSTS ($), ACTUAL VS BUDGET, UP TO FY2025-Q2...........................................................................................................13
FIGURE 9: GAS SERVICE INTERRUPTIONS, FY 2024 TO FY 2025............................................................................................................................14
FIGURE 10: GAS SALES VOLUME (THERMS), UP TO FY2025-Q2...........................................................................................................................14
FIGURE 11: GAS SALES REVENUE ($), UP TO FY 2025-Q2...................................................................................................................................15
FIGURE 12: HETCH HETCHY PRECIPITATION INDEX ..............................................................................................................................................17
FIGURE 13: WATER AVAILABLE TO THE SFPUC..................................................................................................................................................17
FIGURE 14: WATER SERVICE INTERRUPTIONS, FY 2024 TO FY 2025.....................................................................................................................18
FIGURE 15: WATER SALES VOLUME (CCF), UP TO FY 2025-Q2...........................................................................................................................19
FIGURE 16: WATER SALES REVENUE ($), UP TO FY 2025-Q2...............................................................................................................................19
FIGURE 17: PALO ALTO’S SHARE OF ESTIMATED WASTEWATER TREATMENT EXPENSES (PROJECTION AND PLANNED CIP)................................................21
FIGURE 18: CURRENT RWQCP CAPITAL WORK IN-PROGRESS (BASED ON NOVEMBER 2024 PARTNERS MEETING) ........................................................22
FIGURE 19: WASTEWATER SALES REVENUE ($), UP TO FY 2025-Q2.....................................................................................................................24
FIGURE 20: ELECTRIC RESOURCE ADEQUACY DEALS.............................................................................................................................................31
FIGURE 21: ELECTRIC ENERGY DEALS ................................................................................................................................................................32
FIGURE 22: ELECTRIC LOAD RESOURCE BALANCE, FY 2025 - 2027.......................................................................................................................32
FIGURE 23: OFFSET PORTFOLIO COMPOSITION ..................................................................................................................................................33
FIGURE 24: OFFSET PROJECT DESCRIPTIONS ......................................................................................................................................................34
FIGURE 25:UTILITIES VACANCIES AND RECRUITMENTS BY DIVISION, AS OF Q2 FY 2025 ..............................................................................................35
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1 Electric Utility
The City’s electric utility serves all residential and non-residential electric demands in Palo Alto at a lower cost than PG&E
in surrounding communities. Its electric supply portfolio is 100% carbon neutral. The City maintains and operates an
electric distribution system but does not operate any transmission lines or any generating capacity on its own. Instead,
the City belongs to Northern California Power Agency (NCPA) which operates its Calaveras hydroelectric generating plant
and provides power scheduling services for its other generating resources. This carbon free power is supplied through
power purchase agreements with various generation operators.
1.1 Electricity Supply and Transmission
Below is an update on electricity supply and transmission services.
1.1.1 Forecasted Supply Costs
The electric net supply cost for FY 2025 is currently projected to be $76.7 M, which represents a 0.4% decrease from the
Adopted Budget level of $77.0 M. For FY 2026, electric net supply cost is projected to increase to $88.6 M, with the change
primarily due to decreases in Resource Adequacy (RA) and Renewable Energy Credit (REC) sales revenue, which are driven
by market prices for those two products coming down. During Q2 of FY 2025, net supply cost was about $0.5 M higher
than budget, driven mainly by no surplus energy revenue and no credit from contract surplus energy.
Figure 1: FY 2025 Q2 Financial Plan Supply Cost Forecast vs. Actuals
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1.1.2 Hydroelectric Conditions
The City receives power from two hydroelectric projects, the Calaveras project and the Western Base Resource contract
for federal hydropower from the Central Valley Project.1 The watershed for Western hydropower is primarily in the
northern end of California, while the watershed for the Calaveras project is in the Central Sierras.
Following the wet water year of 2023 to 2024, reservoir levels across the state began this water year at above average
levels. After an exceptionally dry January, the Northern Sierras saw better than average conditions in February, while the
Central Sierras saw roughly average conditions for the month. For the water year to date, as of March 12th, precipitation
and snowpack levels are about 10-20% above average levels in Northern California, while they are about 20-30% below
average in Central California. However, reservoirs across the state remain slightly fuller than average for this time of year.
As a result of these conditions, hydro generation levels are projected to be roughly average this fiscal year and slightly
above average the following two years, with total output of about 106% of the long-term average level for FY 2025 through
FY 2027.
Figure 2: Hydro Generation: FY 2025-2027 Actuals & Projections (GWh)
After evaluating all of the proposals received under NCPA’s Request for Proposals (RFP) for new renewable energy and
storage projects2, Utilities staff has tentatively expressed an interest in one standalone battery energy storage system
(BESS) and one standalone solar project. NCPA staff is in the midst of contract negotiations with these two suppliers, and
both sets of discussions are progressing quickly. If these negotiations conclude successfully, staff will present these
contracts to the UAC and City Council for review and approval.
1.2 Capital Improvement Plan Status
The following capital projects are currently in progress or have been recently completed:
EL-17001 (East Meadow Circles 4/12kV Conversion)
This project is scheduled to be completed in several phases. Phase 1 is completed. Phase 2 engineering design is
nearly completed and under review. Phase 2 construction will be completed June 2025.
EL-10006 (Rebuild Underground 24)
This project is in the design phase and scheduled to be completed in April 2025. Construction will be completed
by December 2025.
EL-16000 (Rebuild Underground 26)
1 The Calaveras project is a hydropower project located in Calaveras County that is maintained and operated by the Northern California Power Agency
on behalf of the City and other project participants. The City is also one of several public entities with contracts with the Western Area Power
Administration for “Base Resource” electricity, which is the hydroelectric power available from the federal government’s Central Valley Project
(operated by the Bureau of Reclamation) after accounting for power used for Central Valley Project operations and power delivered to certain
“preference” customers.
2 NCPA’s RFP yielded a total of 29 proposals – nine for standalone solar projects, nine for standalone battery energy storage systems (BESS), and 11
for solar-plus-storage projects.
F F F
C 8 9 1
W 3 3 2
T 3 4 4
%1 1 1
L 3 3 3
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The engineering design for this project is currently in progress. The project will be completed in multiple phases
and will take additional years to complete. All engineering design phases are expected to be completed by Dec
2025. Construction will be completed by summer 2026.
EL-19004 (Wood Pole Replacement)
CPAU staff and contract consultants are continuously working on pole replacement designs for construction.
Replacement of poles in the Grid Modernization – Pilot area is the top priority.
EL-16003 (Substation Physical Security).
This project is scheduled to be completed in two phases. Substation Security lighting and camera contract was
awarded in June 2022. The installation for the first phase was completed for 7 of the 9 substations in
December 2024. The bid package for the 2nd phase and final two substations is being prepared for solicitation.
Construction to be completed by summer 2026.
EL-17002 (Substation 60kV Breaker Replacement)
This project funds the purchase and replacement of both 60kV and 12kV substation circuit breakers that are
reaching the end of their useful life expectancy. Council approved the purchase request for the sixteen 12KV
circuit breakers and seven 60kV breakers. The installation of the 12kV breakers is complete. The project to
purchase the seven 60KV breakers was approved by City Council on May 20, 2024. The engineering design and
installation of the 60kV breakers will begin in FY 2025 and be completed in FY 2026.
EL-21001 (Foothills Rebuild)
This project will rebuild the approximately 11 miles of overhead line in Foothills Park, as necessary to mitigate the
possibility of wildfire due to overhead electric lines. Staff has completed 7,000 feet of substructure work and
design which will eliminate the corresponding 26 poles. Substructure for Phase 1 was completed in Spring 2022
and the substructure for Phase 2 was completed in June 2023. Phase 3 construction is 73% completed. Phase 4
construction is 55% completed. Phase 5 substructure installation along Arastradero road is 53% completed.
Phases 3, 4, and 5 are currently in progress, weather permitting.
EL-02011 (Electric Utility Geographic Information System (GIS))
The project scope includes on-going maintenance/technical support of the existing GIS system and
implementation of the new GIS platform, ESRI.
EL-24000 (Grid Modernization)
Engineering design and construction is in progress. Out of the 75 poles targeted for replacement in the Grid
Modernization Pilot area, 65 (73%) have been replaced, with the remaining 10 poles slated for replacement by
March 2025. Additionally, 563 (62%) of the 908 homes in the Pilot area are ready for electrification, with another
345 homes in line to be connected to the upgraded infrastructure by the end of April 2025.
1.3 Reliability
CPAU tracks electric outages. A summary chart of these outages can be found below.
