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HomeMy WebLinkAbout2025-04-15 Finance Committee Agenda PacketFINANCE COMMITTEE Special Meeting Tuesday, April 15, 2025 Community Meeting Room & Hybrid 5:30 PM Finance Committee meetings will be held as “hybrid” meetings with the option to attend by teleconference/video conference or in person. Information on how the public may observe and participate in the meeting is located at the end of the agenda. The meeting will be broadcast on Cable TV Channel 26, live on YouTube https://www.youtube.com/c/cityofpaloalto, and streamed to Midpen Media Center https://midpenmedia.org. VIRTUAL PARTICIPATION CLICK HERE TO JOIN (https://cityofpaloalto.zoom.us/j/99227307235) Meeting ID: 992 2730 7235    Phone: 1(669)900‐6833 PUBLIC COMMENTS General Public Comment for items not on the agenda will be accepted in person for up to three minutes or an amount of time determined by the Chair. General public comment will be heard for 30 minutes. Additional public comments, if any, will be heard at the end of the agenda. Public comments for agendized items will be accepted both in person and via Zoom for up to three minutes or an amount of time determined by the Chair. Requests to speak will be taken until 5 minutes after the staff’s presentation or as determined by the Chair. Written public comments can be submitted in advance to city.council@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 city.clerk@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 types of handle objects are strictly prohibited; (2) the items do not create a facility, fire, or safety hazard; and (3) persons with such items remain seated when displaying them and must not raise the items above shoulder level, obstruct the view or passage of other attendees, or otherwise disturb the business of the meeting. CALL TO ORDER PUBLIC COMMENT  Members of the public may speak in­person ONLY to any item NOT on the agenda. 1­3 minutes depending on number of speakers. Public Comment is limited to 30 minutes. Additional public comments, if any, will be heard at the end of the agenda. ACTION ITEMS 1.Recommendation to the City Council to Adopt a Resolution Approving the 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) 2.Recommendation to the City Council to 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) and Implement a Climate Credit in FY 2026 FUTURE MEETINGS AND AGENDAS Members of the public may not speak to the item(s) ADJOURNMENT PUBLIC COMMENT INSTRUCTIONS Members of the Public may provide public comments to teleconference meetings via email, teleconference, or by phone. 1. Written public comments may be submitted by email to city.council@cityofpaloalto.org. 2. For in person public comments please complete a speaker request card located on the table at the entrance to the Council Chambers and deliver it to the Clerk prior to discussion of the item. 3. Spoken public comments for agendized items using a computer or smart phone will be accepted through the teleconference meeting. To address the Council, click on the link below to access a Zoom‐based meeting. Please read the following instructions carefully. You may download the Zoom client or connect to the meeting in‐ browser. If using your browser, make sure you are using a current, up‐to‐date browser: Chrome 30 , Firefox 27 , Microsoft Edge 12 , Safari 7 . Certain functionality may be disabled in older browsers including Internet Explorer. Or download the Zoom application onto your smart phone from the Apple App Store or Google Play Store and enter in the Meeting ID below. You may be asked to enter an email address and name. We request that you identify yourself by name as this will be visible online and will be used to notify you that it is your turn to speak. When you wish to speak on an Agenda Item, click on “raise hand.” The Clerk will activate and unmute speakers in turn. Speakers will be notified shortly before they are called to speak. When called, please limit your remarks to the time limit allotted. A timer will be shown on the computer to help keep track of your comments. 4. Spoken public comments for agendized items using a phone use the telephone number listed below. When you wish to speak on an agenda item hit *9 on your phone so we know that you wish to speak. You will be asked to provide your first and last name before addressing the Council. You will be advised how long you have to speak. When called please limit your remarks to the agenda item and time limit allotted. CLICK HERE TO JOIN    Meeting ID: 992‐2730‐7235   Phone: 1‐669‐900‐6833 Americans with Disability Act (ADA) It is the policy of the City of Palo Alto to offer its public programs, services and meetings in a manner that is readily accessible to all. Persons with disabilities who require materials in an appropriate alternative format or who require auxiliary aids to access City meetings, programs, or services may contact the City’s ADA Coordinator at (650) 329‐2550 (voice) or by emailing ada@cityofpaloalto.org. Requests for assistance or accommodations must be submitted at least 24 hours in advance of the meeting, program, or service. California Government Code §84308, commonly referred to as the "Levine Act," prohibits an elected official of a local government agency from participating in a proceeding involving a license, permit, or other entitlement for use if the official received a campaign contribution exceeding $500 from a party or participant, including their agents, to the proceeding within the last 12 months. A “license, permit, or other entitlement for use” includes most land use and planning approvals and the approval of contracts that are not subject to lowest responsible bid procedures and have a value over $50,000. A “party” is a person who files an application for, or is the subject of, a proceeding involving a license, permit, or other entitlement for use. A “participant” is a person who actively supports or opposes a particular decision in a proceeding involving a license, permit, or other entitlement for use, and has a financial interest in the decision. The Levine Act incorporates the definition of “financial interest” in the Political Reform Act, which encompasses interests in business entities, real property, sources of income, sources of gifts, and personal finances that may be affected by the Council’s actions. If you qualify as a “party” or “participant” to a proceeding, and you have made a campaign contribution to a Council Member exceeding $500 made within the last 12 months, you must disclose the campaign contribution before making your comments.  1 April 15, 2025 Materials submitted after distribution of the agenda packet are available for public inspection at www.CityofPaloAlto.org/agendas. FINANCE COMMITTEESpecial MeetingTuesday, April 15, 2025Community Meeting Room & Hybrid5:30 PMFinance Committee meetings will be held as “hybrid” meetings with the option to attend byteleconference/video conference or in person. Information on how the public may observe andparticipate in the meeting is located at the end of the agenda. The meeting will be broadcast onCable TV Channel 26, live on YouTube https://www.youtube.com/c/cityofpaloalto, and streamedto Midpen Media Center https://midpenmedia.org.VIRTUAL PARTICIPATION CLICK HERE TO JOIN (https://cityofpaloalto.zoom.us/j/99227307235)Meeting ID: 992 2730 7235    Phone: 1(669)900‐6833PUBLIC COMMENTSGeneral Public Comment for items not on the agenda will be accepted in person for up to threeminutes or an amount of time determined by the Chair. General public comment will be heardfor 30 minutes. Additional public comments, if any, will be heard at the end of the agenda.Public comments for agendized items will be accepted both in person and via Zoom for up tothree minutes or an amount of time determined by the Chair. Requests to speak will be takenuntil 5 minutes after the staff’s presentation or as determined by the Chair. Written publiccomments can be submitted in advance to city.council@CityofPaloAlto.org and will be providedto the Council and available for inspection on the City’s website. Please clearly indicate whichagenda item you are referencing in your subject line.PowerPoints, videos, or other media to be presented during public comment are accepted onlyby email to city.clerk@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 types of handle objects are strictly prohibited; (2) the items do not create a facility, fire, or safety hazard; and (3) persons with such items remain seated when displaying them and must not raise the items above shoulder level, obstruct the view or passage of other attendees, or otherwise disturb the business of the meeting. CALL TO ORDER PUBLIC COMMENT  Members of the public may speak in­person ONLY to any item NOT on the agenda. 1­3 minutes depending on number of speakers. Public Comment is limited to 30 minutes. Additional public comments, if any, will be heard at the end of the agenda. ACTION ITEMS 1.Recommendation to the City Council to Adopt a Resolution Approving the 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) 2.Recommendation to the City Council to 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) and Implement a Climate Credit in FY 2026 FUTURE MEETINGS AND AGENDAS Members of the public may not speak to the item(s) ADJOURNMENT PUBLIC COMMENT INSTRUCTIONS Members of the Public may provide public comments to teleconference meetings via email, teleconference, or by phone. 1. Written public comments may be submitted by email to city.council@cityofpaloalto.org. 2. For in person public comments please complete a speaker request card located on the table at the entrance to the Council Chambers and deliver it to the Clerk prior to discussion of the item. 3. Spoken public comments for agendized items using a computer or smart phone will be accepted through the teleconference meeting. To address the Council, click on the link below to access a Zoom‐based meeting. Please read the following instructions carefully. You may download the Zoom client or connect to the meeting in‐ browser. If using your browser, make sure you are using a current, up‐to‐date browser: Chrome 30 , Firefox 27 , Microsoft Edge 12 , Safari 7 . Certain functionality may be disabled in older browsers including Internet Explorer. Or download the Zoom application onto your smart phone from the Apple App Store or Google Play Store and enter in the Meeting ID below. You may be asked to enter an email address and name. We request that you identify yourself by name as this will be visible online and will be used to notify you that it is your turn to speak. When you wish to speak on an Agenda Item, click on “raise hand.” The Clerk will activate and unmute speakers in turn. Speakers will be notified shortly before they are called to speak. When called, please limit your remarks to the time limit allotted. A timer will be shown on the computer to help keep track of your comments. 4. Spoken public comments for agendized items using a phone use the telephone number listed below. When you wish to speak on an agenda item hit *9 on your phone so we know that you wish to speak. You will be asked to provide your first and last name before addressing the Council. You will be advised how long you have to speak. When called please limit your remarks to the agenda item and time limit allotted. CLICK HERE TO JOIN    Meeting ID: 992‐2730‐7235   Phone: 1‐669‐900‐6833 Americans with Disability Act (ADA) It is the policy of the City of Palo Alto to offer its public programs, services and meetings in a manner that is readily accessible to all. Persons with disabilities who require materials in an appropriate alternative format or who require auxiliary aids to access City meetings, programs, or services may contact the City’s ADA Coordinator at (650) 329‐2550 (voice) or by emailing ada@cityofpaloalto.org. Requests for assistance or accommodations must be submitted at least 24 hours in advance of the meeting, program, or service. California Government Code §84308, commonly referred to as the "Levine Act," prohibits an elected official of a local government agency from participating in a proceeding involving a license, permit, or other entitlement for use if the official received a campaign contribution exceeding $500 from a party or participant, including their agents, to the proceeding within the last 12 months. A “license, permit, or other entitlement for use” includes most land use and planning approvals and the approval of contracts that are not subject to lowest responsible bid procedures and have a value over $50,000. A “party” is a person who files an application for, or is the subject of, a proceeding involving a license, permit, or other entitlement for use. A “participant” is a person who actively supports or opposes a particular decision in a proceeding involving a license, permit, or other entitlement for use, and has a financial interest in the decision. The Levine Act incorporates the definition of “financial interest” in the Political Reform Act, which encompasses interests in business entities, real property, sources of income, sources of gifts, and personal finances that may be affected by the Council’s actions. If you qualify as a “party” or “participant” to a proceeding, and you have made a campaign contribution to a Council Member exceeding $500 made within the last 12 months, you must disclose the campaign contribution before making your comments.  2 April 15, 2025 Materials submitted after distribution of the agenda packet are available for public inspection at www.CityofPaloAlto.org/agendas. FINANCE COMMITTEESpecial MeetingTuesday, April 15, 2025Community Meeting Room & Hybrid5:30 PMFinance Committee meetings will be held as “hybrid” meetings with the option to attend byteleconference/video conference or in person. Information on how the public may observe andparticipate in the meeting is located at the end of the agenda. The meeting will be broadcast onCable TV Channel 26, live on YouTube https://www.youtube.com/c/cityofpaloalto, and streamedto Midpen Media Center https://midpenmedia.org.VIRTUAL PARTICIPATION CLICK HERE TO JOIN (https://cityofpaloalto.zoom.us/j/99227307235)Meeting ID: 992 2730 7235    Phone: 1(669)900‐6833PUBLIC COMMENTSGeneral Public Comment for items not on the agenda will be accepted in person for up to threeminutes or an amount of time determined by the Chair. General public comment will be heardfor 30 minutes. Additional public comments, if any, will be heard at the end of the agenda.Public comments for agendized items will be accepted both in person and via Zoom for up tothree minutes or an amount of time determined by the Chair. Requests to speak will be takenuntil 5 minutes after the staff’s presentation or as determined by the Chair. Written publiccomments can be submitted in advance to city.council@CityofPaloAlto.org and will be providedto the Council and available for inspection on the City’s website. Please clearly indicate whichagenda item you are referencing in your subject line.PowerPoints, videos, or other media to be presented during public comment are accepted onlyby email to city.clerk@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 types 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.CALL TO ORDERPUBLIC COMMENT Members of the public may speak in­person ONLY to any item NOT on the agenda. 1­3 minutes depending onnumber of speakers. Public Comment is limited to 30 minutes. Additional public comments, if any, will be heard atthe end of the agenda.ACTION ITEMS1.Recommendation to the City Council to Adopt a Resolution Approving the FY 2026Electric 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 ElectricService), E‐EEC‐1 (Export Electricity Compensation), and E‐NSE‐1 (Net Metering SurplusElectricity Compensation)2.Recommendation to the City Council to Adopt a Resolution Approving the FY 2026 GasUtility Financial Forecast and Reserve Transfers, the Natural Gas Cost of Service andRate Study, and General Fund Transfer; and Amending Rate Schedules G‐1 (ResidentialGas Service), G‐2 (Residential Master‐Metered and Commercial Gas Service), G‐3 (LargeCommercial Gas Service), and G‐10 (Compressed Natural Gas Service) and Implement aClimate Credit in FY 2026FUTURE MEETINGS AND AGENDAS Members of the public may not speak to the item(s) ADJOURNMENT PUBLIC COMMENT INSTRUCTIONS Members of the Public may provide public comments to teleconference meetings via email, teleconference, or by phone. 1. Written public comments may be submitted by email to city.council@cityofpaloalto.org. 2. For in person public comments please complete a speaker request card located on the table at the entrance to the Council Chambers and deliver it to the Clerk prior to discussion of the item. 3. Spoken public comments for agendized items using a computer or smart phone will be accepted through the teleconference meeting. To address the Council, click on the link below to access a Zoom‐based meeting. Please read the following instructions carefully. You may download the Zoom client or connect to the meeting in‐ browser. If using your browser, make sure you are using a current, up‐to‐date browser: Chrome 30 , Firefox 27 , Microsoft Edge 12 , Safari 7 . Certain functionality may be disabled in older browsers including Internet Explorer. Or download the Zoom application onto your smart phone from the Apple App Store or Google Play Store and enter in the Meeting ID below. You may be asked to enter an email address and name. We request that you identify yourself by name as this will be visible online and will be used to notify you that it is your turn to speak. When you wish to speak on an Agenda Item, click on “raise hand.” The Clerk will activate and unmute speakers in turn. Speakers will be notified shortly before they are called to speak. When called, please limit your remarks to the time limit allotted. A timer will be shown on the computer to help keep track of your comments. 4. Spoken public comments for agendized items using a phone use the telephone number listed below. When you wish to speak on an agenda item hit *9 on your phone so we know that you wish to speak. You will be asked to provide your first and last name before addressing the Council. You will be advised how long you have to speak. When called please limit your remarks to the agenda item and time limit allotted. CLICK HERE TO JOIN    Meeting ID: 992‐2730‐7235   Phone: 1‐669‐900‐6833 Americans with Disability Act (ADA) It is the policy of the City of Palo Alto to offer its public programs, services and meetings in a manner that is readily accessible to all. Persons with disabilities who require materials in an appropriate alternative format or who require auxiliary aids to access City meetings, programs, or services may contact the City’s ADA Coordinator at (650) 329‐2550 (voice) or by emailing ada@cityofpaloalto.org. Requests for assistance or accommodations must be submitted at least 24 hours in advance of the meeting, program, or service. California Government Code §84308, commonly referred to as the "Levine Act," prohibits an elected official of a local government agency from participating in a proceeding involving a license, permit, or other entitlement for use if the official received a campaign contribution exceeding $500 from a party or participant, including their agents, to the proceeding within the last 12 months. A “license, permit, or other entitlement for use” includes most land use and planning approvals and the approval of contracts that are not subject to lowest responsible bid procedures and have a value over $50,000. A “party” is a person who files an application for, or is the subject of, a proceeding involving a license, permit, or other entitlement for use. A “participant” is a person who actively supports or opposes a particular decision in a proceeding involving a license, permit, or other entitlement for use, and has a financial interest in the decision. The Levine Act incorporates the definition of “financial interest” in the Political Reform Act, which encompasses interests in business entities, real property, sources of income, sources of gifts, and personal finances that may be affected by the Council’s actions. If you qualify as a “party” or “participant” to a proceeding, and you have made a campaign contribution to a Council Member exceeding $500 made within the last 12 months, you must disclose the campaign contribution before making your comments.  3 April 15, 2025 Materials submitted after distribution of the agenda packet are available for public inspection at www.CityofPaloAlto.org/agendas. FINANCE COMMITTEESpecial MeetingTuesday, April 15, 2025Community Meeting Room & Hybrid5:30 PMFinance Committee meetings will be held as “hybrid” meetings with the option to attend byteleconference/video conference or in person. Information on how the public may observe andparticipate in the meeting is located at the end of the agenda. The meeting will be broadcast onCable TV Channel 26, live on YouTube https://www.youtube.com/c/cityofpaloalto, and streamedto Midpen Media Center https://midpenmedia.org.VIRTUAL PARTICIPATION CLICK HERE TO JOIN (https://cityofpaloalto.zoom.us/j/99227307235)Meeting ID: 992 2730 7235    Phone: 1(669)900‐6833PUBLIC COMMENTSGeneral Public Comment for items not on the agenda will be accepted in person for up to threeminutes or an amount of time determined by the Chair. General public comment will be heardfor 30 minutes. Additional public comments, if any, will be heard at the end of the agenda.Public comments for agendized items will be accepted both in person and via Zoom for up tothree minutes or an amount of time determined by the Chair. Requests to speak will be takenuntil 5 minutes after the staff’s presentation or as determined by the Chair. Written publiccomments can be submitted in advance to city.council@CityofPaloAlto.org and will be providedto the Council and available for inspection on the City’s website. Please clearly indicate whichagenda item you are referencing in your subject line.PowerPoints, videos, or other media to be presented during public comment are accepted onlyby email to city.clerk@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 types 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.CALL TO ORDERPUBLIC COMMENT Members of the public may speak in­person ONLY to any item NOT on the agenda. 