HomeMy WebLinkAbout2023-11-07 Finance Committee Agenda PacketFINANCE COMMITTEE
Regular Meeting
Tuesday, November 07, 2023
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. To maximize public safety while still maintaining
transparency and public access, members of the public can choose to participate from home or
attend in person. Information on how the public may observe and participate in the meeting is
located at the end of the agenda. Masks are strongly encouraged if attending in person. The
m e e t i n g w i l l b e b r o a d c a s t o n C a b l e T V C h a n n e l 2 6 , l i v e o n
YouTube https://www.youtube.com/c/cityofpaloalto, 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
Public comments will be accepted both in person and via Zoom for up to three minutes or an
amount of time determined by the Chair. All requests to speak will be taken until 5 minutes
after the staff’s presentation. Written public comments can be submitted in advance to
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.
CALL TO ORDER
PUBLIC COMMENT
Members of the public may speak to any item NOT on the agenda.
ACTION ITEMS
1.Utilities Advisory Commission Recommendation that the Finance Committee Recommend
that the City Council Adopt a Resolution Approving the 2023 Electric Integrated Resource
Plan
2.Discussion and Update of the Palo Alto Fiber Expansion Plan and Construction Alignment
with Electric Grid Modernization. CEQA Status – Not a project.
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 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 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.
1 Regular Meeting November 07, 2023
Materials related to an item on this agenda submitted to the Board after distribution of the agenda packet are
available for public inspection at www.CityofPaloAlto.org.
FINANCE COMMITTEERegular MeetingTuesday, November 07, 2023Community Meeting Room & Hybrid5:30 PMFinance Committee meetings will be held as “hybrid” meetings with the option to attend byteleconference/video conference or in person. To maximize public safety while still maintainingtransparency and public access, members of the public can choose to participate from home orattend in person. Information on how the public may observe and participate in the meeting islocated at the end of the agenda. Masks are strongly encouraged if attending in person. Them e e t i n g w i l l b e b r o a d c a s t o n C a b l e T V C h a n n e l 2 6 , l i v e o nYouTube https://www.youtube.com/c/cityofpaloalto, and streamed to Midpen MediaCenter 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 COMMENTSPublic comments will be accepted both in person and via Zoom for up to three minutes or anamount of time determined by the Chair. All requests to speak will be taken until 5 minutesafter the staff’s presentation. Written public comments can be submitted in advance tocity.council@CityofPaloAlto.org and will be provided to the Council and available for inspectionon the City’s website. Please clearly indicate which agenda item you are referencing in yoursubject 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.
CALL TO ORDER
PUBLIC COMMENT
Members of the public may speak to any item NOT on the agenda.
ACTION ITEMS
1.Utilities Advisory Commission Recommendation that the Finance Committee Recommend
that the City Council Adopt a Resolution Approving the 2023 Electric Integrated Resource
Plan
2.Discussion and Update of the Palo Alto Fiber Expansion Plan and Construction Alignment
with Electric Grid Modernization. CEQA Status – Not a project.
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 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 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.
2 Regular Meeting November 07, 2023
Materials related to an item on this agenda submitted to the Board after distribution of the agenda packet are
available for public inspection at www.CityofPaloAlto.org.
FINANCE COMMITTEERegular MeetingTuesday, November 07, 2023Community Meeting Room & Hybrid5:30 PMFinance Committee meetings will be held as “hybrid” meetings with the option to attend byteleconference/video conference or in person. To maximize public safety while still maintainingtransparency and public access, members of the public can choose to participate from home orattend in person. Information on how the public may observe and participate in the meeting islocated at the end of the agenda. Masks are strongly encouraged if attending in person. Them e e t i n g w i l l b e b r o a d c a s t o n C a b l e T V C h a n n e l 2 6 , l i v e o nYouTube https://www.youtube.com/c/cityofpaloalto, and streamed to Midpen MediaCenter 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 COMMENTSPublic comments will be accepted both in person and via Zoom for up to three minutes or anamount of time determined by the Chair. All requests to speak will be taken until 5 minutesafter the staff’s presentation. Written public comments can be submitted in advance tocity.council@CityofPaloAlto.org and will be provided to the Council and available for inspectionon the City’s website. Please clearly indicate which agenda item you are referencing in yoursubject 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.CALL TO ORDERPUBLIC COMMENT Members of the public may speak to any item NOT on the agenda.ACTION ITEMS1.Utilities Advisory Commission Recommendation that the Finance Committee Recommendthat the City Council Adopt a Resolution Approving the 2023 Electric Integrated ResourcePlan2.Discussion and Update of the Palo Alto Fiber Expansion Plan and Construction Alignmentwith Electric Grid Modernization. CEQA Status – Not a project.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 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 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.
3 Regular Meeting November 07, 2023
Materials related to an item on this agenda submitted to the Board after distribution of the agenda packet are
available for public inspection at www.CityofPaloAlto.org.
Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Utilities
Meeting Date: November 7, 2023
Staff Report: 2307-1749
TITLE
Utilities Advisory Commission Recommendation that the Finance Committee Recommend that
the City Council Adopt a Resolution Approving the 2023 Electric Integrated Resource Plan
RECOMMENDATION
Staff and the Utilities Advisory Commission (UAC) recommend that the Finance Committee
recommend that the City Council adopt a resolution (Attachment A):
1. Approving the 2023 Electric Integrated Resource Plan (IRP)1 , which includes the four
standardized tables required under the California Energy Commission’s (CEC) IRP
Guidelines; and
2. Approving the IRP Objective and Strategies to guide future analysis and decisions2 .
EXECUTIVE SUMMARY
In 2018, staff completed, and the City Council approved, the City’s first IRP—a comprehensive
long-term electric supply planning document that the City is required to complete every five
years under state law. With this report, staff presents the City’s second IRP report to the UAC for
review and recommendation to approve.
The current IRP, which must be approved by Council by January 1, 2024 in order to satisfy the
City’s regulatory requirements, has a planning period of 2023 through 2045. The City of Palo Alto
Utilities (CPAU) currently has sufficient carbon-neutral supply resources to meet projected loads
through 2028, with approximately 40% of its resources projected to come from hydroelectric
supplies and the remaining 60% from renewable energy contracts. The City’s projected load is
1 2023 Electric Integrated Resource Plan https://www.cityofpaloalto.org/files/assets/public/v/1/agendas-minutes-
reports/reports/city-manager-reports-cmrs/attachments/11-07-2023-id-2307-1749-2023-integrated-resource-
plan.pdf
2 Integrated Resource Plan Objectives and Strategies
https://www.cityofpaloalto.org/files/assets/public/v/1/agendas-minutes-reports/reports/city-manager-reports-
cmrs/attachments/11-07-2023-id-2307-1749-integrated-resource-plan-objective-and-strategies.pdf
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Packet Pg. 4
expected to increase significantly over the next several years, largely due to new data center
projects being implemented by multiple large commercial customers, along with the effects of
the City’s building and transportation electrification efforts. A primary focus of this IRP, therefore,
is determining the optimal mix of resources to use to satisfy this growing load. Additionally, the
City’s 20-year contract with the Western Area Power Administration (WAPA) for hydroelectric
resources, which supplies over 30% of the City’s energy needs in a normal hydro year, expires at
the end of calendar year 2024. As with the 2018 IRP, another focus of the current IRP is
determining whether to renew the contract with WAPA for an additional 30-year term (and if so,
at what participation level) and/or seek other renewable supplies to meet City loads.
The IRP includes a set of four standardized tables, which detail the City’s energy, renewable
energy, capacity, and greenhouse gas (GHG) emissions projections through 2045, as well as the
latest versions of the City’s Renewable Portfolio Standard (RPS) Procurement Plan.
In addition to the City’s 2023 IRP and its associated documents, this report includes proposed IRP
Objective and Strategies to guide future analysis and decisions as staff works to prepare the City’s
electric supply portfolio for the upcoming shifts in the electric utility industry.
BACKGROUND
Prior to 2018, the City engaged in integrated resource planning through periodic updates to its
Long-term Electric Acquisition Plan (LEAP)3. On April 16, 2012 Council adopted Resolution 92414,
in accordance with the Staff Report 2710. But in 2015, SB 350 was signed into law, and it includes
a requirement that publicly-owned utilities (POUs) serving loads greater than 700,000 megawatt-
hours per year, such as Palo Alto, develop and adopt an IRP and submit it to the California Energy
Commission (CEC) by January 2019 and every five years thereafter.5
The current IRP planning period is from 2023 through 2045. As noted in the IRP report, through
2028 the City expects to have sufficient resources to meet its forecasted electric loads, with
renewable power contracts supplying about 60% of its needs and the remainder coming from
hydroelectric resources. This all assumes that the City renews its contract for the Western
hydroelectric resource which expires at the end of 2024 for an additional 30-year period. The City
also has the option to reduce its allocation under this contract (or exit it altogether) until July 1,
2024. And if the City does renew the Western contract, it will also have the option to reduce its
allocation or exit the contract once every five years throughout the 30-year contract term.
3 The City’s last LEAP update was approved by Council on April 16, 2012
https://www.cityofpaloalto.org/files/assets/public/v/1/agendas-minutes-reports/reports/city-manager-reports-
cmrs/year-archive/2012/04-16-2012-id-2710.pdf
4 April 16, 2012 Resolution 9241 https://www.cityofpaloalto.org/files/assets/public/v/1/agendas-minutes-
reports/reports/city-manager-reports-cmrs/attachments/04-16-2012-id-2710-resolution-9241.pdf
5 The Clean Energy and Pollution Reduction Act of 2015 also raised the state’s renewable portfolio standard (RPS)
to 50% by 2030 and required a doubling of energy efficiency savings by 2030. (The RPS requirement was later
increased to 60% by 2030 via SB 100.) The primary objective of the IRP requirement in SB 350 is to ensure that the
state’s large POUs are on track to reduce their greenhouse gas emissions, helping the state meet its overall target
of reducing GHG emissions to 40% below 1990 levels by 2030.
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Therefore, a significant consideration for the IRP is the question of whether to renew the contract
with Western (and if so, at what participation level) and/or seek other carbon neutral power
supplies. Staff presented a preliminary analysis of the City’s long-term electric supply portfolio
and a variety of potential new resource options, along with an update to its long-term load
forecast, to the UAC for discussion in July 2023.
Beginning in June 2022, staff has presented five different reports to the UAC and Council
(including the present one) directly or indirectly related to the development of Palo Alto’s 2023
IRP. These presentations and reports are summarized in Table 1 below.
Table 1: Public Process Summary for Development of the 2023 IRP
Forum Date Topic Link
UAC 6/8/2022 Overview of CPAU’s IRP Development Process Report6
UAC 12/7/2022 Discussion of CPAU’s Long-term Electric Load Forecast Report7
UAC 7/5/2023 Presentation of Electric Supply Portfolio Modeling Results Presentation
8
Council 9/18/2023 Annual Carbon Neutral Plan and RPS Supply Update Report
UAC 10/11/2023 Recommendation to Approve CPAU’s 2023 IRP Report9
Finance 11/7/2023 Recommendation to Approve CPAU’s 2023 IRP TBD
Through these presentations and discussions, staff has laid out the motivations and context for
the IRP, and described the resources currently in the City’s supply portfolio as well as the
upcoming planning decisions and uncertainties facing the City. Staff felt that this level of public
discussion was important given that the City must make some important planning decisions in
the next several years.
CEC IRP Guidelines & Required Elements
The schedule and structure of the IRP process has been dictated in large part by state law,10 which
required Council adoption of Palo Alto’s first IRP by January 1, 2019, submission to the CEC by
6 Staff Report 14279 https://www.cityofpaloalto.org/files/assets/public/v/2/agendas-minutes-reports/agendas-
minutes/utilities-advisory-commission/archived-agenda-and-minutes/agendas-and-minutes-2022/06-08-2022/06-
08-2022-id-14279-item-4-irp.pdf
7 Staff Report 14677 (Begins on Page 71) https://www.cityofpaloalto.org/files/assets/public/v/2/agendas-minutes-
reports/agendas-minutes/utilities-advisory-commission/archived-agenda-and-minutes/agendas-and-minutes-
2022/12-07-2022/12-07-2022-agenda-and-packet.pdf
8 Staff Report 2301-0799 (Begins on page 57) https://www.cityofpaloalto.org/files/assets/public/v/1/agendas-
minutes-reports/agendas-minutes/utilities-advisory-commission/archived-agenda-and-minutes/agendas-and-
minutes-2023/07-jul-2023/packet.pdf
9 Staff Report 2307-1748 (Begins on page 19) https://www.cityofpaloalto.org/files/assets/public/v/2/agendas-
minutes-reports/agendas-minutes/utilities-advisory-commission/archived-agenda-and-minutes/agendas-and-
minutes-2023/10-oct-2023/10-11-2023-uac-packet-updated-meeting-location.pdf
10 See Public Utilities Code sections 9621, 9622; Public Utilities Code section 399.11 also established a new
Renewable Portfolio Standard (RPS) to meet 60% of the City’s load from applicable renewable supplies by 2030,
which the City has already achieved.
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April 30, 2019, and updates at least every five years thereafter.11 Specifically, the City’s IRP must
demonstrate how the City’s utility will:
•Meet GHG emissions reduction targets set by the State’s Air Resources Board
•Ensure procurement of at least 60% renewable resources by 2030;
•Minimize impacts to customer bills;
•Ensure system and local reliability, including in the hour of peak net demand, and
ensure the procurement of resource adequacy products to meet its peak demand
and planning reserve margin;
•Strengthen the diversity, sustainability, and resilience of the bulk transmission,
distribution systems and local communities;
•Enhance distribution systems and demand-side energy management;
•Minimize localized air pollutants and other greenhouse gas emissions with early
priority to disadvantaged communities; and
•Address the following procurement topics:
o Energy efficiency and demand resources that are cost effective, reliable
and feasible;
o Energy storage;
o Transportation electrification;
o A diversified procurement portfolio of short-term electricity, long-term
electricity, and demand response products; and
o Resource adequacy capacity.
The IRP report presented herein satisfies all of these requirements. And, it is worthy to note, Palo
Alto has already exceeded the state’s 2030 goals under SB 100 of sourcing 60% of electricity
supplies from renewable resource and reducing greenhouse gas emissions by 40%—which were
the primary drivers of the IRP requirement in the first place.
In addition to addressing the above topics in its IRP, the City is required to submit the following
four Standardized Tables to the CEC along with the IRP:
•Capacity Resource Accounting Table (CRAT): Annual peak capacity demand in each
year and the contribution of each energy resource in the portfolio to meet that
demand.
•Energy Balance Table (EBT): Annual total energy demand and annual estimates for
energy supply from various resources.
•RPS Procurement Table (RPT): A detailed summary of a resource plan to meet the RPS
requirements.
•GHG Emissions Accounting Table (GEAT): Annual GHG emissions associated with each
resource in the portfolio to demonstrate compliance with the GHG emissions
reduction targets established by the California Air Resources Board (CARB).
11 Council adopted the first IRP on December 3, 2018 (Staff Report 9761, Resolution 9802), and staff submitted the
IRP and the four standardized tables to the CEC on April 30, 2019. After reviewing the City’s IRP and associated
documents, the CEC approved the submission on August 29, 2019.
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The CEC has yet to release updated versions of these tables. When they become available staff
will fill them in with the City’s latest portfolio projections and submit them.
Finally, the City is also required to submit to the CEC additional supplementary information along
with the IRP, including the current version of the City’s RPS Procurement Plan. The City last
updated this document in 2020 to reflect the changes brought about by SB 100, and it does not
require any further updates at this time. The current version of this document is included as an
appendix to the IRP.
ANALYSIS
At the July 2023 UAC meeting, staff presented the Commission with an overview of the IRP, along
with a preview of the portfolio modeling results it had completed at the time with help from a
consultant (Ascend Analytics). The remainder of this section will cover additional information
that this portfolio modeling effort has yielded, included a look at how the portfolio fares under
various future hydrological and market price scenarios.
Capacity Expansion Modeling Results
For IRP portfolio development, staff relied on PowerSIMM, an industry-leading market
simulation, capacity expansion, and production cost model developed by Ascend Analytics.
PowerSIMM captures and quantifies elements of risk through the simulation of meaningful
uncertainty with weather as a fundamental driver. After many modeling iterations were
performed to ensure the robustness of the results, staff and Ascend ultimately arrived at a
Recommended Portfolio that is summarized in the following figures. Figure 1 displays the
volumes of new resources that the model selects (in terms of their nameplate capacity) in each
year of the IRP planning period. Although the model selects new solar capacity starting in 2030,
and battery energy storage systems (BESSs) starting in 2041, the actual resources that the City
will contract with to meet its planning objectives will depend heavily on the responses received
in future RFPs. Changing market conditions, the specific characteristics and quality of individual
offers, and changing regulatory requirements all add uncertainty to the selection of future
resources.
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Figure 1: Nameplate Capacity of New Resource Additions for the Recommended Portfolio
Figure 2 below shows the City’s projected load and energy supplies by year under the
Recommended Plan. The small deficit positions depicted in a few years in this figure would be
covered using short-term market purchases of energy bundled with PCC 3 RECs12. Overall, the
Recommended Plan results in a portfolio that would be 98% hedged over the IRP planning period.
12 Portfolio Content Category 3 (PCC 3) Renewable Energy Credits (RECs) are California RPS-eligible RECs that
represent the environmental attributes of electricity generated from renewable energy sources, but which are
transferred independently from the underlying physical electricity.
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Figure 2: Projected Load and Energy Supply Balance for under the Recommended Plan
On an intra-year basis, the Recommended Plan would yield significant energy surpluses in the
spring and summer months, followed by significant energy deficits in the fall and winter months
as shown in Figure 3 below. This pattern, and the resulting market exposure that it would entail,
will be another consideration in the process of selecting new resources to add to the City’s supply
portfolio which could lead to a more diverse mix of new resource selections than is shown here
in the Recommended Plan.
Figure 3: Monthly Load and Energy Supplies in 2025 & 2035 under the Recommended Plan
As Figure 4 below illustrates, the Recommended Plan would ensure that Palo Alto exceeds the
state’s annual RPS procurement targets in all but one year (2035) of the IRP planning period.
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However, because RPS compliance is evaluated based on aggregate procurement over three-year
compliance periods after 2030, the City would still achieve full compliance with its RPS
requirements under the Recommended Plan. (Based on historical performance, CPAU intends to
meet or exceed its annual RPS procurement target in every year.)
Figure 4: SB 100 RPS Requirements and RPS Level under the Recommended Plan
As Figure 1 indicated, the capacity expansion model adds a significant amount of battery energy
storage systems beginning in the 2040s—25 MW each of 4-hour, 8-hour, and 10-hour BESSs.
According to Ascend, the model selected these resources primarily to ensure the Recommended
Plan would satisfy Palo Alto’s system capacity needs during this period (when almost all of the
City’s existing renewable energy power purchase agreements (PPAs) have expired). Figure 5
illustrates how these BESS additions—along with a small volume of demand response capacity—
ensure that Palo Alto can easily satisfy its system capacity needs throughout the planning period
without having to rely on short-term resource adequacy (RA) capacity purchases.
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Figure 5: Projected System Capacity Requirements and Supplies for the Recommended Plan
Scenario Analysis
To try to understand the magnitude of the uncertainty around these modeling results, staff and
Ascend ran the model under several different future scenarios, and then used its production cost
model function to evaluate the overall cost and cost uncertainty of the supply portfolio selected
in each case. The four different scenarios that were evaluated can be summarized as follows:
1.Base Case – Expected hydro output and expected market prices
2.Reduced Hydro Output – Hydro energy output is reduced by 30% and capacity is reduced
by 60%, while hydro costs increase by 25%
3.Dry Year, High Prices – Simulating an extended drought, hydro energy output is reduced
by 25%, while market prices are high
4.Wet Year, Low Prices – Based on historical conditions during wet years, hydro energy
output is increased by 50%, while market prices are low
Interestingly, for the dry year and wet year scenarios the model selected the same new capacity
additions as in the base case (see Figure 1). Despite Palo Alto’s heavy concentration of large hydro
resources in its existing portfolio, these long-term changes in hydrological conditions were not
enough to cause the model to select a different volume or type of resources in the portfolio.
Instead, the model indicates that the City should simply buy more or sell more energy and
capacity in the short-term market to balance its energy and capacity needs in these situations.
(While the Recommended Plan portfolio is 98% hedged on average over the IRP planning period,
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the Dry Year, High Prices scenario would yield a portfolio that is 87% hedged, and the portfolio
would be 121% hedged in the Wet Year, Low Prices scenario.)
In the Reduced Hydro Output case, however, the model made significantly different selections
for the City’s supply portfolio, as summarized in the figures below.
Figure 6: Nameplate Capacity of New Resource Additions in Reduced Hydro Output Scenario
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Figure 7: Projected Load and Energy Supply Balance in the Reduced Hydro Output Scenario
Figure 8: System Capacity Requirements and Supplies in Reduced Hydro Output Scenario
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Portfolio Cost Analysis
Financial metrics for the four scenarios described above are displayed in Table below, including
each scenario’s average supply cost, market price, mark-to-market (MTM)13, and risk premium14.
As expected, this information indicates that the total portfolio in the Reduced Hydro Output
scenario is significantly more costly than the Base Case portfolio. But, interestingly, the modeling
indicates that the portfolio becomes significantly more valuable under both the Dry Year, High
Prices scenario, as well as the Wet Year, Low Prices scenario, compared to the Base Case scenario.
Table 2: Financial Performance Summary of the Four Scenarios Modeled
Base Case Reduced
Hydro Output
Dry Year,
High Prices
Wet Year,
Low Prices
Average Supply Cost ($/MWh)$63.58 $66.27 $83.05 $40.76
Average Market Price ($/MWh)$64.17 $64.17 $88.05 $45.52
Total MTM ($/MWh)$0.65 ($3.34)$4.09 $4.62
Average Annual MTM ($M)$0.47 ($2.00)$5.31 $4.70
Average Annual Risk Premium ($M)$6.43 $3.27 $19.91 $4.33
The Risk Premium results indicate that the portfolio’s cost uncertainty (or value at risk) related
to high market prices/dry hydro conditions is far greater than for low market prices/low hydro
conditions. For this reason, CPAU tends to hedge the supply portfolio based on the assumption
of slightly drier than average conditions, and also maintains significant hydroelectric reserves.