Figure 3: Electric Outage Reliability, FY 2018 to FY 2022
Outage Reliability FY18 FY19 FY20 FY21 FY22
System Average Interruption Duration Index (SAIDI)3 76.28 137.54 72.85 94.22 18.93
System Average Interruption Frequency Index (SAIFI)4 0.51 1.15 0.55 0.90 0.23
Customer Average Interruption Duration Index (CAIDI)5 150.26 119.99 131.97 104.78 81.91
3 System Average Interruption Duration Index (SAIDI) - Measure of the total duration of an interruption for the average customer during a given time
frame. SAIDI = (Sum of Customer Minutes Interrupted) / (Total Customers Served)
4 System Average Interruption Frequency Index (SAIFI) - the average number of times a customer will experience an interruption during a given time
frame. SAIFI = (Total Customers Interrupted) / (Total Customers Served)
5 Customer Average Interruption Duration Index (CAIDI) - the average time to restore service. CAIDI = (Sum of Customer Minutes Interrupted) / (Total
Customers Interrupted)
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Figure 4: Electric Outage Reliability, FY 2023 to FY 2025
FY 2023Outage Reliability Q1 Q2 Q3 Q4 Annual
System Average Interruption Duration Index (SAIDI)3 81.69 7.38 111.90 1.09 198.60
System Average Interruption Frequency Index (SAIFI)4 0.61 0.04 1.00 0.01 1.64
Customer Average Interruption Duration Index (CAIDI)5 134.77 190.12 110.80 121.48 121.15
FY 2024Outage Reliability Q1 Q2 Q3 Q4 Annual
System Average Interruption Duration Index (SAIDI)3 n/a 37.75 67.03 16.01 120.80
System Average Interruption Frequency Index (SAIFI)4
n/a 0.18 0.36 0.19 0.73
Customer Average Interruption Duration Index (CAIDI)5 n/a 213.82 183.33 83.76 164.73
FY 2025Outage Reliability Q1 Q2 Q3 Q4 Annual
System Average Interruption Duration Index (SAIDI)3 42.76 8.88
System Average Interruption Frequency Index (SAIFI)4 0.25 0.07
Customer Average Interruption Duration Index (CAIDI)5 170.21 122.17
1.4 Financial Health
Below is a summary of the financial position for the electric utility.
1.4.1 Sales Forecasts vs. Actuals
Actual electric sales volumes in Q2 of FY 2025 were 8.6% higher than forecasted, driven by new data center load. As a
result, actual sales revenues exceeded the FY 2025 Financial Plan by 11.3%. The total FY 2025 budget electric sales volume
is 810,615 MWh and the total budget revenue is $169.3 M.
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Figure 6: Electric Sales Revenue ($), up to FY 2025-Q2
1.4.2 Financial Position
The Electric Operations Reserves FY 2024 is at $32.3 million, below the target of $44 million, but above the minimum
guideline of $30.7 million. In June 2024, Council approved the FY 2025 Electric Utility Financial Plan6 , that approved a
residential system average rate increase of 9% and a transfer of $17 million from the Electric Operations Reserve to the
Hydroelectric Stabilization reserve. This transfer was completed in FY 2024 and will enhance the utility's ability to manage
supply cost volatility in the future. Staff will provide financial forecast projections in spring 2025.
6 Staff Report 2404-2842, Attachment D, Exhibit 2: https://www.cityofpaloalto.org/files/assets/public/v/2/agendas-minutes-reports/reports/city-
manager-reports-cmrs/attachments/2024-rates/electric-utility-financial-plan-fy25.pdf
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2 Gas Utility
The City’s gas utility serves all residential and non-residential gas demand in Palo Alto. The City maintains and operates a
system of low-pressure gas lines for delivering gas but does not operate any transmission lines. Costs for the gas utility
are split approximately two thirds for the operation, maintenance, and capital improvement and one third for the cost of
the gas commodity, PG&E gas transmission, compliance with the State’s Cap and Trade Program and the City’s Carbon
Neutral Gas Program.
2.1 Gas Supply and Transmission
After experiencing a notable price spike during winter 2022-2023, natural gas prices have seen a significant decline,
returning to more typical ranges. This shift can be attributed to several factors, including milder temperatures and above
average gas storage levels nationwide. The combination of these factors has put downward pressure on natural gas prices,
and we do not expect an extreme price spike to occur in the near future. The chart below shows Palo Alto’s gas commodity
rates from July 2021 through December 2024.
Figure 7: Palo Alto Gas Commodity Rates
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2.1.1 Actual and Forecasted Supply Costs
Actual supply costs were approximately 22% lower than budgeted in the FY 2025 Financial Plan. This variance was primarily
driven by historically low natural gas prices, which remained well below initial expectations for more typical market
conditions. The total FY 2025 gas supply cost is $19.7 M.
Figure 8: Gas Supply Costs ($), Actual vs Budget, up to FY2025-Q2
2.2 Capital Improvement Plan Status
The following capital projects are currently in progress:
GS-14003 – GMR 24B (Gas Main Replacement 24B)
The GMR 24B project construction has started. Gas pipelines on University Avenue from Webster Street to Hwy
101 and surrounding streets, as well as Geng Road and Town & Country Village, are scheduled to be replaced.
Construction on University Avenue is completed from Hwy 101 to Fulton Street, Geng Road area, and Town &
Country Village. Construction is continuing on University Avenue from Fulton Street to Webster Street, Byron Street
from University Avenue to Hamilton Avenue and on Middlefield Road from Lytton Avenue to Hamilton Avenue.
Construction is anticipated to be completed in April 2025.
GS-15000 – GMR 25 (Gas Main Replacement 25)
The GMR 25 design drawings are being finalized and will include the replacement of pipes on Ross Road from
Colorado Avenue to East Meadow Drive and surrounding streets, as well as North and Southampton Drive and
surrounding streets, and Walter Hays Drive and surrounding streets. The project is expected to replace
approximately 26,000 linear feet of gas mains as full federal grant funding was approved. The City received a
preliminary approval for a $16.5 million grant from the Pipeline and Hazardous Material Safety Administration
(PHMSA) for this project. The City has signed the grant agreement and is currently waiting for PHMSA to sign the
agreement. PHMSA is a federal agency, subject to the direction of the current federal administration. Construction
is anticipated to begin in FY26 due to federal grant funding requirements.
2.3 Reliability
The City of Palo Alto tracks all gas service interruptions. A summary chart of these interruptions can be found below. Gas
service interruptions are usually due to repairs of broken or damaged gas services and mains. This kind of damage is often
caused by excavation by outside parties digging in the City. In FY25 Q1, the City recorded higher numbers in gas service
interruption tracking due to the division allocating more resources to resolve existing gas leaks. These leaks are small and
are monitored, however expected changes in gas legislation will require them to be resolved more quickly. The gas division
has been proactively working to meet upcoming compliance goals before the new rules go into effect.
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Figure 9: Gas Service Interruptions, FY 2024 to FY 2025
FY 2024 FY 2025
Gas Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Number of Breaks 5 1 5 6 13 7
Total Minutes 540 120 570 270 1860 1205
Customers
Affected 51 1 41 14 135 48
2.4 Financial Health
Below is a summary of the financial position for the gas utility.
2.4.1 Sales Forecasts vs. Actuals
Actual gas sales volumes in Q2 of FY 2025 were approximately 18.4% below forecast, while actual sales revenues were
20.9% lower than budgeted in the FY 2025 Financial Plan. The decline was primarily driven by reduced heating demand
from residential customers due to a delayed onset of winter, resulting in an extended period of warmer-than-normal
weather. The total FY 2025 budget gas sales volume was 27.4 M therms, and the total revenue was $67.1 M.
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Figure 11: Gas Sales Revenue ($), up to FY 2025-Q2
2.4.2 Financial Position
The FY 2024 ending Operations Reserve balance for the Gas Utility was $4.2 million, which is below the minimum guideline
of $9.1 million and below the short-term risk assessment value of $5.3 million. This was due to one-time expense items
deferred from FY 2023 to FY 2024, such as carbon offset purchases and Cap and Trade revenue transfers, together with
the impact on reserves from the unprecedented gas price spike in FY 2023. In June 2024, Council approved the FY 2025
Gas Utility Financial Plan7 that included a 12.5% increase in gas rates in FY 2025 to gradually restore reserves to within
guideline levels and cover rising costs. Staff will provide financial forecast projections in spring 2025.