1­3 minutes depending onnumber of speakers. Public Comment is limited to 30 minutes. Additional public comments, if any, will be heard atthe end of the agenda.ACTION ITEMS1.Recommendation to the City Council to Adopt a Resolution Approving the FY 2026Electric 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 ElectricService), E‐EEC‐1 (Export Electricity Compensation), and E‐NSE‐1 (Net Metering SurplusElectricity Compensation)2.Recommendation to the City Council to Adopt a Resolution Approving the FY 2026 GasUtility Financial Forecast and Reserve Transfers, the Natural Gas Cost of Service andRate Study, and General Fund Transfer; and Amending Rate Schedules G‐1 (ResidentialGas Service), G‐2 (Residential Master‐Metered and Commercial Gas Service), G‐3 (LargeCommercial Gas Service), and G‐10 (Compressed Natural Gas Service) and Implement aClimate Credit in FY 2026FUTURE MEETINGS AND AGENDASMembers of the public may not speak to the item(s)ADJOURNMENTPUBLIC COMMENT INSTRUCTIONSMembers of the Public may provide public comments to teleconference meetings via email,teleconference, or by phone.1. Written public comments may be submitted by email to city.council@cityofpaloalto.org.2. For in person public comments please complete a speaker request card located on thetable at the entrance to the Council Chambers and deliver it to the Clerk prior todiscussion of the item.3. Spoken public comments for agendized items using a computer or smart phone willbe accepted through the teleconference meeting. To address the Council, click on the linkbelow 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 usingyour 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 inolder browsers including Internet Explorer. Or download the Zoom application ontoyour smart phone from the Apple App Store or Google Play Store and enter in theMeeting ID below.You may be asked to enter an email address and name. We request that youidentify yourself by name as this will be visible online and will be used to notify youthat it is your turn to speak.When you wish to speak on an Agenda Item, click on “raise hand.” The Clerk willactivate and unmute speakers in turn. Speakers will be notified shortly before theyare called to speak.When called, please limit your remarks to the time limit allotted. A timer will beshown on the computer to help keep track of your comments.4. Spoken public comments for agendized items using a phone use the telephone numberlisted below. When you wish to speak on an agenda item hit *9 on your phone so weknow that you wish to speak. You will be asked to provide your first and last name beforeaddressing the Council. You will be advised how long you have to speak. When calledplease limit your remarks to the agenda item and time limit allotted.CLICK HERE TO JOIN    Meeting ID: 992‐2730‐7235   Phone: 1‐669‐900‐6833Americans with Disability Act (ADA) It is the policy of the City of Palo Alto to offer its publicprograms, services and meetings in a manner that is readily accessible to all. Persons withdisabilities 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. California Government Code §84308, commonly referred to as the "Levine Act," prohibits an elected official of a local government agency from participating in a proceeding involving a license, permit, or other entitlement for use if the official received a campaign contribution exceeding $500 from a party or participant, including their agents, to the proceeding within the last 12 months. A “license, permit, or other entitlement for use” includes most land use and planning approvals and the approval of contracts that are not subject to lowest responsible bid procedures and have a value over $50,000. A “party” is a person who files an application for, or is the subject of, a proceeding involving a license, permit, or other entitlement for use. A “participant” is a person who actively supports or opposes a particular decision in a proceeding involving a license, permit, or other entitlement for use, and has a financial interest in the decision. The Levine Act incorporates the definition of “financial interest” in the Political Reform Act, which encompasses interests in business entities, real property, sources of income, sources of gifts, and personal finances that may be affected by the Council’s actions. If you qualify as a “party” or “participant” to a proceeding, and you have made a campaign contribution to a Council Member exceeding $500 made within the last 12 months, you must disclose the campaign contribution before making your comments.  4 April 15, 2025 Materials submitted after distribution of the agenda packet are available for public inspection at www.CityofPaloAlto.org/agendas. Item No. 1. Page 1 of 32 5 8 8 1 Finance Committee Staff Report From: City Manager Report Type: ACTION ITEMS Lead Department: Utilities Meeting Date: April 15, 2025 Report #: 2412-3870 TITLE Recommendation to the City Council to 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 The Utilities Advisory Commission and Staff request that the Finance Committee 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) Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 1  Packet Pg. 5 of 211  Item No. 1. Page 2 of 32 5 8 8 1 j. E-14 (Street Lights) 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. As a locally owned municipal utility, CPAU’s rates are designed to recover the costs of purchasing and delivering these utility services to customers. The City strives to be transparent with utilities customers about the reason for rate changes, including explaining the cost drivers, benefits to customers, what the City is doing to keep costs 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 Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 2  Packet Pg. 6 of 211  Item No. 1. Page 3 of 32 5 8 8 1 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 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. The Hydroelectric Rate Stabilization Reserve has a balance of $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 an upcoming winter is drier than average. In FY 2025, this forecast anticipates the Electric Special Projects Reserve will also be repaid $7.5 million from the Electric Supply Operations Reserve, bringing the balance in the Electric Special Projects Reserve from $22.6 million to $30.1 million. This will fully repay the monies borrowed from the Electric Special Projects Reserve to the Electric Supply Operations Reserve to cover higher costs during the pandemic, the drought, and high winter energy prices during 2022-2023. Table 1: Current Year (FY 2025) and Projected Overall Rate Trajectory from FY 2026 to FY 2030 BACKGROUND This staff report provides the Finance Committee with a financial forecast for the Electric Utility and provides an overview of the utility’s operations costs, capital costs, and debt and includes recommended rate adjustments required to maintain the utility’s financial health. This work is done annually as part of the budget and rate-setting cycle. Attachment A contains a draft Council Resolution. Attachment B contains a redline of the proposed changes to the Electric Utility rate schedules. Attachment C contains a summary of the financial details and CIP budgets underlying the forecast. Attachment D contains a set of Reserves Management Practices describing the reserves. Attachment E contains a summary of the Electric Utility communications strategy and samples. Attachment F contains a technical memo summarizing the methodology and assumptions used to develop the rates for the Unmetered Electric Service Rate Schedule (E-16). Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 3  Packet Pg. 7 of 211  Item No. 1. Page 4 of 32 5 8 8 1 ANALYSIS Past Trends Annual expenses for the Electric Utility increased significantly from FY 2019 to FY 2024. Electric supply costs increased as new renewable projects came online, and transmission access charges have continued to rise as improvements are made to the California grid. Capital improvement and operational expenses have increased due to construction inflation, increased investment in the electric system, and the cost of contract field crews to cover operational work due to challenges with filling vacancies and multi-year construction projects such as Foothills undergrounding and grid modernization. In FY 2024, supply costs were significantly lower than budgeted, driven primarily by favorable hydrological conditions and high resource adequacy (RA) market prices. The record levels of precipitation the state received during FY 2023 led to reservoirs being nearly full in FY 2024, producing high levels of hydroelectric generation and enabling the City to sell significant quantities of surplus generation to other utilities. In addition, the City is a net seller of RA capacity, and record-high RA prices during FY 2024 enabled the City to realize significant RA sales revenue. This trend continued in FY 2025, which is one of the main drivers of the lower than projected overall supply costs. The capital costs for FY 2025 in Figure 1 are unusual due to the timing of various capital investments and related debt issuances in FY 2025 and FY 2026. In FY 2025 the Electric Utility’s reserves will fund the capital investment, including grid modernization, while in FY 2026 CPAU plans to issue the first grid modernization bond which will offset the capital costs paid for by customer revenues or Electric Utility reserves in that year. Electric supply purchase costs increased 2% per year on average from FY 2019 through FY 2024, and other operational costs increased 4% per year on average over the same time period. For capital costs, grid modernization investments are expected to be substantial beginning in FY 2025 through FY 2030 with bond financing occurring in FY 2026. In the longer term, debt service costs will grow as a result of the repayment of principal and interest on the grid modernization bonds. However, the capital and debt service costs combined are expected to be relatively steady from year to year. 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) Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 4  Packet Pg. 8 of 211  Item No. 1. Page 5 of 32 5 8 8 1 Projections Overview In FY 2025, total revenues are expected to be similar to FY 2024 actuals, sales revenues increased by $4.2 million or 2% from FY 2024 actuals primarily due to increased retail sales from higher than anticipated electricity load. However, this was offset by decreases in other revenues and transfers and wholesale revenues. The decline in wholesale revenues compared with FY 2024 is attributed to lower surplus energy revenues, partially offset by higher Renewable Energy Credit (REC) sales revenue. Purchase costs are currently projected to be $1.3 million, or 1%, lower than last year’s forecast. 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. The FY 2025 estimate for the Capital Improvement Program (CIP) budget is $81 million, including $31 million for grid modernization and $14.8 million for a rebuild of the Hanover Substation. From FY 2025 through FY 2030, total revenues and total supply purchases and operating expenses are expected to increase by 4% on average annually. Capital investment and debt service costs are rising due to the grid modernization project. Rates need to increase 5.1% in FY 2026 to cover rising costs, grid modernization CIP, and reserve targets. This financial forecast includes repayment of all internal loans from the Electric Special Projects Reserve by the end of FY 2025. Additionally, this forecast includes a transfer in FY 2025 of $5 million from the Electric Utility Supply Operations Reserve to the Electric Utility Distribution Operations Reserve to manage the impact of the startup capital expenditures of the grid modernization project. Figure 1 shows the electric utility revenues, expenses, and proposed rate changes for the recorded years 2018 through 2024, the current year, and the projections for the next five years. Staff proposes a 5.1% rate increase for FY 2026 and projects rate increases of 6% in FY 2027, 8% in FY 2028 and FY 2029, and 6% in FY 2030 to keep revenues in line with expenses. The FY 2026 CIP cost bars in Figure 1 reflect a one-time timing issue with the startup of the grid modernization project. The first year of spending was budgeted in FY 2024, but the first debt issuance will not take place until FY 2026 (this was to allow time for the City to apply for a grant, which it did not receive). It also reflects a one-time transfer in FY 2024 related to new customer investments. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 5  Packet Pg. 9 of 211  Item No. 1. Page 6 of 32 5 8 8 1 Figure 1: Electric Utility Revenues, Expenses, and Rate Changes: Actual Costs through FY 2024 and Projections through FY 2030 Load Forecast 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) Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 6  Packet Pg. 10 of 211  Item No. 1. Page 7 of 32 5 8 8 1 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 Figure 3 shows forecasted electricity peak demand through FY 2044. Figure 3 highlights the uncertainties around future electricity peak demand. This is because of the growing influence of data centers and electrification initiatives in shaping Palo Alto’s energy landscape. The FY 26 Forecast (high range) line captures a range of uncertainty in the forecast. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 7  Packet Pg. 11 of 211  Item No. 1. Page 8 of 32 5 8 8 1 Figure 3: Forecasted Electricity Peak Demand Revenues The Electric Utility receives most of its revenues from sales of electricity to Palo Alto customers, but about 20 to 25% comes from other non-rate revenue sources. Of these non-rate revenue sources, about 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. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 8  Packet Pg. 12 of 211  Item No. 1. Page 9 of 32 5 8 8 1 The forecast for interest income assumes current interest rates continue, and there are no major reserve reductions aside from what is anticipated in this forecast. If interest rates rise, interest income could increase, and if reserves decrease (due to drought or a withdrawal from the Electric Special Projects (ESP) reserve for a major project), interest income would decrease. The load forecast and the rate changes proposed in this staff report provide the basis for sales revenue projections. Expenses As shown in Figure 1 above, from FY 2026 through FY 2030, increasing power supply costs combined with rising capital investment and debt service costs due to the grid modernization project are projected to require a 5.1% rate increase in FY 2026, 6% in FY 2027, 8% increases per year in FY 2028 and FY 2029, and a 6% increase in FY 2030. These rate increases are necessary to keep revenues in line with expenses. Although total load for FY 2025 is expected to be 10% higher than forecasted a year ago, overall power supply costs are expected to be slightly lower than originally projected. The main factors driving this favorable supply cost shift include executing several sales of excess RA and REC supplies at higher than anticipated prices, and projected hydroelectric output being 11% greater than forecasted a year ago. Hydroelectric generation revenue continues to be a very large source of uncertainty in the City’s supply cost projections, and is expected to decrease over time due to climate change. To reduce the downside risk associated with hydroelectric uncertainty in the future, staff is now making its rate projections assuming that long-term “normal” production from the City’s hydroelectric resources will be about 80% of historical average levels for purposes of estimating future hydroelectric resource costs. Over the longer term, increasing transmission costs, rising renewable energy procurement requirements, and tightening resource adequacy regulations are also expected to steadily increase electric supply costs. Supply Purchases As shown in Figure 4 below, the utility is projected to get roughly 43% of its energy from hydroelectric projects in a normal year, but received over 50% during FY 2024 due to the favorable hydroelectric generation conditions resulting from the rains of the 2022/2023 winter. In the longer term, contracts with renewable sources make up approximately 56% to 64% of the portfolio. If hydroelectric output is lower than forecasted (as was the case in FY 2023) or if loads increase, some additional power purchases may come from unspecified market sources. Under the City’s Carbon Neutral Plan, CPAU purchases additional RECs corresponding to the net amount of market energy it purchases. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 9  Packet Pg. 13 of 211  Item No. 1. Page 10 of 32 5 8 8 1 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% 60% 80% 100% 120% 140% 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Actuals Projection % S h a r e Fiscal Year Net Market Purchases/Sales Hydroelectric Renewable Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 10  Packet Pg. 14 of 211  Item No. 1. Page 11 of 32 5 8 8 1 Figure 5: Electric Supply Portfolio Costs Table 3: Electric Supply Portfolio Costs ($000) Actual ProjectionExpensesFY 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 Net Supply Costs 68,509 84,430 91,682 97,182 103,861 111,961 117,028 0 100 200 300 400 500 600 700 -40 -20 0 20 40 60 80 100 120 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Actuals Projection Hy d r o e l e c t r i c G e n e r a t i o n ( G W h ) Sup p l y C o s t s ( $ M i l l i o n ) Fiscal Year Net Market Purchases / (Sales) Other Costs Renewables Hydroelectric Cost Transmission Average Hydro Generation Actual/Projected Hydro Generation Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 11  Packet Pg. 15 of 211  Item No. 1. Page 12 of 32 5 8 8 1 Operations CPAU’s Electric Utility operations include the following activities: •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. Figure 6 shows the Electric Utility operational costs from FY 2018 through FY 2030. Overall operations costs are expected to rise annually by about 4% on average from FY 2025 to FY 2030. This is primarily driven by increased operations and maintenance and administrative overhead allocations. Operations and maintenance costs are increasing primarily due to inflation driven by the tight labor market and the cost of using contract field crews for multi-year CIPs and to backfill for vacant positions. These costs may be reduced depending on how much work is needed and may be phased out as longer-term employees are gained. Administration costs are rising primarily due to increasing support and labor from other City departments and Utilities Administration costs resulting from filling vacancies, merit increases and cost of living increases. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 12  Packet Pg. 16 of 211  Item No. 1. Page 13 of 32 5 8 8 1 Figure 6: Electric Utility Operational Costs 0 20 40 60 80 100 120 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 Resource Management Demand Side Management Administration Operations & Maintenance (including Engineering) Customer Service Transfers Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 13  Packet Pg. 17 of 211  Item No. 1. Page 14 of 32 5 8 8 1 Capital Improvement Program Staff anticipates CIP spending for FY 2025 through FY 2030 to focus primarily on grid modernization (~$228 million). Other significant one-time projects include a rebuild of Hanover Substation, undergrounding of power lines in the Foothills, and completion of the Smart Grid (Advanced Metering Infrastructure) project. Ongoing projects include replacement of deteriorated wood poles, substation physical security upgrades, and ongoing capital investment in smaller projects on the electric distribution system to maintain/improve reliability. Total spending over the forecast period, including the FY 2025 current year budget, is approximately $340 million. Of this, about $186 million (55%) is planned to be financed through debt while $115 million (34%) is scheduled to be funded by utility rates. This forecast assumes the remaining $38 million (11%) is primarily funded through future debt issuances beyond the 5-year forecast, and less significantly, through other sources including connection fees (for Customer Connections), phone and cable companies (primarily for undergrounding), and other funds (such as funds from the Electric Special Projects Reserve for Smart Grid). Table 4 shows the latest projected budget and the five year CIP spending plan, although these figures are preliminary pending budget discussions starting in May. Table 4: Electric Utility CIP Spending ($000) Apart from the grid modernization capital work, the system would need to invest approximately $15 to $20 million per year for existing capital asset replacement. So, over the next 6 years (FY 2025 – 2030), the Electric Utility would spend a baseline amount of $90 to $120 million. The additional spending for grid modernization is $109 million to $139 million, depending on the full cost of grid modernization (~$229 million estimated in this forecast for FY 2025 - 2030). Debt Service The Electric Utility currently has no debt service expenses related to its own distribution system (though it does have debt service expenses related to the Calaveras Dam, a power supply expense). However, staff expects to issue substantial amounts of debt to fund grid modernization expenses through FY 2030. A tentative estimate of how much of the cost of that project will be debt funded vs. rate funded is shown in Figure 7 below. The timing and amount of the debt issuances will likely change as the grid modernization project progresses. Note that the debt issuance in FY 2026 will be used to reimburse FY 2025 expenses, resulting in the use of rate/reserve funding in FY 2025 and a refund to the reserves in FY 2026 as the bond proceeds are Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 14  Packet Pg. 18 of 211  Item No. 1. Page 16 of 32 5 8 8 1 Table 5: Other Issuances Secured by Electric Utility’s Revenues or Reserves Secured by Electric Utility’s:Bond Issuance Responsible Utilities Annual Debt Service ($000)Net Revenues 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 Reserves The Electric Utility currently has two primary contingency reserves, the Supply Operations Reserve and the Distribution Operations Reserve. In addition, the Electric Utility has a Hydro Stabilization Reserve, an Electric Special Projects (ESP) Reserve, and a Capital Reserve. Reserve funds may be utilized with Council approval. There are a variety of risks associated with the Supply Fund related to resource generation variability, market price volatility, transmission cost increases, and regulatory changes to market rules. Because of the high range of uncertainty in energy price predictions more than 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. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 16  Packet Pg. 20 of 211  Item No. 1. Page 17 of 32 5 8 8 1 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 $5.6 million or 22%. As shown in Figure 8, staff anticipates the Supply Operations Reserve will remain within guideline levels throughout the five year forecast period. Note that the high reserve level in FY Estimates of Adverse Outcomes (M$) Estimates of Adverse Outcomes (M$) FY 2026 FY 2027 1.Load Net Revenue 3.8 4.4 2.Hydro Production: Western & Calaveras 5.6 7.6 3. Renewable Production: Landfill, Wind, Solar, Geothermal 1.1 1.9 4. REC Purchases 0.5 0.5 5. REC Sales 2.3 1.9 6. Market Price 2.1 -0.1 7. Resource Adequacy 5.0 1.4 8. Transmission/CAISO 5.0 5.2 9. Plant Outage 1.0 1.0 10. Western Cost 1.7 1.6 11. Legislative & Regulatory 0.0 0.0 12.Supplier Default+0.2 0.2 Electric Supply Fund Risks 28.4 25.6 Categories of Electric Supply Cost Uncertainties Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 17  Packet Pg. 21 of 211  Item No. 1. Page 18 of 32 5 8 8 1 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 Table 7 summarizes the risk assessment calculation for the Distribution Operations Reserve through FY 2030. As shown in Figure 9, the Distribution Operations Reserve is projected to drop below the minimum reserve guideline range in FY 2025, and is also projected to drop below the risk assessment level. This Financial Forecast recommends a $5 million transfer from the Supply Operations Reserve to the Distribution Operations Reserve in FY 2025 to bring the Distribution Operations Reserve above zero. The Distribution Operations reserve is projected to recover to target levels over the course of the forecast period. The risk assessment includes the revenue shortfall that could accrue due to: 1. Lower than forecasted sales revenue; and 2. An increase of 10% of planned system improvement CIP expenditures for the budget year. Reserve Maximum Reserve Target Reserve Minimum 0 10 20 30 40 50 60 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Actuals Projection $ M i l l i o n s Reserve (Year-End) Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 18  Packet Pg. 22 of 211  Item No. 1. Page 19 of 32 5 8 8 1 Table 7: Electric Distribution Fund Risk Assessment ($000) Fiscal Year 2025 2026 2027 2028 2029 2030 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 Total Risk Assessment value 8,231 6,776 8,486 9,384 9,249 9,036 Figure 9: Electric Distribution Operations Reserve Adequacy Reserve Transfers 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. 1) Up to $20 million from the Electric Special Projects Reserve to the Supply Operations Reserve 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 0 5 10 15 20 25 30 35 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Actuals Projection $ M i l l i o n s Reserve (Year-End) Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 19  Packet Pg. 23 of 211  Item No. 1. Page 22 of 32 5 8 8 1 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 shows that the CIP reserve is not projected to be above the minimum guideline by the end of FY 2025. Per the Reserves Management Practices (Attachment D), Section 10, any rate plan that does not return CIP reserves to minimum levels within one year requires Council approval. Currently, reserves are being used to fund grid modernization spending as well as non- grid modernization Electric CIP spending in the current year. This will allow the Electric Utility to delay the first bond issuance for grid modernization to FY 2026. At this time, staff does not anticipate sufficient rate funding available to bring the CIP Reserve up to within guideline levels during the five year forecast period. Staff will revisit this next year, considering whether the $5 million was transferred to the CIP Reserve in FY 2025, along with the actual grid modernization expenditures and revenue bond issuance. Figure 10: Electric CIP Reserve Adequacy Reserves balances based on these revenue projections are shown in Figure 11 (for Supply Fund Reserves) and Figure 12 (for Distribution Fund Reserves), below. The reserves charts below show significant increases in the Cap and Trade Program Reserve over the forecast period. Staff expects significant utilization of those funds for electrification programs. 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 $ M i l l i o n s CIP Reserve (Year-End) Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 22  Packet Pg. 26 of 211  Item No. 1. Page 23 of 32 5 8 8 1 Figure 11: Electric Utility Reserves (Supply Fund): Actual Reserve Levels through FY 2024 and Projections through FY 2030 Figure 12: Electric Utility Reserves (Distribution Fund): Actual Reserve Levels through FY 2024 and Projections through FY 2030 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 Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 23  Packet Pg. 27 of 211  Item No. 1. Page 24 of 32 5 8 8 1 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 Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 24  Packet Pg. 28 of 211  Item No. 1. Page 25 of 32 5 8 8 1 Cost of Service Supplement - Unmetered Electric Service (E-16) Rate The City offers an E-16 rate for unmetered electric service for wireless communication facilities and related equipment on wood utility poles and streetlight poles. The E-16 unmetered service rate aligns closely with the E-2 rate for small commercial electric service and excludes costs related to meter reading and is determined based on the energy requirement of equipment specifications. The E-16 rate also includes miscellaneous electric utility charges such as licensing fees for City-owned spare conduit, usable space for utility pole attachments, and mounting communication equipment on utility poles and streetlight poles. Wireless communication companies are experiencing increasing demand for fifth generation (“5G”) wireless communication services and are expanding their wireless small cell network to improve their broadband facilities’ capacity and coverage. CPAU engaged the services of EES Consulting (EES) to perform a cost of service analysis of the E-16 rate and update the rate schedule to ensure the City is recovering the actual costs of delivering these services (Attachment F). Since E-16 is limitedly applied, the last significant update was performed in when California Assembly Bill 1027 was enacted (now codified at Public Utilities Code sections 9510-9519). PUC 9510 et seq. limited local fees cities could charge authorized third party telecommunications providers to attach antennas to city-owned poles. In 2012, the annual licensing fee for mounting communication equipment on City-owned poles was reduced from $1,500 per pole to $270 per pole (Staff Report #31338). 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. Table 13 compares the FY 2025 Current Rates and FY 2026 Proposed Rates for E-16, and incorporates updates to the other components of the E-16 rate schedule. The proposed customer charge of $10.96 reflects actual staff costs to administer the bills for unmetered customers. This charge will be updated annually based on the City’s labor agreement salary schedule. The proposed pole attachment fee of $47.60 is based on the net book value of the poles plus annual operating costs. Since CPAU is planning for significant pole replacements in the next 5 years for grid modernization, CPAU will revisit this calculation with updates, as the net book value of the poles is expected to increase over time with the capital expenses planned. The proposed processing fee of $152 represents one hour of review by Engineering and Operations and is aligned to the C-1 hourly rate for utility miscellaneous charges. 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 Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 25  Packet Pg. 29 of 211  Item No. 1. Page 26 of 32 5 8 8 1 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 $2.80/year for each additional foot of leased space up to 4 feet. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 26  Packet Pg. 30 of 211  Item No. 1. Page 27 of 32 5 8 8 1 Table 14: Current and Proposed Electric Rates Rate Schedule Current Rates (as of 7/1/24) Proposed Rates (effective of 7/1/25)Change Change (%) E-1 (Residential) Tier 1 Energy ($/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%. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 27  Packet Pg. 31 of 211  Item No. 1. Page 28 of 32 5 8 8 1 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 Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 28  Packet Pg. 32 of 211  Item No. 1. Page 29 of 32 5 8 8 1 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 Rate Current $/kWh Proposed $/kWh Net Surplus Electricity (E-NSE-1)$0.1427 $0.1012 Export Electricity (E-EEC-1)$0.1420 $0.1206 Palo Alto Green (PAG) Program The Palo Alto Green (PAG) program provides CPAU’s commercial customers an opportunity to voluntarily pay a premium to receive renewable electricity credits to match their energy usage. Under this program, CPAU staff purchase and retire Green-e certified renewable energy certificates (RECs) in the wholesale market on behalf of PAG customers. This enables participating commercial customers to claim credit for the REC purchases in order to satisfy their corporate sustainability goals and meet federal “green certification” requirements. The PAG charge is a pass-through charge; the revenue collected through the PAG rate premium is intended to fully recover the costs of administering the program. The PAG program has very low overhead costs (e.g., the cost of hiring an auditor to carry out an annual Green-e verification process for the program), so most of the program cost is the purchase cost of the RECs. In the past year the wholesale cost of Green-e certified RECs in the Western US market has remained relatively flat at around $7.75/REC. As such, the PAG rate premium should remain at $7.5 per 1,000 kWh block (.75 cents/kWh), enough to cover the cost of the RECs and overhead. The PAG rate premium is reflected on the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4- G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate schedules. Bill Comparisons/Competitiveness For the median consumption level, the CPAU residential electric monthly bill is about $83.94. This is about 50% lower than the monthly bill for a PG&E customer and about 22% higher than the bill for a City of Santa Clara (Silicon Valley Power) customer with the same consumption level, based on rates as of March 1, 2025. PG&E bill calculations are based on the “average” bundled total rates, including the annual climate credit, and Climate Zone X, which includes most nearby comparison communities. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 29  Packet Pg. 33 of 211  Item No. 1. Page 30 of 32 5 8 8 1 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 provides sample residential bills for Palo Alto, PG&E, and the City of Santa Clara at various usage levels, calculated using rates as of March 1, 2025. Table 17: Residential Monthly Electric Bill Comparison (Effective 3/1/2025, $/mo.) Usage (kWh)Palo Alto PG&E Santa Clara 300 63.02 113.11 51.23 (Median) 408 83.94 167.97 69.02 650 135.95 291.72 112.06 1200 256.22 572.39 209.68 For commercial customers, the CPAU electric monthly bill is about 46% to 57% lower than the bill for a PG&E customer, depending on usage levels. Compared to the City of Santa Clara, CPAU commercial bills are approximately 19% lower to 6% higher, depending on usage levels, based on rates as of March 1, 2025. Table 18 presents sample commercial bills for Palo Alto, PG&E, and the City of Santa Clara at various usage levels, calculated using rates as of March 1, 2025. Table 18: Commercial Monthly Electric Bill Comparison (Effective 3/1/2025, $/mo.) Usage (kWh)Palo Alto PG&E Santa Clara 1000 213.72 442.49 263.86 160,000 30,693.47 70,797.66 28,924.47 500,000 95,666.79 195,910.00 90,174.88 2,000,000 340,863.60 632,699.19 360,401.49 General Fund Transfer The City calculates the General Fund Transfer from its Electric Utility based on a methodology adopted by Council in 2009, which has remained unchanged since then.10 Each year it is calculated according to the 2009 Council-adopted methodology and does not require additional Council action. 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. Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 30  Packet Pg. 34 of 211  Item No. 1. Page 31 of 32 5 8 8 1 Next Steps Staff will incorporate the Finance Committee’s recommendations into the draft financial forecast and attachments and bring those to the City Council in June. The City Council will consider the proposed financial forecast and rate schedules with the FY 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 FY 2026 revenues are projected to increase 5% or $9.34 million from FY 2025 projected levels if Council adopts this financial forecast’s recommendations. The City is a non-residential utility customer and can expect an increase to General Fund expenses (due to the rate increases) and revenues (due to the General Fund Transfer). Street light expenses (which are paid from the General Fund) are projected to increase by 11% or $0.22 million. The General Fund revenues from the General Fund Transfer would increase from an estimate of $15.985 million in FY 2025 to an estimated $17.407 million in FY 2026, an increase of $1.422 million. POLICY IMPLICATIONS The proposed electric rate adjustments are consistent with Council-adopted Reserve Management Practices that are part of the Financial Forecast and were developed using a cost- of-service study and methodology consistent with the California Constitution and industry- accepted cost of service principles. STAKEHOLDER ENGAGEMENT On December 3, 2024, staff discussed the preliminary rate proposals at the Finance Committee meeting. Finance Committee members made suggestions to separate the electric grid modernization costs in two categories to show: 1) costs that would have been needed in the next 10 years anyway, and 2) costs that are necessary for grid modernization and electrification. Committee members expressed interest in the portion of the electric rate increase attributable to grid modernization and interest in seeing non-residential bill comparisons and information about future rate changes, if available. The Finance Committee did not take any action on this item. The video of the meeting is available on the City’s website at the following link: https://youtube.com/watch?v=-tshOdaDA3A?feature=share On December 4, 2024, staff discussed the preliminary rate proposals at the UAC meeting. The UAC took no action. The transcript from the meeting is available on the City’s website: https://cityofpaloalto.primegov.com/Public/CompiledDocument?meetingTemplateId=15106&c ompileOutputType=1 This proposal will be presented to City Council in June 2025 during the budget adoption process. On April 2, 2025, staff presented rate proposals to the UAC. The UAC unanimously recommended approval of this proposal. The video of the meeting is available on the City’s website at the following link: https://www.youtube.com/watch?v=021zJQHLADI Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 31  Packet Pg. 35 of 211  Item No. 1. Page 32 of 32 5 8 8 1 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 business and neighborhood customer presentations. ENVIRONMENTAL REVIEW The Finance Committee’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 Attachment A: FY26 Electric Resolution Attachment B: FY26 Electric Rate Schedules Attachment C: FY26 Electric Utility and CIP Financial Details Attachment D: FY26 Electric Reserves Management Practices Attachment E: FY26 Electric Communications Plan and Samples Attachment F: COSA Supplement - Unmetered Electric Service (E-16) Rate APPROVED BY: Kiely Nose, Interim Director of Utilities Staff: Lisa Bilir, Senior Resource Planner Item 1 Item 1 Staff Report        Item 1: Staff Report Pg. 32  Packet Pg. 36 of 211  *NOT YET APPROVED * 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; Attachment A Item 1 Attachment A - FY26 Electric Resolution        Item 1: Staff Report Pg. 33  Packet Pg. 37 of 211  *NOT YET APPROVED * 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 Attachment A Item 1 Attachment A - FY26 Electric Resolution        Item 1: Staff Report Pg. 34  Packet Pg. 38 of 211  *NOT YET APPROVED * 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. // // // Attachment A Item 1 Attachment A - FY26 Electric Resolution        Item 1: Staff Report Pg. 35  Packet Pg. 39 of 211  *NOT YET APPROVED * 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: City Clerk Mayor APPROVED AS TO FORM: APPROVED: Assistant City Attorney City Manager Director of Utilities Director of Administrative Services Attachment A Item 1 Attachment A - FY26 Electric Resolution        Item 1: Staff Report Pg. 36  Packet Pg. 40 of 211  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 receivingElectric 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 $ 0.103730.10270 $ 0.095930.08642 $ 0.006040.00549 $ 0.205700.19461 Tier 2 usage Any usage over Tier 1 0.133720.13240 0.089680.08079 0.006040.00549 0.229440.21868 Customer Charge ($/month) 5.154.64 D.SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above andadjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s billstatement, 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 perday, 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, referto Rule and Regulation 11.{End} Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 37  Packet Pg. 41 of 211  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 $ 0.150750.14926 $ 0.108060.09735 $ 0.006040.00549 $ 0.264850.25210 Winter Period 0.093340.09242 0.073520.06623 0.006040.00549 0.172900.16414 Customer Charge ($/month) 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 Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 38  Packet Pg. 42 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 39  Packet Pg. 43 of 211  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 Benefits Palo Alto Green Charge Total Summer Period $ 0.150750.14 926 $ 0.108060.09 735 $ 0.006040. 00549 $ 0.0075 $ 0.272350. 25960 Winter Period 0.093340.09242 0.073520.06623 0.006040.00549 0.0075 $ 0.171648040 Customer Charge ($/month) 6.225.60 2. 