NEXT STEPS
Staff plans to present the final IRP report and associated documents to the City Council in
December based on the Finance Committee‘s recommendations. Under state law, final approval
of the IRP report is required by January 1, 2024, and staff must submit it to the CEC by April 30,
2024.
13 Mark-to-market is a risk assessment tool which measures the current estimated value of a portfolio relative to
its original contracted price; a positive value indicates an increase in the value of the purchase, which would be
realized only if the transaction was liquidated. It also represents the City’s credit exposure with the supplier. Note
that the MTM values presented in Table are based on the total cost of each supply resource, but only account for
the energy value (as measured by the resource’s Locational Marginal Price). The RA capacity value and REC value
associated with each resource’s output are not considered in this calculation, thus it is not an accurate
representation of the true value of each portfolio; nonetheless, the MTM differences between the four scenarios
are reflective of the differences in their values.
14 The Risk Premium metric represents the magnitude of a given portfolio’s financial exposure to market price
volatility, variation in generation and load, and changes in weather conditions. The risk premium, which is
calculated in a manner similar to an insurance premium, is the probability-weighted average of costs between the
median and 95th percentile of costs in all simulations. A smaller Risk Premium value indicates a greater level of
certainty around the cost estimates presented for the given portfolio or scenario.
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As noted in the IRP report, the City faces a number of significant decisions in the coming years,
including whether to reduce its share of (or exit) the Western contract and what to do with its
share of the California-Oregon Transmission Project when the layoff of that resource ends in
2024. In addition, the City’s load is expected to increase significantly in the coming years, and
staff will need to contract for new resources to meet this increased demand. As staff undertakes
these efforts over the implementation period of this IRP, they will provide the UAC, the Finance
Committee, and the City Council with updates on the progress, successes, and new challenges
they encounter.
FISCAL/RESOURCE IMPACT
Staff plans to implement the IRP in the coming years largely with existing staffing resources, along
with assistance from the staff resources at the Northern California Power Agency (NCPA).
However, staff may also have to utilize some external consulting and legal resources to assist
with some of these efforts. The cost of such external resources may amount to $100,000 to
$200,000 over the next few years.
Though the approval of the IRP by itself does not have direct impact on portfolio-related costs,
the different initiatives that will be undertaken in the coming years will greatly influence the
electric supply costs in the coming decades. Staff will ensure that resource and funding needs in
future years are communicated through the annual budget process with appropriation of funds
subject to Council approval.
POLICY IMPLICATIONS
The IRP report and Objective and Strategies are in line with the Utilities Strategic Plan mission
and strategic direction. Specifically, the IRP report itself was contemplated under Strategy 4,
Action 5, of the Financial Efficiency and Resource Optimization Priority of the Utilities 2018
Strategic Plan15. These IRP documents are also in line with the Sustainability and Climate Action
Plan goals of continuing to lower the carbon footprint of the community.
STAKEHOLDER ENGAGEMENT
Staff presented the 2023 IRP report and associated documents to the UAC at its October 11, 2023
meeting. The UAC questioned the volume of new solar generation that is included in the
Recommended Plan, and asked staff about what other resources were evaluated in the portfolio
modeling effort. Staff indicated that they included a wide range of resources in the modeling
work (e.g., geothermal, out-of-state wind, offshore wind, and small modular nuclear reactors),
and that the model is very sensitive to the cost assumptions used, and selected additional solar
on that basis. Staff also reiterated that when the City actually initiates new resource procurement
efforts, staff will thoroughly evaluate all types of resources, and that its ultimate
recommendation would be based on market conditions and the City’s resource needs at the time
of procurement.
15 Utilities Strategic Plan https://www.cityofpaloalto.org/files/assets/public/v/1/utilities/city-of-palo-alto-utilities-
2018-strategic-plan-overview.pdf
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The UAC also asked whether adding more solar to the portfolio would exacerbate the City’s
hourly and seasonal imbalance between its load and its resources, and expressed interest in staff
investigating a portfolio with hourly matching of resources and load. Staff noted that its existing
portfolio includes a large amount of flexible generation resources (i.e., large hydro) which could
be used to match the City’s resource supplies with its load, but that the current practice is to
instead optimize these resources based on market prices, because this generates the most
financial value for the City and also yields the greatest environmental benefits for the grid as a
whole. Staff also indicated that they are in the process of analyzing the costs and risks associated
with pursuing a portfolio with 24x7 matching of supply resources and load. The UAC ultimately
voted (5-1) to recommended approval of the IRP report at this meeting.
ENVIRONMENTAL REVIEW
The Finance Committee’s review and recommendation to Council on the 2023 IRP report does
not meet the definition of a project under Public Resources Code 21065 and therefore California
Environmental Quality Act (CEQA) review is not required.
ATTACHMENTS
Attachment A: Resolution
Attachment B: 2023 Integrated Resource Plan Report
Attachment C: IRP Objective & Strategies
APPROVED BY:
Dean Batchelor, Director of Utilities
Staff: James Stack, PhD, Senior Resource Planner
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Attachment A
* NOT YET APPROVED *
6056782 1
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the 2023
Electric Integrated Resource Plan (IRP),
R E C I T A L S
A. Senate Bill 350 was adopted in 2015, establishing a requirement that all publicly
owned utilities (POUs) with an average load greater than 700 GWh (in the 2013-16 period) must
adopt Integrated Resource Plans (IRP) by January 1, 2019, submit them to the California Energy
Commission (CEC), and update them at least once every five years thereafter (Public Utilities
Code Sec. 9621(b)).
B. Based on historical data, the City of Palo Alto is one of the California POUs that
are required to file an IRP.
C. The CEC is required to review POU IRPs for consistency with Public Utilities Code
9621 and recommend corrections to deficiencies in the plans, according to the Publicly Owned
Utility Integrated Resource Plan Submission and Review Guidelines (POU IRP Guidelines) most
recently adopted by the CEC in August 2018.
D. The POU IRP Guidelines require POUs to submit certain supporting information
along with the IRP, including a set of four standardized tables and a Renewable Portfolio
Standard (RPS) Procurement Plan.
E. The City of Palo Alto approved the 2018 Electric IRP and related documents on
December 3, 2018 (Resolution 9802) and staff submitted them to the CEC on April 30, 2019.
F. The City of Palo Alto first adopted an RPS Procurement Plan on December 12,
2011 (Resolution 9215) and last updated it on December 7, 2020 (Resolution 9929).
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the 2023 Electric Integrated Resource Plan
(Attachment B).
SECTION 2. The Council hereby approves the four standardized tables that
accompany the 2023 IRP (Appendix C to Attachment B).
//
//
//
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Attachment A
* NOT YET APPROVED *
6056782 2
SECTION 3. The Council finds that the adoption of this resolution approving the 2023
IRP and related documents is not a project subject to California Environmental Quality Act
(CEQA) review because adoption of this resolution is an administrative government activity that
will not result in any direct or indirect physical change to the environment as a result (CEQA
Guidelines section 15378(b)(5)).
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
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City of Palo Alto
2023 Electric Integrated Resource Plan
CITY OF
PALO
ALTO
UTILITIES
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Section I: Executive Summary
1
Table of Contents
Executive Summary ...................................................................................................................... 7
CEC IRP Guidelines & Required Elements.............................................................................. 10
Public Process Summary ....................................................................................................... 11
Background & Achievements to Date ......................................................................................... 12
CPAU History and Mission Statement ................................................................................... 12
Previous IRPs & Recent Accomplishments ............................................................................ 12
Changing Planning Environment ........................................................................................... 13
Load Profile Uncertainty & Overgeneration ................................................................... 14
GHG Emission Reductions .............................................................................................. 14
Renewable Portfolio Standards (RPS) ............................................................................ 15
Regional Grid Transformation ........................................................................................ 16
Energy Efficiency ............................................................................................................ 16
Building & Transportation Electrification ....................................................................... 17
Overview of IRP Methodology .............................................................................................. 17
Forecast Methodology for Energy and Peak Demand ................................................................. 19
Description of Econometric Forecast Models ....................................................................... 19
Energy Econometric Model ............................................................................................ 19
Peak Demand Econometric Model ................................................................................ 19
Impact of COVID‐19 Recession ...................................................................................... 19
Overall Forecast Including Linear and Nonlinear Trends ....................................................... 20
Changes in Seasonal and Hourly Usage Patterns .................................................................. 21
Specific Components of Forecast .......................................................................................... 22
Energy Efficiency Forecast ............................................................................................. 22
Solar Photovoltaic Forecast ........................................................................................... 22
Transportation Electrification Forecast .......................................................................... 22
Building Electrification Forecast ..................................................................................... 23
Energy Storage Forecast ................................................................................................ 23
SB 338 Requirements ..................................................................................................... 23
Existing Resource Portfolio ................................................................ Error! Bookmark not defined.
Energy Efficiency, Building Electrification, Transportation Electrification & Local Renewable
Generation ................................................................................................................................... 25
Energy Efficiency ............................................................................................................ 25
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Section I: Executive Summary
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Building Electrification ................................................................................................... 26
Transportation Electrification ........................................................................................ 26
Local Renewable Generation ......................................................................................... 27
Hydroelectric Resources ....................................................................................................... 28
Sierra Nevada Region Western Area Power Authority (WAPA) Base Resource ............. 28
Calaveras ....................................................................................................................... 29
Renewable Energy Resources ............................................................................................... 30
Wind PPAs ..................................................................................................................... 30
Landfill Gas (LFG) PPAs .................................................................................................. 31
Solar PPAs ...................................................................................................................... 31
Market Purchases & RECs ..................................................................................................... 31
COBUG .................................................................................................................................. 32
California‐Oregon Transmission Project (COTP) .................................................................... 32
Resource Adequacy Capacity ................................................................................................ 32
Future Procurement Needs and Scenario Analysis ..................................................................... 34
Needs Assessment: Energy, RPS, Resource Adequacy Capacity ............................................ 34
Portfolio Optimization Analysis ............................................................................................. 36
Capacity Expansion Modeling Results ............................................................................ 37
Scenario Analysis ........................................................................................................... 42
Portfolio Cost Uncertainty and Management ................................................................ 45
Supply Costs & Retail Rates ........................................................................................................ 47
Transmission & Distribution Systems ......................................................................................... 49
Transmission System ............................................................................................................. 49
Distribution System ............................................................................................................... 49
Low‐income Assistance Programs .............................................................................................. 50
Localized Air Pollutants .............................................................................................................. 51
GHG Emissions Projections ......................................................................................................... 52
Next Steps and Path Forward ..................................................................................................... 53
Future Analytical Efforts ....................................................................................................... 53
Key Issues to Monitor & Attempt to Influence ...................................................................... 53
Appendices .......................................................................................................................... XII—1
Key Supplemental Reports and Documents .................................................................... XII—1
RPS Procurement Plan .................................................................................................... XII—2
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Section I: Executive Summary
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INTRODUCTION ........................................................................................................................ XII—4
A. PURPOSE OF THE PLAN (PUC § 399.30(A)) ................................................................... XII—4
B. PLAN ELEMENTS ................................................................................................................ XII—5
1. Compliance Period Definitions ........................................................................................ XII—5
2. Procurement Requirements ............................................................................................. XII—5
3. Portfolio Content Categories (PCC) ................................................................................ XII—6
4. Portfolio Balancing Requirements .................................................................................. XII—6
5. Long ‐Term Contract Requirement .................................................................................. XII—6
6. Reasonable Progress ......................................................................................................... XII—7
C. OPTIONAL COMPLIANCE MEASURES ............................................................................. XII—7
1. Excess Procurement (PUC §399.13(a)(4)(B)) ................................................................ XII—7
2. Waiver of Timely Compliance (§ 399.30(d)(2), § 399.15(b)(5)) ................................ XII—8
3. Cost Limitations for Expenditures (PUC § 399.30(d), § 399.15(c)) ........................ XII—10
4. Portfolio Balance Requirement Reduction (PUC § 399.16(e)) ................................ XII—11
5. Historic Carryover ............................................................................................................ XII—11
6. Large Hydro Exemption (PUC § 399.30(l)) .................................................................. XII—13
D. ADDITIONAL PLAN COMPONENTS ................................................................................ XII—14
1. Exclusive Control (PUC § 399.30(n)) ............................................................................ XII—14
2. Deliberations & Reporting (PUC § 399.30(e), § 399.30(f)) ...................................... XII—14
3. Annual Review ............................................................................................................. XII—15
4. Plan Modifications/Amendments ................................................................................. XII—15
RPS Enforcement Program ........................................................ Error! Bookmark not defined.
Standardized IRP Tables ................................................................................................ XII—16
Capacity Resource Adequacy Table (CRAT) ............................................................ XII—16
Energy Balance Table (EBT) .................................................................................... XII—17
GHG Emissions Accounting Table (GEAT) ............................................................... XII—18
RPS Procurement Table (RPT) ................................................................................ XII—19
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Section I: Executive Summary
4
List of Figures
Figure 1: Palo Alto Power Supply Changes Since Previous IRP ................................................................ 16
Figure 2. Graph of Long‐term Linear Load Loss and COVID‐19 Recession ............................................... 20
Figure 3. Load Projections with Total EV loads, New Data Center Loads, and Electrification .................. 20
Figure 4: Projected Palo Alto Electric Supply Mix in CY 2025 by Resource Type ..................................... 24
Figure 5: Palo Alto's Projected Load and Contracted Energy Supplies .................................................... 34
Figure 6: Palo Alto’s RPS Generation Projections and RPS Compliance Requirements ........................... 35
Figure 7: Palo Alto's Contracted System Capacity Supplies and Requirements ....................................... 36
Figure 8: Nameplate Capacity of New Resource Additions for the Recommended Portfolio .................. 38
Figure 9: Projected Load and Energy Supply Balance for Palo Alto's Recommended Plan ...................... 39
Figure 10: Palo Alto's Monthly Load and Energy Supplies in 2025 & 2035 .............................................. 40
Figure 11: SB 100 RPS Requirements and RPS Level of the Recommended Plan .................................... 41
Figure 12: Projected System Capacity Requirements and Supplies for Palo Alto's Recommended Plan . 42
Figure 13: Nameplate Capacity of New Resource Additions in Reduced Hydro Output Scenario ........... 43
Figure 14: Projected Load and Energy Supply Balance in the Reduced Hydro Output Scenario ............. 44
Figure 15: Projected System Capacity Requirements and Supplies in Reduced Hydro Output Scenario . 45
Figure 16: CPAU Revenues, Expenses, and Rate Changes through FY 2028 ............................................ 48
Figure 17: CPAU Electric Supply Emissions (2005‐2045) ......................................................................... 52
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Section I: Executive Summary
5
List of Tables
Table 1: California Energy Market Changes Since 2018 ............................................................................ 7
Table 2: City of Palo Alto Energy‐Related Changes Since 2018 ................................................................. 8
Table 3: Public Process Summary for Development of the 2023 IRP....................................................... 11
Table 4. Additional Loads with Nonlinear Components .......................................................................... 21
Table 5. Assumptions behind Growth Factors for Data Centers, EVs, and Building Electrification ......... 21
Table 6: Palo Alto’s Resource Adequacy Capacity Portfolio .................................................................... 33
Table 7: Relative Merits of Candidate Resources Considered to Rebalance Supply Portfolio ................. 37
Table 8: Financial Performance Summary of the Four Scenarios Modeled ............................................. 46
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Section I: Executive Summary
6
List of Key Supplemental Reports and Documents
1. NCPA‐CAISO Metered Sub‐System Agreement
2. FY 2024 Electric Utility Financial Plan
3. Ten‐Year Electric Energy Efficiency Goals (May 2021)
4. City of Palo Alto Utilities 2020 Energy Storage Report (AB2514)
5. Distributed Energy Resources Plan (2017)
6. 2021 RPS and Carbon Neutral Plan Update (October 2022)
7. Impact of Electrification on Electric Resiliency (November 2021)
8. S/CAP Goals and Key Actions (2022)
9. S/CAP Work Plan for 2023‐2025 (June 2023)
10. EV Programs Status Update (August 2022)
11. FY 2021 Demand Side Management Annual Report (June 2023)
12. Electric Distribution Infrastructure Modernization Update (June 2023)
13. Palo Alto Earth Day Report 2023
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Section I: Executive Summary
7
Executive Summary
The City of Palo Alto’s 2023 Electric Integrated Resource Plan (IRP) is a comprehensive plan for
developing a portfolio of power supply resources to meet the utility’s objective of providing safe,
reliable, environmentally sustainable, and cost‐effective electricity services while addressing the
substantial risks and uncertainties inherent in the electric utility business. The IRP also supports the City’s
mission to promote and sustain a superior quality of life in Palo Alto. In partnership with our community,
our goal is to deliver cost‐effective services in a personal, responsive and innovative manner.
The IRP meets the requirements of California Senate Bill (SB) 350 (de León, Chapter 547, Statutes of
2015), which requires publicly owned utilities (POUs) with an average annual energy load greater than
700 gigawatt‐hours (GWh) to submit an updated IRP at least every five years to the California Energy
Commission (CEC).
The IRP discusses current and anticipated California regulatory and policy changes facing Palo Alto and
the electric utility industry. Additionally, the IRP presents the analyses conducted and underlying
assumptions, and outlines a resource plan to reliably and affordably meet customers’ energy needs
through calendar year 2030.
The electric utility industry has undergone significant changes since Palo Alto prepared its last IRP in
2018, with a continuation of the shift towards greater levels of variable, distributed, low‐emissions
generation, along with significant growth in energy storage capacity, building and transportation
electrification load, and an expanding suite of regulatory mandates that the City must satisfy. The region
has also recently experienced extreme volatility in natural gas market prices, the emergence of another
state’s carbon compliance market, and several other states in the region setting aggressive renewable
energy and/or carbon targets. And nationally, the effects of the recent passage of the Inflation Reduction
Act and the Infrastructure Investment and Jobs Act are just beginning to be felt in the industry. Table 1
provides an overview of some of the key structural changes in California’s electricity market that must
be addressed in the 2023 IRP, compared to their status at the time of the 2018 IRP.
Table 1: California Energy Market Changes Since 2018
IRP Topic 2018 Status 2023 Status
GHG Emissions Targets 40% below 1990 levels by 2030
40% below 1990 levels by 2030
and 85% by 2045; 100% carbon‐
free electricity supply by 2045
Renewable Procurement 50% by 2030 and beyond 60% by 2030 and beyond
Energy Storage
Requirement to study adoption of
targets; less than 200 MW of
capacity installed in CAISO
Requirement to study adoption of
targets; more than 5,000 MW of
capacity installed in CAISO
Transportation
Electrification
Requirement to address
procurement of EV infrastructure
All cars sold after 2035 be ZEV; all
new public fleet purchases
required to be ZEVs starting in
2027; all medium and heavy duty
trucks sold to be ZEVs by 2036
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Section I: Executive Summary
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Building Electrification No goals established Ban on new natural gas‐powered
space and water heaters by 2030
Structured Markets Intra‐hour market Intra‐hour market, inter‐regional
real‐time balancing through EIM
Resource Adequacy Local, system, and flexible
capacity requirements
Local, system, and flexible
capacity requirements; CPUC‐
jurisdictional entities moving to
slice‐of‐day framework
Transmission Costs 2.1 cents/kWh 3.5 cents/kWh
Similarly, Palo Alto itself has undergone a myriad of changes over the past five years—both in its long‐
term planning goals and in how it uses electricity currently. Table 2 describes some of the major changes
and accomplishments in Palo Alto since 2018, from dramatic changes in the City’s power supply and
emissions reduction targets, to considerable growth in local solar generation and electric vehicles (EVs).
Table 2: City of Palo Alto Energy‐Related Changes Since 2018
Topic 2018 Status 2023 Status
Community‐wide
GHG Emissions
(from electricity,
natural gas and
transportation)
Goal: Reduce GHG emissions to 80%
below 1990 levels by 2030.
Achieved: 43% below 1990 emission
levels.
Goal: Reduce GHG emissions to 80%
below 1990 by 2030.
Achieved: 54% below 1990 emission
levels (2021).
Electric Supply
Portfolio
Goal: 50% RPS by 2030; 100% Carbon
Neutral by 2013
Achieved: 58% RPS; 100% Carbon
Neutral (annual accounting)
Goal: 60% RPS by 2030; 100% Carbon
Neutral by 2013
Achieved: 65% RPS; 100% Carbon
Neutral (hourly accounting)
Local Solar PV
Systems
Achieved: 2% of load ‐ 1,081 systems Achieved: 3.1% of load ‐ 1,609 systems
(2022)
Energy Efficiency Goal: 0.75% avg. annual load savings;
5.7% cumulative savings (2018‐2027)
Achieved: 0.73% of avg. annual load;
4.4% cumulative 6‐year savings
(2007‐2012)
Goal: 0.68% avg. annual load savings;
4.4% cumulative savings (2022‐2031)
Achieved: 0.74% of avg. annual load;
4.5%1 cumulative 6‐year savings (2013‐
2018)
Energy Storage Goal: No explicit goal. Goal: No explicit goal or rebates as not
yet cost‐effective. Facilitate customer
adoption in coordination with Building
department.
Achieved: 34 systems
1 Includes savings related to Codes and Standards changes, as well as estimated savings for 2023.
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Transportation
Electrification
Goal: No explicit goal.
Achieved: Approx. 3,000 EVs
registered in Palo Alto; 60 City‐owned
EV chargers; incentives for EV charger
installation.
Goal: Target 50% EVs by 2030
Achieved: Approx. 6,000 EVs registered
in Palo Alto; 124 City‐owned EV chargers;
Incentives for EV charger installation.