7 Staff Report 2404-2842, Attachment C, Exhibit 1: https://www.cityofpaloalto.org/files/assets/public/v/2/agendas-minutes-reports/reports/city-
manager-reports-cmrs/attachments/2024-rates/gas-financial-plan-fy25.pdf
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3 Water Utility
The Water Utility serves water to virtually all Palo Alto residential and non-residential customers. All potable water in the
City is from the San Francisco Public Utilities Commission (SFPUC) Hetch Hetchy Water System. This system delivers high
quality water from the Sierra Nevada and uses no pumping to deliver water to the City. Palo Alto uses a small amount of
recycled water for irrigation of the Municipal Golf Course and a few other sites near the Regional Water Quality Control
Plant. The City also maintains a system of reservoirs and wells that enable Palo Alto to serve water during an interruption
of the Hetch Hetchy system. Costs for the Water Utility are split approximately half for the operation, maintenance and
periodic replacement of Palo Alto’s water system and half for the costs of the water purchased.
3.1 Water Supply and Transmission
Shown in the figure below, cumulative Hetch Hetchy Weather Station precipitation for October 2024 through January
2025 was 62% of median. Storms in the month of February should slightly improve this statistic. As of March 3, 2025, the
Regional Water System total storage operated by the San Francisco Public Utilities Commission (SFPUC) was at 87.9% of
maximum storage and Water Bank was at 98.1% of maximum.
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Figure 12: Hetch Hetchy Precipitation Index
The figure below shows water available to the Regional Water System through the first five months of the water year. As
shown, only amounts greater than Modesto Irrigation District’s and Turlock Irrigation District’s senior water rights are
available to the SFPUC and its 26 Wholesale customers, including Palo Alto.
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3.2 Capital Improvement Plan Status
The following capital projects are currently in progress:
WS-15002 – WMR 29 (Water Main Replacement 29)
The WMR 29 project will replace approximately 8,000 linear feet of water main on Park Boulevard from Mariposa
Avenue to Lambert Avenue, on College Avenue from Park Boulevard to El Camino Real, and on Birch Street from
College Avenue to Sherman Avenue. The project started in November 2023 and was completed in September
2024.
WS-16001 – WMR 30 (Water Main Replacement 30)
The WMR 30 project is currently in the design phase and will replace approximately 4,500 linear feet of water main
on Rinconada Avenue, Stanford Avenue, and Towley Way. The anticipated project construction start date is in
January 2026.
The City of Palo Alto tracks all water service interruptions. A summary chart of these interruptions can be found below.
Water service interruptions are usually due to repairs of broken or damaged water services and mains.
Figure 14: Water Service Interruptions, FY 2024 to FY 2025
FY 2024 FY 2025WaterQ1Q2Q3Q4Q1Q2Q3 Q4
Number of Breaks 8 9 8 6 8 7
Combined Minutes 1086 880 1230 475 510 1250
Customers Affected 147 96 164 75 127 99
Below is a summary of the financial position for the water utility.
3.4.1 Sales Forecasts vs. Actuals
Actual water sales volumes in FY 2025 Q2 were about 6.9% higher than forecasted, and actual water sales revenues were
about 1.1% higher than budgeted in the FY 2025 Financial Plan, which aligns with the anticipated recovery in water usage
following periods of drought. The total FY 2025 budget water sales volume was 4.2 M CCF, and the total revenue was
$52.9 M.
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Figure 15: Water Sales Volume (CCF), up to FY 2025-Q2
Figure 16: Water Sales Revenue ($), up to FY 2025-Q2
3.4.2 Financial Position
At the end of FY 2024, the Water Operations Reserve balance was $7.1 million, which is below the minimum guideline
range of $8.4 million. Additionally, the Rate Stabilization Reserve had $4 million remaining at the end of FY 2024. In June
2024, Council approved the FY 2025 Water Utility Financial Plan8, which approved a 9.5% rate increase in FY 2025 to pay
for rising costs and offset decreased sales revenues. Staff provided an updated financial forecast projection to the UAC in
March 2025 (Staff Report 2502-41939).
8 Staff Report 2404-2842, Attachment B, Exhibit 1: https://www.cityofpaloalto.org/files/assets/public/v/1/agendas-minutes-reports/reports/city-
manager-reports-cmrs/attachments/2024-rates/water-financial-plan-fy25.pdf
9 Staff Report 2502-4193: https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=61753
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4 Wastewater Utility
The Wastewater Utility includes the system of sewer pipes that collect and transport wastewater to the Regional Water
Quality Control Plant (RWQCP) operated by the City of Palo Alto under a partnership agreement with several surrounding
communities, as well as Palo Alto’s share of the cost of operating the RWQCP. The RWQCP provides treatment and disposal
of wastewater for Palo Alto. Costs for the Wastewater Utility are split approximately half for the operation, maintenance
and periodic replacement of Palo Alto’s sewer collection system and half for the costs of wastewater treatment at the
RWQCP.
4.1 Wastewater Treatment Updates and Capital Planning Status
The RWQCP, operated by Palo Alto's Public Works Department, provides wastewater treatment to Palo Alto, Mountain
View, Stanford, Los Altos, East Palo Alto, and Los Altos Hills. The Palo Alto Wastewater Collection Utility contributes about
32% of the costs (projected for FY 2025). Capital costs, driven by necessary upgrades to aging equipment and changing
environmental regulations, are a major factor in cost increases. With plant equipment over 40 years old, significant
rehabilitation and replacement are required to maintain safe, compliant wastewater treatment operations.
4.1.1 Treatment Cost Trends
Staff project a 6% annual increase in treatment costs paid by Palo Alto’s Wastewater Utility from FY 2025 to FY 2035. The
main drivers are capital projects, materials, and debt service (including loan repayments). Treatment capital expenses,
including debt service, are expected to rise by about 7% per year on average to fund equipment replacement and major
upgrades. Larger increases in capital expenses are anticipated starting in FY 2030 due to new debt for major projects. The
list below shows the expected year the Wastewater Collection Utility will begin debt service (or loan repayments) for some
of the largest capital projects. The figure below outlines Palo Alto’s share of estimated treatment costs, with upcoming
capital projects and planned debt service payments shown in the "Planned Debt Service" bar. The figure shows RWQCP
estimates adjusted for increased flow share (based on recent trends), and assuming the outstanding amount for remaining
unencumbered and authorized amount for future pay-as-you-go capital is recovered over 4 years.
Joint Interceptor Sewer Rehabilitation (FY 2025)
Building Purchase (FY 2026)
Primary Sedimentation Tank Rehabilitation and Equipment Room Electrical Upgrade (FY 2026)
Outfall Line Construction (FY 2027)
Headworks Facility (FY 2030)
Secondary Treatment Upgrades (FY 2030)
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Figure 17: Palo Alto’s Share of Estimated Wastewater Treatment Expenses (Projection and Planned CIP)
The figure above shows annual CIP reinvestment ("Recurring/Minor CIP" and "Existing Debt Service"), one pay-as-you-go
project (the Joint Intercepting Sewer in FY 2025), and treatment operations costs. While operations costs make up the
bulk of treatment expenses, they are growing more slowly than planned debt service. Additional factors, such as debt
expenses from slow State Revolving Fund loan reimbursements and costs for an acquired property, could further increase
costs. Key drivers of rising treatment costs include higher salaries, sludge hauling price increases, commodity cost hikes,
and Palo Alto’s increased flow share (from 32% in FY 2022 to 36.6% in FY 2024 and assumed 38% in FY 2025 and on).
RWQCP is updating its Long Range Facilities Plan, including cost of service analysis and capital cost allocation.
If the remaining unencumbered and authorized amount for future pay-as-you-go capital (Minor CIP) is not spent by the
RWQCP in a given year, the Wastewater Collection Utility needs to hold the remaining unencumbered and authorized
amount for future pay-as-you-go capital (Minor CIP) in reserves until it is needed by the treatment plant. Staff will provide
more information on this item in the spring 2025 financial forecast.
In June, the Council approved a Cost-Sharing Agreement with the Santa Clara Valley Water District for the Guiding Principle
5 grant program, which funds future RWQCP projects.10 The program supports communities like Palo Alto, where
taxpayers pay State Water Project property taxes but rely on non-Valley Water supplies for most of their water. In FY
2025, staff will factor in an estimated $11.2 million in grant funding for Palo Alto’s share of approved RWQCP projects,
directly benefiting local customers. Four upcoming projects are eligible for this funding:
Outfall Line Construction
Headworks Facility Replacement
12kV Electrical Power Distribution Loop Improvements
Joint Intercepting Sewer Rehabilitation
10 Staff Report 2404-2877, June 3, 2024 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=82864
7.00%12.36%-0.65%2.55%-2.62%
28.11%2.11%1.35%2.38%6.54%2.34%
$-
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030 FY 2031 FY 2032 FY 2033 FY 2034 FY 2035
Palo Alto Estimated Expenses FY 2025-2035
Projection + Planned CIP
Remaining unencumbered and authorized amount for future pay-as-you-go capital (Minor CIP)
Planned Debt Service
Existing Debt Service
One Time CIP for Joint Intercepting Sewer
Recurring/Minor CIP
Treatment Operations
Treatment Operations & Planned CIPs
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4.1.2 Regional Water Quality Control Plant Capital Planning Status
The Long-Range Facilities Plan, completed in 2012, guides the capital plans for the RWQCP. The RWQCP has begun work
on the Long-Range Facilities Plan update. The findings from the Plan update will direct additional/future CIP. The RWQCP’s
current capital work in-progress includes an estimated $422.9 – 467.6 million in projects. The following table summarizes
these ongoing projects and provides their status and costs.