1000 kWh Block Purchase Option: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total Summer Period $ 0.150750.14926 $ 0.108060.09735 $ 0.006040.00549 $ 0.2521026485 Winter Period Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 40  Packet Pg. 44 of 211  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 0.093340.09242 0.073520.06623 0.006040.00549 0.172900.16414 Customer Charge ($/month) 6.225.60 Palo Alto Green Charge (per 1000 kWh block) $ 7.50 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use in both the Summer and Winter Periods, usage will be prorated based upon the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Palo Alto Green Program Description and Participation Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities Department of enough renewable energy credits (RECs) to match 100% of the metered energy usage at the Customer’s facility each month. Any Customer may alternately request that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs. CPAU will charge the Customer the Palo Alto Green Charge for each such requested block. These REC purchases support the production of renewable energy, increase the financial value of power from renewable sources, and create a transparent and sustainable market that encourages new development of wind and solar power. Customers choosing to participate shall fill out a Palo Alto Green Power Program Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 41  Packet Pg. 45 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 42  Packet Pg. 46 of 211  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) 0.124410.12318 0.027970.02520 0.006040.00549 0.158420.15387 Winter Period Demand Charge (per kW) $ 2.602.57 $ 23.4921.16 $ 26.0923.73 Energy Charge (per kWh) 0.080280.07949 0.027970.02520 0.006040.00549 0.114290.11018 Customer Charge ($/month) 126.24113.73 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 43  Packet Pg. 47 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 44  Packet Pg. 48 of 211  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: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $ 8.508.41 $ 38.0834.31 $ 46.5842.72 Winter Period $0.00 $ 23.4921.16 $23.4921.16 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 45  Packet Pg. 49 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 46  Packet Pg. 50 of 211  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: Commodity Distribution Public Benefits Palo Alto Green Charge Total Summer Period Demand Charge (per kW) $ 11.0910.98 $ 38.0834.31 $ 49.1745.29 Energy Charge (per kWh) 0.124410.12318 0.027970.02520 0.006040.00549 0.0075 0.165920.16137 Winter Period Demand Charge (per kW) $ 2.602.57 $ 23.4921.16 $ 26.0923.73 Energy Charge (per kWh) 0.080280.07949 0.027970.02520 0.006040.00549 0.0075 0.11768 Customer Charge ($/month) 126.24113.73 Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 47  Packet Pg. 51 of 211  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: Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $ 11.0910.98 $ 38.0834.31 $ 49.1745.29 Energy Charge (per kWh) 0.124410.12318 0.027970.02520 0.006040.00549 0.158420.15387 Palo Alto Green Charge (per 1000 kWh block) $7.50 Winter Period Demand Charge (per kW) $ 2.602.57 $ 23.4921.16 $ 23.73 Energy Charge (per kWh) 0.080280.07949 0.027970.02520 0.006040.00549 0.114290.11018 Palo Alto Green Charge (per 1000 kWh block) $7.50 Customer Charge ($/month) 126.24113.73 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 48  Packet Pg. 52 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 49  Packet Pg. 53 of 211  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: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $ 8.508.41 $ 38.0834.31 $ 46.5842.72 Winter Period $0.00 $23.4921.16 $23.4921.16 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 50  Packet Pg. 54 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 51  Packet Pg. 55 of 211  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): Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) Peak $ 9.829.72 $ 19.0717.18 $ 28.8926.90 Max Demand 1.301.29 19.0717.18 20.3718.47 Energy Charge (per kWh) Peak $ 0.172080.17038 $ 0.028170.02538 $ 0.006040.00549 $ 0.206290.20125 Mid-Peak 0.141810.14041 0.028170.02538 0.006040.00549 0.176020.17128 Off-Peak 0.106620.10556 0.028170.02538 0.006040.00549 0.140830.13643 Winter Period Demand Charge (per kW) Peak $ 1.311.30 $ 11.9110.73 $ 13.2212.03 Max Demand 1.311.30 11.9110.73 13.2212.03 Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 52  Packet Pg. 56 of 211  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 Commodity Distribution Public Benefits Total Energy Charge (per kWh) Peak $ 0.120960.11976 $ 0.02775 0.02500 $ 0.006040.00549 $ 0.154750.15025 Mid-Peak 0.095470.09452 0.027750.02500 0.006040.00549 0.129260.12501 Off-Peak 00.06590.06525 0.027750.02500 0.006040.00549 0.099690.09574 Customer Charge ($/month) 126.24113.73 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 53  Packet Pg. 57 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 54  Packet Pg. 58 of 211  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: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $ 8.508.41 $ 38.0834.31 $ 46.5842.72 Winter Period $0.00 $23.4921.16 $23.4921.16 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 55  Packet Pg. 59 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 56  Packet Pg. 60 of 211  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): Commodity Distribution Public Benefits Total Summer Period Demand Charge (kW) $ 12.0711.95 $ 31.5428.41 $ 43.61 40.36 Energy Charge (kWh) 0.127860.12659 0.004020.00362 0.006040.00549 0.137920.13570 Winter Period Demand Charge (kW) $ 2.822.79 $ 27.7525.00 $ 30.5727.79 Energy Charge (kWh) 0.079730.07894 0.003930.00354 0.006040.00549 0.089700.08797 Customer Charge ($/month) 578.08520.80 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 57  Packet Pg. 61 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 58  Packet Pg. 62 of 211  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: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $ 9.259.16 $ 31.5428.41 $ 40.7937.57 Winter Period $0.00 $27.7525.00 $27.7525.00 c. Meters. A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 59  Packet Pg. 63 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 60  Packet Pg. 64 of 211  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: Commodity Distribution Public Benefits Palo Alto Green Charge Total Summer Period Demand Charge ( per kW) $ 12.0711.95 $ 31.5428.41 $ 43.6140.36 Energy Charge (per kWh) 0.127860.12659 0.004020.00362 0.006040.00549 0.0075 0.145420.14320 Winter Period Demand Charge (per kW) $ 2.822.79 $ 27.7525.00 $ 30.5727.79 Energy Charge (per kWh) 0.079730.07894 0.003930.00354 0.006040.00549 0.0075 0.097200.09547 Customer Charge ($/month) 578.08520.80 Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 61  Packet Pg. 65 of 211  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: Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $ 12.0711.95 $ 31.5428.41 $ 43.6140.36 Energy Charge (per kWh) 0.127860.12659 0.004020.00362 0.006040.00549 0.137920.13570 Palo Alto Green Charge (per 1000 kWh block) $ 7.50 Winter Period Demand Charge (per kW) $ 2.822.79 $ 27.7525.00 $ 30.5727.79 Energy Charge (per kWh) 0.079730.07894 0.003930.00354 0.006040.00549 0.089700.08797 Palo Alto Green Charge (per 1000 kWh block) $7.50 Customer Charge ($/month) 578.08520.80 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 62  Packet Pg. 66 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 63  Packet Pg. 67 of 211  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: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $ 9.259.16 $ 31.5428.41 $ 40.7937.57 Winter Period $0.00 $27.7525.00 $27.7525.00 c. Meters: A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit: Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 64  Packet Pg. 68 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 65  Packet Pg. 69 of 211  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): Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) Peak $ 11.3911.28 $ 16.3314.71 $ 27.7225.99 Max Demand 1.461.45 16.3314.71 17.7916.16 Energy Charge (per kWh) Peak $ 0.181990.18019 $ 0.004020.00362 $ 0.006040.00549 $ 0.192050.18930 Mid-Peak 0.149990.14850 0.004020.00362 0.006040.00549 0.160050.15761 Off-Peak 0.112760.11164 0.004020.00362 0.006040.00549 0.122820.12075 Winter Period Demand Charge (per kW) Peak $ 1.461.45 $ 14.4212.99 $ 15.8814.44 Max Demand 1.461.45 14.4212.99 15.8814.44 Energy Charge (per kWh) Peak $ 0.122250.12104 $ 0.003930.00354 $ 0.006040.00549 $ 0.132220.13007 Mid-Peak 0.096480.09552 0.003930.00354 0.006040.00549 0.106450.10455 Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 66  Packet Pg. 70 of 211  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 Off-Peak 0.066600.06594 0.003930.00354 0.006040.00549 0.076570.07497 Customer Charge ($/month) 578.08520.80 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 67  Packet Pg. 71 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 68  Packet Pg. 72 of 211  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: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $ 9.259.16 $ 31.5428.41 $ 40.7937.57 Winter Period $0.00 $27.7525.00 $27.7525.00 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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 69  Packet Pg. 73 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 70  Packet Pg. 74 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 71  Packet Pg. 75 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 72  Packet Pg. 76 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 73  Packet Pg. 77 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 74  Packet Pg. 78 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 75  Packet Pg. 79 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 76  Packet Pg. 80 of 211  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 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 77  Packet Pg. 81 of 211  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 ElectionA Customers who, at the end of an annual settlement period, as described in Rule 29, are Net SurplusCustomer-Generators of electricity who elect to receive monetary compensation as such preference isindicated on the net surplus electricity election form. This Rate Schedule only applies to Customerswho participate in Net Energy Metering, and does not apply to Customers that take service under theCity’s Net Energy Metering Successor Rate, as each of these terms are defined in Rule and Regulation2. 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 abovecompensation rate to determine the Customer’s annual net surplus electricity compensation statedin dollars.2. Additional terms, conditions and definitions govern Net Energy Metering Service andInterconnection, as described in Rule 29.{End} Attachment B Item 1 Attachment B - FY26 Electric Rate Schedules        Item 1: Staff Report Pg. 78  Packet Pg. 82 of 211  Attachment C 6 8 5 8 Electric Utility Financial Details Item 1 Attachment C - FY26 Electric Utility and CIP Financial Details        Item 1: Staff Report Pg. 79  Packet Pg. 83 of 211  Attachment C 6 8 5 8 Electric Utility Capital Improvement Program (CIP) Financial Details Item 1 Attachment C - FY26 Electric Utility and CIP Financial Details        Item 1: Staff Report Pg. 80  Packet Pg. 84 of 211  Attachment D 6 8 5 9 ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES The following reserves management practices are used when developing the Electric 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 Electric Supply Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserve for Commitments) b) For operating budgets reappropriated from previous years, as described in Section 5 (Reserve for Reappropriations) c) For special projects for the benefit of the Electric Utility ratepayers, as described in Section 6 (Electric Special Projects Reserve) d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric resources, as described in Section 7 (Hydroelectric Stabilization Reserve) e) For rate stabilization, as described in Section 11 (Rate Stabilization Reserves) f) For operating contingencies, as described in Section 12 (Operations Reserves) g) For tracking 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, as described in Section 16 (Cap and Trade Program Reserve) h) For tracking funding of City buildings, appliance and vehicle electrification projects and programs, as described in Section 17 (Electrification 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 3. Distribution Fund Reserves The Electric Distribution Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserves for Commitments) b) For operating and capital budgets reappropriated from previous years, as described in Section 5 (Reserves for Reappropriations) c) As an offset to underground loan receivables, as described in Section 8 (Underground Loan Reserve) d) To hold Public Benefit Program funds collected but not yet spent, as described in Section 9 (Public Benefits Reserve) Item 1 Attachment D - FY26 Electric Reserves Management Practices        Item 1: Staff Report Pg. 81  Packet Pg. 85 of 211  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; Item 1 Attachment D - FY26 Electric Reserves Management Practices        Item 1: Staff Report Pg. 82  Packet Pg. 86 of 211  Attachment D 6 8 5 9 Section 7. Hydroelectric Stabilization Reserve The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts associated with variations in generation from hydroelectric resources. Staff will manage the Hydroelectric Stabilization Reserve as follows: a) Projected Hydro Output: Near the end of each fiscal year, staff will determine the actual and expected hydro output for that fiscal year, compare that to the long-term average annual output level (495,957 MWh as of March 2018), and multiply the difference by the average of the monthly round-the-clock forward market prices for each month of the current fiscal year. b) Changes in Reserves. Staff is authorized to transfer the amount described in Sec. 7(a) from the Operations Reserve to the Hydroelectric Stabilization Reserve for hydro output deviations above long-term average levels, or transfer this amount from the Hydroelectric Stabilization Reserve to the Operations Reserve for hydro output deviations below long-term average levels. c) Implementation of HRA. The level of the 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. d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve according to the following guideline levels: Minimum Level $3 million Target Level $19 million Maximum Level $35 million Section 8. Underground Loan Reserve At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the principal payments made against outstanding underground loans. Section 9. Public Benefits Reserve The Public Benefits Reserve will be increased by the amount of unspent Public Benefits Revenues remaining at the end of each fiscal year. Expenditure of these funds requires action by the City Council. Section 10. CIP Reserve The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for capital contingencies. Staff will manage the CIP Reserve according to the following practices: a) The following guideline levels are set forth for the CIP Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period and approved by Council resolution. Minimum Level 20% of the maximum CIP Reserve guideline level Item 1 Attachment D - FY26 Electric Reserves Management Practices        Item 1: Staff Report Pg. 83  Packet Pg. 87 of 211  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: Item 1 Attachment D - FY26 Electric Reserves Management Practices        Item 1: Staff Report Pg. 84  Packet Pg. 88 of 211  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 Item 1 Attachment D - FY26 Electric Reserves Management Practices        Item 1: Staff Report Pg. 85  Packet Pg. 89 of 211  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. Item 1 Attachment D - FY26 Electric Reserves Management Practices        Item 1: Staff Report Pg. 86  Packet Pg. 90 of 211  Attachment E COMMUNICATIONS PLAN AND OUTREACH 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. Item 1 Attachment E - FY26 Electric Utility Communications Plan and Samples        Item 1: Staff Report Pg. 87  Packet Pg. 91 of 211  Attachment E Item 1 Attachment E - FY26 Electric Utility Communications Plan and Samples        Item 1: Staff Report Pg. 88  Packet Pg. 92 of 211  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 1 Attachment F - COSA Supplement - Unmetered Electric Service (E-16) Rate        Item 1: Staff Report Pg. 89  Packet Pg. 93 of 211  MEMORANDUM Unmetered Electric Service Rate Methodology 2 Input Assumptions and Methodology Assembly Bill 10272 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 Description Assumption or Data Source 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 attachment divided by usable space • 7.4% using 1 foot per attachment and 13.5 feet of usable space Pole Height Average pole height for all utility poles • 46 ft • CPAU pole database Number of Poles Total number of utility poles • 5,888 • CPAU pole database Net Book Value Poles Depreciated cost of poles • Depreciation equal to 46.9 years 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 this memo Net Book Value All Plant Total plant value of all pole assets less depreciation • Fixed Assets as of FY2024 end Net Cost of Bare Pole Pole only costs (net of depreciation) • Depreciated pole investment is adjusted by 15% to remove value of appurtenances used only for electric service Overhead Maintenance Expense Annual cost of overhead maintenance costs • Based on FY2024 preliminary actual costs Administrative Expense Annual administrative and general expense • 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 Attachment F Item 1 Attachment F - COSA Supplement - Unmetered Electric Service (E-16) Rate        Item 1: Staff Report Pg. 90  Packet Pg. 94 of 211  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 $47.60/ attachment. CPAU is planning for significant pole replacements in the next 5-10 years and should revisit this calculation with updates, as the net book value of the poles is expected to increase over time with the capital expenses planned. FIGURE 1: POLE ATTACHMENT LEASE METHODOLOGY Pole Attachment Lease Rate ($/Attachment/Year) Bare Pole Net Book Value ($/Pole) Annual Operating Costs ($/Pole) Adder for Depreciation + G&A +Annual O&M Annual Operating Costs ($/Pole) Bare Pole Net Book Value ($/Pole) Cost of Ownership ($/Pole) Cost of Ownership ($/Pole) Usable Space Factor (%) Attachment F Item 1 Attachment F - COSA Supplement - Unmetered Electric Service (E-16) Rate        Item 1: Staff Report Pg. 91  Packet Pg. 95 of 211  MEMORANDUM Unmetered Electric Service Rate Methodology 4 TABLE 2: POLE ATTACHMENT RATE CALCULATION Line Formula/Source Carrying Cost Adder Calculations 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 Overhead Maintenance Expense Adder Line 1/Line 2 34.3% 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 G&A Adder Line 4/Line 5 2.8% 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 Capital Carrying Cost Adder Line 8/Line 9 × Line 7 2.5% Net Book Value Calculations 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 Attachment Fee Calculation 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 $642.62 23 Usable Space Factor (%) Line 15/ Line 16 7.4% 24 Pole Attachment Fee ($/year) Line 22 × Line 23 $47.60 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 1 Attachment F - COSA Supplement - Unmetered Electric Service (E-16) Rate        Item 1: Staff Report Pg. 92  Packet Pg. 96 of 211  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 Hours Labor Rate Cost Engineering Review 0.5 $152.00 $76.00 Field Review 0.5 $152.00 $76.00 Total, $/pole $152.00 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 1 Attachment F - COSA Supplement - Unmetered Electric Service (E-16) Rate        Item 1: Staff Report Pg. 93  Packet Pg. 97 of 211  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 Net Cost of per Foot of Conduit $0.52 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 Carrying Cost, $/ft/year $1.42 15 Line 7 + Line 14 Annual Lease Rate, $/ft Exclusive Use $1.94 Attachment F Item 1 Attachment F - COSA Supplement - Unmetered Electric Service (E-16) Rate        Item 1: Staff Report Pg. 94  Packet Pg. 98 of 211  MEMORANDUM Unmetered Electric Service Rate Methodology 7 SUMMARY Table 5 compares the current and recommended rates for Unmetered Utility Service: TABLE 5: RECOMMENDED RATES Service Current Rate Recommended FY2026 Rate 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. 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 1 Attachment F - COSA Supplement - Unmetered Electric Service (E-16) Rate        Item 1: Staff Report Pg. 95  Packet Pg. 99 of 211  MEMORANDUM Unmetered Electric Service Rate Methodology 8 APPENDIX TABLE 6: POLE ATTACHMENT RATE COMPARISON $/foot City of Palo Alto (Recommended) $47.60 Silicon Valley Power $18.50 Lodi Electric Utilities $21.94 TABLE 7: SMALL CELL ATTACHMENT RATE COMPARISON $/foot City of Palo Alto (Recommended) $329.44 Alameda Municipal Power $1,475 deposit Silicon Valley Power $94.08 increased 2.5% annually Lodi Electric Utilities (2025) $303.41 increased 3% annually Roseville Electric Utilities $270 increased 3% annually each effective date TABLE 8: UNMETERED SCHEDULE $/month $/kWh City of Palo Alto (Recommended FY2026) $10.961 Summer (May 1-Oct 31) (E-2) $0.26485 Winter (Nov 1- Apr 30) (E-2) $0.17290 Alameda Municipal Power $15.75 $0.20113 Silicon Valley Power $5.06 First 800 kWh $0.24377 Above 800 kWh $0.22130 Roseville Electric Utility $13.28 $0.15700 Redding Electric Utility $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 Attachment F Item 1 Attachment F - COSA Supplement - Unmetered Electric Service (E-16) Rate        Item 1: Staff Report Pg. 96  Packet Pg. 100 of 211  1 5 8 7 7 Finance Committee Staff Report From: City Manager Report Type: ACTION ITEMS Lead Department: Utilities Meeting Date: April 15, 2025 Report #: 2412-3868 TITLE Recommendation to the City Council to 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) and Implement a Climate Credit in FY 2026 RECOMMENDATION The Utilities Advisory Commission and Staff request that the Finance Committee 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) The Utilities Advisory Commission also recommends that the Finance Committee recommend that the City Council approve the use of approximately $1.6 million of Cap-and-Trade allowance auction proceeds to provide a one-time flat climate credit of $73.20 to each residential (G-1) customer only in FY 2026. 