Building
Electrification
Goal: No explicit goal.
Goal: Reduce GHG emissions from the
direct use of natural gas in the buildings
sector by at least 60% below 1990 levels
by 2030
Annual Energy
Load 925 GWh 860 GWh
Summer Peak
Capacity Load 182.5 MW 178.1 MW
Average Retail
Rate2 13.9 cents/kWh 21.36 cents/kWh
The IRP planning period is from 2023 through 2045. Through 2028, the City of Palo Alto Utilities (CPAU)
has sufficient renewable contracts to supply over 60% of the City’s needs. The City’s one long‐term wind
contract and all five landfill‐gas‐to energy contracts expire in the late 2020’s or early 2030’s, while the
six long‐term solar contracts all extend beyond 2040. The City’s contract with the Western Area Power
Administration (WAPA) for hydroelectric resources, which supplies nearly 40% of the City’s energy needs
in a normal hydro year, expires at the end of 2024, but the City has already executed a renewed 30‐year
contract with WAPA (although it retains the ability to reduce its allocation or exit the contract until July
2024).
CPAU expects to continue operating within the Northern California Power Agency’s (NCPA) Metered Sub‐
System Aggregation (MSSA) Agreement with the California Independent System Operator (CAISO).
Under this agreement, NCPA balances CPAU’s loads and resources to comply with CAISO planning and
operating protocols. With resources available under the NCPA MSSA Agreement, Palo Alto has access to
sufficient system, local, and flexible capacity, as well as resources to provide ancillary services to reliably
meet City loads.
Costs are projected to increase through 2045, primarily due to transmission and distribution system
upgrade costs, increasing environmental regulations, and renewable integration costs (which are part of
the tradeoff between pursuing sustainable electricity supplies and reducing overall supply costs). Retail
energy sales are also projected to increase through 2045 due to building and transportation
electrification; increases in energy efficiency and local solar installations are expected to offset these
load increases to some degree, but the overall trend in load is expected to be upward.
2 Retail rate and energy efficiency values are for Fiscal Years 2018 and 2023; the rest of the values in Table 2 are for Calendar
Years 2018 and 2023.
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CPAU staff will provide public updates on the progress, successes, and new challenges over the
implementation period of this IRP.
CEC IRP Guidelines & Required Elements
The schedule and structure of the IRP process is being guided in large part by state law,3 which requires
Council adoption of Palo Alto’s IRP by January 1, 2019, submission to the CEC by April 30, 2019, and
updates at least once every five years thereafter. Specifically, the City’s IRP demonstrates how the City’s
utility will:
Meet GHG emissions reduction targets set by the State’s Air Resources Board (Sections
II.B, II.C.ii, X.B);
Ensure procurement of at least 60% renewable resources by 2030 (see IRP Sections II.B, II.C.iii,
V.A, X.A);
Minimizes impacts to ratepayers’ bills (Section VI);
Ensure system and local reliability, including in the hour of peak net demand, and ensure the
procurement of resource adequacy products to meet its peak demand and planning reserve
margin, sufficient to provide reliable electric service to its customers (Sections III.B.vii, IV.E,
IV.F, VII)
Strengthen the diversity, sustainability, and resilience of the bulk transmission and
distribution systems, and local communities (Sections II.B, IV.A.ii, IV.E, IV.F, VII, VIII)
Enhance distribution systems and demand‐side energy management (Sections IV.A.i, VII.B)
Minimize localized air pollutants and other greenhouse gas emissions with early priority to
disadvantaged communities (Sections II.B, IV.A.ii, IX)
Address rate design, existing or planned incentives, and customer education and outreach
that support transportation electrification consistent with the state’s carbon‐neutrality goals
in Executive Order B‐55‐18 (Sections II.C.vi, IV.A.iii, VI)
Address the following procurement topics:
o Energy efficiency and demand resources that are cost effective, reliable, and feasible
(Sections II.B, II.C.iv, III.B.i, IV.A.i)
o Energy storage (Section III.B.iv)
o Transportation electrification (Section II.C.vi, III.D.iii, IV.A.iii)
o A diversified procurement portfolio of short‐term electricity, long‐term electricity,
and demand response products and strategies or programs (Section III.B.v)
o Resource adequacy (Sections IV.G, V.A)
The City currently has the resources, plans, and programs in place needed to achieve all of the objectives
addressed by the IRP. In addition, and in order to demonstrate compliance with the objectives listed in
the IRP Guidelines, CPAU must include the following four Standardized Tables as part of its IRP
submission:
3 See Public Utilities Code sections 9621, 9622; Public Utilities Code section 399.11 also established a new Renewable Portfolio
Standard (RPS) to meet 60% of the City’s load from applicable renewable supplies by 2030, which the City has already
achieved. SB 350 also requires the doubling of energy efficiency savings targets by 2030 and establishes a new Renewable
Portfolio Standard (RPS) to meet 50% of the City’s load from applicable renewable supplies by 2030. The 10‐Year Energy
Efficiency Potential Plan approved by Council in March 2017 addresses the new energy efficiency savings requirements and
the City expects to achieve an RPS of 58% in 2023.
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Capacity Resource Accounting Table (CRAT): Annual peak capacity demand in each year and
the contribution of each energy resource (capacity) in the POU’s portfolio to meet that
demand.
Energy Balance Table (EBT): Annual total energy demand and annual estimates for energy
supply from various resources.
RPS Procurement Table (RPT): A detailed summary of a POU resource plan to meet the RPS
requirements.
GHG Emissions Accounting Table (GEAT): Annual GHG emissions associated with each
resource in the POU’s portfolio to demonstrate compliance with the GHG emissions reduction
targets established by CARB.
This IRP along with the four aforementioned Standardized Tables and the materials listed in the
Supporting Information section satisfy the IRP filing guidelines listed in the CEC guidelines.
Public Process Summary
Palo Alto staff has provided numerous reports and presentation related to various facets of the IRP to
the Utilities Advisory Commission (UAC) over the past 15 months. The current IRP report was reviewed
by the UAC on October 11, 2023, before being presented to the Finance Committee and City Council for
approval in November and December 2023. Table 3 below lists all public presentations related to the
IRP, with links to the associated reports.
Table 3: Public Process Summary for Development of the 2023 IRP
Forum Date Topic Link
UAC 6/8/2022 Overview of CPAU’s IRP Development Process Report
UAC 12/7/2022 Discussion of CPAU’s Long‐term Electric Load
Forecast
Report
UAC 7/5/2023 Presentation of Electric Supply Portfolio Modeling
Results
Presentation
Council 9/18/2023 Annual Carbon Neutral Plan and RPS Supply Update TBD
UAC 10/11/2023 Recommendation to Approve CPAU’s 2023 IRP TBD
Finance 11/7/2023 Recommendation to Approve CPAU’s 2023 IRP TBD
Council 12/4/2023 Approval of CPAU’s 2023 IRP TBD
An IRP represents a snapshot of a continuous process that evolves and transforms over time. The
conditions and circumstances in which utilities must make decisions about how to meet customers’
future electric energy needs are ever‐changing. The IRP process utilizes a methodology and framework
for assessing a utility’s ever‐changing business and operating requirements and adapting to factors such
as changing technology, regulations, and customer behavior. Assumptions, scenarios, and results are all
reviewed and updated as information and events unfold, and the process is continually revisited under
formal or informal resource planning efforts.
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Background & Achievements to Date
CPAU History and Mission Statement
The City of Palo Alto Utilities' (CPAU) history began over one hundred years ago, in 1896, when the water
supply system was first installed. Two years later, the wastewater or sewer collection system came
online. In 1900, the municipal electric power system began operation, followed in 1917 by a natural gas
distribution system. While CPAU and the utilities industry have evolved dramatically over 123 years, the
City has nonetheless maintained a consistent set of core values: Quality, Courtesy, Efficiency, Integrity,
and Innovation.
Palo Alto’s 2023 IRP is a comprehensive planning document to guide long‐term power planning aligned
with CPAU’s Mission Statement, which is “to provide safe, reliable, environmentally sustainable and cost
effective services.”4
Previous IRPs & Recent Accomplishments
Palo Alto regularly engages in long‐term planning efforts related to its electric supply portfolio –
previously under the auspices of the Long‐term Electric Acquisition Plan (LEAP) and more recently
through the IRP. The last time the City completed a LEAP update was on April 16, 2012 (Staff Report
2710, Resolution 9241). A few years later, in 2015, Senate Bill 350 (SB 350) was signed into law, and it
includes a requirement that publicly‐owned utilities (POUs) serving loads greater than 700,000
megawatt‐hours per year, such as Palo Alto, develop and adopt an IRP by January 1, 2019 and submit it
to the CEC by April 30, 2019 and every five years thereafter.5
As part of the 2012 LEAP update and the 2018 IRP, the City Council approved a set of electric portfolio
decision‐making Objectives and Strategies; as part of the current IRP process, staff developed an
updated version. The current Objective and Strategies, which aligns with the Utilities 2018 Strategic Plan,
is very similar to the ones adopted in 2012 and 2018, with the new version placing greater emphasis on
managing uncertainty related to resource availability and costs, regulatory uncertainty, and the
increased penetration of DERs, electric vehicles (EVs), and building electrification.
The 2018 IRP included a Work Plan describing a set of ongoing tasks and new initiatives for the City to
undertake in order to satisfy the Objectives and Strategies. In carrying out this Implementation Plan and
other initiatives, Palo Alto has accomplished the following over the past five years:
Continued to achieve the goals set in the City’s Carbon Neutral Electric Supply Plan, as it has
every year since 2013, while also changing from an annual accounting methodology to a stricter
hourly accounting approach in 2020;
4 See the City of Palo Alto Utilities 2018 Strategic Plan, which includes the Mission Statement and Strategic Direction,
here:https://www.cityofpaloalto.org/files/assets/public/utilities/city‐of‐palo‐alto‐utilities‐2018‐strategic‐plan‐overview.pdf.
5 See Public Utilities Code sections 9621, 9622. The Clean Energy and Pollution Reduction Act of 2015 also raised the state’s
renewable portfolio standard (RPS) to 50% by 2030 (a standard that was subsequently raised to 60% through SB 100 (2018))
and required a doubling of energy efficiency savings by 2030. The primary objective of the IRP requirement in SB 350 is to
ensure that the state’s large POUs are on track to reduce their greenhouse gas emissions, helping the state meet its overall
target of reducing GHG emissions to 40% below 1990 levels by 2030.
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Increased the renewable energy supply from 57% of total load to 65% of total load, fully
complying with all CEC RPS procurement and filing requirements without relying on any optional
compliance measures or the use of historic carryover generation;
Reduced GHG emissions related to electricity by 123,000 MT CO2e, helping reduce community‐
wide emissions by 54% compared to 1990 levels;
Increased the amount of local solar generation participating in the City’s Feed‐in Tariff program
(Palo Alto CLEAN) from 1.6 MW to 2.9 MW;
Executed a new geothermal power contract (10 MW of capacity);
Executed a 30‐year extension of the Western Area Power Administration hydroelectric contract;
Achieved cumulative energy efficiency savings of 7.4%6 since 2012;
Coordinated with other departments on the installation of dozens of new public EV charger ports
owned and maintained by the City, more than doubling the overall total (now 124);
Launched a heat pump water heater program that provides installation service and on‐bill
financing to homeowners;
Launched rebates and a building electrification technical assistance program to support
electrification projects in commercial buildings;
Adopted aggressive energy efficiency goals which require new and innovative programs;
Adopted a Sustainability and Climate Action Plan (S/CAP) Implementation Work Plan to help
the community achieve its goal of reducing emissions to 80% below 1990 levels by 2030;
Continued to balance the City’s loads and resources under the CAISO‐NCPA Metered Subsystem
Agreement;
Participated in the SunShares solar group buy program with 63 solar installations, 21 of which
include a storage system, and 3 standalone storage installations initiated since 2021;
Adopted local reach codes that requires all new construction projects to be all‐electric with no
natural gas appliances.
Expanded EV charging infrastructure requirements for new construction projects above state’s
minimum requirements.
Operated an appliance recycling program that recycled 50 freezers and 380 refrigerators over
the programs 3‐year lifetime.
Changing Planning Environment
Across the industry, integrated resource planning has undergone significant changes in recent years.
Traditionally, an IRP was an opportunity for a utility to evaluate the steady growth of its customer loads
over a 10+ year planning horizon, and develop a plan for meeting that load growth through staged
additions of new centralized thermal generation resources. Today’s IRPs, however, have to consider how
to integrate increasing volumes of variable and/or distributed generation in an environment of increasing
regulatory mandates, all while maintaining reliability and controlling costs. Accordingly, the objective of
this IRP is to evaluate Palo Alto’s portfolio of resources against the changing utility landscape and
California’s environmental requirements, while recommending strategies to ensure Palo Alto continues
to meet the Council’s goals for affordability and sustainability. The following is a description of some of
the primary changes to the utilities planning environment over the past several years.
6 Includes savings related to Codes and Standards changes, as well as estimated savings for 2023.
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Load Profile Uncertainty & Overgeneration
California’s resource mix has changed considerably in recent years as a result of its ambitious renewable
mandates and the rapidly declining costs of solar and wind resources. The shift to renewables has led to
a fundamental change in the grid’s daily net load shape, which traditionally had a single peak lasting
several hours each day, but which now has a small peak in the morning and a large, sharp peak in the
late evening, and a much lower level throughout the middle of the day. During these midday “solar
hours,” market prices tend to be dramatically lower and at times can even be negative, as the market
sends a price signal that there is too much energy on the grid and that generators either need to pay to
generate or curtail their generation. The changing load shape means new resources will be needed, and
existing resources will need to be used differently, while maintaining affordability for customers.
Solar and wind resources, unless paired with multi‐hour energy storage systems, are intermittent
sources of generation, where energy output is a function of fuel availability (i.e., sunlight and wind). In
order to accommodate large volumes of intermittent resources, the system must include a sufficient
supply of highly responsive resources (or load) to follow this new demand profile. Recent capacity
additions for RPS compliance have largely been solar resources, which are introducing a surplus of
energy supply in the daytime hours, particularly in the spring and fall when renewable resources
maintain higher levels of output and customer loads are at seasonal lows.
GHG Emission Reductions
In 2006, California passed Assembly Bill (AB) 32, the California Global Warming Solutions Act. AB 32 is a
mandate for several sectors, including the electricity sector, to reduce GHG emissions to 1990 levels by
2020. In 2016, AB 32 was augmented by Senate Bill (SB) 32, which mandated a GHG emissions reduction
target of 40% below 1990 levels by 2030. In 2022, CARB raised the 2030 GHG emissions reduction goal
to 48% below 1990 levels and added a new target of net zero emissions by 2045. California’s aggressive
GHG emissions reduction goals will be achieved through a combination of market mechanisms (e.g., Cap
and Trade) and prescriptive mandates (e.g., RPS) to retire and replace high emitting resources with
cleaner resources.
In order to achieve these targets, many sectors of the economy – including industry, transportation, and
electricity – will need to reduce their GHG emissions. The state’s electric sector GHG emissions in 1990
were 108 MMT CO2e. Reducing this amount by 48% creates a target of 56 MMT CO2e; however, CARB’s
2030 GHG planning target range of 30‐53 MMT CO2e for the electricity sector is a 51% to 72% reduction,
well in excess of the sector’s pro‐rata share of the overall reduction target.7
The electricity sector is expected to surpass its pro‐rata emission reduction share due primarily to the
60% RPS goal and aggressive energy efficiency requirements. SB 350 requires that POU IRPs not only
describe how they will meet their 60% RPS target by 2030, but also how they will contribute to the
7 The two other major sectors in the economy are the industrial and transportation sectors. In the Scoping Plan, CARB
estimates the industrial sector can reduce GHG emissions between 8% and 15%, while the transportation sector can reduce
GHG emissions between 27% and 32%. Much of the transportation sector’s emissions reduction burden is expected to be
shifted to the electricity sector via transportation electrification, which was not accounted for in CARB’s Scoping Plan. This
means the electricity sector’s GHG emissions reduction burden will be even greater than it appears.
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electricity sector's share of GHG emissions reductions target for that year. For benchmarking in this IRP
and for portfolio planning purposes, Palo Alto used the mid‐range value of 41.5 MMT CO2e as the 2030
target for the electricity sector (of which Palo Alto’s load‐based pro rata share is 72,000 MT CO2e). These
goals are for planning purposes and not compulsory; however, if changes to the regulations occur, Palo
Alto will reflect those updates in its future resource planning efforts.
Renewable Portfolio Standards (RPS)
One of the primary mechanisms for reducing GHG emissions in the electricity sector is the state’s RPS.
The state’s RPS program mandates that an increasing percentage of retail sales be served by qualifying
renewable generation. An RPS mandate was first imposed on Palo Alto by SB X1‐2 in 2011, and
subsequently expanded by SB 350 in 2015 and SB 100 in 2018. Currently, the major targets are 50% by
2026 and 60% by 2030. Through a formal rulemaking process, the CEC adopted multi‐year Compliance
Periods and procurement targets for each calendar year (CY) through the year 2030, as outlined below:
Compliance Period 4 Target ≥ 35.75% × CPAU Retail Sales2021 + 38.5% × CPAU Retail Sales2022 +
41.25% × CPAU Retail Sales2023 + 44% × CPAU Retail Sales2024
Compliance Period 5 Target ≥ 46% × CPAU Retail Sales2025 + 50% × CPAU Retail Sales2026 + 52% ×
CPAU Retail Sales2027
Compliance Period 6 Target ≥ 54.67% × CPAU Retail Sales2028 + 57.33% × CPAU Retail Sales2029 +
60% × CPAU Retail Sales2030
In addition to the minimum renewable generation procurement requirements, the RPS program also
includes portfolio balancing requirements and long‐term contract requirements, as described in Palo
Alto’s RPS Procurement Plan (included as Supplementary Information).
Palo Alto satisfies its RPS requirements through a diverse portfolio of qualifying renewable resources –
wind, solar, bioenergy (landfill gas), and small hydro. In addition, approximately half of Palo Alto's load
is served by large hydro, a carbon‐free resource that helps reduce GHG emissions but which cannot be
counted for RPS compliance. Figure 1 illustrates Palo Alto’s actual and projected power supply mix for
2018 and 2023. If the City maintains its full contract allocation with the Western Area Power
Administration after 2024, the 2030 power supply mix is projected to be similar to the 2023 mix, but
with less wind and landfill gas; these resources would be replaced with another (as yet undetermined)
renewable energy source.
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Section II: Background & Achievements to Date
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Figure 1: Palo Alto Power Supply Changes Since Previous IRP
Regional Grid Transformation
CPAU is a market participant in CAISO, the non‐profit agency that manages 26,000 circuit miles of high‐
voltage power lines that make up 80% of California's power grid, serving 30 million consumers. CAISO
also operates a competitive wholesale energy and ancillary services market, and is responsible for grid
reliability and efficiency. While the vast amount of new variable renewable energy resources that have
been built in California in recent years have driven down the state’s GHG emissions associated with
electricity usage, they have also presented CAISO with significant challenges for maintaining grid
reliability and energy market stability.
In an effort to promote the reliability of the greater regional electric transmission system, CAISO has
recently been pursuing several initiatives aimed at greater integration of the CAISO grid with other
balancing authority areas (BAAs) in the region. These efforts – including the Western Energy Imbalance
Market (WEIM) and the Extended Day Ahead Market (EDAM) – are attempting to leverage the significant
resource diversity and transmission connectivity between major supply and demand regions throughout
the western United States, creating additional benefits through strong regional collaboration across a
larger geographic footprint. Since its launch in 2014, the WEIM has grown to 22 participating entities
representing 79% of the load in the Western Interconnection, and delivering more than $3 billion in
benefits, along with reliability and environmental benefits.
Energy Efficiency
California has continually increased the energy efficiency of its new buildings and appliances since the
Warren Alquist Act of 1974. These efficiency standards (Title 24) were updated to mandate Zero Net
Energy (ZNE) residential new construction starting in 2020. ZNE homes require energy efficiency that will
be achieved through implementing a high‐efficiency envelope (insulation, windows, etc.), and efficient
heating, ventilation, and air conditioning units. The remaining energy consumption must be offset by on‐
2018
iv .
v.
Sm all
.,,.,,-hydroel ectric
/ 1%
Large
Hydroelectric
47%
2023
Wind
5%
Biomass
& wast e
10%
Sm all
/ hydroel ectric
,/ 1%
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Section II: Background & Achievements to Date
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site generation, sized so that the annual building electricity consumption is equal to the building’s
electricity generation.
Building & Transportation Electrification
Since January 2020, Palo Alto’s local reach codes require that all low‐rise residential new construction
projects to be all‐electric. Beginning January 2023, Palo Alto has expanded the all‐electric new
construction requirement to include nonresidential buildings and has also prohibited new gas
infrastructure for outdoor equipment such as pools, spas and BBQ grills. Since 2016, Palo Alto has offered
rebates to encourage homeowners to replace their gas water heaters with heat pump water heaters
(HPWH). Uptake of the rebate program has been low due to high upfront cost and low awareness of
heat pump technology. In Spring 2023, Palo Alto launched an innovative program that offers end‐to‐end
HPWH installation service with on‐bill financing to lower the upfront cost to homeowners. Within the
Bay Area, other community choice aggregators (CCAs) and agencies such as BayREN have begun
incentivizing the adoption of HPWHs as a strategy to reduce fossil fuel use and lower GHG emissions. At
the state level, the TECH Clean program is a statewide initiative to accelerate the adoption of heat pump
water heating and space heating technology across California. The Federal Inflation Reduction Act of
2022 further created tax incentives and rebates to support heat pump technologies. Collectively, these
incentives are expected to reduce the cost barrier and advance the market transformation for heat pump
technologies. In September 2022, the California Air Resources Board voted to ban the sale of new natural
gas‐powered space and water heaters in California by 2030. This is an important step to help California
meet its carbon‐neutral goal by 2045, given that residential and commercial buildings account for around
25% of the state’s GHG emissions.