Figure 18: Current RWQCP Capital Work In-Progress (based on November 2024 Partners Meeting)
Project Status Planned Expense
(million $)
Primary Sedimentation Tanks
Rehabilitation and Equipment
Room Electrical Upgrade
Substantially Complete $16.5
12kV Electrical Loop Upgrades Phase 1: Substantially Complete
Phase 2: In Construction (award in
October 2024)
Phase 1: $6.7
Phase 2: $6.8
New and Rehabilitated Outfall
Pipeline
In Design (Paused at 90% Complete)$17.8
Secondary Treatment Upgrades In Construction (~30% complete)$193
Advanced Water Purification
System
Bidding for Construction $66.8
Headworks Facility
Replacement
Advanced Planning $55.3 (forecast
includes $100)
Joint Interceptor Sewer
Rehabilitation Phase 1
In Construction (~30% complete)$8.9
Long Range Facility Plan Update In Planning $2.5
Subtotal $374.3 - $419
One of the largest projects is the Headworks Facility Replacement, which involves replacing or rehabilitating parts of the
facility that pump raw sewage and refurbishing primary sedimentation tanks. The estimated cost is $55.3 million, and
included in the forecast is $100 million, but it could rise to $120–$150 million based on similar Bay Area projects.
Additionally, new regulations limiting nitrogen discharges into the Bay will require upgrades to the secondary treatment
system, as the current design cannot remove nitrogen. The Secondary Treatment Upgrades project will address this
regulatory change and replace aging mechanical and electrical equipment. In addition to the projects listed in Figure 18,
the RWQCP plans to rent a laboratory building and is evaluating the purchase of neighboring properties in order to build
an environmental services and lab building.
The RWQCP plans to fund these capital projects through a combination of mechanisms including State Revolving Fund
loans, and revenue bonds. Several sources of funding will be used for the Advanced Water Purification System: Valley
Water will provide $16 million, Palo Alto was awarded a $12.9 million grant from the United States Bureau of
Reclamation’s WaterSMART program, which allocates Title XVI Program funding under the Water Infrastructure
Improvements for the Nation (WIIN) Act, and the City of Mountain View will pay for the remainder of the capital cost.
4.2 Collection System Capital Improvement Plan Status
The following capital projects are currently in progress:
WC-15002 – Sewer Master Plan Study
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The Master Plan Study will evaluate the City’s existing wastewater collection system, flows, and flow patterns to
determine the adequacy of the system’s hydraulic capacity to meet current and anticipated future wastewater flow
demands and develop a recommended prioritized Sewer Main rehabilitation plan. The project kicked off in
December 2023 and is anticipated to be completed in July 2025.
WC-20000 - SSR 32 (Sanitary Sewer Replacement 32)
The SSR 32 project is currently in the design phase and will replace approximately 26,000 lineal feet of sewer mains,
laterals, and manholes including Middlefield Road and Webster Street between Seale and Oregon Ave; and various
street in Crescent Park, Old Palo Alto, Midtown, Palo Verde, Fair Meadows, Marron Park, and Green Acres
neighborhoods. The anticipated project construction start date has been delayed from FY26 to FY28 due to an
unanticipated reduction in revenue and additional costs.
WC-26001 – CCTV Sanitary Sewer Mainline Inspection
The City is in the process of developing an Invitation for Bid (IFB) for a three-year program to use Closed Circuit
Television Cameras (CCTV) to inspect Sanitary Sewer Mains. The project will CCTV approximately 225,000 lineal
feet of Sanitary Sewer Main over a three-year duration at an annual rate of approximately 75,000 lineal feet per
year. Results of the project will be used to identified defective Sanitary Sewer Mains which will be incorporated
into future SSRs to rehabilitate and replace Sanitary Sewer Mains.
WC-99013 – Sanitary Sewer Lateral Rehabilitation and Replacement
The City is in the process of developing an Invitation for Bid (IFB) for a three-year program to rehabilitate or replace
Sanitary Sewer Lower Laterals (Lower Laterals or the pipes between customer properties and the sewer mains).
City staff has identified approximately 210 Lower Laterals that will be rehabilitated or replaced over a three-year
period at an annual rate of approximately 70 per year. In addition to addressing defective Lower Laterals, the
project will reduce inflow and infiltration into the sanitary sewer system.
4.3 Financial Health
Below is a summary of the financial position for the wastewater utility.
4.3.1 Sales Forecasts vs. Actuals
Wastewater sales revenues through FY 2025 was 1.4% higher than forecasted, which is consistent with the FY 2025
Financial Plan. Total FY 2025 budget wastewater sales revenue is $25.6 M.
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Figure 19: Wastewater Sales Revenue ($), up to FY 2025-Q2
4.3.2 Financial Position
Costs were higher than forecasted in FY 2023 and FY 2024. Additionally, Palo Alto began Sanitary Sewer Replacement
project 31 with an earlier start date in FY 2023 instead of FY 2024. This project was completed in FY 2024. Completing this
sewer replacement earlier than previously anticipated was necessary in order to coordinate with Caltrans to limit or avoid
digging into newly-paved street on El Camino Real. In June 2024, Council approved the FY 2025 Wastewater Collection
Financial Plan11 that included a 15% rate increase in FY 2025 and a short-term loan of $3 million from the Fiber Optics
Fund Reserve for FY 2024 to cover the cash needs of the Wastewater Collection Utility. Although the Wastewater
Collection Operations Reserve remained low at the end of FY 2024, the utility’s overall cash balance was $0.34 million due
to the $3 million short-term loan. The short-term loan is expected to be paid in FY 2026. Staff expects revenues to cover
rising costs in FY 2025 and begin to replenish the utility’s reserves. Staff provided a financial forecast projection to the
UAC in March 2025 (Staff Report 2411-375212).
11 Staff Report 2404-2842, Attachment A, Exhibit 1: https://www.cityofpaloalto.org/files/assets/public/v/2/agendas-minutes-reports/reports/city-
manager-reports-cmrs/attachments/2024-rates/wastewater-financial-plan-fy25.pdf
12 Staff Report 2411-3752: https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=61748
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5 Fiber Utility
The City offers a "Dark" fiber service providing a fiber connection from Palo Alto businesses to the downtown Internet
Exchange. At the exchange, businesses select an internet service provider (ISP) for bandwidth and connection speed.
5.1 Fiber Utility Strategic Planning
Below are highlights and status updates of the Fiber-to-the-Premises (FTTP) Project:
The fiber hut has been built . The fiber hut is a pre-cast concrete building (11’ x 20’) which will house the networking
equipment including electrical system, cable entry, HVAC, lighting, fire suppression system, alarms, and racks. The
City expects delivery of the hut to the Colorado power station in April after approval of the building permit,
preparation of the hut site including pouring of the padmount, substructure work for power and fiber, and final
inspection.
The contract for the operating support system and business support system (OSS/BSS) software is in progress and
anticipated to be completed by end of March. OSS supports infrastructure and network management by monitoring
operations and provisioning service. BSS supports customer-facing activities such as billing, scheduling, and
customer experience.
CPAU has filled the role of Outside Plant Manager to oversee planning, construction, and inspection of the FTTP
infrastructure and new fiber backbones. This position will oversee field technicians and coordinate design changes,
construction, and installation. CPAU is recruiting for a Fiber Systems Manager to lead the fiber network design by
integrating the existing dark fiber backbone (where necessary) with the building of FTTP and new fiber backbone.
5.2 Capital Improvement Plan Status
The following capital projects are currently in progress:
FO-16000 – Fiber Optic System Rebuild
o The new fiber backbone will be built in segments in alignment with the phased FTTP. CPAU does not have
resources to construct an entire new fiber backbone along with FTTP. In addition to aligning with FTTP,
CPAU will install new aerial ducts or substructure (conduit and boxes) and fiber backbone cables to
increase capacity in areas that are at or near capacity to meet customer connection requests.