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 Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 1  Packet Pg. 101 of 211  2 5 8 7 7 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. As a locally owned municipal utility, CPAU’s rates by law, are designed to recover the costs of purchasing and delivering these utility services to customers. The City strives to be transparent with utilities customers about the reason for rate changes, including explaining the cost drivers, benefits to customers, what the City is doing to keep costs 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. During the pandemic, the City kept overall Gas Utility rate increases to 2% to 3% annually and utilized reserve funding to cover costs. In the winter of 2022-23, surging gas prices depleted the Gas Utility reserves, which were used to cover the difference between actual gas costs and the revenue generated by charging customers the Council-approved maximum gas commodity charge. Reserves need to be replenished over time to ensure funds are available for safety and reliability needs, while managing ongoing cost inflation. The FY 2025 financial plan forecasted an overall gas rate increase of 5% for FY 2026. In this financial forecast, staff proposes the same 5% overall rate increase, which is about an 8.7% increase to distribution rates, assuming no change in supply costs, effective July 1, 2025. Additionally, this forecast projects overall rate increases of 6% annually from FY 2027 through FY 2030 though the rate by customer class varies significantly. In recognition, of the significant impact on the specific residential customer class (G-1), a one-time climate credit is recommended to assist in smoothing the rate increase recommended. Table 1: Current Year (FY2025) and Projected Overall Rate Trajectory from FY 2026 to FY 2030 The UAC recommended approval of this proposal with a 5-1 vote with one abstention. The UAC also recommended through a 6-1 vote to recommend to the Finance Committee and Council to approve the use of approximately $1.6 million of Cap-and-Trade allowance auction proceeds to provide a one-time flat climate credit of $73.20 to each residential (G-1) customer only in FY 2026. BACKGROUND Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 2  Packet Pg. 102 of 211  3 5 8 7 7 This staff report provides the Finance Committee with a financial forecast for the Gas Utility, provides an overview of the utility’s operations costs, capital costs, and debt and includes recommended rate adjustments required to maintain the utility’s financial health. Attachment D contains a set of Reserves Management Practices describing the reserves. This work is done annually as part of the budget and rate-setting cycle. ANALYSIS Past Trends The Gas Utility raised distribution rates on July 1, 2024, resulting in an estimated 12.5% increase in the overall system average gas rate, provided gas supply costs remained stable. For FY 2024, sales revenues were $5.5 million below projections in the FY 2025 Financial Plan, mainly due to reduced revenues from lower gas commodity prices and decreased gas consumption. Other sources of funds were lower by $0.4 million, largely due to lower connection fee revenues. On the expense side, supply costs were about $4.6 million lower than projected, reflecting lower market commodity prices. Operational expenses were about $0.9 million higher than projected, 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 Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 3  Packet Pg. 103 of 211  5 5 8 7 7 Load Forecast Gas usage in Palo Alto declined from FY 2020 to FY 2022, mainly due to the impacts of the COVID- 19 pandemic. However, FY 2023 saw an increase in gas usage, likely driven by a modest recovery from COVID-19 effects and colder than average winter temperatures. However, 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 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 5 10 15 20 25 30 35 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 20 3 5 20 3 6 20 3 7 20 3 8 20 3 9 20 4 0 Mil l i o n T h e r m s Fiscal Year FY25 Load Forecast FY26 Load Forecast Actual Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 5  Packet Pg. 105 of 211  6 5 8 7 7 Revenues This financial forecast bases sales revenue projections on the load forecast. 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 The Gas Utility’s costs fall into two main categories: gas supply costs and distribution-related costs. Gas supply costs encompass the cost of the gas itself, its transmission to Palo Alto, and associated environmental expenses. These supply-related costs vary with the market or are set by other entities and are passed through to customers. Distribution-related costs cover the operation of the distribution system, capital improvement, and overall business operations and are collected through a distribution rate adjusted annually. Table 3 shows total Gas Utility costs. The operations and capital costs are considered distribution costs. Current projections show distribution costs increasing 7% on average from FY 2025 through FY 2030. 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 Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 6  Packet Pg. 106 of 211  8 5 8 7 7 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. 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 Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 8  Packet Pg. 108 of 211  9 5 8 7 7 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. 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. As residential and commercial buildings in Palo Alto are electrified, the City may be able to retire some PVC and steel mains in neighborhoods where these materials exist. Staff is developing an efficient phasing plan for electrification and the scaling back of the gas infrastructure, while assessing both operations and financial implications. Some decommissioning and electrification costs are included in the CIP budgets. Table 4 shows the current status of these project categories and projected spending. In addition to the table shown below, CIP budgets include $3 million annually in gas decommissioning costs from FY 2028 through FY 2030. Table 4: Budgeted Gas CIP Spending ($000) Debt Service The Gas Utility currently makes debt service payments on one bond issuance. Table 5 shows debt service for this bond and debt service coverage ratio for the financial forecast period. Debt service on this bond will continue through FY 2026. Table 5: Debt Service Coverage Ratio ($000) FY 2025 FY 2026 Revenues 65,730 80,775 Expenses (Excluding CIP and Debt Service) (44,163) (50,179) Net Revenues 21,568 30,597 Debt Service 799 802 Coverage Ratio 2,698%3,817% Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 9  Packet Pg. 109 of 211  10 5 8 7 7 Reserves The unprecedented and extreme gas prices experienced in FY 2023 depleted the Gas Utility's reserves. A series of multi-year rate increases to the distribution rates were planned to bring the reserves back within guideline levels. The rate increases in this financial forecast continue that plan to replenish the Gas Utility’s reserves over the next several years. The FY 2025 Financial Plan proposed allowing the Operations Reserve to fall below the risk assessment levels for FY 2024 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 summarizes the risk assessment calculation for the Gas Utility through FY 2030. The risk assessment is intended to be covered by the Operations Reserve and includes the revenue shortfall that could occur due to: 1. Maximum non-commodity revenue percentage variance from the previous ten years; and 2. An increase of 10% of planned system improvement CIP expenditures for the budget year. Reserve Maximum Reserve Target Reserve Minimum Risk Assessment 0 5 10 15 20 25 30 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 Reserve (Year-End) Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 10  Packet Pg. 110 of 211  11 5 8 7 7 Table 6: Gas Risk Assessment ($000) FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030 Total non-commodity revenue 36,754 41,131 45,295 49,599 54,285 59,344 Risk of Revenue Loss @14% 5,157 5,771 6,356 6,960 7,617 8,327 CIP Budget 2,068 14,070 20,375 8,784 15,877 9,303 CIP Contingency @10% 207 1,407 2,037 878 1,588 930 Total Risk Assessment value 5,364 7,178 8,393 7,838 9,205 9,257 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. Reserve Balances 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. Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 11  Packet Pg. 111 of 211  12 5 8 7 7 Figure 5: Gas CIP Reserve Levels for FY 2018 through FY 2030 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. Figure 6: Gas Utility Reserves; Actual Reserve Levels for FY 2018 through FY 2024 and Projections FY 2025 through FY 2030 Reserve Minimum Reserve Maximum $0 $2 $4 $6 $8 $10 $12 $14 $16 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Actuals Projection $ M i l l i o n Fiscal Year CIP Reserve (Year-End) $0 $5 $10 $15 $20 $25 $30 $35 2018 2019 2020 2021 2022 2024 2025 2026 2027 2028 2029 2030 Actuals Projection $ M i l l i o n s Fiscal Year Rate Stabilization Commitments & Reappropriations CIP Reserve Operations Reserve Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 12  Packet Pg. 112 of 211  13 5 8 7 7 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. Natural Gas Cost of Service and Rate Study 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) Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 13  Packet Pg. 113 of 211  14 5 8 7 7 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 The Natural Gas Cost of Service and Rate Study recommends a refinement of the G-2 rate schedule. Based on its review of existing G-2 services’ meter capacities, associated costs and recorded sales, the study recommends 3 meter capacity groupings for G-2 by Standard Cubic Feet per Hour (scfh), with a higher monthly service charge for larger meter capacity. The G-2 customer class has a wide range of meter types and capacities. The larger meters require a higher cost to serve because generally they have higher average use, require larger service lines to connect the meter to the distribution system, and impose greater demand on the system. This meter capacity grouping refinement will better reflect customer-related fixed costs in the fixed monthly service charge. The volumetric distribution charge is the same for all G-2 customers. Table 8 presents the meter capacity groupings recommended for G-2 monthly service charge application. Section 4.1.2 of the Natural Gas Cost of Service and Rate Study (Attachment F of this report) describes the recommended refinement in the development of Monthly Service Charge for G-2, including analysis of G-2 meter capacities, usage and allocated costs. EES analyzed average consumption for various meter capacities in the G-2 rate class, and developed 3 meter capacity ranges and customer-related costs for each range. The proposed G-2 Monthly Service Charge is higher for larger capacity meters to reflect higher fixed costs. Table 8: G-2 Service by Maximum Meter Capacity7 G-2 Service by Maximum Meter Capacity Range # of Services G-2: ≤ 220 scfh Less than 220 standard cubic feet per hour (scfh)1,134 G-2: > 220 and < 4,000 scfh More than 220 scfh and less than 4,000 scfh 942 G-2: ≥ 4,000 scfh 4,000 scfh and above 116 Distribution Revenue Requirement The Natural Gas Cost of Service and Rate Study contains gas sales forecasts and estimates for Gas Utility assets and expenses (including estimated contributions to reserves). The Natural Gas Cost 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). Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 14  Packet Pg. 114 of 211  15 5 8 7 7 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. For FY 2026, the Natural Gas Cost of Service and Rate Study estimates a $41.3 million distribution revenue requirement8 – 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. Table 9 below presents a comparison of estimated revenue at current distribution rates and the FY 2026 distribution revenue requirement. The Natural Gas Cost of Service and Rate Study’s updates and adjustments to classification and allocation factors9 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 Table 10 below presents revenue and revenue requirement results associated with the proposed G-2 meter capacity groupings. The Natural Gas Cost of Service and Rate Study uses these revenue requirements to develop the proposed monthly service charges and the uniform distribution charge for the G-2 rate schedule (presented in Table 12 of this report). 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. FY 2026 Total G-1 G-2 G-3 Distribution Only Revenues at Current Rates $37,957,863 $16,311,063 $16,565,086 $5,081,713 Allocated Revenue Requirement $41,268,342 $18,853,368 $16,568,614 $5,846,360 Revenue Shortfall ($3,310,479)($2,542,305)($3,527)($764,647) % Revenue Increase Needed 8.7%15.6%0.0%15.0% Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 15  Packet Pg. 115 of 211  16 5 8 7 7 Table 10: COS Revenue Requirement and Revenue Increase, G-2 Proposed Rates 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 FY 2026 G-2 Rate Schedule G-2: ≤ 220 scfh G-2: > 220 and < 4,000 scfh G-2: ≥ 4,000 scfh Distribution Only Revenues at Current Rates $16,565,086 $2,948,824 $7,685,399 $5,930,863 Allocated Revenue Requirement $16,568,614 $1,713,540 $7,987,841 $6,867,232 Revenue Shortfall ($3,527)$1,235,283 ($302,442)($936,369) % Revenue Increase Needed 0%-41.9%3.9%15.8% Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 16  Packet Pg. 116 of 211  17 5 8 7 7 Table 11: Current and Proposed Monthly Service Charges Rate Schedule Current Rates (as of 7/1/24) Proposed Rates (effective 7/1/25) Change ($) Change (%) 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% Table 12: Current and Proposed Gas Distribution Charges Rate Schedule Current Rates (as of 7/1/24) Proposed Rates (effective 7/1/25) Change ($) Change (%) G-1 (Residential) Tier 1 Rates $ 0.8229 $ 1.2274 $ 0.4045 49.2% Tier 2 Rates 2.1043 1.8972 (0.2071) (9.8%) G-2 (Residential Master-Metered and Small Commercial) Uniform Rate $ 1.0809 $ 1.2616 $ 0.1807 16.7% G-3 (Large Commercial) Uniform Rate $ 1.0702 $ 1.1616 $ 0.0914 8.5% G-10 (Compressed Natural Gas) Uniform Rate $ 0.0175 $ 0.0190 $ 0.0015 8.6% Bill Impacts 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. Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 17  Packet Pg. 117 of 211  18 5 8 7 7 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 $127.84 in Monthly Service Charge, partially offset by the volumetric rate increase). For the G-3 rate class, the usage reflects a sample large commercial customer with an annual consumption of approximately 250,000 therms. 11 Current rates are derived from actual commodity prices up to January 2025 and forecasted prices until June 2025. Proposed rates, while based on the same supply-related rates as current rates, incorporate adjustments solely in the increase of distribution rates. Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 18  Packet Pg. 118 of 211  19 5 8 7 7 Table 14: Impact on Commercial Monthly Bill due to Proposed Gas Rate Changes12 ChangeUsage (Therms/month) Bill Amount (Current Rates) Bill Amount (Proposed Rates)$/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. Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 19  Packet Pg. 119 of 211  20 5 8 7 7 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. 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. Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 20  Packet Pg. 120 of 211  23 5 8 7 7 $73.20 to each residential (G-1) customer only in FY 2026. The Commissioner who voted against the climate credit option said that green funds should not be used to subsidize the use of fossil fuels. The video of the meeting is available on the City’s website at the following link: https://www.youtube.com/watch?v=021zJQHLADI 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 The Finance Committee’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: Attachment A: FY26 Gas Resolution Attachment B: FY26 Gas Rate Schedules Attachment C: FY26 Gas Utility and CIP Financial Details Attachment D: FY26 Gas Reserve Management Practices Attachment E: FY26 Gas Communications Plan and Samples Attachment F: Natural Gas Cost of Service and Rate Study Attachment G: Natural Gas Cost of Service Schedules APPROVED BY: Kiely Nose, Interim Director of Utilities Staff: Lisa Bilir, Senior Resource Planner Item 2 Item 2 Staff Report        Item 2: Staff Report Pg. 23  Packet Pg. 123 of 211  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 Item 2 Attachment A - FY26 Gas Resolution        Item 2: Staff Report Pg. 24  Packet Pg. 124 of 211  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 / / / / / / Item 2 Attachment A - FY26 Gas Resolution        Item 2: Staff Report Pg. 25  Packet Pg. 125 of 211  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 Item 2 Attachment A - FY26 Gas Resolution        Item 2: Staff Report Pg. 26  Packet Pg. 126 of 211  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 residentialfacilities. 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 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 27  Packet Pg. 127 of 211  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 andadjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s billstatement, the bill amount may be broken down into appropriate components ascalculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index fordelivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’sMeter. The Commodity Charge also includes adjustments to account for Council-approved programs implemented to reduce the cost of Gas, including a municipal purchase discount1 and $0.055 per therm for mitigating the impact of short-term natural gas market price spikes2. The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’scompliance obligations. The Cap and Trade Compliance Charge will changes inresponse to changing market conditions, retail sales volumes and the quantity ofallowances 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 greenhousegases 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. Attachment B Item 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 28  Packet Pg. 128 of 211  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-WSL3 (Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto, accounting for delivery losses to the Customer’s Meter. The Commodity and, Cap and Trade Compliance, Carbon Offset and Transportation Charges will fall within the minimum/maximum ranges set forth in Section C. Current and historic per therm rates for the Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the City Utilities website.4 2. Seasonal Rate Changes: The Summer period is effective April 1 to October 31 and the Winter period is effective from November 1 to March 31. When the billing period includes use in both the Summerand the Winter periods, the usage will be prorated based on the number of days in eachseasonal period, and the charges based on the applicable rates for each period. For furtherdiscussion 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 thermsper 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 at0.767667 therms per day during the Summer period (0.767 therms per day x 30 days = 23therms) and 2.0 therms per day during the Winter period (2.0 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 ofbill 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 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 29  Packet Pg. 129 of 211  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 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 30  Packet Pg. 130 of 211  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 discount1 and $0.055 per therm for mitigating the impact of short-term natural gas market price spikes2. The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge 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-WSL3 (Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto, accounting for delivery losses to the Customer’s Meter. The Commodity, Cap and Trade Compliance, and Carbon Offset and Transportation Charges will fall within the minimum/maximum ranges set forth in Section C. Current and historic per therm rates for the Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the City Utilities website.4 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 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 31  Packet Pg. 131 of 211  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 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 32  Packet Pg. 132 of 211  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 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 33  Packet Pg. 133 of 211  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 discount1 and $0.055 per therm for mitigating the impact of short-term natural gas market price spikes2. The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge 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- WSL3 (Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto, accounting for delivery losses to the Customer’s Meter. The Commodity, Cap and Trade Compliance, and Carbon Offset and Transportation Charges will fall within the minimum/maximum ranges set forth in Section C. Current and historic per therm rates for the Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the City Utilities website.4 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 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 34  Packet Pg. 134 of 211  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 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 35  Packet Pg. 135 of 211  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 spikes2. 1 Adopted via Resolution 9451, on September 15, 2014. 