The 2022 California Green Building Standards (CALGreen) specify minimum EV infrastructure
requirements for new buildings and existing multifamily buildings. Through its local green building codes,
Palo Alto has adopted EV infrastructure requirements that exceed these minimum state requirements.
These local efforts, along with EV customer programs described below and the state’s Advanced Clean
Cars regulations that require 100% sales to be emission free by 2035 and Advanced Clean Trucks/Fleets
Regulations requiring fleets and trucks sold to be emission free by 2036 will greatly enhance Palo Alto’s
ability to meet its GHG reduction goals.
Overview of IRP Methodology
Integrated resource planning is the process that utilities undertake to determine a long‐term plan to
ensure generation resources are adequate to meet projected future peak capacity and energy needs,
while achieving other utility goals such as maintaining an adequate capacity reserve margin for system
reliability. Resource plans must ensure generation reliability is maintained at or above industry‐standard
levels. IRPs should also forecast long‐term costs and potential rate impacts to customers to ensure that
the utility can monitor and track trends with sufficient time to implement solutions to ensure reliability,
compliance, and affordable electric service. An effective resource plan should also provide a reasonable
degree of flexibility for the utility to deal with uncertainty in technological change and future regulations.
IRPs require the use of sophisticated analytical tools capable of evaluating and comparing the costs and
benefits of a comprehensive set of alternative supply and demand resources. Supply options typically
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include the evaluation of new conventional generation resources, renewable energy technologies, and
distributed energy resources. Demand options typically include consideration of demand response
programs, energy efficiency programs, and other “behind the meter” options which may reduce the
overall load that the utility must be prepared to supply.
IRPs utilize various economic analyses and methodologies to assess alternative scenarios (e.g., different
combinations of supply and demand resources) and sensitivities to key assumptions to arrive at an
economically optimal resource plan (subject to various constraints, such as regulatory mandates and
local policies). The key steps in the resource planning process are outlined below.
Step 1: EXAMINE PLANNING FRAMEWORK AND RISKS: Identify and assess challenges the utility
faces in the current business and regulatory environment.
Step 2: ASSESS NEEDS: Develop forecasts of load changes (incorporating impacts of cost‐effective
demand‐side resources), existing plant conditions, contract terms, and operational constraints to
determine resource needs over the planning period.
Step 3: CONSIDER RESOURCE OPTIONS: Evaluate available generation resources, including
centralized and distributed renewables and long‐term market power purchases to identify the
role each will play in meeting customer needs and regulatory and policy goals.
Step 4: DEVELOP RESOURCE PORTFOLIOS: Develop resource portfolios and evaluate them
quantitatively and qualitatively to determine a preferred portfolio. Evaluation relies upon GHG
emission requirements, needs assessment, and planning data specified in previous steps.
Step 5: PERFORM SCENARIO AND RISK ANALYSIS: Perform detailed evaluations of preferred
resource portfolios through scenario and risk analysis, to assess performance under a range of
potential market and regulatory conditions.
Step 6: IDENTIFY PLAN: Identify a “Preferred Plan” based on the resource portfolio expected to
reliably serve demand at a reasonable long‐term cost, while achieving regulatory compliance,
accounting for inherent risks, and allowing for flexibility to respond to future policy changes.
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19
Forecast Methodology for Energy and Peak Demand
Palo Alto’s forecasted energy and demand were generated by creating an econometric model for
monthly energy and peak demand and then adding the non‐linear components of EV load growth,
building electrification growth, and additional commercial projects planned. Energy and peak demand
profiles for these additional loads were generated they were added to the energy and peak demand
forecast.
Equation 1: Methodology Energy and Peak Demand Forecast
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡 𝐸𝑐𝑜𝑛𝑜𝑚𝑒𝑡𝑟𝑖𝑐 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡 𝐸𝑉 𝐵𝑢𝑖𝑙𝑑𝑖𝑛𝑔 𝐸𝑙𝑒𝑐.𝑁𝑒𝑤 𝐶𝑜𝑚. 𝐿𝑜𝑎𝑑𝑠
More details on the econometric forecast and additional nonlinear loads that were added to the IRP
long‐term forecast are shown in the December 2022 Utilities Advisory Commission meeting (ID #
14677).8
Description of Econometric Forecast Models
Energy Econometric Model
The econometric model inputs (i.e. independent variables) have been selected based on the availability
of data, economic theory, and tests to validate the forecasts with actual energy (or demand) data. The
coefficients of the models were obtained via statistical estimation on historical (in‐sample) data where
the Yule‐Walker Generalized Least Squares method was employed to take into account the
autocorrelation structure of the residuals to obtain valid standard error estimates. The coefficients were
then combined with forecasts of each driver (independent variable) to produce the forecasted energy
(or peak demand). Forecasts of the economic driver variable were provided by the Bureau of Economic
Analysis and the forecasted values provided by the UCLA Anderson Forecast group. Weather variables
were obtained from NOAA, and the forecasted weather conditions were set to reflect normal weather
based on average temperatures across the training data set.
Peak Demand Econometric Model
The Peak Demand forecast is also an econometric model that maps a set of calendar variables, weather
variables, and the energy forecast onto Palo Alto’s monthly peak demand measured at its CAISO meter.
Similar to the Energy Forecast, monthly dummy variables are used in the model to capture underlying
changes in Palo Alto customers’ electric consumption throughout the year. Daily heating and cooling
degree days corresponding to the peak day of the month is used as the weather driver. Monthly historical
energy usage is added as the final variable explaining peak demand.
Impact of COVID‐19 Recession
The recession due to COVID‐19 required an additional ‘recession dummy’ variable superimposed on top
of it, given it is the only time in recent history of stay at home orders and required working from home.
8https://www.cityofpaloalto.org/files/assets/public/agendas‐minutes‐reports/agendas‐minutes/utilities‐advisory‐
commission/archived‐agenda‐and‐minutes/agendas‐and‐minutes‐2022/12‐07‐2022/12‐07‐2022‐agenda‐and‐packet.pdf
Page 71 (ID # 14677)
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The electricity consumption of Palo Alto is rebounding as Palo Alto exits the COVID‐19 recession, and
electricity consumption expected to largely normalize by 2023.
Figure 2. Graph of Long‐term Linear Load Loss and COVID‐19 Recession
Overall Forecast Including Linear and Nonlinear Trends
The combined forecast for low, mid, and high projections are shown in Figure 3 total expected additional
data center load, total EV load, building electrification load, in order show the relative scale of expected
loads.
Figure 3. Load Projections with Total EV loads, New Data Center Loads, and Electrification
1,250,000
1,200,000
1,150,000
1,100,000
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B.
Low Scenario Mid Scenario High Scenario
Annual Energy (GWh) Annual Energy (GWh) 1,400
Annual Energy (GWh)
1,400 1,400
1,200 1,200 1,200
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~ -..... .c
5
~ 800 l? 800 ~ 800 -..... >--..... .c "" .c
5 :;; 5
l? C: l?
>-600 w 600 >-600 "" '" "" :;; ::, :;;
C: C: C: w -Other Load s (Low) C: w <{
'" 400 -EV Total (Low) 400 -Other Load s (Mid) "' 400 -Other Load s (High) ::, ::,
C: C:
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-Bldg Elec (Low) -Add 'I Loads (Mid) C: -Add'I Load (High) <{ <{
-Total (Low) 200
-EV Total (Mid) -EV Total (High)
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-Total (Mid) -Total (High)
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2020 2025 2030 2035 2040 2045 2020 2025 2030 2035 2040 2045 2020 2025 2030 2035 2040 2045
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For both electric vehicle adoption and building electrification rate, the high case assumes meeting 71%
reduction in CO2 emissions from 1990 levels by 2030. The low forecasts for both electric vehicle adoption
and building electrification rate assume linear extrapolation of current trends of the last three to five
years. The mid forecasts for both electric vehicles and building electrification are aggressive but
potentially realistic. The data center additional load growth is for additional data centers which are
planned for the next three years, with 70% of customer projected loads assumed for the mid forecast,
and 100% for the high case.
Table 4. Additional Loads with Nonlinear Components
2020 2045 projection
Additional Modeled Load Growth Actual Low Mid High
Additional Data Centers, GWh
‐
0
(0%)
161
(19%)
230
(27%)
Electric Vehicles, GWh
10
(1%)
46
(5%)
129
(15%)
165
(19%)
Building Electrification, GWh
1
(0.1%)
16
(2%)
69
(8%)
91
(11%)
Total, GWh
11
(1%)
62
(7%)
359
(42%)
486
57%
Table 5. Assumptions behind Growth Factors for Data Centers, EVs, and Building Electrification
Low Projection Mid Projection High Projection
New Load Assumptions 2020 2030 2045 2020 2030 2045 2020 2030 2045
New Data Centers ‐ ‐ ‐ ‐ 70% 70% 100 100% 100%
Electric Vehicles
Residents Vehicles 10% 21% 42% 10% 31% 61% 10% 44% 86%
Res. New Vehicles 30% 40% 62% 30% 50% 80% 30% 85% 100%
Building Electrification
Single‐Family All‐electric 1% 7% 26% 1% 10% 87% 1% 100% 100%
Gas Packs Converted 0% 0% 0% 0% 0% 75% 0% 75% 100%
School Sqft Converted 0% 0% 0% 0% 0% 25% 0% 25% 50%
Large Com. Converted 0% 0% 0% 0% 5% 20% 0% 20% 40%
Changes in Seasonal and Hourly Usage Patterns
Staff is also exploring the changing trends of electricity usage and have updated the hourly models to
encompass these hourly and seasonal trends (higher winter loads, nighttime loads), behind the meter
solar and batteries, and elevated temperatures from climate change (e.g. more air conditioning, less
heating overall). Approximately half of the building electrification load is expected to be from heating
homes and businesses, which will have more usage in the winter and in the night. Staff has incorporated
this into our hourly forecast and will consider running sensitivities around it. Electric vehicles used for
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commuting are also assumed to charge more in the evenings and at night, which staff have also
integrated into the hourly forecast.
Specific Components of Forecast
Energy Efficiency Forecast
a. Committed Energy Efficiency
AB 2021 (2006) required POUs to identify all potentially achievable cost‐effective electric efficiency
savings and to establish annual targets for energy efficiency savings over ten years, with the first set of
EE targets to be reported to the CEC by June 1, 2007, and updated every three years thereafter. AB 2227
(2012) amended this target‐setting schedule to every four years. Palo Alto adopted its first Ten‐Year
Energy Efficiency Portfolio Plan in April 2007, which included annual electric and gas efficiency targets
between 2008 and 2017, with a ten‐year cumulative savings goal of 3.5% of forecasted energy use. In
accordance with California law, the electric efficiency targets were updated in 2010, with the ten‐year
cumulative savings goal doubling to 7.2% between 2011 and 2020. Since then, increasingly stringent
statewide building code and appliance standards have resulted in substantial energy savings. However,
these “codes and standards” energy savings cannot be counted toward meeting the utility’s EE goals.
The ten‐year electric efficiency targets were updated again in 2012, with the ten‐year cumulative electric
efficiency savings being revised downwards to 4.8% between 2014 and 2023. For fiscal year (FY) 2017,
CPAU achieved electric savings of 0.7% of load through its customer efficiency programs. Cumulative
electric efficiency savings since 2006 are about 6% of the FY 2017 electric usage. Adoption rates for EE
are based on the 10‐year Energy Efficiency Goals for 2023‐2027 which were updated in 2017. The ten‐
year cumulative electric efficiency savings target was updated to 5.7% between 2023 and 2027. In 2021,
CPAU updated its 10‐year Energy Efficiency goals for 2022‐2031 with a cumulative EE savings goals of
4.4%. Energy efficiency goals were set lower for this period due to the impacts of Covid‐19 on energy
efficiency program participation and the growing focus on promoting electrification over efficiency.
b. Additional Achievable Energy Efficiency
There is no additional achievable energy efficiency assumed in this IRP forecast because the additional
achievable energy efficiency is already included in the adopted energy efficiency goals for 2022 to 2031.
Solar Photovoltaic Forecast
We have projected approximately linear growth of local solar through 2045. Solar PV projections are
based on technical and economic potential; they indicate that adoption will grow steadily, with the
growth rate itself plateauing as is typically seen in a maturing market. These projections include only
behind‐the‐meter installations in residential and commercial sectors.
Transportation Electrification Forecast
The EV adoption rate in Palo Alto is around 15% of total vehicles registered in the City at the end of 2022,
approximately four times greater than the California statewide average, and this residential adoption
rate relative to statewide average projections is assumed to continue at a roughly linear pace until 2045.
To estimate the EV adoption rates of commuters into Palo Alto, the observed adoption rate from 2017
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census data for the entire Bay Area was extended to 2030. In addition to the number of residential EVs
there are projected to be approximately 1,900, 3,000, and 11,000 commuter EVs in 2017, 2020 and 2030,
respectively. CPAU staff projects roughly linear energy consumption growth from EVs until 2045 given
the competing forces of increasing EV adoption, smaller EVs such as electric bikes, and fewer vehicle
miles traveled (from increased telecommuting, walking, and cycling). Detailed estimates of load growth
are shown above in Table 5.
Building Electrification Forecast
As mentioned above, staff has estimated a substantial amount of conversions of current residential and
commercial natural gas appliances to electric. Table 5 shows the underlying assumptions for rate of
conversions. The assumed scenario is represented in the ‘mid’ scenario.
Energy Storage Forecast
CPAU, in coordination with the Palo Alto Development Services Department, is facilitating the adoption
of energy storage systems by customers by streamlining the process for permitting and interconnecting
such systems. Detailed analysis in 2020 showed that batteries are currently not cost effective from a
societal perspective within CPAU’s service territory and therefore Palo Alto currently does not provide
any rebates for energy storage systems.9 The current net energy metering rate provides some incentive
for energy storage systems by incentivizing onsite usage, with a lower buyback rate for power exported
to the grid. The current relatively high monthly demand charges for commercial customers incentivizes
energy storage systems to lower peak monthly demand. Staff is also currently evaluating proposals for
large utility‐scale batteries at our resources or new resources. Some battery storage is included in our
recommended electric supply portfolio.
SB 338 Requirements
On September 30, 2017, SB 338 was signed into law by Governor Brown, including additional provisions
for the POU IRPs, which were effective January 1, 2018. This included revisions to Public Utilities Code
section 9621(c), requiring the POU’s governing board to “consider the role of existing renewable
generation, grid operational efficiencies, energy storage, and distributed energy resources, including
energy efficiency, in helping to ensure each utility meets energy needs and reliability needs in hours to
encompass the hour of peak demand of electricity, excluding demand met by variable renewable
generation directly connected to a California balancing authority, as defined in Section 399.12, while
reducing the need for new electricity generation resources and new transmission resources in achieving
the state’s energy goals at the least cost to ratepayers.”
As part of the comprehensive process undertaken to develop this IRP, CPAU staff reviewed and
considered resource options that included all of the technologically feasible and cost‐effective options
available to it, including what options would be best utilized to meet energy needs and reliability
requirements during hours of net peak10 demand for the utility. This includes a review of the best
9https://efiling.energy.ca.gov/GetDocument.aspx?tn=236202‐1&DocumentContentId=69171
https://www.cityofpaloalto.org/files/assets/public/city‐clerk/resolutions/reso‐9396.pdf
10 “Net peak demand” is defined as peak electricity demand, excluding demand met by variable renewable generation directly
connected to a California balancing authority.
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available options considering both new and existing preferred resources, as would necessarily be
assessed in order to ensure that Palo Alto provides its customers with the cleanest and most cost‐
effective generation resources, while also ensuring that the City meets all of the statutory requirements
of not only Section 9621, but other procurement and resources mandates, as well.
The City’s current electric supply portfolio comprises the following major types of resources:
Energy efficiency and distributed generation;
Federal hydro (Western contract);
Owned hydro (Calaveras);
Long‐term, in‐state, RPS‐eligible power purchase agreements (PPAs), which include solar, wind,
and landfill‐gas resources; and
Market power purchases, matched with RECs, for monthly/hourly portfolio balancing.
For calendar year 2025, the projected contribution of each of these five resource types to the City’s
overall electric supply portfolio is represented in Figure 4 below.
Figure 4: Projected Palo Alto Electric Supply Mix in CY 2025 by Resource Type
* Estimated Average Annual Unit Cost of 6 ¢/kWh *
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Energy Efficiency, Building Electrification, Transportation Electrification & Local Renewable
Generation
Energy Efficiency
Palo Alto has long recognized cost‐effective energy efficiency (EE) as the highest priority energy resource,
given that EE typically displaces relatively expensive electricity generation and lowers energy bills for
customers.
Palo Alto places such emphasis on energy efficiency and demand side management programs that each
year we prepare a detailed Demand Side Management Annual Report describing and reporting on
efficiency savings from electricity, gas, and water.
Highlights of Current Energy Efficiency Programs
Multifamily Residence Plus+ Program ‐ This CPAU program focuses on multifamily buildings,
especially below‐market rate apartment complexes, providing free, direct installation of energy
efficiency measures to multifamily residences with four or more units including hospices, care
centers, and rehabilitation facilities. Efficiency measures covered under this program include
efficient lighting, attic insulation, refrigerator replacement, and more recently, high efficiency
toilets as well as air source heat pump systems to replace gas furnaces.
The Home Efficiency Genie Program ‐ The Genie was launched in 2015 as a home efficiency
assessment program. The program provides phone consultation to customers to review their
utility bills and advise on efficiency upgrade projects. For a fee, residents can receive an in‐depth
home efficiency assessment which includes air leakage testing, duct inspection, and insulation
analysis. In 2019, a home electrification readiness assessment was added to help homeowners
determine existing home amp loads and electric main panel size, and to provide project guidance on home
electrification projects such as adding EV charger or a HPWH.
Heat‐Pump Water Heater Program – In Spring 2023, Palo Alto launched a full‐service HPWH
program that provides end‐to‐end service to replace a gas water heater with a HPWH in single
family homes. The project cost is subsidized by CPAU, and to further lower the upfront cost to
residents, CPAU offers a zero interest on‐bill financing option. Customers can also opt for a rebate
if they prefer to choose their own contractor. The program has a goal of installing 1000 HPWHs
in one year.
Green Building Ordinance – The Green Building Ordinance (GBO) is Palo Alto’s local building
reach code that is more stringent than the state’s Title 24 standards. Prior to the 2022 code cycle,
the GBO requires that new construction projects exceed the state’s energy and water efficiency
standards. For the 2022 code cycle, Palo Alto requires that all new construction projects be all‐
electric with no gas‐fired equipment or appliances.
Residential Energy Assistance Program (REAP) ‐ This program provides qualifying low‐income
residents with free energy and water efficiency measures such as LED lighting, heating system
upgrades, weather stripping and shell insulation. More recently, high efficiency toilets, heat
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pump water heaters, and air source heat pump systems are added to the measure list. This
program has equal focus on efficiency and comfort, so there may not be reported energy savings
for a customer project.
Business Energy Advisor – Commercial customers can get a free consultation and on‐site
assessment from the Business Energy Advisor with custom recommendations for to help them
lower their utility costs with more efficient equipment. From there, the Business Energy Advisor
can help them find qualified contractors, identify rebates available, and explore financing
options.
Commercial and Industrial Energy Efficiency Program (CIEEP) – This program provides
commercial and industrial (C&I) customers with a free high‐level assessment of their facility's
energy usage and concrete recommendations for saving energy. The program has been running
since 2009, providing cash incentives and no‐cost expert engineering support through Enovity.
Building Electrification
CPAU is currently offering a concierge program (the Heat Pump Water Heater program) to help single
family residents switch from a gas water heater to a heat pump water heater at a discounted project
cost using a City contractor; zero‐interest financing is available to lower the upfront project cost.
Residents can also choose their own contractor to install a heat pump water heater and receive a $2,300
rebate.
For commercial customers, CPAU is offering free on‐site assessment to identify electrification
opportunities and free consultation for contractor selection, equipment selection and permitting.
Electrification rebates are available for eligible products to offset project costs.
Transportation Electrification
CPAU provides customers with a wealth of information on choosing and comparing vehicles and provides
both financial and technical assistance to support the installation of EV charging equipment. CPAU offers
qualifying customers (including school, non‐profits, and multi‐family properties) rebates of up to $80,000
for installing EV charging equipment. If customers installing EV charging infrastructure need to upgrade
their electric service capacity, CPAU also offers Transformer Upgrade Rebates (up to $10,000 for single‐
family homes and up to $100,000 for schools, non‐profits organizations, public entities, and multi‐
family/mixed‐use properties).
In terms of technical assistance, CPAU provides customers who want to install an EV charger at their
home with a free online estimate for their project and also connects them with a local, vetted
professional who will handle the permitting and inspections process for them. CPAU also offers an EV
Charging Technical Assistance Program that provides personalized technical assistance, free of charge,
to support owners and managers of schools, non‐profits, multifamily properties, and small to medium
businesses navigate the process of installing EV charging infrastructure. This assistance can include help
with site assessments, engineering, design, vetting contractor bids, and project managing the
installations.
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Local Renewable Generation
Local renewable energy programs are critical to lowering emissions of local air pollutants and CPAU has
enacted a number of initiatives and programs to facilitate customer adoption.
The following is a description of Palo Alto’s current customer‐side renewable generation programs:
SunShares ‐ Every year since 2015 Palo Alto has been an active partner in promoting the Bay Area
SunShares PV Group‐buy program which pre‐screens solar installers and negotiates lower rates
for customers. Since 2015, Palo Alto has been the top “Outreach Partner,” both in terms of the
number of solar contracts signed and the kilowatts of rooftop solar capacity installed annually
through the program. In 2021 and 2022 Palo Alto customers completed 63 solar installations
totaling 368 kW through the SunShares program, 21 of which include a storage system, and 3
standalone storage installations.