FO-24000 – Fiber-to-the-Premises
o The pilot area has been identified, which is bounded by Embarcadero Road, Louis Road, Colorado Avenue,
Greer Road and West Bayshore Road, to determine the best approach at integrating FTTP and grid
modernization. Some criteria that will be used to analyze alignment include impact costs, reductions to
community disruptions, internal staffing, and project timelines. Construction of the FTTP pilot is scheduled
to be completed by August 2025.
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5.3 Reliability
There were no unplanned fiber outages or events to report in Q2 of FY 2025.
Below is a summary of the financial position for the fiber utility.
5.4.1 Fiber Sales
Actual dark fiber licensing sales as of Q2 FY 2025 were $1.6M and $0.1M or 4% below the revenue forecast. Operating
fiber expenses were $1.0M and $0.4M or 10% below forecast due to vacancy savings. The Fiber Fund added four new
positions in FY 2024 to support FTTP. CPAU recently filled the Outside Plant Manager role and is recruiting for the Fiber
Systems Manager. The Assistant Director for Fiber and Senior Network Architect positions are currently on hold as staff
and consultants are collectively performing the work that staff in those roles would perform at this time. As the pilot
progresses, the City will reassess whether these positions will need to be filled in FY 2026.
5.4.2 Financial Position
The ending FY 2024 Fiber Optic Utility Rate Stabilization Reserve is $8 million and an additional $25.5 million of CIP
commitments and reappropriations. In addition, the Fiber Fund loaned the Wastewater Collection Fund $3 million in FY
2024. The Wastewater Collection utility will repay the short-term loan in FY 2026 (or sooner) at a rate equal to the City’s
portfolio rate plus 0.25%. Staff will provide financial forecast projections in spring 2025.
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6 Communications
This section summarizes communications highlights, updates on major campaigns and noteworthy events. Copies of ads
bill inserts, and brochures are available online at www.cityofpaloalto.org/UTLbillinsert
Utilities Rate Changes: In fiscal year 2026 (July 1, 2025-June 30, 2026), the City is proposing rate increases for electric,
natural gas, wastewater and water services. A stormwater management fee increase is will occur per the CPI index as
approved by residents in a 2017 ballot measure. The decision to increase rates is never taken lightly. It is the result of
careful consideration of the need for infrastructure upgrades, system maintenance, regulatory compliance, and
maintaining adequate financial reserves. These investments are crucial to maintaining the integrity of our utility systems
and ensuring that you receive the dependable service you rely on every day. The Utilities Communications team will ensure
this information about rate changes is provided through public meeting processes and to the community through a variety
of outreach channels. Rate increases are necessary to support infrastructure maintenance and replacement, and to
replenish depleted Utilities financial reserves to allow the City to continue to provide high quality utility services to the
community. Factors contributing to the need for increases include:
Increased costs for wastewater treatment and facility upgrades at the Regional Water Quality Control Plant
(RWQCP). The Wastewater Collection Utility experienced increased wastewater treatment costs due to a higher
flow share compared to the prior year forecast and other operating cost increases. The RWQCP began operations
in 1934 and was the first wastewater treatment plant on South San Francisco Bay. The treatment plant needs to
upgrade its equipment and facilities to ensure that the City continues to effectively clean wastewater before it is
discharged to the Bay or treated for reuse as recycled water.
Upgrades to the City’s electric grid distribution system. The City needs to replace aging electrical poles, wires and
equipment with newer infrastructure that allows for additional electric capacity, safety, and reliability throughout
the City. In addition to enhancing grid resiliency and reliability of the electric distribution system, these efforts
assist in accelerating the City’s clean energy and decarbonization goals.
Cost of Service Requirements. The City of Palo Alto’s gas and electric rates must represent the cost of
service consistent with Proposition 26 and the State Constitution. The Utilities Department completed a
cost of service analysis for the Gas Utility in February 2025. Results of the analysis require rate increases
for residential customers to ensure the rates Palo Alto charges are in alignment with the costs to provide
gas service.
Utility financial reserves are depleted. Utility financial reserves were used during times of emergencies and
unexpected cost increases to protect customers from large rates spikes. These financial reserves are depleted and
need to be replenished to maintain utility services. Examples include:
o Minimal rate increases during the pandemic to alleviate economic burden on residents and businesses.
o Energy price spikes in winter 2022-2023 affected Electric and Gas Utilities.
Water use reductions during the 2021-2023 drought impacted the Water Utility.
Public Power and Natural Gas Week: In the first week of October every year, CPAU highlights the Public Power and Public
Natural Gas Week national campaigns to raise awareness about the benefits of public utilities. CPAU is one of over 2,000
community-powered, not-for-profit electric utilities that provide electricity to 54 million Americans and one of more than
1000 not-for-profit gas utilities in the US. As for Public Natural Gas Week, some may question why we highlight natural
gas, considering our goals to transition from fossil fuels to clean electricity for buildings and transportation. We continue
to promote the integrity and safety of our natural gas distribution system, as well as the important work our utility
employees perform while we still own, operate and maintain a gas system in Palo Alto.
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Customer Service Week: The first week of October is also Customer Service Week. CPAU recognizes our Customer Service
team who go above & beyond to help customers navigate their bills, answer questions about their accounts, find services,
and so much more.
Smart Energy Provider Award: This quarter, CPAU was honored with the American Public Power Association’s (APPA)
Smart Energy Provider Award. This award recognizes public power utilities for demonstrating leading practices in four key
disciplines: smart energy program structure; energy efficiency and distributed energy programs; environmental and
sustainability initiatives; and the customer experience. Staff accepted the award at the APPA Customer Connections
conference in October.
Gas Safety Outreach: Throughout the year, CPAU delivers a variety of outreach materials to the community about utilities
safety. An important element of our public awareness program is the annual distribution of our gas safety awareness
brochure. Per Federal Department of Transportation regulations, we directly mail this information to stakeholders
including all customers, non-customers living near a gas pipeline, public officials, emergency responders, excavators,
contractors, and locators working in Palo Alto. Gas safety brochures were delivered in October.
FOG Outreach: Around the holiday season, when many people gather and cook large meals, CPAU focuses educational
outreach on reminding customers to not dispose of Fats, Oils, and Grease (FOG) in drains. FOG can build up in sewer lines,
causing clogged pipes and sewer backups. This is an environmental and public health risk.
Week of Gratitude: During the week of Thanksgiving, CPAU shared a few videos we created which we dubbed our “Week
of Gratitude” series. This will be an ongoing endeavor to highlight CPAU's work in the community to deliver safe and
reliable utilities services.
Electric Grid Modernization: https://youtube.com/shorts/SM25G0PPaqg?feature=share
Gas Main Replacement Project #24B: https://youtube.com/shorts/MXvnbMeBV7s?feature=share
Water Main Replacement Project #29: https://youtube.com/shorts/4Ou4s25EDXc?feature=share
Program and Event Support: CPAU communications staff provide ongoing annual, monthly, and daily support for outreach
to residential and non-residential customers about issues pertaining to sustainability, energy and water efficiency, solar,
electric vehicles and eBikes, beneficial electrification, capital improvement projects, operations and maintenance,
customer service, and technological innovations for utility customers. This quarter included outreach on a multitude of
events and workshops on these topics, as well as promotion via website, utility bill inserts, email newsletters, social media,
print and digital advertisements, community outreach events, media relations and public correspondence.
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7 Legislative, Regulatory and Industry Activity
7.1 State Legislative Activity
The second quarter of FY25 had no legislative activity due to the legislature being on recess. However, the 2025 session
will have several impactful issues on the table: reauthorization of Cap and Trade beyond 2030, creation of a regional
wholesale energy market via the Pathways Initiative, general utility affordability, and wildfire mitigation. Additionally, one
third of the incoming legislators are new and will require education on the issues and how CPAU is meeting them head
on. Lastly, California officials are primed to react to anticipated moves from President Trump, creating possible
distractions.
7.2 State Regulatory Activity
There has been little significant regulatory activity is Q2 of FY25. The Cap and Trade regulatory draft from the California
Air Resources Board (CARB) is not expected until the second half of FY25, so any changes will not go into effect until the
second half of FY26 at the earliest. Expected amendments could have significant negative impacts on CPAU revenue; for
reference, natural gas and electric Cap and Trade revenues for FY24 were a combined $12.4 million.
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Appendices
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8 Appendix A: Energy Risk Management Program
This appendix provides a quarterly update on the City’s Energy Risk Management Program.
8.1 Overview of Hedging Programs
The City’s Utilities Department maintains a hedging program for its Electric and Gas Utilities. In the Gas Utility the program
protects against short-term (intra-month) price spikes caused by weather or major incidents on the Western gas system.