2 Adopted via Resolution 10187 on August 19, 2024. Attachment B Item 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 36  Packet Pg. 136 of 211  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-WSL3 (Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto, accounting for delivery losses to the Customer’s Meter. The Commodity, Cap and Trade Compliance, and Carbon Offset and Transportation Charges will fall within the minimum/maximum ranges set forth in Section C. Current and historic per therm rates for the Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the City Utilities website.4 {End} 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 2 Attachment B - FY26 Gas Rate Schedules        Item 2: Staff Report Pg. 37  Packet Pg. 137 of 211  Attachment C 6 7 5 6 Item 2 Attachment C - FY26 Gas Utility and CIP Financial Details        Item 2: Staff Report Pg. 38  Packet Pg. 138 of 211  Attachment C 6 7 5 6 Gas Utility Capital Improvement Program (CIP) Financial Details Item 2 Attachment C - FY26 Gas Utility and CIP Financial Details        Item 2: Staff Report Pg. 39  Packet Pg. 139 of 211  Attachment D 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) Item 2 Attachment D - FY26 Gas Reserve Management Practices        Item 2: Staff Report Pg. 40  Packet Pg. 140 of 211  Attachment D Section 4. Reserve for Commitments At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for Commitments will be set to an amount equal to the total remaining spending authority for all contracts in force for the Wastewater Collection Utility at that time. Section 5. Reserve for Reappropriations At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for Reappropriations will be set to an amount equal to the amount of all remaining capital and non-capital budgets, if any, that will be re-appropriated to the following fiscal year for each fund in accordance with Palo Alto Municipal Code Section 2.28.090. Section 6. CIP Reserve The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for capital contingencies. Staff will manage the CIP Reserve according to the following practices: a) The following guideline levels are set forth for the CIP Reserve1. These guideline levels are calculated for each fiscal year of the Financial Planning Period and approved by Council resolution. a) Minimum Level 12 months of budgeted CIP expense Maximum Level 24 months of budgeted CIP expense b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and the Reserve for Commitments when funds are added to or removed from the Reserve for Commitments as a result of a change in contractual commitments related to CIP projects. Any other additions to or withdrawals from the CIP reserve require Council action. c) Minimum Level: i) Funds held in the Reserve for Commitments may be counted as part of the CIP Reserve for the purpose of determining compliance with the CIP Reserve minimum guideline level. ii) 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, 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 Maximum Level Average annual (12 month)2 CIP budget, for 48 months of budgeted CIP expenses3 Item 2 Attachment D - FY26 Gas Reserve Management Practices        Item 2: Staff Report Pg. 41  Packet Pg. 141 of 211  Attachment D 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, 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. Item 2 Attachment D - FY26 Gas Reserve Management Practices        Item 2: Staff Report Pg. 42  Packet Pg. 142 of 211  Attachment D 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. 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. Item 2 Attachment D - FY26 Gas Reserve Management Practices        Item 2: Staff Report Pg. 43  Packet Pg. 143 of 211  ATTACHMENT E COMMUNICATIONS PLAN AND OUTREACH EXAMPLES 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. Item 2 Attachment E - FY26 Gas Utility Communications Plan and Samples        Item 2: Staff Report Pg. 44  Packet Pg. 144 of 211  ATTACHMENT E Item 2 Attachment E - FY26 Gas Utility Communications Plan and Samples        Item 2: Staff Report Pg. 45  Packet Pg. 145 of 211  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 2025 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 46  Packet Pg. 146 of 211  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 ain 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 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 47  Packet Pg. 147 of 211  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 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 48  Packet Pg. 148 of 211  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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 49  Packet Pg. 149 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 2 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 Service Charge, $/meter/month 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 Tier 2: All other therms 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 facilities Service Charge, $/meter/month Volumetric Charge, $/therm G3: Large Commercial Commercial customers who use at least 250,000 therms per year at one site.2 Service Charge, $/meter/month 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%. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 50  Packet Pg. 150 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 3 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 51  Packet Pg. 151 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 4 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 Transfers to Reserves $5,874,887 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 $3,310,479 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 52  Packet Pg. 152 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 5 TABLE 1-4: DISTRIBUTION COSA RESULTS: FY 2025-2026 Projected FY 2025- 2026 Revenues Revenue Requirement Projected FY 2025-2026 Deficiency/ (Surplus) Revenue Change Needed G1 – Residential $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% 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 53  Packet Pg. 153 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 6 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 54  Packet Pg. 154 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 7 TABLE 1-6: G2 MONTHLY SERVICE CHARGES: FY 2025-2026 CPAU Approved Maximum Meter Capacity (scfh4) Number of Services Current Monthly Service Charge $/Meter/Month Recommended Monthly Service Charge $/Meter/Month Up to 220 1,134 $156.90 $29.06 Above 220 but Below 4,000 942 $156.90 $94.94 4,000 and Above 116 $156.90 $417.62 Total G2 2,193 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 Meter Capacity (scfh) Projected FY 2026 Revenues at Current Monthly Service Charge Revenue Requirement Projected FY 2026 Deficiency/(Surplus) Revenue Change Needed Up to 220 $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). Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 55  Packet Pg. 155 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 8 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 Rate Recommended FY 2025-2026 Rate $ Change Percent Change G1 Residential Monthly Service Charge $16.93 $19.52 $2.59 15.3% Distribution Charge ($/therm) Tier 1 For Winter: first 60 therms/30-day-billing For Summer: first 20 therms/30-day-billing (current); first 23 therms/30-day-billing (recommended) $0.8229 $1.2274 $0.4045 49.2% Tier 2 For Winter: over 60 therms/30-day-billing For Summer: over 20 therms/30-day-billing (current); over 23 therms/30-day-billing (recommended) $2.1043 $1.8972 -$0.2071 -9.8% G2 – Small Commercial (Total) Monthly Service Charge $156.90 $78.00 -$78.90 -50.3% Distribution Charge ($/therm) $1.0809 $1.2616 $0.1807 16.7% G2: Meter Capacity ≤ 220 scfh Monthly Service Charge $156.90 $29.06 -$127.84 -81.5% Distribution Charge ($/therm) $1.0809 $1.2616 $0.1807 16.7% G2: Meter Capacity > 220 scfh and < 4,000 scfh Monthly Service Charge $156.90 $94.94 -$61.96 -39.5% Distribution Charge ($/therm) $1.0809 $1.2616 $0.1807 16.7% G2: Meter Capacity ≥ 4,000 scfh Monthly Service Charge $156.90 $417.62 $260.72 166.2% Distribution Charge ($/therm) $1.0809 $1.2616 $0.1807 16.7% G3 Large Commercial Monthly Service Charge $717.89 $1,713.67 $995.78 138.7% Distribution Charge ($/therm) $1.0702 $1.1616 $0.0914 8.5% Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 56  Packet Pg. 156 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 9 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 57  Packet Pg. 157 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 10 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 58  Packet Pg. 158 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 11 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 59  Packet Pg. 159 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 12 TABLE 2-2: SUMMARY OF NATURAL GAS 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 Transfers to Reserves $5,874,887 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% Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 60  Packet Pg. 160 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 13 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 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 61  Packet Pg. 161 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 14 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 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 62  Packet Pg. 162 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 15 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 63  Packet Pg. 163 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 16 TABLE 3-1: DISTRIBUTION RATE BASE Asset Description Asset Value FY 2021-20227 Classification and Allocation Factor Description Distribution Plant Equip-Meters $12,334,716 CUSTM Number of Services Weighted by Meters and Services Equip-Services $59,109,371 AE Average & Excess Equip-Misc. $2,729,148 AE Average & Excess Equipment-Regulators $976,067 AE Average & Excess Equip-Distribution Mains $77,559,779 AE Average & Excess Equip-Measuring $2,869,793 AE Average & Excess Total Distribution Plant $155,578,873 (Distribution Rate Base) General Plant Building-Gen Plant $1,910,425 GPLT Gross Plant without General Plant And Intangibles Equip-Gen Plant $2,911,310 GPLT Gross Plant without General Plant And Intangibles Total General Plant $4,821,735 (General Plant Rate Base) Total Gross Plant in Service $160,400,608 (Gross Plant) Less: Accumulated Depreciation Distribution Plant $49,833,503 RBD Distribution Rate Base General Plant $3,812,789 RBGP General Plant Rate Base Total Accumulated Depreciation $53,646,292 Total Net Plant $106,754,316 (Net Plant) Working Capital: 1/8 Operating Costs $2,251,043 OMWOP Operation & Maintenance Expense without Production TOTAL RATE BASE $109,005,358 (Rate Base) Constructions Working in Progress (CWIP) Distribution Plant $6,127,014 RBD Distribution Rate Base General Plant $1,902,306 RBGP General Plant Rate Base Total CWIP $8,029,320 TOTAL RATE BASE plus CWIP $117,034,679 Next, the methodology for classification and allocation for the City’s Natural Gas Distribution revenue requirement can be found in Table 3-2. More detail on the classification and allocation factor codes used in the classification and allocation process can be found in Table 3-3. 7 Fiscal year ending June 30, 2022 was the audited asset values available for the study period. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 64  Packet Pg. 164 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 17 TABLE 3-2: DISTRIBUTION REVENUE REQUIREMENT FY 2025-2026 Classification and Allocation Factor Description Distribution Operation & Maintenance Engineering Support 768,861 RBD Distribution Rate Base Operations & Maintenance 9,028,547 RBD Distribution Rate Base Total Distribution 9,797,408 Customer Service, Accounts, & Sales Admin - Customer & Marketing $227,967 CUSTW Number of Services Weighted for Accounting/Metering Meter Reading $485,915 CUSTM Number of Services Weighted for Meters & Services Utility Billing $543,152 CUSTW Number of Services Weighted for Accounting/Metering Credit & Collections $9,850 CUSTW Number of Services Weighted for Accounting/Metering Key & Major Accounts $155,106 DA1 Direct Assignment to Large Commercial (G3) Customer Service $1,266,689 CUSTW2 Number of Services Weighted for Accounting/Metering excluding G3 Low Income Programs $53,792 therm Annual Energy (therms) Efficiency - Demand Side Mngmt $465,537 therm Annual Energy (therms) Total Customer Service, Accounts & Sales $3,208,008 Administrative & General Administrative & General Salaries8 $1,451,715 OMAG O&M Expense without Production and Admin & General Expense Allocated Charges9 $2,735,638 OMAG O&M Expense without Production and Admin & General Expense Rents $574,830 OMAG O&M Expense without Production and Admin & General Expense Transfers to Non-Enterprise Funds $59,411 OMAG O&M Expense without Production, and Admin & General Expense Transfers to Enterprise Funds $181,333 OMAG O&M Expense without Production, and Admin & General Expense 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 65  Packet Pg. 165 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 18 FY 2025-2026 Classification and Allocation Factor Description Administrative & General Salaries $5,002,927 Total Costs with A&G $18,008,343 Interest and Debt Service Expense 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 Total Debt Service /Capital Improvement $8,339,643 General Fund Transfer $9,734,580 REV Current Rate Revenues Reserves Contribution $5,874,887 therm Annual Energy (therms) Revenue Requirement Before Other Revenues $41,957,453 Other Revenues/Discounts Customer Discounts10 -$318,105 NETPLT Net Plant Connection Fees $700,000 NETPLT Net Plant Misc. Revenue and other contributions (Other) -$449,823 NETPLT Net Plant Transfer Credits $131,346 NETPLT Net Plant Interest Income (Loss) from Investments $625,693 NETPLT Net Plant Total Other Revenues $689,111 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 66  Packet Pg. 166 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 19 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 report. Therm Annual Energy (therm) 100% Energy Energy consumption of each class of service in annual therms CUSTW Customers Weighted for Accounting/Metering 100% Customer Number of services weighted for cost of accounting and metering CUSTM Customers Weighted for Meters and Services 100% Customer Number of services weighted for cost of installing, maintaining and reading meters CUSTW2 Customers Weighted for Accounting/Metering w/o G3 100% Customer Number of services weighted for cost of accounting and metering but excluding G3 costs DA1 Direct Assignment for Large Commercial 100% Customer Direct assignment of key account costs to G3, large commercial class RBD On the Basis of Distribution Rate Base 42% Demand 50% Energy 8% Customer Classified and allocated to classes of service based on the net book value of all shared services assets and other capital assets assigned to each class of service OMAG On the Basis of O&M (w/o Gas Supply and A&G) 32% Demand 42% Energy 26% Customer Allocated based on O&M expenses without Gas Supply and A&G expenses RBGP On the Basis of General Plant Rate Base 42% Demand 50% Energy 8% Customer Classified and allocated to classes of service based on the book value of all general plant assets assigned to each class of service GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 42% Demand 50% Energy 8% Customer Allocated on the basis of the gross book value of all capital assets (initial cost) assigned to each class of service. NETPLT On the Basis of Net Plant 42% Demand 50% Energy 8% Customer Allocated on the basis of the net book value of all capital assets (initial cost less accumulated depreciation) assigned to each class of service. OMWOP On the Basis of O&M (w/o Purchased Gas Supply) 32% Demand 42% Energy 26% Customer Allocated based on O&M expenses without 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 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 67  Packet Pg. 167 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 20 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). Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 68  Packet Pg. 168 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 21 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 69  Packet Pg. 169 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 22 TABLE 3-5: DISTRIBUTION RATE BASE ALLOCATION RESULTS: FY 2025-2026 Asset Description Total G1 Residential G2 Small Commercial G3 Large Commercial Distribution Plant Equip-Meters $12,334,716 $9,135,516 $2,878,448 $320,752 Equip-Services $59,109,371 $24,674,393 $25,111,143 $9,323,835 Equip-Misc. $2,729,148 $1,139,245 $1,159,411 $430,492 Equipment-Regulators $976,067 $407,446 $414,658 $153,963 Equip-Distribution Mains $77,559,779 $32,376,261 $32,949,339 $12,234,179 Equip-Measuring $2,869,793 $1,197,956 $1,219,160 $452,677 Total Distribution Plant $155,578,873 $68,930,816 $63,732,158 $22,915,899 General Plant Building-Gen Plant $1,910,425 $846,434 $782,597 $281,395 Equip-Gen Plant $2,911,310 $1,289,886 $1,192,604 $428,820 Total General Plant $4,821,735 $2,136,319 $1,975,201 $710,215 Total Gross Plant in Service $160,400,608 $71,067,135 $65,707,359 $23,626,113 Less: Accumulated Depreciation Distribution Plant $49,833,503 $22,079,245 $20,414,062 $7,340,197 General Plant $3,812,789 $1,689,295 $1,561,891 $561,602 Total Accumulated Depreciation $53,646,292 $23,768,540 $21,975,953 $7,901,799 Total Net Plant $106,754,316 $47,298,595 $43,731,406 $15,724,314 Working Capital 1/8 Operating Expenses $2,251,043 $1,131,981 $820,532 $298,530 Total Working Capital $2,251,043 $1,131,981 $820,532 $298,530 TOTAL RATE BASE $109,005,358 $48,430,576 $44,551,938 $16,022,845 Total CWIP $8,029,320 $3,557,473 $3,289,173 $1,182,674 TOTAL RATE BASE plus CWIP $117,034,679 $51,988,048 $47,841,112 $17,205,519 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 70  Packet Pg. 170 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 23 TABLE 3-6: DISTRIBUTION REVENUE REQUIREMENT ALLOCATION RESULTS: FY 2025-2026 Plant Description FY 2026 Total G1 Residential G2 Small Commercial G3 Large Commercial Distribution 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 Meter Reading $485,915 $359,885 $113,394 $12,636 Utility Billing $543,152 $427,673 $99,452 $16,027 Credit & Collections $9,850 $7,756 $1,804 $291 Key & Major Accounts $155,106 $0 $0 $155,106 Customer Service $1,266,689 $1,027,704 $238,985 $0 Low Income Programs $53,792 $20,371 $24,009 $9,413 Efficiency - Demand Side Management $465,537 $176,296 $207,781 $81,460 Total Customer Service $3,208,008 $2,199,184 $727,166 $281,658 Administrative & General Administrative & General Salaries $1,451,715 $730,023 $529,167 $192,525 Allocated Charges $2,735,638 $1,375,669 $997,173 $362,797 Rents $574,830 $289,064 $209,532 $76,233 Transfers to Non-Enterprise Funds $59,411 $29,876 $21,656 $7,879 Transfers to Enterprise Funds $181,333 $91,187 $66,098 $24,048 Total Administrative & General $5,002,927 $2,515,819 $1,823,626 $663,482 Total Costs with A&G $18,008,343 $9,055,845 $6,564,254 $2,388,244 Interest and Debt Service Expense Interest on Long-Term Debt $23,348 $10,344 $9,564 $3,439 Principal on Long-Term Debt $778,250 $344,812 $318,806 $114,632 System Improvement $7,538,046 $3,339,809 $3,087,925 $1,110,312 Total Debt Service /CIP Expense $8,339,643 $3,694,965 $3,416,296 $1,228,383 General Fund Transfer $9,734,580 $4,183,095 $4,248,241 $1,303,244 Reserves Contribution $5,874,887 $2,224,781 $2,622,114 $1,027,992 Revenue Requirement Before Other Revenues $41,957,453 $19,158,686 $16,850,905 $5,947,862 Other Revenues/Discounts Customer Discounts -$318,105 -$140,940 -$130,310 -$46,855 Connection Fees $700,000 $310,142 $286,752 $103,106 Misc. Revenue (Other) -$449,823 -$199,299 -$184,268 -$66,256 Transfer Credits $131,346 $58,194 $53,805 $19,347 Income (Loss) from Equity Investments $625,693 $277,220 $256,312 $92,161 Total Other Revenues $689,111 $305,318 $282,291 $101,502 NET REVENUE REQUIREMENT $41,268,342 $18,853,368 $16,568,614 $5,846,360 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 71  Packet Pg. 171 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 24 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 Requirement Projected FY 2026 Deficiency Revenue Change Needed G1 – Residential $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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 72  Packet Pg. 172 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 25 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 • Update fixed and volumetric charges to cost of service unit costs • Calculate tiered rates based on A&E cost allocation • Update Tier 1 summer baseline quantity Small Commercial G2 Fixed Monthly Charge Volumetric Charge • Update fixed and volumetric charges to cost of service • Implement three separate fixed monthly charges based on meter’s maximum capacity Large Commercial G3 Fixed Monthly Charge Volumetric Charge • Update fixed and volumetric charges to cost of 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 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 73  Packet Pg. 173 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 26 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 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 74  Packet Pg. 174 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 27 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 6,203,589 Share of Demand-Related Costs in Tier 1 Baseline g = d÷ f 54.4% 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 75  Packet Pg. 175 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 28 TABLE 4-6: G1 BILL IMPACTS AT AVERAGE CUSTOMER USE, DISTRIBUTION ONLY At Current FY 25 Rates At Recommended FY 26 Rates $ Change % Change Average Use Therms/30- day-billing G1 Summer $43.83 $51.09 $7.26 16.6% 22.0 G1 Winter $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 (Therms/month) At Current FY 25 Rates At Recommended FY 26 Rates Bill Impact $/Month Bill Impact (%) Summer 10 $33.75 $40.38 $6.64 19.7% (Median) 17 $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% (Median) 51 $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) 31 $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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 76  Packet Pg. 176 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 29 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 77  Packet Pg. 177 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 30 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 Rate At Recommended FY 2025-2026 Rate $ Change % Change Average Therms/Mo # of Accounts G2 Total $629.59 $629.72 $0.13 0.0% 437 2,193 G2: ≤ 220 scfh 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   G2: > 220 and ˂ 4,000 scfh 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   G2: ≥4,000 scfh 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 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 78  Packet Pg. 178 of 211  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 2024-2025 Rate At Recommended FY 2025-2026 Rate $ Change % Change 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. Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 79  Packet Pg. 179 of 211  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 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 80  Packet Pg. 180 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 33 Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 81  Packet Pg. 181 of 211  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 The Cap and Trade Compliance Charge 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 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) = $/Therm Where: Number of Allowances Required (%) = (Projected Emissions for Current Year - Palo Alto’s Allocated Allowances for Current Year) ÷ Projected Emissions for Current Year Attachment F Item 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 82  Packet Pg. 182 of 211  CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study prepared by EES CONSULTING 35 3. Transportation Charge The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for delivery losses to Customer Meters. The current rates are shown in this tariff https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G- WSL.pdf, provided by PG&E. Additionally, there is a distribution loss factor (updated annually), which is calculated by the variances of gas supply purchases and gas retail sales for the past three fiscal years. The Transportation Charge calculation formula is: PG&E G-WSL Transportation Charges ($/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 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 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 2 Attachment F - Natural Gas Cost of Service and Rate Study        Item 2: Staff Report Pg. 83  Packet Pg. 183 of 211  Date: February 7, 2025 Version: Revised Final Version Test Period: FY: 2026 Distribution System Allocation Method: Average and Excess Method (AE) EES Consulting, A GDS Associates Company 16701 NE 80th Street - Suite 102 - Redmond, WA 98052 - 425-889-2700 - www.eesconsulting.com Georgia / Texas / Alabama / New Hampshire / Wisconsin / Florida / Maine / Washington / California For questions regarding this model, please contact: Russ Schneider, Senior Project Manager Amber Gschwend, Managing Director russ.schneider@gdsassociates.com amber.gschwend@gdsassociates.com 406-471-8015 425-655-1042 Palo Alto Gas Utility Cost of Service Schedules Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 84  Packet Pg. 184 of 211  Prepared By EES Consulting, Inc.Palo Alto Gas Utility - Average and Excess Method (AE) Forecast Year: 2026 Total G1 Residential G2 - All G3 Large Commercial Revenues - Present Rate Distribution $37,957,863 $16,311,063 $16,565,086 $5,081,713 Less Allocated Revenue Requirement Distribution $41,268,342 $18,853,368 $16,568,614 $5,846,360 Difference -$3,310,479 -$2,542,305 -$3,527 -$764,647 Revenue To Cost Ratio 92.0%86.5%100.0%86.9% Adjusted Revenue to Cost Ratio 100.0%94.1%108.7%94.5% Distribution Rate Increase 8.7%15.6%0.0%15.0% SUMMARY OF PRESENT AND PROPOSED RATE REVENUE BY CUSTOMER CLASS Schedule 1.1 Schedule 1.1 Page 1 of 1 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 85  Packet Pg. 185 of 211  Prepared By EES Consulting, Inc.Palo Alto Gas Utility - Average and Excess Method (AE) Forecast Year: 2026 Total G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large Billing Determinants Tier 1 Energy (therms)6,672,656 Tier 2 Energy (therms)3,089,869 Total Energy (therms)25,779,489 9,762,524 11,506,051 4,510,914 752,970 5,468,897 5,284,184 Average Monthly Services 23,477 21,255 2,193 30 1,134 942 116 Average Monthly Energy (therms)92 38 437 12,743 55 484 3,783 Functional Cost Total Cost G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large Distribution Demand (DD)$8,974,464 $4,155,398 $3,585,525 $1,233,541 $234,223 $1,756,065 $1,595,237 $/therm $0.3481 $0.4256 $0.3116 $0.2735 $0.3111 $0.3211 $0.3019 Energy (DE)$24,657,494 $9,720,461 $10,930,854 $4,006,179 $1,083,948 $5,158,322 $4,688,584 $/therm $0.9565 $0.9957 $0.9500 $0.8881 $1.4396 $0.9432 $0.8873 Customer (DC)$7,636,384 $4,977,509 $2,052,235 $606,640 $395,369 $1,073,454 $583,412 $/Customer/Month $27.11 $19.52 $78.00 $1,713.67 $29.06 $94.94 $417.62 Total Distribution $41,268,342 $18,853,368 $16,568,614 $5,846,360 $1,713,540 $7,987,841 $6,867,232 Total $/therm $1.6008 $1.9312 $1.4400 $1.2960 $2.2757 $1.4606 $1.2996 Demand + Energy $/therm $1.3046 $1.4213 $1.2616 $1.1616 $1.7506 $1.2643 $1.1892 Total Unit Costs Total Cost G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large Total $/therm $2.5996 $2.9299 $2.4387 $2.2948 $3.2745 $2.4593 $2.2983 Demand + Energy $/therm $1.6431 $1.9343 $1.4887 $1.4067 $1.8349 $1.5161 $1.4110 $/Customer/Month $27.11 $19.52 $78.00 $1,713.67 $29.06 $94.94 $417.62 Current Rates Tier 1 Energy $/therm $0.8229 $1.0809 $1.0702 $1.0809 $1.0809 $1.0809 Tier 2 Energy $/therm $2.1043 $/Customer/Month $16.93 $156.90 $717.89 $156.90 $156.90 $156.90 Total Revenue from Current Distribution Rates $16,311,063 $16,565,086 $5,081,713 $2,948,824 $7,685,399 $5,930,863 SUMMARY OF REVENUE REQUIREMENT UNIT COSTS BY CUSTOMER CLASS Schedule 2.1 Schedule 2.1 Page 1 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 86  Packet Pg. 186 of 211  Prepared By EES Consulting, Inc.Indicated Billing Determinants baseline Tier 1 Energy (therm)6,935,563 Tier 2 Energy (therm)2,826,961 Total Energy (therms)25,779,489 9,762,524 11,506,051 4,510,914 752,970 5,468,897 5,284,184 Average Monthly Services 23,477 21,255 2,193 30 1,134 942 116 Indicated Rates -- Distribution Tier 1 Energy $/therm $1.2274 $1.2616 $1.1616 $1.7506 $1.2643 $1.1892 Tier 2 Energy $/therm $1.8972 $/Customer/Month $19.52 $78.00 $1,713.67 $29.06 $94.94 $417.62 Total Revenue from Indicated Distribution Rates$41,268,342 $18,853,368 $16,568,614 $5,846,360 $1,713,540 $7,987,841 $6,867,232 % change in Distribution Revenues 15.6% 0.0% 15.0%-41.9%3.9%15.8% % change in Distribution Revenues from Summary tab 15.6% 0.0% 15.0%-41.9%3.9%15.8% Schedule 2.1 Page 2 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 87  Packet Pg. 187 of 211  Prepared By EES Consulting, Inc.Palo Alto Gas Utility INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2026 & Allocation Cost, $Function Factor Classification & Allocation Method Operation & Maintenance Expense Rent Other Transfers $1,779,909 P therm Annual Energy (therm) General Admin & Overhead $55,882 P therm Annual Energy (therm) Commodity Admin & Overhead $410,622 P therm Annual Energy (therm) Alternative Energy Programs $432,697 P therm Annual Energy (therm) Supply Commodity $22,843,053 P therm Annual Energy (therm) Supply Transportation $224,953 P therm Annual Energy (therm) Total Gas Supply $25,747,117 Total Production $25,747,117 Distribution Engineering Support $768,861 D RBD On the Basis of Distribution Rate Base Operations & Maintenance $9,028,547 D RBD On the Basis of Distribution Rate Base Total Distribution $9,797,408 Total Operation & Maintenance $35,544,526 Customer Service, Accounts, & Sales Admin - Customer & Marketing $227,967 D CUSTW Customers Weighted for Accounting/Metering Meter Reading $485,915 D CUSTM Customers Weighted for Meters and Services Utility Billing $543,152 D CUSTW Customers Weighted for Accounting/Metering Credit & Collections $9,850 D CUSTW Customers Weighted for Accounting/Metering Key & Major Accounts $155,106 D DA1 Direct Assignment for Large Commercial Customer Service $1,266,689 D CUSTW2 Customers Weighted for Accounting/Metering w/o G3 Low Income Programs $53,792 D therm Annual Energy (therm) Efficiency - Demand Side Management $465,537 D therm Annual Energy (therm) Total Customer Service, Accounts & Sales $3,208,008 Total O&M w/o Gas Supply & A&G $13,005,416 Administrative & General Administrative & General Salaries $1,451,715 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G) Allocated Charges $2,735,638 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G) Rents $574,830 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G) Transfers to Non-Enterprise Funds $59,411 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G) Transfers to Enterprise Funds $181,333 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G) Total Administrative & General $5,002,927 Total O&M plus A&G $43,755,460 Interest and Debt Service Expense Interest on Long-Term Debt $23,348 D NETPLT On the Basis of Net Plant Principal on Long-Term Debt $778,250 D NETPLT On the Basis of Net Plant System Improvement $7,538,046 D NETPLT On the Basis of Net Plant Total Debt Service /CIP Expense $8,339,643 Schedule 3.1 Page 1 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 88  Packet Pg. 188 of 211  Prepared By EES Consulting, Inc.Palo Alto Gas Utility INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2026 & Allocation Cost, $Function Factor Classification & Allocation Method Operation & Maintenance Expense General Fund Transfer $9,734,580 D REV On The Basis of Revenue General Fund Transfer $9,734,580 Other Contributions Supply Rate Stabilization Funding, portion to pay for supply cost $5,874,887 D therm Annual Energy (therm) Reserves $5,874,887 Revenue Requirement Before Other Revenues $67,704,570 Revenue Req. Before Taxes and Other Revenues $67,704,570 Other Revenues Customer Discounts -$318,105 D NETPLT On the Basis of Net Plant Connection Fees $700,000 D NETPLT On the Basis of Net Plant Misc. Revenue (Other)-$449,823 D NETPLT On the Basis of Net Plant Transfer Credits $131,346 D NETPLT On the Basis of Net Plant Income (Loss) from Equity Investments $625,693 D NETPLT On the Basis of Net Plant Total Other Revenues $689,111 REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply $67,015,459 Schedule 3.1 Page 2 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 89  Packet Pg. 189 of 211  Prepared By EES Consulting, Inc.Palo Alto Gas Utility Total PROJECTED PROJECTED 2021 FY FY FY FY FY Expenses 2022 2023 2024 2025 2026 Operation & Maintenance Expense Rent Other Transfers $1,119,866 $1,610,428 $1,497,489 $1,686,286 $1,676,884 $1,779,909 General Admin & Overhead $143,564 $94,776 $41,008 $46,428 $50,933 $55,882 Commodity Admin & Overhead $135,664 $215,572 $254,699 $341,219 $374,288 $410,622 Alternative Energy Programs $35,053 $229,201 $334,256 $358,209 $393,686 $432,697 Supply Commodity $12,749,972 $24,103,336 $45,926,133 $22,772,125 $23,488,300 $22,843,053 Supply Transportation $236,397 $128,324 $193,614 $193,138 $208,366 $224,953 Total Gas Supply $14,420,516 $26,381,637 $48,247,199 $25,397,406 $26,192,457 $25,747,117 Total Production $14,420,516 $26,381,637 $48,247,199 $25,397,406 $26,192,457 $25,747,117 Distribution Engineering Support $570,710 $659,207 $515,334 $572,847 $710,430 $768,861 Operations & Maintenance $5,482,286 $5,930,678 $6,729,162 $7,629,575 $8,297,561 $9,028,547 Total Distribution $6,052,995 $6,589,885 $7,244,496 $8,202,422 $9,007,991 $9,797,408 Total Operation & Maintenance $20,473,511 $32,971,523 $55,491,694 $33,599,828 $35,200,449 $35,544,526 Customer Service, Accounts, & Sales Admin - Customer & Marketing $161,317 $159,503 $172,850 $188,769 $207,439 $227,967 Meter Reading $338,268 $387,293 $405,687 $405,072 $443,606 $485,915 Utility Billing $351,402 $407,858 $430,968 $449,373 $494,035 $543,152 Credit & Collections $46,751 $4,091 $4,996 $8,446 $9,118 $9,850 Key & Major Accounts $116,248 $109,274 $91,876 $128,535 $141,192 $155,106 Customer Service $890,630 $968,054 $1,002,409 $1,084,631 $1,171,732 $1,266,689 Low Income Programs $12,024 $44,956 $47,739 $50,656 $53,792 Efficiency - Demand Side Management $417,254 $294,307 $309,345 $365,294 $436,300 $465,537 Total Customer Service, Accounts & Sales $2,321,869 $2,342,403 $2,463,086 $2,677,857 $2,954,078 $3,208,008 Total O&M w/o Gas Supply & A&G $8,374,864 $8,932,288 $9,707,582 $10,880,279 $11,962,069 $13,005,416 Administrative & General Administrative & General Salaries $743,079 $1,116,047 $584,536 $624,362 $685,039 $1,451,715 Allocated Charges $1,527,854 $2,001,867 $1,897,412 $2,135,588 $2,715,918 $2,735,638 Rents $471,205 $481,000 $501,000 $526,050 $559,717 $574,830 Transfers to Non-Enterprise Funds $96,985 $115,443 $678,760 $54,929 $57,126 $59,411 Transfers to Enterprise Funds $414,965 $161,320 $171,100 $176,267 $181,333 Total Administrative & General $3,254,087 $3,875,677 $3,661,708 $3,512,028 $4,194,067 $5,002,927 Total O&M plus A&G $26,049,468 $39,189,602 $61,616,488 $39,789,714 $42,348,594 $43,755,460 Schedule 3.2 PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Page 1 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 90  Packet Pg. 190 of 211  Prepared By EES Consulting, Inc.Palo Alto Gas Utility Total PROJECTED PROJECTED 2021 FY FY FY FY FY Expenses 2022 2023 2024 2025 2026 Operation & Maintenance Expense Schedule 3.2 PROJECTED REVENUE REQUIREMENTS Interest and Debt Service Expense Interest on Long-Term Debt $134,622 $108,488 $87,643 $66,144 $45,953 $23,348 Principal on Long-Term Debt $665,500 $693,000 $715,000 $734,250 $753,500 $778,250 System Improvement $9,282,688 $4,674,169 $10,216,894 $7,224,553 $3,682,185 $7,538,046 Total Debt Service /CIP Expense $10,082,810 $5,475,657 $11,019,537 $8,024,947 $4,481,638 $8,339,643 General Fund Transfer $6,847,000 $7,240,000 $6,683,000 $8,215,000 $10,917,195 $9,734,580 General Fund Transfer $6,847,000 $7,240,000 $6,683,000 $8,215,000 $10,917,195 $9,734,580 Other Contributions Supply Rate Stabilization Funding, portion to pay for supply cost -$85,599 -$89,019 -$218,124 $10,407,418 $1,884,104 $5,874,887 Reserves -$85,599 -$89,019 -$218,124 $10,407,418 $1,884,104 $5,874,887 Revenue Requirement Before Other Revenues $42,893,678 $51,816,240 $79,100,901 $66,437,079 $59,631,530 $67,704,570 Revenue Req. Before Taxes and Other Revenues $42,893,678 $51,816,240 $79,100,901 $66,437,079 $59,631,530 $67,704,570 Other Revenues Discounts/Uncollectables -$306,740 -$690,468 -$403,008 $625,296 $348,562 -$318,105 Connection Fees $840,231 $475,239 $413,841 $343,776 $700,000 $700,000 Misc. Revenue (Other)-$18,802 -$259,987 -$80,772 -$429,895 -$283,078 -$449,823 Reimbursements $160,332 $110,184 $110,738 $108,550 $119,405 $131,346 Income (Loss) from Equity Investments $479,407 $426,815 $502,344 $701,607 $610,432 $625,693 Total Other Revenues $1,154,428 $61,782 $543,144 $1,349,335 $1,495,321 $689,111 REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply $41,739,250 $51,754,458 $78,557,757 $65,087,745 $58,136,209 $67,015,459 Schedule 3.2 Page 2 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 91  Packet Pg. 191 of 211  Prepared By EES Consulting, Inc. Allocation Date 2026 Direct Direct Direct Total Energy Assignment Demand Energy Assignment Demand Energy Customer AssignmentExpensesPEPDATDTETDADDDEDCDDA Operation & Maintenance Expense Rent Other Transfers $1,779,909 $1,779,909 General Admin & Overhead $55,882 $55,882 Commodity Admin & Overhead $410,622 $410,622 Alternative Energy Programs $432,697 $432,697 Supply Commodity $22,843,053 $22,843,053 Supply Transportation $224,953 $224,953 Total Gas Supply $25,747,117 $25,747,117 Total Production $25,747,117 $25,747,117 Distribution Engineering Support $768,861 $325,219 $382,685 $60,957 Operations & Maintenance $9,028,547 $3,818,970 $4,493,769 $715,808 Total Distribution $9,797,408 $4,144,190 $4,876,453 $776,765 Total Operation & Maintenance $35,544,526 $25,747,117 $4,144,190 $4,876,453 $776,765 Customer Service, Accounts, & Sales Admin - Customer & Marketing $227,967 $227,967 Meter Reading $485,915 $485,915 Utility Billing $543,152 $543,152 Credit & Collections $9,850 $9,850 Key & Major Accounts $155,106 $155,106 Customer Service $1,266,689 $1,266,689 Low Income Programs $53,792 $53,792 Efficiency - Demand Side Management $465,537 $465,537 Total Customer Service, Accounts & Sales $3,208,008 $519,329 $2,533,573 $155,106 Total O&M w/o Gas Supply & A&G $13,005,416 $4,144,190 $5,395,782 $3,310,338 $155,106 Administrative & General Administrative & General Salaries $1,451,715 $462,590 $602,298 $369,513 $17,314 Allocated Charges $2,735,638 $871,714 $1,134,982 $696,317 $32,626 Rents $574,830 $183,170 $238,489 $146,314 $6,856 Transfers to Non-Enterprise Funds $59,411 $18,931 $24,649 $15,122 $709 Transfers to Enterprise Funds $181,333 $57,782 $75,233 $46,156 $2,163 Total Administrative & General $5,002,927 $1,594,188 $2,075,651 $1,273,422 $59,666 Total O&M plus A&G $43,755,460 $25,747,117 $5,738,378 $7,471,433 $4,583,759 $214,773 Interest and Debt Service Expense Interest on Long-Term Debt $23,348 $9,876 $11,621 $1,851 Principal on Long-Term Debt $778,250 $329,191 $387,358 $61,702 System Improvement $7,538,046 $3,188,506 $3,751,903 $597,637 Total Debt Service /CIP Expense $8,339,643 $3,527,572 $4,150,882 $661,190 General Fund Transfer $9,734,580 $7,503,283 $2,231,297 General Fund Transfer $9,734,580 $7,503,283 $2,231,297 Other Contributions Supply Rate Stabilization Funding, portion to pay for supply cost$5,874,887 $5,874,887 Reserves $5,874,887 $5,874,887 Production Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 Schedule 3.3 Page 1 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 92  Packet Pg. 192 of 211  Prepared By EES Consulting, Inc. Allocation Date 2026 Direct Direct Direct Total Energy Assignment Demand Energy Assignment Demand Energy Customer AssignmentExpensesPEPDATDTETDADDDEDCDDA Operation & Maintenance Expense Production Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 Revenue Requirement Before Other Revenues $67,704,570 $25,747,117 $9,265,950 $25,000,484 $7,476,246 $214,773 Revenue Req. Before Taxes and Other Revenues $67,704,570 $25,747,117 $9,265,950 $25,000,484 $7,476,246 $214,773 Other Revenues Customer Discounts -$318,105 -$134,555 -$158,330 -$25,220 Connection Fees $700,000 $296,092 $348,410 $55,498 Misc. Revenue (Other)-$449,823 -$190,270 -$223,890 -$35,663 Transfer Credits $131,346 $55,558 $65,375 $10,413 Income (Loss) from Equity Investments $625,693 $264,661 $311,426 $49,607 Total Other Revenues $689,111 $291,486 $342,991 $54,635 REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply$67,015,459 $25,747,117 $8,974,464 $24,657,494 $7,421,611 $214,773 REVENUE REQUIREMENT for COST ALLOCATION - Delivery $41,268,342 $8,974,464 $24,657,494 $7,421,611 $214,773 Schedule 3.3 Page 2 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 93  Packet Pg. 193 of 211  Prepared By EES Consulting, Inc. Allocation Date 2026 Total Expenses Operation & Maintenance Expense G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large Rent Other Transfers $1,779,909 $674,040 $311,450 $51,988 $377,592 $364,839 General Admin & Overhead $55,882 $21,162 $9,778 $1,632 $11,855 $11,455 Commodity Admin & Overhead $410,622 $155,500 $71,851 $11,993 $87,110 $84,168 Alternative Energy Programs $432,697 $163,860 $75,714 $12,638 $91,793 $88,693 Supply Commodity $22,843,053 $8,650,515 $3,997,094 $667,202 $4,845,958 $4,682,284 Supply Transportation $224,953 $85,188 $39,363 $6,570 $47,722 $46,110 Total Gas Supply $25,747,117 $9,750,265 $4,505,250 $752,024 $5,462,030 $5,277,548 Total Production $25,747,117 $9,750,265 $4,505,250 $752,024 $5,462,030 $5,277,548 Distribution Engineering Support $768,861 $340,652 $113,249 $21,486 $153,082 $140,392 Operations & Maintenance $9,028,547 $4,000,190 $1,329,855 $252,308 $1,797,604 $1,648,590 Total Distribution $9,797,408 $4,340,842 $1,443,104 $273,794 $1,950,686 $1,788,982 Total Operation & Maintenance $35,544,526 $14,091,108 $5,948,353 $1,025,819 $7,412,716 $7,066,530 Customer Service, Accounts, & Sales Admin - Customer & Marketing $227,967 $179,500 $6,727 $11,970 $23,872 $5,899 Meter Reading $485,915 $359,885 $12,636 $14,516 $65,859 $33,019 Utility Billing $543,152 $427,673 $16,027 $28,520 $56,878 $14,055 Credit & Collections $9,850 $7,756 $291 $517 $1,032 $255 Key & Major Accounts $155,106 $155,106 Customer Service $1,266,689 $1,027,704 $68,533 $136,678 $33,774 Low Income Programs $53,792 $20,371 $9,413 $1,571 $11,411 $11,026 Efficiency - Demand Side Management $465,537 $176,296 $81,460 $13,597 $98,760 $95,424 Total Customer Service, Accounts & Sales $3,208,008 $2,199,184 $281,658 $139,225 $394,490 $193,451 Total O&M w/o Gas Supply & A&G $13,005,416 $6,540,026 $1,724,762 $413,019 $2,345,175 $1,982,434 Administrative & General Administrative & General Salaries $1,451,715 $730,023 $192,525 $46,103 $261,777 $221,287 Allocated Charges $2,735,638 $1,375,669 $362,797 $86,877 $493,298 $416,997 Rents $574,830 $289,064 $76,233 $18,255 $103,655 $87,622 Transfers to Non-Enterprise Funds $59,411 $29,876 $7,879 $1,887 $10,713 $9,056 Transfers to Enterprise Funds $181,333 $91,187 $24,048 $5,759 $32,699 $27,641 Total Administrative & General $5,002,927 $2,515,819 $663,482 $158,880 $902,143 $762,603 Total O&M plus A&G $43,755,460 $18,806,110 $6,893,493 $1,323,924 $8,709,348 $8,022,585 Interest and Debt Service Expense Interest on Long-Term Debt $23,348 $10,344 $3,439 $652 $4,649 $4,263 REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Schedule 3.4 Page 1 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 94  Packet Pg. 194 of 211  Prepared By EES Consulting, Inc. Allocation Date 2026 Total Expenses Operation & Maintenance Expense G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Principal on Long-Term Debt $778,250 $344,812 $114,632 $21,749 $154,951 $142,107 System Improvement $7,538,046 $3,339,809 $1,110,312 $210,655 $1,500,842 $1,376,428 Total Debt Service /CIP Expense $8,339,643 $3,694,965 $1,228,383 $233,056 $1,660,442 $1,522,798 General Fund Transfer $9,734,580 $4,183,095 $1,303,244 $756,248 $1,970,979 $1,521,015 General Fund Transfer $9,734,580 $4,183,095 $1,303,244 $756,248 $1,970,979 $1,521,015 Other Contributions Supply Rate Stabilization Funding, portion to pay for supply cost $5,874,887 $2,224,781 $1,027,992 $171,594 $1,246,307 $1,204,212 Reserves $5,874,887 $2,224,781 $1,027,992 $171,594 $1,246,307 $1,204,212 Revenue Requirement Before Other Revenues $67,704,570 $28,908,951 $10,453,112 $2,484,822 $13,587,075 $12,270,610 Revenue Req. Before Taxes and Other Revenues $67,704,570 $28,908,951 $10,453,112 $2,484,822 $13,587,075 $12,270,610 Other Revenues Customer Discounts -$318,105 -$140,940 -$46,855 -$8,890 -$63,335 -$58,085 Connection Fees $700,000 $310,142 $103,106 $19,562 $139,372 $127,818 Misc. Revenue (Other)-$449,823 -$199,299 -$66,256 -$12,571 -$89,561 -$82,137 Transfer Credits $131,346 $58,194 $19,347 $3,671 $26,151 $23,983 Income (Loss) from Equity Investments $625,693 $277,220 $92,161 $17,485 $124,577 $114,250 Total Other Revenues $689,111 $305,318 $101,502 $19,258 $137,204 $125,830 REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply $67,015,459 $28,603,633 $10,351,610 $2,465,565 $13,449,871 $12,144,780 REVENUE REQUIREMENT for COST ALLOCATION - Delivery $41,268,342 $18,853,368 $5,846,360 $1,713,540 $7,987,841 $6,867,232 Schedule 3.4 Page 2 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 95  Packet Pg. 195 of 211  Prepared By EES Consulting, Inc. Allocation Date 2026 Total Expenses Operation & Maintenance Expense G1 Residential G3 Large Commercial G2 Commercial G2 - Medium G2 - Large Rent Other Transfers General Admin & Overhead Commodity Admin & Overhead Alternative Energy Programs Supply Commodity Supply Transportation Total Gas Supply Total Production Distribution Engineering Support Operations & Maintenance Total Distribution Total Operation & Maintenance Customer Service, Accounts, & Sales Admin - Customer & Marketing Meter Reading Utility Billing Credit & Collections Key & Major Accounts $155,106 $155,106 Customer Service Low Income Programs Efficiency - Demand Side Management Total Customer Service, Accounts & Sales $155,106 $155,106 Total O&M w/o Gas Supply & A&G $155,106 $155,106 Administrative & General REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Schedule 3.5 Page 1 of 3 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 96  Packet Pg. 196 of 211  Prepared By EES Consulting, Inc. Allocation Date 2026 Total Expenses Operation & Maintenance Expense G1 Residential G3 Large Commercial G2 Commercial G2 - Medium G2 - Large REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Administrative & General Salaries $17,314 $17,314 Allocated Charges $32,626 $32,626 Rents $6,856 $6,856 Transfers to Non-Enterprise Funds $709 $709 Transfers to Enterprise Funds $2,163 $2,163 Total Administrative & General $59,666 $59,666 Total O&M plus A&G $214,773 $214,773 Interest and Debt Service Expense Interest on Long-Term Debt Principal on Long-Term Debt System Improvement Total Debt Service /CIP Expense General Fund Transfer General Fund Transfer Other Contributions Supply Rate Stabilization Funding, portion to pay for supply cost Reserves Revenue Requirement Before Other Revenues $214,773 $214,773 Revenue Req. Before Taxes and Other Revenues $214,773 $214,773 Other Revenues Customer Discounts Connection Fees Misc. Revenue (Other) Schedule 3.5 Page 2 of 3 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 97  Packet Pg. 197 of 211  Prepared By EES Consulting, Inc. Allocation Date 2026 Total Expenses Operation & Maintenance Expense G1 Residential G3 Large Commercial G2 Commercial G2 - Medium G2 - Large REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Transfer Credits Income (Loss) from Equity Investments Total Other Revenues REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply$214,773 $214,773 Schedule 3.5 Page 3 of 3 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 98  Packet Pg. 198 of 211  Prepared By EES Consulting, Inc. Palo Alto Gas Utility INPUT RATE BASE Schedule 4.1 Year Classification 2022 & Allocation Cost, $ Function Factor Classification & Allocation Method FERC Account Distribution Plant 56670 Equip-Meters $12,334,716 D CUSTM Customers Weighted for Meters and Services 56680 Equip-Services $59,109,371 D AE Average and Excess 56710 Equip-Misc $2,729,148 D AE Average and Excess 56840 Equipment-Regulators $976,067 D AE Average and Excess 56850 Equip-Distribution Mains $77,559,779 D AE Average and Excess 56860 Equip-Measuring $2,869,793 D AE Average and Excess Total Distribution Plant $155,578,873 Total Transmission & Distribution $155,578,873 General Plant 56400 Building-Gen Plant $1,910,425 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 56700 Equip-Gen Plant $2,911,310 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) Total General Plant $4,821,735 Total Plant Before General Plant & Intangible $155,578,873 Total Gross Plant in Service $160,400,608 Less: Accumulated Depreciation Distribution Plant $49,833,503 D RBD On the Basis of Distribution Rate Base General Plant $3,812,789 D RBGP On the Basis of General Plant Rate Base Total Accumulated Depreciation $53,646,292 Total Net Plant $106,754,316 Working Capital 1/8 O&M $2,251,043 D OMWOP On the Basis of O&M (w/o Purch. Gas Supply) Total Working Capital $2,251,043 TOTAL RATE BASE $109,005,358 CWIP Distribution Plant $6,127,014 D RBD On the Basis of Distribution Rate Base General Plant $1,902,306 SS RBGP On the Basis of General Plant Rate Base Total CWIP $8,029,320 TOTAL RATE BASE plus CWIP $117,034,679 Schedule 4.1 Page 1 of 1 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 99  Packet Pg. 199 of 211  Prepared By EES Consulting, Inc. FERC Account 56670 56680 56710 56840 56850 56860 56400 56700 Direct Total Demand Energy Customer Assignment Account Description Rate Base DD DE DC DDA Distribution Plant Equip-Meters $12,334,716 $12,334,716 Equip-Services $59,109,371 $27,155,542 $31,953,829 Equip-Misc $2,729,148 $1,253,803 $1,475,345 Equipment-Regulators $976,067 $448,417 $527,650 Equip-Distribution Mains $77,559,779 $35,631,877 $41,927,902 Equip-Measuring $2,869,793 $1,318,417 $1,551,376 Total Distribution Plant $155,578,873 $65,808,054 $77,436,103 $12,334,716 Total Transmission & Distribution $155,578,873 $65,808,054 $77,436,103 $12,334,716 General Plant Building-Gen Plant $1,910,425 $808,088 $950,874 $151,464 Equip-Gen Plant $2,911,310 $1,231,450 $1,449,043 $230,817 Total General Plant $4,821,735 $2,039,538 $2,399,917 $382,280 Total Plant Before General Plant & Intangible $155,578,873 $65,808,054 $77,436,103 $12,334,716 Total Gross Plant in Service $160,400,608 $67,847,592 $79,836,020 $12,716,996 Less: Accumulated Depreciation Distribution Plant $49,833,503 $21,078,993 $24,803,575 $3,950,936 General Plant $3,812,789 $1,612,765 $1,897,735 $302,288 Total Accumulated Depreciation $53,646,292 $22,691,758 $26,701,310 $4,253,224 Total Net Plant $106,754,316 $45,155,834 $53,134,709 $8,463,772 Working Capital RATE BASE FOR COST ALLOCATION Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 4.2 Schedule 4.2 Page 1 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 100  Packet Pg. 200 of 211  Prepared By EES Consulting, Inc. FERC Account Direct Total Demand Energy Customer Assignment Account Description Rate Base DD DE DC DDA RATE BASE FOR COST ALLOCATION Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 4.2 1/8 O&M $2,251,043 $717,297 $933,929 $572,970 $26,847 Total Working Capital $2,251,043 $717,297 $933,929 $572,970 $26,847 TOTAL RATE BASE $109,005,358 $45,873,132 $54,068,638 $9,036,742 $26,847 CWIP Distribution Plant $6,127,014 $2,591,656 $3,049,592 $485,766 General Plant $1,902,306 $804,653 $946,833 $150,820 Total CWIP $8,029,320 $3,396,309 $3,996,425 $636,586 TOTAL RATE BASE plus CWIP $117,034,679 $49,269,441 $58,065,063 $9,673,328 $26,847 Schedule 4.2 Page 2 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 101  Packet Pg. 201 of 211  Prepared By EES Consulting, Inc. FERC Account 56670 56680 56710 56840 56850 56860 56400 56700 Palo Alto Gas Utility - Average and Excess Method (AE) Account Description Total Rate Base G1 Residential G2 Commercial G3 Large Commercial G2 - Small G2 - Medium G2 - Large Distribution Plant Equip-Meters $12,334,716 $9,135,516 $2,878,448 $320,752 $368,469 $1,671,799 $838,180 Equip-Services $59,109,371 $24,674,393 $25,111,143 $9,323,835 $1,642,039 $12,092,352 $11,376,752 Equip-Misc $2,729,148 $1,139,245 $1,159,411 $430,492 $75,815 $558,318 $525,278 Equipment-Regulators $976,067 $407,446 $414,658 $153,963 $27,115 $199,680 $187,863 Equip-Distribution Mains $77,559,779 $32,376,261 $32,949,339 $12,234,179 $2,154,585 $15,866,861 $14,927,893 Equip-Measuring $2,869,793 $1,197,956 $1,219,160 $452,677 $79,722 $587,090 $552,348 Total Distribution Plant $155,578,873 $68,930,816 $63,732,158 $22,915,899 $4,347,745 $30,976,100 $28,408,313 Total Transmission & Distribution $155,578,873 $68,930,816 $63,732,158 $22,915,899 $4,347,745 $30,976,100 $28,408,313 General Plant Building-Gen Plant $1,910,425 $846,434 $782,597 $281,395 $53,388 $380,370 $348,839 Equip-Gen Plant $2,911,310 $1,289,886 $1,192,604 $428,820 $81,358 $579,648 $531,598 Total General Plant $4,821,735 $2,136,319 $1,975,201 $710,215 $134,746 $960,018 $880,437 Total Plant Before General Plant & Intangible $155,578,873 $68,930,816 $63,732,158 $22,915,899 $4,347,745 $30,976,100 $28,408,313 Total Gross Plant in Service $160,400,608 $71,067,135 $65,707,359 $23,626,113 $4,482,492 $31,936,118 $29,288,750 Less: Accumulated Depreciation Distribution Plant $49,833,503 $22,079,245 $20,414,062 $7,340,197 $1,392,627 $9,921,961 $9,099,473 General Plant $3,812,789 $1,689,295 $1,561,891 $561,602 $106,551 $759,135 $696,206 Total Accumulated Depreciation $53,646,292 $23,768,540 $21,975,953 $7,901,799 $1,499,178 $10,681,096 $9,795,679 Total Net Plant $106,754,316 $47,298,595 $43,731,406 $15,724,314 $2,983,314 $21,255,022 $19,493,071 Working Capital 1/8 O&M $2,251,043 $1,131,981 $820,532 $298,530 $71,487 $405,915 $343,130 Total Working Capital $2,251,043 $1,131,981 $820,532 $298,530 $71,487 $405,915 $343,130 TOTAL RATE BASE $109,005,358 $48,430,576 $44,551,938 $16,022,845 $3,054,801 $21,660,936 $19,836,201 CWIP Distribution Plant $6,127,014 $2,714,637 $2,509,903 $902,475 $171,223 $1,219,902 $1,118,777 RATE BASE COST ALLOCATION CLASSIFICATION BY CUSTOMER Schedule 4.3 Schedule 4.3 Page 1 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 102  Packet Pg. 202 of 211  Prepared By EES Consulting, Inc. FERC Account Palo Alto Gas Utility - Average and Excess Method (AE) Account Description Total Rate Base G1 Residential G2 Commercial G3 Large Commercial G2 - Small G2 - Medium G2 - Large RATE BASE COST ALLOCATION CLASSIFICATION BY CUSTOMER Schedule 4.3 General Plant $1,902,306 $842,836 $779,271 $280,199 $53,161 $378,753 $347,356 Total CWIP $8,029,320 $3,557,473 $3,289,173 $1,182,674 $224,384 $1,598,655 $1,466,134 TOTAL RATE BASE plus CWIP $117,034,679 $51,988,048 $47,841,112 $17,205,519 $3,279,185 $23,259,592 $21,302,334 Schedule 4.3 Page 2 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 103  Packet Pg. 203 of 211  Prepared By EES Consulting, Inc. FERC Account 56670 56680 56710 56840 56850 56860 56400 56700 Palo Alto Gas Utility - Average and Excess Method (AE) Account Description Total Rate Base G1 Residential G2 - All G3 Large Commercial Distribution Plant Equip-Meters Equip-Services Equip-Misc Equipment-Regulators Equip-Distribution Mains Equip-Measuring Total Distribution Plant Total Transmission & Distribution General Plant Building-Gen Plant Equip-Gen Plant Total General Plant Total Plant Before General Plant & Intangible Total Gross Plant in Service Less: Accumulated Depreciation Distribution Plant General Plant Total Accumulated Depreciation RATE BASE COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 4.4 Schedule 4.4 Page 1 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 104  Packet Pg. 204 of 211  Prepared By EES Consulting, Inc. FERC Account Palo Alto Gas Utility - Average and Excess Method (AE) Account Description Total Rate Base G1 Residential G2 - All G3 Large Commercial RATE BASE COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 4.4 Total Net Plant Working Capital 1/8 O&M $26,847 $26,847 Total Working Capital $26,847 $26,847 TOTAL RATE BASE $26,847 $26,847 CWIP Distribution Plant General Plant Total CWIP TOTAL RATE BASE plus CWIP $26,847 $26,847 Schedule 4.4 Page 2 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 105  Packet Pg. 205 of 211  Prepared By EES Consulting, Inc. Palo Alto Gas Utility 2025 Total G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large Number of Customers Jul-25 23,735 21,503 - 30 1,145 939 118 Aug-25 23,936 21,690 - 30 1,152 947 117 Sep-25 22,632 20,404 - 30 1,134 946 118 Oct-25 23,790 21,558 - 31 1,138 946 117 Nov-25 23,694 21,474 - 28 1,136 940 116 Dec-25 23,391 21,178 - 30 1,129 940 114 Jan-26 23,752 21,508 - 30 1,147 950 117 Feb-26 23,158 20,947 - 31 1,120 949 111 Mar-26 23,636 21,443 - 29 1,124 927 113 Apr-26 23,117 20,894 - 29 1,137 937 120 May-26 23,218 21,012 - 28 1,118 943 117 Jun-26 23,663 21,446 - 28 1,127 943 119 Total / Average 23,477 21,255 30 1,134 942 116 Customer Charge Revenues Rate: $/Month $16.93 $156.90 $717.89 $156.90 $156.90 $156.90 Jul-25 $731,072 $364,041 $21,537 $179,651 $147,329 $18,514 Aug-25 $736,432 $367,205 $21,537 $180,749 $148,584 $18,357 Sep-25 $711,845 $345,442 $21,537 $177,925 $148,427 $18,514 Oct-25 $732,576 $364,984 $22,255 $178,552 $148,427 $18,357 Nov-25 $727,586 $363,561 $20,101 $178,238 $147,486 $18,200 Dec-25 $722,593 $358,544 $21,537 $177,140 $147,486 $17,887 Jan-26 $733,050 $364,137 $21,537 $179,964 $149,055 $18,357 Feb-26 $718,925 $354,629 $22,255 $175,728 $148,898 $17,416 Mar-26 $723,386 $363,035 $20,819 $176,356 $145,446 $17,730 Apr-26 $718,787 $353,729 $20,819 $178,395 $147,015 $18,828 May-26 $717,560 $355,730 $20,101 $175,414 $147,957 $18,357 Jun-26 $726,641 $363,086 $20,101 $176,826 $147,957 $18,671 Total $8,700,453 $4,318,124 $254,133 $2,134,938 $1,774,068 $219,189 Forecast Therms Jul-25 1,295,010 329,344 - 311,858 39,430 305,711 308,667 Aug-25 1,202,729 297,815 - 299,554 44,035 281,424 279,902 Sep-25 1,183,613 302,266 - 281,717 37,800 287,018 274,812 Oct-25 1,394,195 383,267 - 313,156 49,422 353,322 295,027 Nov-25 1,873,214 770,841 - 344,487 42,632 332,849 382,405 FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Schedule 7.1 Page 1 of 3 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 106  Packet Pg. 206 of 211  Prepared By EES Consulting, Inc. 2025 Total G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Dec-25 2,856,282 1,300,253 - 399,645 81,682 561,375 513,328 Jan-26 3,583,858 1,659,415 - 492,602 93,535 701,266 637,041 Feb-26 3,163,932 1,396,643 - 449,567 92,845 641,953 582,923 Mar-26 3,103,871 1,366,526 - 444,411 88,902 619,516 584,516 Apr-26 2,609,800 927,315 - 443,470 76,982 557,552 604,479 May-26 1,960,064 614,608 - 391,055 57,905 448,156 448,340 Jun-26 1,552,922 414,232 - 339,393 47,798 378,755 372,743 Total / Average 25,779,489 9,762,524 - 4,510,914 752,970 5,468,897 5,284,184 Energy Rates Flat Rate:Flat Rate $/Therm $1.08090 $1.07020 $1.08090 $1.08090 $1.08090 1st Block $/Therm $0.822900 2nd Block $/Therm $2.104300 3rd Block $/Therm 4th Block $/Therm Energy Revenues Jul-25 $1,404,271 $363,820 $333,750 $42,620 $330,443 $333,638 Aug-25 $1,290,245 $315,328 $320,583 $47,598 $304,191 $302,546 Sep-25 $1,281,178 $331,544 $301,493 $40,859 $310,238 $297,044 Oct-25 $1,568,687 $479,325 $335,140 $53,421 $381,906 $318,895 Nov-25 $2,114,273 $926,405 $368,670 $46,081 $359,776 $413,341 Dec-25 $3,200,805 $1,523,169 $427,700 $88,290 $606,791 $554,856 Jan-26 $4,280,735 $2,205,875 $527,182 $101,102 $757,999 $688,578 Feb-26 $3,631,914 $1,726,462 $481,126 $100,357 $693,887 $630,082 Mar-26 $3,480,774 $1,607,633 $475,609 $96,094 $669,635 $631,803 Apr-26 $2,968,472 $1,154,620 $474,602 $83,210 $602,658 $653,382 May-26 $2,322,725 $872,606 $418,507 $62,589 $484,412 $484,611 Jun-26 $1,713,329 $486,150 $363,219 $51,665 $409,397 $402,898 Subtotal $29,257,410 $11,992,939 $4,827,580 $813,885 $5,911,331 $5,711,674 Surcharge Total $29,257,410 $11,992,939 $4,827,580 $813,885 $5,911,331 $5,711,674 Schedule 7.1 Page 2 of 3 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 107  Packet Pg. 207 of 211  Prepared By EES Consulting, Inc. 2025 Total G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Total Revenues - Distribution G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large Jul-25 $2,135,343 $727,861 $355,287 $222,271 $477,772 $352,152 Aug-25 $2,026,677 $682,533 $342,119 $228,346 $452,775 $320,903 Sep-25 $1,993,023 $676,986 $323,030 $218,783 $458,665 $315,558 Oct-25 $2,301,263 $844,310 $357,394 $231,973 $530,333 $337,252 Nov-25 $2,841,860 $1,289,965 $388,771 $224,320 $507,262 $431,542 Dec-25 $3,923,399 $1,881,713 $449,236 $265,430 $754,277 $572,743 Jan-26 $5,013,786 $2,570,013 $548,719 $281,066 $907,054 $706,935 Feb-26 $4,350,840 $2,081,091 $503,381 $276,085 $842,785 $647,498 Mar-26 $4,204,160 $1,970,668 $496,427 $272,450 $815,081 $649,533 Apr-26 $3,687,259 $1,508,350 $495,421 $261,605 $749,674 $672,210 May-26 $3,040,284 $1,228,337 $438,608 $238,004 $632,369 $502,968 Jun-26 $2,439,970 $849,236 $383,320 $228,491 $557,353 $421,569 Subtotal $37,957,863 $16,311,063 $5,081,713 $2,948,824 $7,685,399 $5,930,863 Surcharge Total $37,957,863 $16,311,063 $5,081,713 $2,948,824 $7,685,399 $5,930,863 Schedule 7.1 Page 3 of 3 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 108  Packet Pg. 208 of 211  Prepared By EES Consulting, Inc. Forecast Rate Class Customer Count Total G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large Jul-25 23,735 21,503 30 1,145 939 118 Aug-25 23,936 21,690 30 1,152 947 117 Sep-25 22,632 20,404 30 1,134 946 118 Oct-25 23,790 21,558 31 1,138 946 117 Nov-25 23,694 21,474 28 1,136 940 116 Dec-25 23,391 21,178 30 1,129 940 114 Jan-26 23,752 21,508 30 1,147 950 117 Feb-26 23,158 20,947 31 1,120 949 111 Mar-26 23,636 21,443 29 1,124 927 113 Apr-26 23,117 20,894 29 1,137 937 120 May-26 23,218 21,012 28 1,118 943 117 Jun-26 23,663 21,446 28 1,127 943 119 Total Average Forecast Customers 23,477 21,255 30 1,134 942 116 Schedule 8.1 Page 1 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 109  Packet Pg. 209 of 211  Prepared By EES Consulting, Inc. Customer Information Total G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large Weighting Factors for: Customers Meters & Services 414.00$ 1,262.00$ 10,473.00$ 313.00$ 1,709.00$ 6,935.00$ Customer Billing and Collection 1.00 1.25 27.00 1.25 3.00 6.00 Customer Billing and Collection w/o G3 1.00 1.25 1.25 3.00 6.00 Weighted Number of Customers Customers Meters & Services 11,881,010 8,799,486 - 308,954 354,916 1,610,305 807,350 Customer Billing and Collection 26,994 21,255 - 797 1,417 2,827 699 Customer Billing and Collection w/o G3 26,197 21,255 - - 1,417 2,827 699 Test Date Forecast Rate Class Sales therm Total G1 Residential G2 - All G3 Large Commercial G2 - Small G2 - Medium G2 - Large Jul-25 1,295,010 329,344 311,858 39,430 305,711 308,667 Aug-25 1,202,729 297,815 299,554 44,035 281,424 279,902 Sep-25 1,183,613 302,266 281,717 37,800 287,018 274,812 Oct-25 1,394,195 383,267 313,156 49,422 353,322 295,027 Nov-25 1,873,214 770,841 344,487 42,632 332,849 382,405 Dec-25 2,856,282 1,300,253 399,645 81,682 561,375 513,328 Jan-26 3,583,858 1,659,415 492,602 93,535 701,266 637,041 Feb-26 3,163,932 1,396,643 449,567 92,845 641,953 582,923 Mar-26 3,103,871 1,366,526 444,411 88,902 619,516 584,516 Apr-26 2,609,800 927,315 443,470 76,982 557,552 604,479 May-26 1,960,064 614,608 391,055 57,905 448,156 448,340 Jun-26 1,552,922 414,232 339,393 47,798 378,755 372,743 Total Sales 25,779,489 9,762,524 4,510,914 752,970 5,468,897 5,284,184 Schedule 8.1 Page 2 of 2 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 110  Packet Pg. 210 of 211  Prepared By EES Consulting, Inc. Calculation of AE Allocation Method Total G1 Residential G3 Large Commercial G2 Small G2 Medium G2 Large Annual Sales, Therms 25,779,489 9,762,524 4,510,914 752,970 5,468,897 5,284,184 Jul-25 1,741 443 419 53 411 415 Aug-25 1,790 443 446 66 419 417 Sep-25 1,591 406 379 51 386 369 Oct-25 1,936 532 435 69 491 410 Nov-25 2,518 1,036 463 57 447 514 Dec-25 3,967 1,806 555 113 780 713 Jan-26 4,817 2,230 662 126 943 856 Feb-26 4,253 1,877 604 125 863 783 Mar-26 4,311 1,898 617 123 860 812 Apr-26 3,508 1,246 596 103 749 812 May-26 2,722 854 543 80 622 623 Jun-26 2,087 557 456 64 509 501 Min therm/hr 1,591 406 379 51 386 369 Max therm/hr 4,817 2230 662 126 943 856 Share of max therms 100%46%14%3%20%18% Min Therms 13,936,088 3,558,936 3,316,990 445,070 3,379,404 3,235,688 100%26%24%3%24%23% Excess therms 11,843,401 6,203,589 1,193,924 307,900 2,089,494 2,048,495 100%52%10%3%18%17% Average Use 2,937 1,111 515 86 623 602 Excess Use 4,817 2,230 662 126 943 856 Average + Excess 7,754 3,341 1,177 212 1,566 1,458 43%15%3%20%19% Customer or Minimum Therms 54%36%74%59%62%61% Demand 46% 64% 26% 41% 38% 39% Tier 1 6,672,656 68%36% Tier 2 3,089,869 Tier 1 Demand Costs 54.4% Schedule 6.5 Page 1 of 1 Item 2 Attachment G - Natural Gas Cost of Service Schedules        Item 2: Staff Report Pg. 111  Packet Pg. 211 of 211