Net‐Energy Metering Successor Program ‐ Prior to January 1, 2018 residential and commercial
customers in Palo Alto who installed approved PV systems were able to sign up for the CPAU Net
Energy Metering (NEM) program. CPAU reached the NEM cap of 10.8 MW in January 2018 and
CPAU is now offering a NEM Successor Program instead. The NEM Successor process is integrated
with the permitting process, and customers receive a credit for electricity exported to the grid
based on CPAU’s avoided costs.
Palo Alto CLEAN (Clean Local Energy Accessible Now) ‐ This feed‐in tariff program purchases
electricity generated by renewable energy resources located in Palo Alto’s service territory and
interconnected on the utility‐side of the electric meter. The electricity is purchased by Palo Alto
for the electric renewable portfolio standard. The program was launched in 2012 and has been
modified several times since then. In February 2014 the City Council approved a total program
capacity of 3 MW at a price of 16.5 cents per kilowatt hour (kWh) fixed for 20 years. In May 2017
the City Council approved additional minor changes to the program, including adding a 15‐year
contract term option and removing the total participation cap for both solar and non‐solar
eligible renewable energy resources. CPAU is currently offering to purchase the output of eligible
renewable electric generation systems located in Palo Alto at the following prices:
o For solar energy resources: 16.5 cents per kilowatt hour (¢/kWh) for a 15‐, 20‐ or 25‐year
contract term until the subscribed capacity reaches 3 MW – after that the price will drop
to 8.8 ¢/kWh for a 15‐year contract term, 8.9 ¢/kWh for a 20‐year contract term, or 9.1
¢/kWh for a 25‐year contract term; and
o For non‐solar eligible renewable energy resources: 8.3 ¢/kWh for a 15‐year contract term,
8.4 ¢/kWh for a 20‐year contract term, or 8.5 ¢/kWh for a 25‐year contract term.
There is no minimum or maximum project size, but the program is best suited for commercial
property owners with available roof‐tops or parking lots. In 2016, Palo Alto’s Public Works
Department solicited proposals to install solar PV systems and electric vehicle chargers at four
City‐owned parking structures; all four of these parking garage solar PV systems participate in
the CLEAN program and are now operational. As of August 2023, there are a total of six solar PV
systems participating in the Palo Alto CLEAN program, accounting for 2.915 MW of the capacity
available at the 16.5 ¢/kWh contract rate, with contract terms ranging from 15 to 25‐years.
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Hydroelectric Resources
Sierra Nevada Region Western Area Power Authority (WAPA) Base Resource
Since the 1960s, CPAU’s participation as a power customer of the Central Valley Project (CVP) has been
an instrumental factor in its ability to deliver low‐carbon electricity to Palo Altans at low rates. The U.S.
Bureau of Reclamation (BOR) built the CVP in the 1930s and is charged with the operation, maintenance,
and stewardship of the project. The CVP was constructed primarily for flood control of the Sacramento
Valley area; however, it is also used to provide water for irrigation and municipal use and for navigation
and recreational purposes. Hydroelectric generation is a lower priority function of the CVP, relative to
the purposes listed previously.
The BOR is legally required to first provide power to “Project Use” for operations and pumping water
through the CVP project, and then to “First Preference Customers,” those customers whose livelihood
and/or property/land was impacted by the construction of the CVP. The remaining hydroelectricity
(“Base Resource”) is then made available for marketing under long‐term contracts with not‐for‐profit
entities such as municipal utilities and special districts. The Western Area Power Administration (WAPA)
is the federal Power Marketing Agency charged with marketing and contracting with customers for the
electric output associated with the CVP, and collecting funds to meet allocated revenue requirements
on behalf of the BOR. WAPA also responsible for transmission of the federal power.
In 2000, the City executed a new 20‐year contract with WAPA for CVP power deliveries starting in 2005.
Under this contract the City receives 12.3% of all the Base Resource product output and is obligated to
pay 12.3% of all the CVP’s revenue requirements as allocated to power customers, regardless of the
amount of energy received. Under normal precipitation and hydrological conditions, this resource
provides over 30% of CPAU’s electricity needs. However, since 2005 the amount has varied from a low
of 11% to a high of 64%. Given that the overall cost of this contract is essentially fixed while the amount
of energy the City receives from it varies significantly with weather conditions, the corresponding cost
per MWh has ranged from $22 to $105/MWh.
The current Base Resource contract will expire at the end of 2024. Under WAPA’s 2025 Power Marketing
Plan, CPAU, as an existing Base Resource power customer, recently executed a contract to renew its Base
Resource allocation at 98% of its existing allocation level for a thirty‐year term (2025‐2054).11 However,
under the terms of the Power Marketing Plan, all Base Resource power customers have the ability to
reduce their allocation under the new contract—or exit the agreement entirely—until the end of June
2024. Therefore, a key consideration of the current IRP is whether or not the City should exercise this
option to reduce its allocation, and if so, to what degree—and what alternative resources to replace it
with.
The analysis necessary to aid Council in its decision will consider the cost and the value of the resource
going forward. Generation is highly variable and uncertain due to unpredictable precipitation conditions,
11 Resolution 9946: https://www.cityofpaloalto.org/files/assets/public/v/1/city‐clerk/resolutions/resolutions‐1909‐to‐
present/2021/reso‐9946.pdf
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climate change, and the potential for new environmental policies and/or projects which threaten to
erode generation volumes and/or value.
The costs associated with participating in the Base Resource are also highly uncertain. The project has
many parts that need to be replaced, as it was first put into service nearly eighty years ago. Additionally,
funding requirements under the Central Valley Project Improvement Act (CVPIA)12 and the
appropriateness of the allocation of Restoration Fund collections between water and power customers
is of serious concern to CPAU and other power customers, who have been actively encouraging BOR and
Congress to adjust this allocation.
NCPA staff and CPAU staff are in the process of assessing the potential impact and likelihood of several
issues which threaten to dilute the future value of Base Resource, as well as NCPA’s and CPAU’s ability
to influence these issues. These issues are in addition to highly variable hydrological and precipitation
conditions which naturally create substantial year‐to‐year variations in the value of the resource. Staff
and NCPA have begun analyzing each of these risk factors to aid in the decision of whether to reduce
CPAU’s Base Resource allocation by June 30, 2024 for the 2025‐2030 period. One aspect that helps to
mitigate the financial risk of this resource is the contractual ability to decrease CPAU’s share or exit the
contract entirely every five years.
Calaveras
The Calaveras hydroelectric project was bond‐funded and built as a joint project between members13 of
the Northern California Power Agency (NCPA) and the Calaveras County Water District (CCWD) in 1983.
CCWD holds the Federal Energy Regulatory Commission (FERC) license and NCPA is the project operator.
The project resides on the North Fork of the Stanislaus River in Calaveras, Alpine and Tuolumne Counties.
Calaveras was built primarily for hydroelectric generation purposes and as such water is stored and
managed to optimize generation value and to meet member owners’ energy needs. Palo Alto’s share in
the project is 22.92%, which serves approximately 10% of the City’s annual load in an average hydro
year.
Calaveras’ project capacity is about 253 MW and it can generate approximately 400 gigawatt‐hours
(GWh) of energy annually under average hydroelectric conditions. Palo Alto’s corresponding share of the
output is 58 MW of capacity and 92 GWh of annual energy under average conditions.
As of January 2024, the City’s outstanding debt on the project is approximately $39 million, of which a
large portion will be maturing in 2024 and the remainder will mature in 2032. Through fiscal year 2024,
the City’s annual debt related to this project is on average about $8.5 million; for the remaining years
until 2032, the annual debt is about $4.2 million. In addition, efforts are underway to apply for
12 The Central Valley Project Improvement Act was passed by the U.S. Congress in 1992 to establish the Restoration Fund,
funding requirements and goals to restore the habitat of the area impacted by the CVP. Water and power customers are
obligated to pay into the Restoration Fund. https://www.usbr.gov/mp/cvpia/docs/public‐law‐102‐575.pdf
13 NCPA members participating in the Calaveras Project via the Calaveras Third Phase Agreement with NCPA include the cities
of Alameda, Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Roseville, Santa Clara, and Ukiah, and the Plumas‐Sierra Rural
Electric Cooperative.
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relicensing, given that the current FERC license for the project expires in 2032. The costs associated with
this relicensing effort are yet to be finalized, but they will be collected from participants in the coming
years. NCPA has also recently initiated efforts to dredge one of the Calaveras system’s major reservoirs,
to remove trees, soil, sand, gravel and other debris that have been deposited into the reservoir in recent
years by high inflows. Like the relicensing effort, the costs associated with this dredging project have yet
to be finalized but will be collected by the project’s participants in the coming years.
Historically, debt and other costs associated with Calaveras have resulted in the overall value of the
project being below market.14 However, because Calaveras’ variable operating and maintenance costs
are relatively low, the project is dispatched regularly for the purpose of generating energy. Additionally,
Calaveras has the ability to meet several CAISO compliance and operating requirements, including:
following variations in the City’s load in real‐time (load following), ancillary services related to regulation
energy and spinning reserves; and meeting some of the City’s Resource Adequacy requirements,
including flexible capacity and system capacity. Calaveras also serves as an energy storage asset, since
water is stored in the main reservoir, New Spicer Meadow, and released at optimal times to meet energy
and capacity needs. In the long‐term it is expected that the value of Calaveras will increase, assuming
average or above average hydroelectric conditions and favorable regulatory requirements.
While there are no imminent decisions associated with Calaveras, a few issues may be worth evaluating
in the context of the IRP, including:
1. Assessment of Calaveras’ value and operating strategies, given the City’s commitment to other
large hydroelectric resources, RPS resources, and hydro risk management objectives;
2. How to best optimize Calaveras given its flexible dispatch ability, which enables it to meet
intermittent resource integration requirements; and
3. The value of the City’s long‐term stake in Calaveras, including the post‐2032 period, when the
current FERC license expires.
Renewable Energy Resources
Wind PPAs
Palo Alto currently has one long‐term contract for the output of a wind power project. Under this
contract with Avangrid Renewables the City receives a 20 MW share of the output of the High Winds I
project located in Solano County. This resource typically supplies about 4% of Palo Alto’s total electric
supply needs and its contract term ends in 2028. The project is considered fully deliverable, and it is
located in the Bay Area local capacity area.
14 In anticipation of Direct Access and the possibility for load to leave CPAU, in 1996 Council approved a competitive‐
transition‐charge (CTC) to be added as a non‐by‐passable fee on all CPAU customers electricity bills. This was done to collect
the above market cost (stranded cost) associated with Calaveras debt and the funds were held in the Calaveras Reserve,
which had been established in 1983 to help defray cost associated with Calaveras. The Calaveras Reserve was repurposed in
2011 and is now the Electric Special Project Reserve (see Staff Report 2160).
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Landfill Gas (LFG) PPAs
Palo Alto currently has five long‐term contracts with Ameresco for the output of landfill gas electricity
projects. The five contracts include a 1.5 MW share of a project located in Watsonville, a 5.1 MW share
of a project located in Half Moon Bay, a 1.9 MW share of a project located in Pittsburg, and the entire
output of a 1.4 MW project located in Gonzales and a 4.1 MW project located in Linden. The terms of
these agreements are all 20 years, with contract expiration dates between 2025 and 2034. Together, the
five resources currently supply about 11% of Palo Alto’s total electric supply needs. All five projects are
also considered fully deliverable, with two of them located in the Bay Area local capacity area.
Solar PPAs
Since the beginning of 2012, Palo Alto has executed six long‐term contracts for utility‐scale solar PV
projects. These six contracts include three with AES (the 26.7 MW Hayworth Solar project located in
Bakersfield, the 20 MW Western Antelope Blue Sky Ranch B project and the 40 MW Elevation Solar C
project – both of which are located in Lancaster), two with Boralex (the 20 MW EE Kettleman Land
project in Kettleman City and the 20 MW Frontier Solar project located in Newman), and one with
Clearway Energy (the 26 MW Golden Fields Solar III project in Rosamond). These six projects are all
currently operational, and they provide over 40% of Palo Alto’s total electricity needs. The terms of these
agreements are all at least 25 years, with contract expiration dates starting in 2040. The three projects
operated by AES are considered fully deliverable, with the Hayworth project located in the Kern local
capacity area, and the other two located in the Big Creek‐Ventura local capacity area. Golden Fields Solar
III is also considered fully deliverable, providing valuable system capacity to the grid.
Market Purchases & RECs
Palo Alto has nine active Master Agreements for the purchase and sale of market electric power (with
BP Energy, Shell Energy North America, Powerex Corp, Cargill Power Markets, Exelon Generation,
Avangrid Renewables, NextEra Energy Marketing, Turlock Irrigation District, and PacifiCorp) to facilitate
competitive forward market power purchases and sales to meet Palo Alto’s loads in the short‐ to
medium‐term. As of June 30, 2023, Palo Alto had outstanding electricity purchase commitments for the
period July 2023 to June 2024 totaling 42 GWh, and sales commitments for this period totaling 33 GWh.
These market based purchases and sales are made within the parameters of Palo Alto’s Energy Risk
Management Program, which the City is in the process of revising to bring them into alignment with
current market conditions and norms.
In FY 2023, gross market‐based purchases (including both forward transactions and spot‐market
transactions) provided approximately 12% of Palo Alto’s electricity needs, while gross market‐based
sales were equivalent to 13% of Palo Alto's needs (i.e., the City was a net seller of market‐based energy).
However, the volume of market purchases and sales is highly dependent on hydro conditions and long‐
term commitments to renewable resource‐based supplies. During normal hydro conditions, gross
market purchases are expected to meet approximately 15% of energy needs, while gross market sales
will amount to approximately 25% of energy needs. NCPA serves as Palo Alto’s scheduling and billing
agent for all transactions, and acts as the interface with the CAISO under a Metered Subsystem
Aggregation Agreement (MSSA).
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Since 2013, Palo Alto has operated under a Carbon Neutral Plan for its electric supply portfolio, ensuring
that all electrical generation that serves the City’s needs produces zero GHG emissions on a net annual
basis. In 2020, in recognition of the changing dynamics of California’s electric grid and power supply mix,
the City updated its Carbon Neutral Plan, switching from the original annual accounting approach to a
stricter hourly accounting approach for defining “carbon neutrality.” Under the new methodology, the
City weights its hourly net surplus or net deficit positions by the grid’s average emissions intensity value
for that hour, then sums these hourly emissions totals over the course of the year. (In years where this
calculation determines that the City has been a net emitter of greenhouse gases, CPAU purchases
unbundled RECs to neutralize these residual emissions.) By recognizing the effects that the huge
amounts of new solar generation have had on the hourly emissions profile of grid electricity in the state,
the City is holding its carbon neutrality claims to the highest possible standard.
COBUG
In 2002, shortly after experiencing a series of rolling blackouts during the California energy crisis, the City
decided to invest in a set of locally‐sited natural gas‐fired back‐up generators in order to stave off such
events in the future. These four generators, together known as the Cooperatively Owned Back‐Up
Generator (COBUG), total 4.5 MW in capacity. These units are close to their end of life, and an evaluation
is underway to determine the best use of the space these units are currently occupying in the Municipal
Services Center.
California‐Oregon Transmission Project (COTP)
Fourteen Northern California cities and special districts and one rural electric cooperative, including Palo
Alto, are members or associate members of a California joint powers agency known as the Transmission
Agency of Northern California (TANC). TANC, together with the City of Redding, WAPA, two California
water districts, and Pacific Gas and Electric (PG&E) own the California‐Oregon Transmission Project
(COTP), a 339‐mile long, 1,600 MW, 500 kV transmission power project between Southern Oregon and
Central California. Palo Alto is entitled to 4.0% of TANC's share of COTP transfer capability (50 MW). As
a result of low utilization of the transmission capacity and therefore low value relative to costs (in
addition to a focus on acquiring in‐state renewable resources), in August 2008 Palo Alto effected a long‐
term assignment of its full share and obligations in COTP to the Sacramento Municipal Utility District
(SMUD), Turlock Irrigation District (TID), and Modesto Irrigation District (MID). The long‐term assignment
is for 15 years (through the beginning of 2024), with an option to extend the assignment for an additional
five years. Staff is currently evaluating executing a new layoff or bringing the resource back to the
portfolio.
Resource Adequacy Capacity
As described above, the majority of Palo Alto’s long‐term generation contracts (and its one owned
thermal generating asset) are deemed fully deliverable and provide the City with Resource Adequacy
(RA) capacity to satisfy its CAISO regulatory requirements. The amounts of RA capacity provided to Palo
Alto by each resource are detailed in the CRAT standardized table in the appendices of this report, and
a high‐level overview is provided in Table 6 below.
E.
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Table 6: Palo Alto’s Resource Adequacy Capacity Portfolio
Project Resource Type Local Area Flexible RA? Average NQC (MW)
Western Base Resource Hydroelectric CAISO System No 147.015
Calaveras Hydroelectric CAISO System Yes 58.0
High Winds Wind Bay Area No 5.4
Santa Cruz LFG Landfill Gas CAISO System No 1.5
Ox Mountain LFG Landfill Gas Bay Area No 5.2
Keller Canyon LFG Landfill Gas Bay Area No 1.8
Johnson Canyon LFG Landfill Gas CAISO System No 1.4
San Joaquin LFG Landfill Gas CAISO System No 4.2
Hayworth Solar Solar PV Kern No 12.8
Elevation Solar C Solar PV Big Creek‐Ventura No 26.3
Western Antelope Solar PV Big Creek‐Ventura No 13.2
Golden Fields Solar III Solar PV CAISO System No 17.1
COBUG Natural Gas Bay Area No 2.25
15 https://www.wapa.gov/regions/SN/Operations/Documents/FinalGreenbook2004.pdf Palo Alto’s share of average Base
Resource Capacity from Greenbook values.
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Future Procurement Needs and Scenario Analysis
Needs Assessment: Energy, RPS, Resource Adequacy Capacity
To evaluate the need for additional resource procurement during the IRP planning period, CPAU
compared its load forecast with its resource supply projections (on both a monthly and an annual basis)
in terms of energy, RPS supplies, and capacity. Over the next few years, Palo Alto’s resource portfolio
has a slight surplus of energy, as well as a surplus of RPS generation (relative to its RPS procurement
requirements under SB 100) and capacity, as detailed in the Standardized Tables presented in Appendix
D.
Figure 5 below presents the City’s projected load and contracted energy supplies through 2045. (Note
that all figures in this section are based on the assumptions that the Western Base Resource contract is
renewed in 2025, all renewable energy PPAs are allowed to expire at the end of their contract terms,
and no additional resources are procured.) Although the City is projected to have an annual energy
surplus through 2025, the relatively rapid projected growth in total load over the next few years is
expected to result in slight overall energy deficits beginning in 2029, with these deficits growing over
time as existing contracts expire.
Figure 5: Palo Alto's Projected Load and Contracted Energy Supplies
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Figure 6 below depicts the City’s projected supplies16 of eligible renewable generation for the period
2003 to 2045, as well as the City’s annual RPS generation procurement requirements under SB 100,
based on its actual and forecasted retail sales volumes. (Note that this figure assumes no utilization of
CPAU’s Historic Carryover and Excess Procurement supplies from prior years. Such supplies do exist and
could be utilized in the event of an RPS supply shortage, but it is not the City’s plan to rely on these
supplies for compliance with SB 100’s RPS procurement requirements.) Just like with the City’s projected
long‐term energy deficits, Figure 6 indicates that the City’s RPS deficits are also projected to begin in
2029.
Figure 6: Palo Alto’s RPS Generation Projections and RPS Compliance Requirements
In terms of capacity needs, the City has a projected surplus of system RA capacity until the early 2040s
(as Figure 7 illustrates), but deficit positions in local and flexible RA capacity.17 The City makes up these
deficits each year via bilateral RA capacity purchases. One of the challenges that CPAU faces over the IRP
planning period is ensuring that it can continue to procure adequate supplies of local and flexible RA
16 Note that renewable energy supplies shown in Figure 6 which are surplus to the City’s RPS procurement requirements may
ultimately be sold or banked for use in future compliance periods. A portion of the excess supplies for 2020‐2023 were sold
and replaced with PCC 3 supplies (unbundled RECs).
17 For additional details on Palo Alto’s projected needs and supplies of electrical generation, RPS generation, and RA capacity,
please see the EBT, RPT, and CRAT standardized tables in Appendix D to this report.
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Section V: Future Procurement Needs and Scenario Analysis
36
capacity – both to satisfy its regulatory compliance obligations, and to ensure the overall reliability of
the CAISO bulk transmission system.18
Figure 7: Palo Alto's Contracted System Capacity Supplies and Requirements
The remainder of this section will focus on determining the optimal mix of new resource acquisitions
that will allow Palo Alto to satisfy its energy, RPS, and capacity needs while minimizing supply costs and
cost uncertainty—all while remaining compliant with the City’s Carbon Neutral Plan requirements.
Portfolio Optimization Analysis
As noted in the July 2023 presentation to the Palo Alto UAC, CPAU staff worked with a consultant, Ascend
Analytics (Ascend), to evaluate a large number of potential new supply‐side and demand‐side resources
in the portfolio optimization analysis it performed for this IRP. CPAU staff and Ascend worked together
to develop assumptions around the long‐term generation levels and costs for its existing portfolio of
resources, and Ascend provided a forecast of long‐term capital and operating costs for various new
resource options.
18 Also, if Palo Alto opts not to renew its Western Base Resource contract in 2025 – or significantly scales back its share of this
resource – then the City will face the additional challenge of ensuring it has adequate system RA capacity to meet its planning
reserve margin requirements. As Table 6 indicates, the Western Base Resource contract is by far the City’s largest source of
system RA capacity.
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Table 7 below summarizes the various resource types and their relative merits that staff considered most
closely in its portfolio analysis. The key indicators used for comparing the different portfolio options are:
Value: The net value of a resource; the projected revenue from selling the resource’s energy into
the CAISO market less the resource’s bi‐lateral contract cost;
Portfolio Fit: Lower reliance on the grid for hourly load balancing;
Diversification: Geographic and resource diversity;
Term Flexibility: Flexibility in length of contract and termination provisions; and
Cost Certainty: Degree of certainty of future resource costs.