However, the City does not hedge its gas supply more than one month in advance, choosing instead to protect the Gas
Utility’s financial position by passing gas supply costs through to customers via a charge that varies monthly based on gas
market prices. As a result, the Gas Utility’s only market exposure is the amount by which gas demand deviates from
forecasts within the month. This exposure is relatively small and can be managed using Gas Utility Operating Reserves. A
risk assessment is performed each year as part of the Gas Utility financial planning process to ensure adequate reserves
to cover all risks. The most recent Gas Utility Financial Plan was adopted June 21, 2021 (Staff Report #1224013).
The City has entered into long-term contracts for its Electric Utility to ensure that the City has carbon free electricity
supplies equal to 100% of Palo Alto’s annual electric demand. However, the output from these generating sources does
not match Palo Alto’s electric load. In the summer, the City has a surplus of carbon free energy and it has a deficit in the
winter. This exposes the City to market risk, and staff maintains a hedging program to protect against this risk. In addition,
hydroelectric generators make up approximately half the City’s energy supply. During dry years these resources do not
generate as much energy, creating an additional market exposure that must be hedged. Unlike the gas hedging program,
which is operated by City staff, the electric hedging program is operated by the Northern California Power Agency (NCPA),
a joint powers agency the City formed in partnership with several other California publicly owned electric utilities, with
oversight by City staff.
8.2 Overview of Energy Risk Management Program
The hedging programs described above are conducted in accordance with the City’s Energy Risk Management Program,
which includes a set of Program Policies adopted by the City Council, Guidelines adopted by the City’s Utilities Risk
Oversight Coordinating Committee (UROCC), and Procedures approved by the Utilities Director. In addition, for the electric
hedging program, NCPA maintains its own Risk Management Program. The City is able to provide policy level oversight of
this program through its seat on the NCPA Risk Oversight Committee, which is held by the City’s Risk Manager.
Per the Energy Risk Management Policies, the City Council must receive quarterly reports on the City’s forward contract
purchases, market exposure, credit exposure, counterparty credit ratings, transaction compliance, and other relevant
data.
8.3 Forward Deals
Palo Alto executed the following Electric and Gas transactions in Q2 of FY 2025.
Figure 20: Electric Resource Adequacy Deals
Delivery Month Deal Type Avg RA
(MW-mo)
Price ($/kW-mo)
Apr’25 Sale 55 3.55
13 Staff Report #12240 https://www.cityofpaloalto.org/files/assets/public/v/3/agendas-minutes-reports/reports/city-manager-reports-cmrs/year-
archive/2021/06-21-21-id-12240.pdf
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Jun’25-Sept’25 Sale 8.5 19.75
Figure 21: Electric Energy Deals
Delivery Month Deal Type Tota Energy
(MWh)
Price ($/MWh)
Jan’25 Purchase 11,160 66.70
Feb’25 Purchase 5,760 58.40
8.4 Electric Market Exposure
The chart below shows the City’s electric supply market exposure and committed purchases and sales to cover exposed
positions. Additional purchases and sales will be executed for FY 2026 and FY 2027 in the coming months. The City is also
currently pursuing long-term contracts, through NCPA’s RFP process, for one battery energy storage system and one
stand-alone solar project. However, these resources are not expected to begin operating until FY 2028.
Figure 22: Electric Load Resource Balance, FY 2025 - 2027
8.5 Transaction Compliance
There are no transaction exceptions or violations to report.
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Appendix C: PaloAltoGreen Gas Program
In December 2020, Council adopted Resolution #993014 maintaining the Carbon Neutral Natural Gas Plan to achieve
carbon neutrality for the gas supply portfolio using high-quality carbon offsets with a cost cap of $19 per ton CO2e.
Offsets are purchased to neutralize emissions equal to those caused by natural gas usage in Palo Alto. Staff procured
290,000 tons of offsets during Winter 2023/24 to cover FY23 and FY24 usage. The figure below shows the composition of
offset purchases.
Figure 23: Offset Portfolio Composition
The following table provides a description of the projects.
14 Resolution #9930 https://www.cityofpaloalto.org/files/assets/public/v/1/city-clerk/resolutions/resolutions-1909-to-present/2020/reso-9930.pdf
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Figure 24: Offset Project Descriptions
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9 Appendix B: Staffing and Vacancies
As of Q2 FY 2025, the Utilities Department has 51 vacant positions out of 269 authorized positions or a 19% vacancy rate.
Below is a breakdown of the vacancies by division. Utilities is training two new HR liaisons from Utilities to assist HR with
some of the recruitments. With additional support from the Human Resources Department and when the new HR liaisons,
CPAU will be able to fill more positions and reduce the vacancy rate. CPAU is actively recruiting for two executive
management positions: Director of Utilities and Assistant Director, Electric Engineering and Operations.
Figure 24: Utilities Vacancies and Recruitments by Division, as of Q2 FY 2025
A
D
A
F
V
F
A
R V
A 2 3 2 1
C 1 2 5 2 2
F 7 4 2 5
R 2 2 2 8
E 7 2 1 2
E 2 6 6 2
W 7 6 6 8
W 2 4 4 1
T 2 5 4 1
1
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10 Appendix D: Wastewater Utility Annual Infrastructure Maintenance and
Replacement Report
Executive Summary
The City continues to keep up with daily routine maintenance
Sewer Main Replacement program continues as planned
Emergency Standby team continually responded to fewer calls
Infrastructure Overview
See attached for an overview of all assets. Key infrastructure replacement
efforts in the next five years include:
Regular main replacement
Regular manhole rehabilitation/replacement
Regular lateral replacement
Routine maintenance program for main, laterals, siphons and lift
station
Routine testing/maintenance of SCADA overflow monitoring devices
System Operations and Maintenance
Total FTE’s working on Wastewater O&M.
Main
Maintenance
[3.55]
44%
Construction
[0.45]
6%
Emergency
Standby [1.00]
Main/Lateral
Inspection [1.00]
13%
Lateral
Maintenance
[2.00]
25%
Main Maintenance Construction
Emergency Standby Main/Lateral Inspection
Lateral Maintenance
Wastewater Operations and
Maintenance
(Full-Time Equivelent [FTE] and % of total)
Asset Management Goals
What are our goals?
- Repair, rehabilitate, replace, and upgrade
system components as needed
-Maintain our ability to reliably deliver service
to our community
- Properly manage, operate and maintain the
wastewater collection system
-Keep costs down by maximizing asset life
and controlling unplanned maintenance costs
- Cost effectively minimize Inflow and
Infiltration (I/I) and provide sufficient
system capacity
- Eliminate all preventable overflows in dry
and wet weather
- Maintain an effective sanitary sewer spills
response that reduces overflow impact to
public health & the environment
- Analyze and evaluate historical spills to
provide recommendations to reduce future
risk
- Identify system blockages due to fats, oil and
grease (FOG) and develop strategies to
decrease backups
- Provide regular training for City of Palo Alto
Utility Staff and Contractors in wastewater
collection system maintenance, operations
and emergency response
How do we achieve those goals?
-Inspect our collection system to make sure it
is flowing properly
-Make necessary repairs in a timely manner
-Replace assets as they reach end of life or as
their condition deteriorates
-Identify capacity constraints and risks to our
collection system and mitigate these issues
promptly through appropriate capital
improvement projects
-Seek ways to increase our productivity and
control costs by completing our work more
safely and efficiently
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●Main Maintenance (3.55 FTE):
o *Hydro-flushing: High Velocity hydroflushing/vacuum truck
o *Root/Grease Treatment: Heribicides, along with grease emulsifying agents are used to control root and
Fat, Oils and Grease (FOG) issues.
●Lateral Maintenance (2.0 FTE):
o *SOAP / AJAC: Preventive maintenance program includes: Sewer Overflow Alternative Program (SOAP)
using an electric power rodder and Advanced Jetting and Cleaning (AJAC) which uses a hydrojetting tool to
clear systemic sewer blockages.
●Main / Lateral Inspections (1.0 FTE): Routine field inspections of mains, laterals, siphons, manholes and other
sewer components (lift station). Process involves remote Closed-Circuit Television (CCTV) cameras and visual
inspections.
●Emergency Standby Team (1.0 FTE): consist of a standby team of 3 which includes 2 installers and a heavy
equipment operator. ERT receives calls 24/7 daily from Dispatch center and responds promptly to investigate
and mitigate sewer issues. When team is not responding to calls, the team works on Lateral Maintenance.
●Construction (0.45 FTE): Installation of new services laterals, pipe repairs, and manhole replacements.