Table 7: Relative Merits of Candidate Resources Considered to Rebalance Supply Portfolio
* Ratings reflect relative changes from current portfolio of resources *
Capacity Expansion Modeling Results
For IRP portfolio development, CPAU relied on PowerSIMM, an industry‐leading market simulation,
capacity expansion, and production cost model developed by Ascend. PowerSIMM captures and
quantifies elements of risk through the simulation of meaningful uncertainty with weather as a
fundamental driver. PowerSIMM is a “hybrid model,” meaning it uses both market data and long‐term
fundamentals to simulate load, renewables, and CAISO spot market prices against which resources are
dispatched and valued. Setting the model up involved gathering historical generation data, resource
specifications, cost projections, and other relevant inputs and feeding them into the model. CPAU staff
then validated the model by running it under various weather and pricing conditions and confirming that
its outputs matched staff’s expectations. A set of economic dispatch studies were then run for every
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Section V: Future Procurement Needs and Scenario Analysis
38
resource, and these results were fed into PowerSIMM’s Automated Resource Selection (ARS) module,
which used the information to select resource additions based on minimizing the cost of procuring and
operating new and existing resources while also satisfying all of the IRP objectives.
Once additional resources were selected by the ARS module, they were incorporated into a portfolio
including CPAU’s existing resources and evaluated using an hourly dispatch model to understand the
overall implications of the selections on the portfolio. To capture the uncertainty in future conditions,
these hourly dispatch studies used a stochastic framework to simulate 100 different future conditions,
in which market prices, weather patterns, renewable generation, water availability, and load were varied
according to distributions observed in the historical data. To capture the uncertainty associated with the
distribution of portfolio costs across these 100 different simulations, a risk premium metric for the
portfolio was developed, which represents the magnitude of the portfolio’s financial exposure to market
price volatility, variation in generation and load, and changes in weather conditions.
After many modeling iterations were performed to ensure the robustness of the results, CPAU staff and
Ascend ultimately arrived at a Recommended Portfolio that is summarized in the following figures.
Figure 8 displays the volumes of new resources that the model selects (in terms of their nameplate
capacity) in each year of the planning period. Although the model selects new solar capacity starting in
2030, and storage capacity starting in 2041, the actual resources that the City will contract with to meet
its planning objectives will depend heavily on the responses received in future RFPs. Changing market
conditions, the specific characteristics and quality of individual offers, and changing regulatory
requirements all add uncertainty to the selection of future resources.
Figure 8: Nameplate Capacity of New Resource Additions for the Recommended Portfolio
Figure 9 below shows the City’s projected load and energy supplies by year under the Recommended
Plan. The small deficit positions depicted in a few years in this figure would be covered using short‐term
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Section V: Future Procurement Needs and Scenario Analysis
39
market purchases of energy bundled with PCC 3 RECs. Overall, the Recommended Plan results in a
portfolio that would be 98% hedged over the IRP planning period.
Figure 9: Projected Load and Energy Supply Balance for Palo Alto's Recommended Plan
On an intra‐year basis, the Recommended Plan would yield significant energy surpluses in the spring and
summer months, followed by significant energy deficits in the fall and winter months as shown in Figure
10 below. This pattern, and the resulting market exposure that it would entail, will be another
consideration in the process of selecting new resources to add to the City’s supply portfolio which could
lead to a more diverse mix of new resource selections than is shown here in the Recommended Plan.
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Section V: Future Procurement Needs and Scenario Analysis
40
Figure 10: Palo Alto's Monthly Load and Energy Supplies in 2025 & 2035
As Figure 11 below illustrates, the Recommended Plan would ensure that Palo Alto exceeds the state’s
annual RPS procurement targets in all but one year (2035) of the IRP planning period. However, because
RPS compliance is evaluated based on aggregate procurement over three‐year compliance periods after
2030, the City would still easily achieve full compliance with its RPS requirements under the
Recommended Plan. (And in reality, CPAU intends to meet or exceed its annual RPS procurement target
in every year.)
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Figure 11: SB 100 RPS Requirements and RPS Level of the Recommended Plan
As Figure 8 indicated, the capacity expansion model adds a significant amount of battery energy storage
systems (BESSs) beginning in the 2040s—25 MW each of 4‐hour, 8‐hour, and 10‐hour BESSs. According
to Ascend, the model selected these resources primarily to ensure the Recommended Plan would satisfy
Palo Alto’s system capacity needs during this period (when almost all of the City’s existing renewable
energy PPAs have expired). Figure 12 illustrates how these BESS additions—along with a small volume
of demand response capacity—ensure that Palo Alto can easily satisfy its system capacity needs
throughout the planning period without having to rely on short‐term RA purchases.
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Section V: Future Procurement Needs and Scenario Analysis
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Figure 12: Projected System Capacity Requirements and Supplies for Palo Alto's Recommended Plan
Scenario Analysis
Given the extended length of the IRP planning period, there is obviously a tremendous amount of
uncertainty around the performance and characteristics of the City’s electric supply portfolio. Changes
in hydrological conditions, regulatory requirements, technological advancements, and the City’s load,
among many other factors, could all have tremendous implications for the results of this portfolio
modeling analysis and the ultimate selection of new resources to include in the City’s portfolio. To try to
understand the magnitude of this uncertainty, CPAU staff and Ascend ran the ARS module under several
different future scenarios, and then used PowerSIMM’s production cost model function to evaluate the
overall cost and cost uncertainty of the supply portfolio selected in each case. The four different
scenarios that were evaluated can be summarized as follows:
1. Base Case – Expected hydro output and expected market prices (P50)
2. Reduced Hydro Output – Hydro energy output is reduced by 30% and capacity is reduced by 60%,
while hydro costs increase by 25%
3. Dry Year, High Prices – Simulating an extended drought, hydro energy output is reduced by 25%,
and market prices are high (P95)
4. Wet Year, Low Prices – Based on historical conditions during wet years, hydro energy output is
increased by 50%, and market prices are low (P5)
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Interestingly, for the wet year and dry year scenarios the model selected the same new capacity
additions as in the base case (see Figure 8). Despite Palo Alto’s heavy concentration of large hydro
resources in its existing portfolio, these long‐term changes in hydrological conditions were not enough
to cause the model to select a different volume or type of resources to include in the portfolio. Instead,
the model indicates that the City should simply buy more or sell more energy and capacity in the short‐
term market to balance its energy and capacity needs in these situations. (While the Recommended Plan
portfolio is 98% hedged on average over the IRP planning period, the Dry Year, High Prices scenario
would yield a portfolio that is 87% hedged, while the portfolio would be 121% hedged in the Wet Year,
Low Prices scenario.)
In the Reduced Hydro Output case, however, the model made significantly different selections for the
City’s supply portfolio, as summarized in the figures below.
Figure 13: Nameplate Capacity of New Resource Additions in Reduced Hydro Output Scenario
Because of the new resources added to the portfolio in the Reduced Hydro Output scenario, the overall
hedge level was 106% for the planning period, as Figure 14 illustrates.
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Section V: Future Procurement Needs and Scenario Analysis
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Figure 14: Projected Load and Energy Supply Balance in the Reduced Hydro Output Scenario
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Figure 15: Projected System Capacity Requirements and Supplies in Reduced Hydro Output Scenario
Portfolio Cost Uncertainty and Management
Financial metrics for the four scenarios described above are displayed in Table 8 below, including each
scenario’s average supply cost, NP15 market price, mark‐to‐market (MTM)19, and risk premium20. As
expected, this information indicates that the total portfolio in the Reduced Hydro Output scenario is
significantly more costly than the Base Case portfolio. But, interestingly, the modeling indicates that the
19 Mark‐to‐market is a risk assessment tool which measures the current estimated value of a portfolio relative to its original
contracted price; a positive value indicates an increase in the value of the purchase, which would be realized only if the
transaction was liquidated. It also represents the City’s credit exposure with the supplier. Note that the MTM values
presented in Table 8 are based on the total cost of each supply resource, but only account for the energy value (as measured
by the resource’s Locational Marginal Price). The RA capacity value and REC value associated with each resource’s output are
not considered in this calculation, thus it is not an accurate representation of the true value of each portfolio; nonetheless,
the MTM differences between the four scenarios are reflective of the differences in their values.
20 The expected value of the cost of each portfolio is the probability‐weighted average cost of CPAU’s supply portfolio across
all simulations performed in the analysis. The risk premium, which is calculated in a manner similar to an insurance premium,
is the probability‐weighted average of costs between the median and 95th percentile of costs in all simulations. It is essentially
a measure of the uncertainty or risk in the estimated value of the different portfolios considered, reflecting the possibility
that supply costs may be greater than the expected costs.
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Section V: Future Procurement Needs and Scenario Analysis
46
portfolio becomes significantly more valuable under both the Dry Year, High Prices scenario, as well as
the Wet Year, Low Prices scenario, compared to the Base Case scenario.
Table 8: Financial Performance Summary of the Four Scenarios Modeled
Base Case Reduced
Hydro Output
Dry Year,
High Prices
Wet Year,
Low Prices
Average Supply Cost ($/MWh) $63.58 $66.27 $83.05 $40.76
Average Market Price ($/MWh) $64.17 $64.17 $88.05 $45.52
Total MTM ($/MWh) $0.65 ($3.34) $4.09 $4.62
Average Annual MTM ($M) $0.47 ($2.00) $5.31 $4.70
Average Annual Risk Premium ($M) $6.43 $3.27 $19.91 $4.33
The Risk Premium results indicate that the portfolio’s cost uncertainty (or value at risk) related to high
market prices/dry hydro conditions is far greater than for low market prices/low hydro conditions. For
this reason, CPAU tends to hedge the supply portfolio based on the assumption of slightly drier than
average conditions, and also maintains significant hydroelectric reserves.
The cost uncertainty of the electric supply portfolio in the short‐term is primarily driven by the water
available for hydroelectric production, and is estimated at $15 to $20 million per year at prevailing
market prices. Palo Alto is well positioned to manage this cost uncertainty through its hydro rate
adjustment mechanism21 and by maintaining sufficient cash reserves. The cost uncertainty related to
seasonally balancing the portfolio22 is minimal since market price variability between seasons is highly
correlated and because staff executes seasonal buy‐sell transactions at the same time.
As noted above, in the long‐term, there are a number of issues that could dramatically affect the value
of the Western resource in the coming years. As such, a large focus of staff efforts in the next five years
will be to better understand the long‐term economics of the Western Base Resource contract and
determine if and when to reduce its allocation of this resource.
There are also proceedings underway to investigate market restructuring to deal with issues related to
the integration of variable renewable resources, very steep evening ramp periods, and the appropriate
valuation of dispatchable generation capacity. Volatility in market prices, as the CAISO and the CEC
determine how to send price signals to ensure a reliable grid, could leave a seasonally unbalanced
portfolio such as the City’s current portfolio exposed. Increases in transmission charges could also make
remote resources compare less favorably to local resources and demand‐side management in the future.
21 For additional detail on the hydro rate adjustment mechanism, please see Staff Report ID 8962 (March 2023):
https://www.cityofpaloalto.org/civicax/filebank/documents/63851.
22 Revenues received from the sale of surplus energy during the spring and summer periods are utilized to purchase electricity
needs for the fall and winter periods.
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Section IV: Supply Costs & Retail Rates
47
Supply Costs & Retail Rates
Critical to the success of an IRP, in addition to ensuring that the adopted plan leads to compliance with
all regulatory requirements, is ensuring that it also results in supply cost minimization and (ideally) low
and stable customer retail rates. As described in the FY 2024 Electric Utility Financial Plan and Rate
Proposal to the Palo Alto City Council, CPAU staff projects supply costs to rise substantially for the next
several years, largely driven by increases in transmission costs, higher RPS requirements, general
capacity shortfalls, and increased natural gas prices.
Retail rates are also projected to rise due to substantial additional capital investment in the electric
distribution system (largely driven by modernizing the residential portion of the distribution system to
accommodate increased building and transportation electrification), and operational cost increases.
CPAU is also in the midst of a capital‐intensive project to convert all of its existing metering infrastructure
to Advanced Metering Infrastructure (AMI), or “smart meters,” with a planned completion date of July
2025. These investments are being funded through the City’s existing Electric Special Projects (ESP)
reserve fund.
CPAU is also currently evaluating the implementation of several new specialized rates, including: a
commercial DC Fast Charging EV rate, a residential time of use rate, and a residential All Electric Rate.
This effort is intended to see if these rates can be justified under cost of service principles and can better
support transportation and building electrification. If we are able to find a way to improve the existing
rate structure to better support transportation and building electrification goals, we will likely implement
a new rate offering in the near future.
In order to ensure adequate revenue recovery, the Palo Alto City Council recently approved a 21% retail
rate increase for FY 2024 (taking effect July 1, 2023), and adopted a Financial Plan that calls for additional
5% annual rate increases for FY 2025 through FY 2028, as illustrated in Figure 16. However, it should be
noted that the City’s current electric rates are far lower than the statewide average electric retail rates,
and, under the recommended portfolio presented in Section V of this report, staff projects that they will
remain so. In fact, even under the worst‐case scenarios staff evaluated the City’s retail electric rates
remain lower than the projected statewide average rates.
VI.
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Section IV: Supply Costs & Retail Rates
48
Figure 16: CPAU Revenues, Expenses, and Rate Changes through FY 2028
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Section VII: Transmission & Distribution Systems
49
Transmission & Distribution Systems
Transmission System
At the transmission level, CPAU staff has two main focuses during the IRP planning period: (1)
determining the optimal utilization of the COTP asset when Palo Alto’s long‐term layoff of this resource
ends on February 1, 2024, as discussed above in the Existing Resource Portfolio section; and (2) pursuing
an additional interconnection point with PG&E’s transmission system. The new interconnection point
with PG&E is being sought in order to provide redundancy, and therefore increased local reliability, in
the event that an outage affects the three current interconnection lines – as happened in February
2010.23 To minimize the possibility of a City‐wide outage caused by an interconnection line outage, it is
in the City’s interest to find a physically diverse connection to the PG&E transmission system for power
supply to the City. Staff has been investigating options for an alternative connection to the transmission
grid for numerous years.24
Distribution System
Palo Alto’s electric distribution system is directly interconnected with the transmission system of Pacific
Gas and Electric Company (PG&E) by three 115 kV lines, which have a delivery point at Palo Alto’s
Colorado substation. Palo Alto’s distribution system consists of the 115 kV to 60 kV delivery point, two
60 kV switching stations, nine distribution substations, approximately 12 miles of 60 kV sub transmission
lines, and approximately 469 miles of 12 kV and 4kV distribution lines – including 223 miles of overhead
lines and 245 miles of underground lines.
In 2018 CPAU staff completed a high‐level distribution system assessment report to begin the process of
understanding the distribution system upgrades that will be required to integrate increasing penetration
levels of distributed energy resources, particularly electric vehicles. A detailed assessment of electric
distribution system upgrade needs to accommodate City’s ambitious building electrification and
transportation electrification goals was undertaken in 2023. The assessment projected the need to plan
the CPAU distribution system for an average residential customer capacity demand of 6 kVA, up from
the current planning paradigm of 2 kVA per customer, in order to accommodate future electrification
efforts. Based on this assessment, efforts are underway to upgrade the following infrastructure
elements:
Distribution transformers and secondary conductors
12 kV Circuit Ties
Substation Transformers
The upgrades are expected to cost $220 to $306 million over the next decade.
23 Although three lines would normally provide redundancy and back‐up power delivery to the City, all three lines run in a
common corridor on the bay side of the City, a corridor that is in close proximity to the Palo Alto Airport. The common corridor
and proximity to an airport means that the City’s power supply is susceptible to single events that can affect all three lines,
as happened in February of 2010 when a small aircraft hit the power lines resulting in a city‐wide power outage for over 10
hours.
24 See this January 2016 staff report for additional background on the efforts to secure an additional transmission
interconnection point: https://www.cityofpaloalto.org/civicax/filebank/documents/50608.
VII.
C.
D.
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Section VIII: Low‐income Assistance Programs
50
Low‐income Assistance Programs
CPAU has three programs to provide financial assistance to low‐income customers:
Residential Energy Assistance Program (REAP): This program provides qualifying low‐income
residents with free energy and water efficiency measures such as LED lighting, heating system
upgrades, weather stripping and shell insulation. More recently, high efficiency toilets, heat
pump water heaters, and air source heat pump systems are added to the measure list. This
program has equal focus on efficiency and comfort, so there may not be reported energy savings
for a customer project.
Rate Assistance Program (RAP): This program provides a 25% discount for electric and gas charges
for income‐qualified customers. Applicants can qualify based on medical or financial need.
ProjectPLEDGE: This program provides a one‐time contribution of up to $750 applied to the
utilities bill of qualifying residential customers. Eligibility criteria include experiencing recent
employment and/or health emergency events. Administered by CPAU, this program is funded by
voluntary customer contributions.
VIII.
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Section IX: Localized Air Pollutants
51
Localized Air Pollutants
The City currently offers various building electrification and transportation electrification program
services to both residential and nonresidential customers. By lowering consumption of gasoline and
natural gas use in buildings, these programs contribute not only to achieving the City’s aggressive GHG
emissions reduction goal, but also reducing localized air pollutants including NOx, SOx and other
particulate matter. Detailed descriptions of these programs are provided in Section IV.A.
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Section X: GHG Emissions Projections
52
GHG Emissions Projections
CARB’s 2017 Scoping Plan identified GHG emissions targets for the entire state, as well as individual
economic sectors, including the electricity industry. The Scoping Plan established an overall electric
sector GHG target for 2030 of 30 to 53 million metric tonnes (MMT) of CO2e, of which Palo Alto’s pro
rata share (based on load) is 0.174%, or 52,049 to 92,103 MT CO2e. As Figure 17 indicates, given its
electric supply portfolio consisting entirely of carbon‐free resources (hydroelectric, wind, solar, and
biogas), Palo Alto is on track to emit far less than even the most aggressive end of the target range
identified in the CARB Scoping Plan.
Figure 17: CPAU Electric Supply Emissions (2005‐2045)
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Section X: GHG Emissions Projections
53
Next Steps and Path Forward
Future Analytical Efforts
The City will have until June 30, 2024 to make a decision to reduce or reject its allocated share of the
future Western contract, which would be 98% of the City’s current share and provides over 30% of the
City’s total electric supply under average conditions. The additional analysis regarding this decision
should include:
1. An examination of the City’s net load forecast and associated uncertainties, with particular
emphasis on how it may be affected by customer electrification and adoption of DERs (Demand
Response, Energy Efficiency, Solar PV, and storage) in order to avoid stranding assets.
2. An update and extension of CPAU’s supply portfolio analysis, including updates to hourly LMP
forecasts and the costs, assumptions, and uncertainties associated with all resource options.
3. Analysis of the projected costs, output, and flexibility of the renewed Western contract, to reduce
and estimate the amount of uncertainty around this resource.
Aside from the Western contract decision, staff will be actively following state regulators’ activities
related to electric supply portfolio GHG emissions accounting and allocation of statewide GHG emissions
reduction targets, as well as efforts to promote greater regionalization of the bulk transmission system
in the western US.
And of course, staff will continue its activities in pursuit of lowering the overall cost to serve customer
loads. These include continuing to optimize the use of the City’s Calaveras resource, evaluating the
benefits of the NCPA pool, and/or the procurement of alternative scheduling services for its renewable
resources.
Key Issues to Monitor & Attempt to Influence
In the course of developing this IRP, CPAU staff has identified a number of important issues and sources
of uncertainty to closely monitor and attempt to positively influence over the course of the planning
period. Some of the primary issues and uncertainties that staff will be focused on include:
Cost and operations of Western hydroelectric resource: environmental restoration cost, water
delivery timing and priorities, Western transmission upgrade needs, environmental regulations
affecting water releases, and long‐term climate change
Frequency and magnitude of economic curtailment of solar PV resources
Renewing the FERC license of the Calaveras hydroelectric project
Seasonal and daily variation in CAISO energy market prices, given the overall generation profile
of CPAU’s resource portfolio
Changes in overall energy market prices and changes in carbon allowance prices associated with
State's cap‐and‐trade program
Increased market prices related to load‐following capacity and ancillary services
Customer load profiles changes and potential loss of customer loads available for the City to serve
New legislative and regulatory mandates
XI.
E.
F.
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Section XI: Appendices
XII—1
Appendices
Key Supplemental Reports and Documents
14. NCPA‐CAISO Metered Sub‐System Agreement
15. FY 2024 Electric Utility Financial Plan
16. Ten‐Year Electric Energy Efficiency Goals (May 2021)
17. City of Palo Alto Utilities 2020 Energy Storage Report (AB2514)
18. Distributed Energy Resources Plan (2017)
19. 2021 RPS and Carbon Neutral Plan Update (October 2022)
20. Impact of Electrification on Electric Resiliency (November 2021)
21. S/CAP Goals and Key Actions (2022)
22. S/CAP Work Plan for 2023‐2025 (June 2023)
23. EV Programs Status Update (August 2022)
24. FY 2021 Demand Side Management Annual Report (June 2023)
25. Electric Distribution Infrastructure Modernization Update (June 2023)
26. Palo Alto Earth Day Report 2023
XII.
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Section XI: Appendices
XII—2
RPS Procurement Plan
CITY OF PALO ALTO’S
RENEWABLE PORTFOLIO STANDARD
PROCUREMENT PLAN
Version 4
December 2020
REVISION HISTORY
Version Date Resolution Description
4 12/07/20 9929 Updated to reflect Senate Bill 100 (2018) requirements
3 12/03/18 9802 Updated to reflect Senate Bill 350 (2015) requirements
2 11/12/13 9381 Updated to reflect adoption of final CEC regulations, effective
10/1/13, permitting the City to adopt rules for Excess Procurement,
Compliance Delay, Cost Limitations, Portfolio Balancing Reductions,
and Historic Carryover. Other non‐substantive clean up.
1 12/12/11 9215 Original version per Senate Bill X1 2 (2011) requirements
H.
CI TY OF
PALO
A 0
UTILITIES
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Section XI: Appendices
XII—3
TABLE OF CONTENTS
INTRODUCTION ........................................................................................................................ XII—4
A. PURPOSE OF THE PLAN (PUC § 399.30(A)) ................................................................... XII—4
B. PLAN ELEMENTS ................................................................................................................ XII—5
1. Compliance Period Definitions ........................................................................................ XII—5
2. Procurement Requirements ............................................................................................. XII—5
3. Portfolio Content Categories (PCC) ................................................................................ XII—6
4. Portfolio Balancing Requirements .................................................................................. XII—6
5. Long ‐Term Contract Requirement .................................................................................. XII—6
6. Reasonable Progress ......................................................................................................... XII—7
C. OPTIONAL COMPLIANCE MEASURES ............................................................................. XII—7
1. Excess Procurement (PUC §399.13(a)(4)(B)) ................................................................ XII—7
2. Delay of Timely Compliance (§ 399.30(d)(2), § 399.15(b)(5)) .................................. XII—8
3. Cost Limitations for Expenditures (PUC § 399.30(d), § 399.15(c)) ........................ XII—10
4. Portfolio Balance Requirement Reduction (PUC § 399.16(e)) ................................ XII—11
5. Historic Carryover ............................................................................................................ XII—11
6. Large Hydro Exemption (PUC § 399.30(l)) .................................................................. XII—13
D. ADDITIONAL PLAN COMPONENTS ................................................................................ XII—14
1. Exclusive Control (PUC § 399.30(n)) ............................................................................ XII—14
2. Deliberations & Reporting (PUC § 399.30(e), § 399.30(f)) ...................................... XII—14
3. Annual Review ............................................................................................................. XII—15
4. Plan Modifications/Amendments ................................................................................. XII—15
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Section XI: Appendices
XII—4
INTRODUCTION
This document presents the City of Palo Alto Utilities’ (CPAU) Renewable Portfolio Standard Procurement
Plan (RPS Procurement Plan), as required for compliance with Senate Bill (SB) 100.25 This legislation,
which was signed into law in the 2018 Session of the Legislature, modified the state’s renewable portfolio
standard (RPS) program and set forth RPS requirements applicable to all load‐serving entities in the state.
Pursuant to Public Utility Code § 399.30(a) and Section 3205 of the California Energy Commission’s (CEC)
“Enforcement Procedures for the Renewables Portfolio Standard for Local Publicly Owned Electric
Utilities”26 (RPS Regulations), each POU must adopt and implement a renewable energy resources
procurement plan (RPS Procurement Plan). SB X1 2, signed into law in 2011, directed the CEC to adopt
regulations specifying procedures for enforcement of the RPS for Publicly Owned Utilities.
This RPS Procurement Plan replaces the RPS Procurement Plan approved by the Palo Alto City Council
(City Council) on December 3, 2018 (Resolution No. 9802, Staff Report No. 9761) and is consistent with
the provisions set forth in the CEC’s RPS Regulations, which have been adopted by the CEC and approved
by the Office of Administrative Law, with an effective date of April 12, 2016.27
CPAU’s RPS Procurement Plan consists of:
A. Purpose of the plan;
B. Plan Elements;
C. Measures that address each of the optional provisions set forth in §399.30(d) and RPS
Regulations Section 3206; and
D. Additional provisions.
Where appropriate, this RPS Procurement Plan includes section citations to the Public Utilities Code
(PUC) and the CEC’s RPS Regulations.
A. PURPOSE OF THE PLAN (PUC § 399.30(A))
In order to fulfill unmet long‐term generation resource needs, the City Council adopts and implements
this RPS Procurement Plan. This Plan requires the utility to procure a minimum quantity of electricity
products from eligible renewable energy resources, including renewable energy credits (RECs), as a
25 SB 100 (2018) was signed by California’s Governor on September 10, 2018, and made significant revisions to Public Utilities
Code sections 399.11‐399.32, the California Renewable Portfolio Standard Program.
26 California Code of Regulations, Title 20, Division 2, Chapter 13, Sections 3200 ‐ 3208 and Title 20, Division 2, Chapter 2,
Section 1240.
27 At the time of writing for this edition of CPAU’s RPS Procurement Plan, the RPS Regulations had not been updated with SB
350 and subsequent legislative requirements. Where both Public Utility Codes and RPS Regulations are cited but the RPS
Regulations are outdated, CPAU’s RPS Procurement Plan will reflect the more current Public Utility Codes.
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Section XI: Appendices
XII—5
specified percentage of CPAU’s total kilowatt‐hours of electrical energy sold to its retail end‐use
customers, during each compliance period, to achieve the targets specified in SB 100 and the RPS
Regulations. This RPS Procurement Plan establishes the framework for achieving the minimum
requirements under SB 100 and the RPS Regulations, and does not include or preclude actions taken by
CPAU to achieve the City Council’s goals.
B. PLAN ELEMENTS
CPAU will comply with the requirements for renewables procurement targets set forth in SB 100 and the
applicable enforcement procedures codified in the CEC’s RPS Regulations, including implementation of
the following Plan Elements:
1. Compliance Period Definitions
CPAU has adopted the relevant compliance period definitions identified in PUC § 399.30(b).
2. Procurement Requirements
CPAU shall meet or exceed the following procurement targets of renewable energy resources for
each compliance period per PUC §§ 399.30(c)(1) and (2) and the CEC’s RPS Regulations:
Compliance Period 1 Target ≥ 20% × (CPAU Retail Sales2011_+ CPAU Retail Sales2012 + CPAU Retail
Sales2013).
Compliance Period 2 Target ≥ 20% × CPAU Retail Sales2014 + 20% × CPAU Retail Sales2015 + 25% ×
CPAU Retail Sales2016
Compliance Period 3 Target ≥ 27% × CPAU Retail Sales2017 + 29% × CPAU Retail Sales2023 + 31% ×
CPAU Retail Sales2019 + 33% × CPAU Retail Sales2020
Compliance Period 4 Target ≥ 35.75% × CPAU Retail Sales2021 + 38.5% × CPAU Retail Sales2022 +
41.25% × CPAU Retail Sales2023 + 44% × CPAU Retail Sales2024
Compliance Period 5 Target ≥ 46% × CPAU Retail Sales2025 + 50% × CPAU Retail Sales2026 + 52% ×
CPAU Retail Sales2027
Compliance Period 6 Target ≥ 54.67% × CPAU Retail Sales2028 + 57.33% × CPAU Retail Sales2029 +
60% × CPAU Retail Sales2030
For every subsequent three‐year Compliance Period (e.g., 2031‐2033), CPAU shall procure
renewable energy resources equivalent to at least sixty percent (60%) of retail kilowatt‐hour sales
during that Compliance Period.
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Section XI: Appendices
XII—6
The procurement targets listed for each individual year above are soft targets. That is, by the end of
each Compliance Period, CPAU’s RPS total for the period has to equal the sum of the annual targets,
but the targets do not have to be achieved in each individual year.
3. Portfolio Content Categories (PCC)
CPAU adopts the definitions for qualifying electric products and Portfolio Content Categories
(PCC) per Sections 3202 and 3203 of the CEC’s RPS Regulations.
a. How CPAU Plans to Achieve its RPS Requirements per Section 3205(a)(1) of the CEC’s RPS
Regulations
CPAU’s RPS portfolio will include grandfathered contracts (commonly referred to as “PCC
0”), which are executed prior to June 1, 2010, and PCC 1 eligible resources, which are
typically directly or dynamically connected to a California balancing authority. CPAU’s
RPS portfolio may also include PCC 2 eligible resources that are scheduled into a California
balancing authority, and PCC 3 eligible resources, which are typically unbundled
renewable energy credits (RECs). PCC 0 resources are defined in Section 3202(a)(2) of the
CEC’s RPS Regulations, while PCC 1, 2, and 3 resources are defined in Section 3203 of the
CEC’s RPS Regulations. CPAU shall determine the category to which each procured
resource belongs.
In its 2011 through 2017 RPS Compliance Reports, CPAU listed a total of five PCC 0
contracts. All five of these contracts extend through the end of Compliance Period 3, and
all have achieved commercial operation. On their own, these PCC 0 contracts were
sufficient to enable CPAU to meet its Compliance Period 1 and 2 RPS targets.
CPAU has currently executed six contracts for PCC 1 resources, all of which have
commenced operation. With these six PCC 1 resources, along with its five PCC 0 contracts,
CPAU forecasts that its renewable energy supplies will be well in excess of its
procurement requirements through at least Compliance Period 6.
4. Portfolio Balancing Requirements
In satisfying the procurement requirements listed in section B.3 of this RPS Procurement Plan,
CPAU shall also satisfy the legally‐required portfolio balancing requirements specifying the limits
on quantities for PCC 1 and PCC 3 per PUC § 399.30(c)(3), §§ 399.16(c)(1) and (2). CPAU shall
apply the formulae specified in Section 3204(c) of the CEC’s RPS Regulations to determine these
portfolio balance requirements. Renewable energy procured from PCC 0 contracts shall be
excluded from these portfolio balancing requirement formulae.
5. Long ‐Term Contract Requirement
In meeting the RPS procurement requirements identified in section B.3 of this RPS Procurement
Plan, CPAU is subject to long‐term contract requirements. Consistent with Public Resources Code
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§ 399.13(b), CPAU may enter into a combination of long‐ and short‐term contracts for electricity
and associated renewable energy credits. Beginning January 1, 2021, at least 65 percent of
CPAU’s procurement that counts toward the RPS requirement of each compliance period shall
be from its contracts of 10 years or longer or in its ownership or ownership agreements for
eligible renewable energy resources.
6. Reasonable Progress
CPAU shall demonstrate that it is making reasonable progress towards ensuring that it shall meet
its compliance period targets during intervening years per PUC §§ 399.30(c)(2).
C. OPTIONAL COMPLIANCE MEASURES
As permitted by Section 3206(a) of the CEC’s RPS Regulations, the City Council hereby adopts rules
permitting the use of each of the following five optional compliance measures included in the CEC’s RPS
Regulations: Excess Procurement, Delay of Timely Compliance, Cost Limitations, Portfolio Balance
Requirement Reduction, and Historic Carryover. The City Council also hereby adopts rules permitting the
use of the Large Hydro Exemption as described in PUC § 399.30(l).
1. Excess Procurement (PUC §399.13(a)(4)(B))
a. Adoption of Excess Procurement Rules
The City Council has elected to adopt rules permitting CPAU to apply excess procurement
in one compliance period to a subsequent compliance period, as described in Section
3206(a)(1) of the CEC’s RPS Regulations.
b. Limitations on CPAU’s Use of Excess Procurement
CPAU shall be allowed to apply Excess Procurement from one compliance period to
subsequent compliance periods as long as the following conditions are met:
1. Excess Procurement shall only include generation from January 1, 2011 or later.
2. Eligible resources must be from Content Category 1 or Grandfathered Resources to
be Excess Procurement. Resources from Content Category 2 or Content Category 3
will not count towards Excess Procurement.
c. Excess Procurement Calculation
CPAU shall calculate its Excess Procurement according to formulae in section 3206
(a)(1)(D) of the CEC’s RPS Regulations.
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d. City Council Review
CPAU’s use of the Excess Procurement to apply towards CPAU’s RPS procurement target
in any compliance period will be reviewed by the City Council during its annual review as
per section D.3 of this RPS Procurement Plan.
2. Waiver of Timely Compliance (§ 399.30(d)(2), § 399.15(b)(5))
a. Adoption of Waiver of Timely Compliance Rules
The City Council has elected to adopt rules permitting it to make a finding that conditions
beyond CPAU’s control exist to delay timely compliance with RPS procurement
requirements, as described in Section 3206(a)(2) of the CEC’s RPS Regulations.
b. Waiver of Timely Compliance Findings
The City Council may make a finding, based on sufficient evidence presented by CPAU
staff, and as described in this Section C.2, that is limited to one or more of the following
causes of delay, and shall demonstrate that CPAU would have met its RPS procurement
requirements but for the cause of the delay:
(1) Inadequate Transmission
i. There is inadequate transmission capacity to allow for sufficient
electricity to be delivered from CPAU’s proposed eligible renewable energy
resource projects using the current operational protocols of the California
Independent System Operator’s Balancing Authority Area.
ii. If the City Council’s delay finding rests on circumstances related to
CPAU’s transmission resources or transmission rights, the City Council may find
that:
a) CPAU has undertaken, in a timely fashion, reasonable measures
under its control and consistent with its obligations under local, state, and
federal laws and regulations, to develop and construct new transmission
lines or upgrades to existing lines intended to transmit electricity
generated by eligible renewable energy resources, in light of its
expectation for cost recovery.
b) CPAU has taken all reasonable operational measures to
maximize cost‐effective purchases of electricity from eligible renewable
energy resources in advance of transmission availability.
(2) Permitting, interconnection, or other factors that delayed procurement or
insufficient supply.
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i. Permitting, interconnection, or other circumstances have delayed
procured eligible renewable energy resource projects, or there is an insufficient
supply of eligible renewable energy resources available to CPAU.
ii. In making its findings relative to the existence of this condition, the
City Council’s deliberations shall include, but not be limited to the following:
a) Whether CPAU prudently managed portfolio risks, including, but
not limited to, holding solicitations for RPS‐eligible resources with
outreach to market participants and relying on a sufficient number of
viable projects;
b) Whether CPAU sought to develop its own eligible renewable
energy resources, transmission to interconnect to eligible renewable
energy resources, or energy storage used to integrate eligible renewable
energy resources.
c) Whether CPAU procured an appropriate minimum margin of
procurement above the minimum procurement level necessary to comply
with the renewables portfolio standard to compensate for foreseeable
delays or insufficient supply;
d) Whether CPAU has taken reasonable measures, under its control
to procure cost‐effective distributed generation and allowable unbundled
renewable energy credits;
e) Whether actions or events beyond CPAU’s control have
adversely impacted timely deliveries of renewable energy resources
including, but not limited to, acts of nature, terrorism, war, labor difficulty,
civil disturbance, or market manipulation;
(3) Unanticipated curtailment of eligible renewable energy resources if the delay
would not result in an increase in greenhouse gas emissions.
(4) Unanticipated increase in retail sales due to transportation electrification. In
making a finding that this condition prevents timely compliance, the City Council
shall consider both of the following:
(i) Whether transportation electrification significantly exceeded forecasts in
CPAU’s service territory based on the best and most recently available
information filed with the State Air Resources Board, the Energy
Commission, or another state agency.
(ii) Whether CPAU took reasonable measures to procure sufficient resources to
account for unanticipated increases in retail sales due to transportation
electrification.
c. Procedures upon Approving Waiver:
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In the event of a Waiver of Timely Compliance due to any of the factors set forth above,
CPAU shall implement the following procedures:
(1) Establish additional reporting for intervening years to demonstrate that
reasonable actions under the CPAU’s control are being taken (§399.15(b)(6)).
(2) Require a demonstration that all reasonable actions within the CPAU’s control
have been taken to ensure compliance in order to grant the waiver (§
399.15(b)(7)).
3. Cost Limitations for Expenditures (PUC § 399.30(d), § 399.15(c))
a. Cost Limitations for Expenditures
The City Council has elected to adopt rules for cost limitations on the procurement
expenditures used to comply with CPAU’s procurement requirements, as described in
Section 3206(a)(3) of the CEC’s RPS Regulations. These cost limitation rules are intended
to be consistent with PUC §399.15(c).
b. Considerations in Development of Cost Limitation Rules
In adopting cost limitation rules, the City Council has relied on the following:
1) This Procurement Plan;
2) Procurement expenditures that approximate the expected cost of building,
owning, and operating eligible renewable energy resources;
3) The potential that some planned resource additions may be delayed or canceled;
and
4) Local and regional economic conditions and the ability of CPAU’s customers to
afford produced or procured energy products. These economic conditions may
include but are not limited to unemployment, wages, cost of living expenses, the
housing market, and cost burden of other utility rates on the same customers. The
City Council may also consider cost disparities between customer classes within
Palo Alto, and between Palo Alto customers and other Publicly Owned Utility and
Investor Owned Utility customers in the region.
c. Cost Limitations
Since 2002, the City of Palo Alto’s RPS policy has required that CPAU pursue a target level
of renewable purchases while “[e]nsuring that the retail rate impact for renewable
purchases does not exceed 0.5 ¢/kWh on average,” i.e., the cumulative incremental cost
of all renewable resources over and above the estimated cost of an equivalent volume
and shape of alternative non‐RPS resources shall not cause a retail rate impact in excess
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XII—11
of 0.5 ¢/kWh on average. This limit was first established by the City Council in October
2002 based on public input, and the goal of balancing resource reliability and cost
considerations in the consideration of investment in renewable and energy efficiency
resources.
d. Actions to be Taken if Costs Exceed Adopted Cost Limitation
If costs are anticipated to exceed the cost limitations set by the City Council, staff will
present proposals to the City of Palo Alto’s Utilities Advisory Commission to either reduce
the RPS requirements or increase the cost limitation. Staff and the Commission’s
recommendations will then be taken to the City Council for action.
4. Portfolio Balance Requirement Reduction (PUC § 399.16(e))
a. Adoption of Portfolio Balance Requirement Reduction Rules
The City Council has elected to adopt rules that allow for the reduction of the portfolio
balance requirement for PCC 1 for a specific compliance period, consistent with PUC
§399.16(e), as described in Section 3206(a)(4) of the CEC’s RPS Regulations.
b. Portfolio Balance Requirement Reduction Rules
CPAU may reduce the portfolio balance requirement for PCC1 for a specific compliance
period, consistent with PUC §399.16 (e) and the following:
1. The need to reduce the portfolio balance requirements for PCC 1 must have
resulted because of conditions beyond CPAU’s control, as provided in Section
3206(a)(2) of the CEC’s RPS Regulations.
2. CPAU may not reduce its portfolio balance requirement for PCC 1 below 65
percent for any compliance period after December 31, 2016.
3. Any reduction in portfolio balance requirements for PCC 1 must be adopted at a
publicly noticed meeting, providing at least 10 calendar days’ notice to the CEC,
and include an updated renewable energy resources procurement plan detailing
the portfolio balance requirement changes.
5. Historic Carryover
a. Adoption of Historic Carryover Rules
The City Council has elected to adopt rules to permit its use of Historic Carryover, as
defined in Section 3206(a)(5) of the RPS Regulations, to meet its RPS procurement targets.
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Current calculations indicate that CPAU has Historic Carryover due to CPAU’s early
investment in renewable energy resources.
b. Historic Carryover Procurement Criteria
CPAU’s use of Historic Carryover is subject to section 3206 (a)(5) of the CEC’s RPS
Regulations, including the following:
1) Procurement generated before January 1, 2011 may be applied to CPAU’s RPS
procurement target for the compliance period ending December 31, 2013, or
for any subsequent compliance period; and
2) The procurement must also meet the criteria of Section 3202 (a)(2) of the CEC’s
RPS Regulations; and
3) The procurement must be in excess of the sum of the 2004‐2010 annual
procurement targets defined in Section 3206(a)(5)(D) of the CEC’s RPS
Regulations; and
4) The procurement cannot have been applied to the RPS of another state or to a
voluntary claim.
5) The Historic Carryover must be procured pursuant to a contract or ownership
agreement executed before June 1, 2010.
6) Both the Historic Carryover and the procurement applied to CPAU’s annual
procurement targets must be from eligible renewable energy resources that
were RPS‐eligible under the rules in place for retail sellers at the time of
execution of the contract or ownership agreement, except that the generation
from such resources need not be tracked in the Western Renewable Energy
Generation Information System.
c. Historic Carryover Formula
CPAU will calculate its Historic Carryover according to formulae in section 3206 (a)(5)C)
and (D) of the CEC’s RPS Regulations.
d. Historic Carryover Claims
The number of RECs qualifying for Historic Carryover is dependent upon the acceptance
by the CEC of CPAU’s applicable procurement claims for January 1, 2004 – December 31,
2010, which are due to the CEC within 90 calendar days after the effective date of the
CEC’s RPS Regulations (October 30, 2013). The Historic Carryover submittal shall also
include baseline calculations, annual procurement target calculations, and any other
pertinent data.
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e. Council Review
CPAU’s use of the Historic Carryover to apply towards CPAU’s RPS procurement target in
any compliance period will be reviewed by the City Council during its annual review as per
section D.3 of this RPS Procurement Plan.
6. Large Hydro Exemption (PUC § 399.30(l))
a. Adoption of Large Hydro Exemption Rules
The City Council has elected to adopt rules permitting CPAU to reduce its annual RPS
procurement requirements, as described in PUC §399.30(l).
b. Limitations on CPAU’s Use of the Large Hydro Exemption
CPAU shall be allowed to invoke the Large Hydro Exemption as long as the following
conditions are met:
1. During a year within a compliance period, CPAU shall have received greater than
40% of its retail sales from large hydroelectric generation, which is defined as
electricity generated from a hydroelectric facility that is not an eligible renewable
energy resource.
2. The large hydroelectric generation is produced at a facility owned by the federal
government as a part of the federal Central Valley Project or a joint powers agency.
3. Only large hydroelectric generation that is procured under an existing agreement
effective as of January 1, 2015, or an extension or renewal of that agreement, shall
counted in the determination that CPAU has received more than 40% of its retail sales
from large hydroelectric generation in any year.
c. Large Hydro Exemption Calculation
CPAU’s annual RPS procurement target for a year in which the Large Hydro Exemption is
invoked shall equal the lesser of (a) the portion of CPAU’s retail sales unsatisfied by its
large hydroelectric generation or (b) the annual RPS procurement soft target for that year,
as listed in section B.2 of this RPS Procurement Plan. CPAU’s RPS procurement
requirement for the compliance period that includes said year shall be adjusted to reflect
any reduction in CPAU’s annual RPS procurement target pursuant to this section.
d. City Council Review
CPAU’s use of the Large Hydro Exemption to reduce its annual RPS procurement target in
any compliance period will be reviewed by the City Council during its annual review as per
section D.3 of this RPS Procurement Plan.