*First priority programs critical to daily operation
Maintenance Status:
●Essential maintenance programs continue as Operation’s primary routine daily task.
●Main/Lateral inspection program continues to provide Engineering Dept. with valuable pipe assessment for CIP
project inclusion.
●Aging remote overflow monitoring devices have been replaced with new reliable units for accuracy and
performance.
Wastewater Maintenance and Construction Charts
In the last 10 years, the sanitary sewer spills have noticeably decreased due to annual maintenance and biennial sewer
main and lateral replacement projects.
102
81
121
70 64 67
43 43 55
36
25
17 23 23
23 22 11
9 15
25
123
33
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Spills Median Spill Volume, gallons
SPILLS
(By Year)
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52,097
29,136 37,008
71,882 59,768
52,496 56,963 66,332
34,573 31,539 20,664 26,751
J F M A M J J A S O N D
Flushing (Linear Feet)Goal (32,120)
Main Maintenance
185
255 234 232 273
224
296
197
139 141
191 181
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Lateral Tags Goal (200)
LATERAL MAINTENANCE COMPLETED
7
2 3
1
3
5 4 5
2
4
1 2
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
CONSTRUCTION TASKS COMPLETED
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Table 1: Status of Collection System Operation and Maintenance Programs
System
Operation or
Maintenance
Program
Status
Green = good
Yellow = room for
improvement
Comments
Lateral
Maintenance
Daily SOAP/AJAC tags are completed year-long with help from standby ERT
crew members. Annual goal was met. However, during last quarter of 2024,
the crew had not reached its monthly goal of 200 tags.
Main
Maintenance
Flushing is performed on a regular schedule throughout the year. City is
keeping up with its flushing schedule. The crew fell below their goal in only
three months out of year 2024. Overall, the City goal of 385,440 L.F. of mains
was surpassed this year with City completing 539,209 L.F. of main flushing.
Main/Lateral
Inspections
(CCTV)
Operations typically work off a scheduled inspection; however, there are times
when the crew work on a list of special request inspections that tend to
postpone the current month inspections.
Emergency
Standby
Wastewater operations maintains a 24-hour system monitoring for any
emergency events. A wastewater crew has assigned to be ready for any on-
call emergencies and respond promptly to mitigate any wastewater issues at
any hour of the day or night.
Construction
(Repair
main/laterals,
new laterals)
An Operations crew is assigned the task to perform construction work for new
Development Services installations and emergency repair work for our sewer
mains and lower laterals, when work is needed and not included in our Capital
Improvement Projects (CIP).
Asset Class Quantity Maintenance Asset Condition
Manholes 3870 Hydro-Vacuum manhole bases
for excessive debris and visually
inspecting manhole walls for I &
I, report to Engineering with
recommendations for future
replacement.
Old brick manholes are typically replaced with more
reliable pre-cast concrete structures. Over time
brick manholes introduce groundwater via cracks in
bases or wall structures.
Mains and Lateral
service
~ 217
miles of
mains,
~2,988
services
Most mains/laterals are flushed
annually, where as some less
severe areas are flushed every
36 months. For high frequency
lines, flushing happens every 6
months.
With routine maintenance, our mains and lateral
services can be easily assessed by our Operations
crew for remaining useful life of our aging sewer
assets.
Lift Station / Force
main
1 station
/ ~900
Wastewater Operations perform
routine operational checks of the
station once a month and the wet
Our lift station currently requires only minor and
routine maintenance and is in good condition
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linear
feet of
10-inch
force
main
well is cleaned quarterly.
Preventive maintenance for
mechanical and electrical
equipment is done annually by
WGW Operations. The station has
an audible alarm and is connected
through a SCADA system to the
Utilities Dispatch Center. The
station serves approximately 25
homes and a portable generator is
available in the event of power
outages.
overall.
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11 Appendix E: Fiscal Year 2024 Demand Side Management Report
11.1 Executive Summary
This Demand Side Management (DSM) Report for Fiscal Year (FY) 2024 is a public document summarizing the
achievements of the City of Palo Alto Utilities’ (CPAU) customer efficiency and sustainability programs. CPAU is committed
to supporting environmental sustainability through conservation of electric, gas and water resources. Additionally, CPAU
promotes distributed renewable generation, building electrification, and electric vehicles using incentives and educational
programs. CPAU accomplishes these goals by delivering a wide range of customer programs and services as described in
this report and strives to do so while remaining in touch with customer needs.
The Fiscal Year 2024 DSM Report follows the format of the FY 2023 report, which is designed to highlight key performance
indicators in the major areas of focus for the City of Palo Alto’s sustainability efforts. FY 2024 marks the second year the
DSM reports are included as an attachment to the Q2 Utilities Quarterly Update provided to the Utilities Advisory
Commission in April each year.
11.1.1 Summary Goals and Achievements
CPAU offers incentives and education programs for customers to encourage energy and water efficiency – Table ES.1
summarizes FY 2024 efficiency goals and achievements. The energy and water efficiency savings achieved through the
City’s energy reach code and green building ordinance are included in the table.
Palo Alto updated its 10-year electric efficiency (EE) goals in 202115, setting lower annual targets compared to the previous
cycle in anticipation that EE savings levels would recover slowly following the economic downturn. For FY 2024, CPAU fell
short of meeting its EE goal. There are many factors that could have contributed to the below-target efficiency
achievements, including an updated calculation of energy code savings and a continued slowdown of large commercial EE
project completions post-pandemic. CPAU has also continued its focus on developing and promoting electrification
programs over energy efficiency programs with the Advanced Heat Pump Water Heater Pilot Program kicking off in early
2023. Overall, annual electric efficiency savings has begun to trend up, with more than three time the kWh savings in FY
2024 compared to FY 2023. FY 2025 will be an important year to see if this trend continues its upward trajectory.
CPAU has previously adopted gas efficiency goals to reduce gas use; these goals ranged from 0.5% to 1.1% gas use
reduction per year. These goals are no longer relevant and are superseded by the S/CAP goal for the building sector. Water
efficiency goals are in transition as the State is expected to issue new urban water use objectives in compliance with water
conservation legislation16 passed in 2019. The State-mandated water use targets will inform the City’s water conservation
goals.
Table ES.1: Efficiency Goals vs. Achievements
Resource FY 2024 Savings
Goals (% of Load)
FY 2024 Savings
Achieved (% of Load)
FY 2024 Savings
Achieved
Electricity 0.55%0.16%1,362 MWh
Gas N/A 0.22%53,557 Therms
Water N/A 0.59%24,646 CCF
15 Electric Efficiency Goals: https://www.cityofpaloalto.org/files/assets/public/agendas-minutes-reports/reports/city-manager-reports-cmrs/year-
archive/2021/id-12068.pdf
16 Water Efficiency Legislation Fact Sheet:
https://www.waterboards.ca.gov/publications_forms/publications/factsheets/docs/6.7.18_water_efficiency_bill_fact_sheet_FNL_updated_5.21.2
0.pdf
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CPAU is committed by its own policies and State law to implementing all cost-effective energy and water efficiency
measures (i.e. those that are less expensive than supply-side resources). Table ES.2 summarizes the cost of efficiency over
the last three years compared to the projected cost of supply resources. The rolling 3-year average is a suitable metric to
track the cost effectiveness of efficiency portfolios, as it accounts for yearly variations in program engagement and
funding.
The current 3-year average cost for the electric and water efficiency portfolios are below the cost of supply resources,
demonstrating the cost effectiveness of the portfolios. The cost gap leaves room for increasing customer incentives while
maintaining overall portfolio cost effectiveness. The gas efficiency portfolio 3-year average cost has been pushed above
the estimated future supply cost mainly due to the high startup costs of the water heater electrification program in FY
2023. The gas portfolio efficiency was close to the future supply cost in FY 2024 and should continue to improve as the
water heater program and other electrification programs become better established in Palo Alto.
Table ES.2: Actual Levelized Efficiency Costs vs. Projected Supply Costs
FY 2022
Efficiency
FY 2023
Efficiency
FY 2024
Efficiency
3-yr Average
Efficiency
Future
Supply
Electricity $/kWh $0.05 $0.13 $0.04 $0.07 $0.12
Gas $/Therm $1.66 $4.02 $1.25 $2.31 $1.16
Water $/CCF $0.51 $1.53 $2.12 $1.39 $7.03
11.2 Electric Efficiency
CPAU offers both residential and non-residential programs that target EE improvements for customers. Every year CPAU’s
energy efficiency program details are published by the California Municipal Utilities Association (CMUA)17 as required by
California Senate Bill 1037. Table 1 contains a high-level summary of FY 2024 electric program savings and expenditures,
as well as the EE savings target.
Table 1: Electric Efficiency Metrics
Electric Efficiency
MWh Reduced 1,362
$ Spent $703,185
Cost of Efficiency ($/kWh)$0.04
Total MWh Load 865,782
Savings (% of Load)0.16%
Savings Goal (% of Load)0.55%
CPAU fell short of its FY 2024 EE savings goal for a variety of reasons, the most impactful of which being the shortage of
large commercial EE projects. Large commercial EE projects have historically been the backbone of CPAU’s EE savings in
previous years, and these projects have yet to bounce back to pre-pandemic levels. Electrification has also been an
17 SB 1037 Status Reports: https://www.cmua.org/sb1037-reports
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increasing focus to push Palo Alto towards its sustainability goals. To date, this focus has been particularly prominent in
the residential sector where heat pump water heaters made up the majority of projects in FY 2024. CPAU’s estimated
savings from energy codes also dropped significantly starting in FY 2023 due to a change in calculation methodology to
better reflect the impact of Palo Alto’s reach codes.
Figure 1: Cumulative Net Electric Efficiency Savings
2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2
T
I
C F
E
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Figure 2: Composition of Net Electric Efficiency Savings in FY 2024
11.3 Gas Efficiency and Electrification
CPAU has previously adopted gas efficiency goals to reduce gas use; these goals ranged from 0.5% to 1.1% gas use
reduction per year. These goals are no longer relevant as they are superseded by the S/CAP (Sustainability and Climate
Action Plan) goal to reduce GHG emissions from the direct use of natural gas in Palo Alto’s building sector by at least 60%
below 1990 levels by 2030. Rather than continuing gas efficiency rebates and services to support the installation of new
gas equipment that would remain in place for the next decade or longer, CPAU replaced traditional gas efficiency rebates
with technical assistance and rebates to help customers with the transition off of gas equipment. Building envelope
improvements will remain a program priority to ensure comfort for building occupants and to avoid oversizing of all-
electric heating, ventilation and air conditioning (HVAC) equipment.
Table 2 contains a summary of FY 2024 program gas savings through electrification or efficiency projects. CPAU is focusing
initial residential electrification efforts on water heating due to its relatively low impact on the electric grid as Palo Alto
continues to upgrade the distribution system in preparation for increased electric load. The majority of other gas savings
are coming from retro-commissioning of commercial building HVAC systems in Palo Alto.
In FY 2024, the cost per metric ton (MT) of GHG avoided was $236, compared to CPAU’s long term goal of spending less
than $200/MT GHG avoided. The cost was high in FY 2024 due to a combination of factors including low gas reduction
relative to the fixed costs of program operation and marketing costs for the Advanced Heat Pump Water Heater Pilot
Program. CPAU anticipates that the cost per MT GHG avoided could stay above the target and even increase in the near
future due to the expansion of pilot programs that are designed to kickstart the electrification market in Palo Alto. For
N
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reference, the current cost of direct air carbon capture ranges from $500-1000/MT CO218, so even these electrification
programs continue to be more cost effective than the carbon sequestration alternative.
Table 2: Gas Efficiency and Electrification Metrics
Gas Efficiency and Electrification
Figure 3: Historical Gas Usage and Savings
18 Forbes, “Will Direct Air Capture Ever Cost Less Than $100 Per Ton Of CO2?”: https://www.forbes.com/sites/phildeluna/2024/11/29/will-direct-
air-capture-ever-cost-less-than-100-per-ton-of-co/
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As illustrated in Figure 4, 98% of CPAU’s gas reductions in FY 2024 can be attributed to the electrification of residential
water heaters through CPAU’s heat pump water heater programs. This is up from 56% in FY 2023, illustrating the success
of the Advanced Heat Pump Water Heater Pilot Program. The remaining 2% of gas reductions come from a handful of
residential projects and one commercial gas efficiency project, along with one commercial HVAC electrification project.
Figure 4: Composition of Natural Gas Use Reduction in FY 2024
11.4 Water Efficiency
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Table 3: Water Efficiency Metrics
CCF Water Reduced 24,646
$ Spent $52,290
Cost of Efficiency ($/CCF)2.12
Total CCF Load 4,146,710
Savings (% of Load)0.59%
Savings Goal (% of Load)N/A
Figure 5 illustrates the City’s historical total water usage and savings. In FY 2024 CPAU programs yielded lower than
average water savings and total usage was around 275,000 CCF higher than FY 2023. Palo Alto’s water usage continues to
trend downward long term as the city navigates water efficiency and drought restrictions.
11.5 Electric Vehicles
Powering transportation through Electric Vehicles (EVs), as opposed to fossil fuel-powered vehicles, can significantly
reduce GHG emissions and climate pollution. As of 2021, on-road transportation accounted for 52% of the city’s
greenhouse gas emissions. An S/CAP priority is to facilitate the adoption of EVs registered in Palo Alto by ensuring
adequate EV charging infrastructure throughout the city, with equitable access for multifamily and lower income
residents, as well as workplaces, public parking lots and retail areas. Correspondingly, cross-departmental work is
progressing on proposals for curbside charging, fleet electrification and permit streamlining.
The 2022 S/CAP includes GHG emissions reduced by at least 65% below 1990 levels by 2030 in the transportation sector.
This is proposed to be achieved by:
a. Increasing EVs registered in Palo Alto from around 4,500 (2019) to 28,000 (44% of vehicles)
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b. Develop a public and private charging network to support these levels of EV penetration
Table 4 summarizes EV uptake and the City’s contributions to EV charger availability in FY 2019, FY 2023, and FY 2024.
Estimates are also provided for the GHG emission reduction attributed to EVs registered in Palo Alto and EV charging at
city-owned chargers.
Table 4: Electric Vehicle and Charger Metrics
Electric Vehicles FY 2019 FY 2023 FY 2024
Estimated Electric Vehicles Registered 4,454 8,064 9,499
Annual Vehicle Emission Savings (MT GHG)21,610 39,124 46,085
EV Charger Installations Rebated
Level 2 22 142 170
DCFC 0 2 3
Multifamily Development EV Charger Projects Completed 5 8 4
Multifamily Units Provided Access to EV Charging 296 403 50
Number of City Owned EV Chargers 56 85 89
FY 2022 Utilization of City Owned EV Chargers (kWh)393,081 734,057 1,031,340
MT GHG Savings from City Owned EV Charger Utilization 440 822 1,155
The average utilization rates of city owned EV chargers exceeds pre-COVID levels illustrated by the FY 2019 statistics, and
the total utilization continues to grow as the city installs more public chargers.
Figure 6 highlights the evolution of EV adoption in Palo Alto compared to our S/CAP transportation electrification target.
2024 data has been requested from the DMV and will be updated in the next DSM report.
Figure 6: EV Adoption and Forecast vs. 2030 Target
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11.6 Solar and Storage
Solar-plus-storage systems generally consist of a solar array connected to a battery storage system. These systems allow
solar energy to be deployed both day and night, making the electricity grid more resilient to changes in demand. Rooftop
solar-plus-storage systems also provide resiliency by providing backup power during power outages or public safety power
shutoff events. The City participates in Bay Area SunShares – a group-buy program that offers discounts and vetted
contractors for installing rooftop solar and battery storage systems. In FY 2024, there were 13 residential solar installations
and 3 storage installations completed through the SunShares program.
Table 5: SunShares Metrics
Solar and Storage FY 2019 FY 2022 FY 2023 FY 2024
SunShares Installations
Solar 28 23 21 10
Solar + Storage 2 8 7 3
Storage 0 1 2 0
At the end of FY 2024, PV installations in Palo Alto totaled 1,853, with 1,750 residential, 97 non-residential, and 6 Clean
Local Energy Accessible Now (CLEAN) projects installed since CPAU began supporting local solar PV installations in FY 2000.
These customer-side generation systems represent 20.4 megawatts (MW) of generating capacity and are not included in
CPAU’s Renewable Portfolio Standard (RPS) supply requirements. In FY 2024, CPAU customers installed 170 new solar
systems (168 residential and 2 non-residential) with a total 1.5 MW of additional capacity.
Figure 7: Photovoltaic (PV) Cumulative Installations
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Figure 8: PV Cumulative System Capacity (kW)
As of the end of FY 2024, there were 150 battery storage installations with a total capacity of 1.5 MW, all of which were
in the residential sector. In FY 2024, CPAU customers installed 23 new storage systems with a total 227 kW of additional
capacity.
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Figure 10: Battery Storage Cumulative System Capacity (kW)
:
Kiely Nose, Interim Director of Utilities
Staff: Tim Denterlein, Resource Planner
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