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D. ADDITIONAL PLAN COMPONENTS
1. Exclusive Control (PUC § 399.30(n))
In all matters regarding compliance with the RPS Procurement Plan, CPAU shall retain exclusive control
and discretion over the following:
a. The mix of eligible renewable energy resources procured by CPAU and those additional
generation resources procured by CPAU for purposes of ensuring resource adequacy and
reliability.
b. The reasonable costs incurred by CPAU for eligible renewable energy resources owned by
it.
2. Deliberations & Reporting (PUC § 399.30(e), § 399.30(f))
a. Deliberations on Procurement Plan (§399.30(f)):
(1) Public Notice: Annually, CPAU shall post notice of meetings if the CPA Council will
deliberate in public regarding this RPS Procurement Plan.
(2) Notice to the California Energy Commission (CEC): Contemporaneous with the
posting of a notice for such a meeting, CPAU shall notify the CEC of the date, time
and location of the meeting in order to enable the CEC to post the information on
its Internet website.
(3) Documents and Materials Related to Procurement Status and Plans: When CPAU
provides information to the CPA Council related to its renewable energy resources
procurement status and future plans, for the City Council’s consideration at a
noticed public meeting, CPAU shall make that information available to the public
and shall provide the CEC with an electronic copy of the documents for posting on
the CEC’s website.
b. Compliance Reporting (Section 3207 of the CEC RPS Regulations)
(1) CPAU shall submit an annual report to the CEC by July 1. The annual reports shall
include the information specified in Section 3207(c) of the CEC RPS Regulations.
(2) By July 1, 2021; July 1, 2025; July 1, 2028; July 1, 2031; and by July 1 of every third
year thereafter, CPAU shall submit to the CEC a compliance report that addresses
the annual reporting requirements of the previous section, and information for
the preceding compliance period as specified in Section 3207(d) of the CEC RPS
Regulations.
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3. Annual Review
CPAU’s RPS Procurement Plan shall be reviewed annually by the City Council in accordance with CPAU’s
RPS Enforcement Program.
4. Plan Modifications/Amendments
This RPS Procurement Plan may be modified or amended by an affirmative vote of the City Council during
a public meeting. Any City Council action to modify or amend the plan must be publicly noticed in
accordance with Section D.2.a.
Effective Date: This plan shall be effective on December 7, 2020.
APPROVED AND ADOPTED this 7th day of December, 2020.
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XII—16
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7
Item 1
Attachment B - 2023
Integrated Resource Plan
Report
Packet Pg. 89
Section XI: Appendices
XII—17
Energy Balance Table (EBT)
ii.
Stat e of California
California Energy Commission
!lilnd;udized Reportin1:Ti1bles for Public Owned Utility IRP Fil inc
EnercvBillilnCl!Tilble
Sc:emirioNilme: Expected
NET ENERGY FOR LOAD CALCULATIONS
Retailsalestoend-usecustomers
Other loads
Unmanaged net energy for load
Managedretailsalestoend-usecustomers
Managednetenergyforload
Fi rm Sal e s Obliga tions
Totill netenercvforlo.! (5+-6)
[Customer-side solar generation]
[Light Duty PEVelect ricity procurement requirement]
10 [Other transportation electricity~procurement requirement]
[Otherelectrifiration/fuelsubstit ution;~rocurementrequirement]
12h
Bi
13j
13k
131
13m
"" 13. ..
16a
16e
16
19
19a
20
21
"
EXISTING ANO PLANNED GENERATION RESOURCES
Utility-Owned Generiltion Resources (not RP5-elicible):
[list resource byname]
Collierville
Lonc-TermContrilcts (not RPS-elicible):
[list contracts byname]
\VestcmBasc Rcsou·ce Generation
Totill eneriv from existinc ilnd plilnnl!d supply resources (not RPS-elicible) (sum of 12il ... 12n)
Utility-Owned RP5-elicible Genl!l"iltion Resources:
flis t resourcebvolantorunitl
NewS iccrHm,.,.,.lcctric
Lonc-TermContrilcts (RPS-elicible):
flistcontractsbvnamel
PROJECT #l -IDGHWINDS
PROJECT #2 -SHILOH #1
Santa Cruz ffiucna Vt st Lnnfi II)
Ck Mountain<HalfMoon Bav)
KcllcrCanvon
Jdnson C Anrrcsco
San Joonuin ( Amcrcsco)
EEKcttlanmLam
Flevation Solar C
WcstcmAntclnn<" Blue Sl..-vRanc:hB
FromicrSolar
HavworthSolar
\VilsonaSolar
P.iloAltoCIEANPro"ccts
Si.nail Part of\Vcstcm Arca Power Association
Totill enerl!V from RP5-elil!ible resources fsum of 13il ... 13n, ilnd 13zl
Undali..,.r■d RPS ■n■r£V
Totill eneriNfromexistin ilnd lilnnl!dsuool resources 12+13
GENERIC ADDITIONS
NON-RPS ELIGIBLE RESOURCES:
flis t resourcebvnameordesai tionl
Totill ■n■ rcv from 1:11n ■ric suppl r■sourc■s {not RPS-.licibl ■)
RPS-ELIGIBLE RESOURCES:
flist resourcebvnameordesai tionl
Totill enerl!V from americ RPS-elicibl• resources
Totill ■n■ri,vfromNn■ricsuDDI r■sourc■s 15+16
Totill ■n■ r"" from RPS-.liPibl■ short-tum contrilcts
ENERGY FROM SHORT-TERM PURCHASES
Short t■rm ilnd s ot ITlil rk ■t P1Jrchi1s■s :
ENERGY BALANCE SUMMARY
Totill enerl!V from sui:ii:il resources {14+17+17zl
Undaliwr■dRPS ■n■rcv{froml3z}
Short t■rm ilnd snot ITlil rk ■t nurchilS■s from 18
Totill deliveredeneriNfl9-19i1+20l
Totillnl!tenl!l"1Nforloiid {from7}
9.JrlusShortt.r.1121-22
H lcctric
Isauto-,nxbtin<>
ttm,.,.,.lcctric
WiIKI
WiIKI
Landfill Gas
Landfill Gas
Landfill Gas
Landfill Gas
Landfill Gas
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Hvdroclcctric
3%
0%
Units=MWh
Yel lo w fi llrelate~t o,ma pplic.ition fo rconfidenti.ility.
Historical Diltil
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 =-== == -= =-mua -===mu•====-=
941423 938,410 934,782 932 532 931063 930,216 930,201 930,358 930,553 931173 931 787 933,453
941,423 l 941,423 941,423 938,410 934,782 932,532 931,()63 930,216 930,201 930,358 930,553 931,173 931,787 933,453
18,005 20,277 22,674 24,065 25,620 27,360 29,304 31,474 33,897 36,599 39,614 42,975 46,719 50,890
7316 9510 11,967 14704 17685 20933 24444 28246 32275 36579 41144 46000 51073 56406
1,049 1,423 1,876 2,431 3,083 3,831 4,639 5,507
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
241017 92 779 115 701 131 668 131,668 131668 131 668 131,668 131668 131 668 131,668 131 668 131 668 131 668
782,556 504,184 525,212 517,482 495,957 495,957 495,957 495,957 495,957 495,957 495,957 495,957 495,957 495,957
5,000 5,000 5,000 5,000 5,0CX) 5,000 5,000 5,0CX) 5,000 5,000 5,0CX) 5,000 5,000 5,0CX)
48,207 42 664 42 668 42 754 42,721 42 708 42 672 42 711 42 671 42 709 42 722 12 615
64,513 57.281 57290 57425 57366
9853 8961 8961 8986 8961 8961 8961 8,985 8961 1449
14.894 13,827 13 827 13 865 13,827 13 827 13 827 13 863 13 827 13 827 13 827 13 865 9 205
10,433 9,200 9 200 9 225 9 200 9 200 9 200 9 224 9 200 9 200 9 200 9 225 9 200 9 200
30 283 27.468 27 468 27 544 27 468 27 468 27 468 27 540 27 468 27 468 27 468 27 544 27 468 27 468
50,367 50,115 49864 49615 49367 49120 48874 48630 48387 48145 4790! 47665 47426 47189
52 338 52 077 51816 51557 51,299 51043 50 788 50 534 50 281 50030 49 780 49 531 49 283 49 037
2,062 2,052 2 042 2 031 2,021 2 011 2 001 1,991 1981 1971 1961 1951 1942 1932
5,000 5,000 5,000 5,000 5,0CX) 5,000 5,000 5,0CX) 5,000 5,000 5,0CX) 5,000 5,000 5,0CX)
553,984 532,171 530,582 529,489 572,668 543,350 541,370 539,743 537,511 528,123 524,782 493,034 445,156 420,115
279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885
1,336,540 1,036,355 1,055,794 1,()46,970 1,068,625 1,039,307 1,037,327 1,035,700 1,033,468 1,024,080 1,020,739 988,991 941,114 916,073
r 2011 2021 r 2022 2026 r 2021 202s r 2029
81,940 79,524 154,110 182,370 160,888 170,642 172,094 173,495 177,953 184,029 188,028 207,719 239,323 258,553
1,336,540 1,036,355 1,055,794 1,046,970 1,068,625 1,039,307 1,037,327 1,035,700 1,033,468 1,024,080 1,020,739 988,991 941,114 916,073
279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885
81,940 79,524 154,110 182,370 160,888 170,642 172,()94 173,495 177,953 184,029 188,028 207,719 239,323 258,553
1,138,833 935,349 923,253 949,255 945,624 942,548 941,081 940,236 947,485 947,643 947,840 948,459 949,074 950,741
941,423 941,423 941,423 938,410 934,782 932,532 931,()63 930,216 930,201 930,358 930,553 931,173 931,787 933,453
197,409 6,075 18,170 10,845 10,842 10,016 10,018 10,020 17,284 17,286 17,287 17,287 17,287 17,288
Item 1
Attachment B - 2023
Integrated Resource Plan
Report
Packet Pg. 90
Section XI: Appendices
XII—18
GHG Emissions Accounting Table (GEAT)
iii.
State of California
Californi a Energy Commission
Standardized Reporting Tabl es for Public Owned utility IRP Filing
GHG Emissions Accounting Table
Scenario Name: Expected
GHG EMISSIONS FROM EXISTING ANO PLANNED SUPPLY RESOURCES
utility-Owned Generation (not RPS--eligible):
listresourcebvn.amel
#REF!
Long•TermContracts (notRPS-eligible):
listcontractsbvn amel
lh Western Base Rcsotn:c Gene-ration
Total GHG emissions of existing and planned supply resource s (not RPS.
eli ible)fsumofla ... ln)
utility-OwnedRPS--eligi ble Generation Resources:
listresourcebv lant orunitl
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EMISSIONS FROM GENERIC ADD ITIONS
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GHG EMISSIONS OF SHORT TERM PURCHASES
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TOTAL GHG EMISSIONS
Total GHG emissions to meet net enervvfor load 3+6+7
EMISSIONS ADJUSTMENTS
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Emi ssions Intensity Units" mt CO2e/MWh
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Emissionslntensit 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Emissionslntensit
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Emissio nslntensit 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Emissio nslnte nsit
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0.428 35,070 34,036 65,959 78,054 68,860 73,035 73,656 74,256 76,164 78,764 80,476 88,904 102,430 110,661
35,070 34,036 65,959 78,054 68,860 73,035 73,656 74,256 76,164 78,764 80,476 88,904 102,430 110,661
279.647 180.530 286.651 280.085 283.889 267.401 268.34 1 268.959 263.937 260.465 260.927 248.251 231.363 223.885
0 0 0 0 0 0 0 0 0 0 0 0 0
279.647 180.530 286.651 280.085 283.889 267.401 268.341 268.959 263.937 260.465 260.927 248.251 231.363 223.885
0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428
119.689 77.267 122.687 119.877 121.505 114.448 114.850 115.114 112.965 111.479 111.677 106.251 99.023 95.823
-84.619 -43.231 -56.728 -41.822 -52.645 -41.413 -41.193 -40.859 -36.801 -32.715 -31.201 -17.348 3.407 14.838
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Item 1
Attachment B - 2023
Integrated Resource Plan
Report
Packet Pg. 91
Section XI: Appendices
XII—19
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Item 1
Attachment B - 2023
Integrated Resource Plan
Report
Packet Pg. 92
6056782
2
3
7
6
Integrated Resource Plan (IRP)
Objective and Strategies
IRP Objective
To provide safe, reliable, environmentally sustainable and cost-effective electricity supplies and
services to all customers.
IRP Strategies
1. Pursue an Optimal Mix of Supply-side and Demand-side Resources: When procuring to
meet demand, pursue an optimal mix of resources that meets the IRP Objective, with
cost-effective energy efficiency, distributed generation, and demand-side resources as
preferred resources. Consider portfolio fit and resource uncertainties when evaluating
cost-effectiveness.
2.Maintain a Carbon Neutral Supply: Maintain a carbon neutral electric supply portfolio to
meet the community’s greenhouse gas (GHG) emission reduction goals.
3.Actively Manage Portfolio Supply Cost Uncertainties: Structure the portfolio or add
mitigations to manage short-term risks (e.g. market price risk and hydroelectric
variability) and build flexibility into the portfolio to address long-term risks (e.g. resource
availability, customer load profile changes, and regulatory uncertainty) through
diversification of suppliers, contract terms, and resource types.
4.Manage Electric Portfolio to Ensure Lowest Possible Ratepayer Bills: Pursue resources
in a least-cost, best-fit approach in an effort to ensure ratepayer bills remain as low as
possible, while achieving other Council-adopted sustainability, rate, and financial
objectives.
5.Partner with External Agencies to Implement Optimization Opportunities: Actively
engage and partner with external agencies to maximize resource value and optimize
operations.
6.Manage Supplies to Meet Changing Customer Loads and Load Profiles: Maintain electric
supply resource flexibility in anticipation of potential changes in customer loads due to
distributed energy resources, efficiency, electrification, or for other reasons. At the same
time, use retail rates and other available tools to influence customer load changes in a
manner that minimizes overall costs and achieves other Council objectives.
7.Ensure Reliable and Low-cost Transmission Services: Work with the transmission system
operator to receive reliable service in a least-cost manner.
8.Support Local Electric Supply Resiliency: Coordinate supply portfolio planning with
utility-wide efforts to support local measures and programs that enhance community
electric supply resiliency.
9.Comply with State and Federal Laws and Regulations: Ensure compliance with all
statutory and regulatory requirements for energy, capacity, reserves, GHG emissions,
distributed energy resources, efficiency goals, resource planning, and related initiatives.
Attachment C
Item 1
Attachment C - IRP
Objective & Strategies
Packet Pg. 93
Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Utilities
Meeting Date: November 7, 2023
Staff Report:2309-2082
TITLE
Discussion and Update of the Palo Alto Fiber Expansion Plan and Construction Alignment with
Electric Grid Modernization. CEQA Status – Not a project.
RECOMMENDATION
This memorandum and presentation are for discussion purposes only; no action is requested at
this time.
EXECUTIVE SUMMARY
On December 19, 2022, City Council directed staff to proceed with the Fiber Expansion Plan to
implement the Fiber Rebuild project and Phase 1 of the Fiber-to-the-Premises (FTTP) project. In
Phase 1, FTTP would be built out in selected areas of the city, and expanded gradually (Staff
Report ID # 14800)1. Construction of the fiber backbone in the Fiber Rebuild project and last mile
infrastructure to provide FTTP broadband internet to the community in the FTTP project will be
a significant undertaking for the City. Before construction commences, staff needs to address the
following to control project costs, minimize construction impacts to the community, and prevent
major delays:
✓Align fiber and grid modernization projects - Engineering make-ready work and
construction for the grid modernization project will overlap with projects in the Fiber
Expansion Plan. Staff analyzed the projects to identify opportunities for alignment. Staff
is deploying a pilot to help inform on how alignment efforts impact costs, reductions to
community disruptions, and project timelines.
✓California Environmental Quality Act (CEQA) - The City must analyze and evaluate the
potential impacts of the project on various environmental factors and identify whether
those impacts can be mitigated.
1 https://www.cityofpaloalto.org/files/assets/public/agendas-minutes-reports/agendas-minutes/city-council-
agendas-minutes/2022/20221219/20221219pccsm-amendedtime.pdf
Item 2
Item 2 Staff Report
Packet Pg. 94
✓Joint Poles - The existing joint pole agreement with AT&T requires coordination between
the City and AT&T to relocate 3rd party telecom equipment on utility poles and provide
space for new fiber attachments, while remaining in compliance with California Public
Utilities Commission General Order 95 (GO 95) requirements for overhead electric line
construction to insure electric utility service and secure personnel safety.
✓Contract amendments – Staff is evaluating the utilization of existing construction and
engineering design contracts to expedite design and construction for both FTTP and grid
modernization for the pilot. Existing contractors have the technical expertise and
familiarity with the City’s construction standards, so construction may begin as soon as
the power engineering design is complete.
BACKGROUND
City Council considered three courses of action for a City-owned FTTP service and directed staff
to proceed with the phased build approach. Under this approach, FTTP will be built out in
selected areas of the city using $34 million from the Fiber Fund and $13 million from the Electric
Fund, and the project will expand gradually from there to eliminate the need for debt financing.
Building the fiber backbone and last-mile infrastructure to provide FTTP broadband internet to
the community will require significant planning, coordination, communication, and construction
over the next 18 – 24 months.
On May 1, 2023, City Council approved Amendment Number 4 to Contract Number C20176363
with Magellan for Fiber program management, organizational change management, network
operations and technical support, and utility pole electric make-ready engineering (Staff Report
#2303-12152). Although the phased build approach to FTTP will decrease the City’s financial risk
and increase Council’s control over the velocity of the buildout, the City does not have the in-
house staffing to fully pursue the Fiber Expansion Plan and efforts to coordinate with
Electrification Grid Modernization. These programs require significant staffing and specialized
skill sets over the next few years. While it is economically prudent to utilize available staffing
resources, the City must also strategically invest in external resources for a successful roll-out.
On June 19, 2023, the City Council approved the FY 2024 CIP Budget with the new FTTP project,
and Grid Modernization for Electrification Project. The approval of the electrification project
accelerated efforts to align electrification and fiber construction, which impacted the Fiber
Expansion Plan. Staff is deploying a pilot to determine how to align the grid modernization project
and projects under the Fiber Expansion Plan to help minimize utility engineering pole make-ready
work, pole replacements, noise disruption, and construction activity in neighborhoods.
2 https://cityofpaloalto.primegov.com/meeting/document/1960.pdf?name=Item%208%20Staff%20Report
Item 2
Item 2 Staff Report
Packet Pg. 95
ANALYSIS
Align fiber and grid modernization projects
The City conducted a high-level electrification study to evaluate the impacts of projected
electrification loads on Palo Alto’s distribution and substation transformers, primary/secondary
distribution circuits, and to propose upgrades needed to mitigate overloads. The estimated cost
to construct the necessary electric system upgrades for a 100% electrification scenario is
between $220 million to $306 million, depending on the approach. The workplan for this project
is a staged, multi-year approached designed to accomplish the upgrade of the electric
distribution system to meet the City’s goal of being ready for full-scale electrification by 2030.
Staff is in the process of implementing a pilot project to convert a 4kV area to 12 kV and upgrade
the transformers and secondary networks to facilitate electrification. This work is expected to be
completed by the middle of 2024, depending on other factors which impact project timelines,
such as material lead times, pole make ready, and alignment with the fiber projects. The initial
purpose of the pilot was to determine the feasibility of electrification design and construction
methods and implement best practices to facilitate the most cost-effective deployment of
resources. This purpose has since been expanded to also test aligning the Fiber Expansion Plan
with electrification efforts. Staff will be analyzing the cost savings, timeline, and resources
(staffing and contractors) required for project alignment.
Given the hundreds of miles of overhead and underground construction activity between FTTP
and electric grid modernization, the pilot enables staff to explore various construction phasing
options to minimize disruption, construction activity, and construction costs within
neighborhoods while avoiding prolonged deployments. In addition, aligning these projects in the
pilot helps alleviate construction constraints as staff does not have enough internal resources to
project manage, perform engineering make ready, and inspect construction for both projects in
parallel.
California Environmental Quality Act (CEQA) Compliance
The City will conduct an Initial Study on the environmental impacts associated with the
construction and operation of the potential citywide FTTP network, will cross much of the City of
Palo Alto and include some new infrastructure (i.e. fiber hut, fiber cabinets, aerial and
underground cables, utility vaults). The Initial Study is estimated to take about 30 weeks to
complete, including internal and mandated review time such as 30 days for public review and
comment.
The preliminary assessment, or Initial Study, will evaluate the project’s potential impacts on
various environmental factors and identify whether those impacts can be mitigated. If the
project’s impacts can be mitigated to a less-than-significant level, then the City may issue a
Mitigated Negative Declaration (MND) or Negative Declaration (ND). If the preliminary
assessment of the project determines one or more significant impacts on the environment
despite mitigation, a full environmental impact report (EIR) will be required, involving a more
comprehensive and detailed analysis of the project’s impacts and alternatives.
Item 2
Item 2 Staff Report
Packet Pg. 96
The City has retained a CEQA consultant to prepare a CEQA Initial Study in accordance with local,
state, and federal statutes. The Initial Study identifies physical, biological, social and economic
factors that might be affected by the fiber expansion project. Some environmental factors that
could potentially be affected by this project include aesthetics, air quality, geology/soils,
hazardous materials, noise, utilities services, and hydrology/water quality. Specific examples of
likely CEQA analysis include:
o Hydrological analysis to see if any proposed fiber lines would run through areas
near bodies of water and show that there would not be significant impacts to
waters of the state or waters of the US, as well as provide recommendations for
how to protect nearby waterbodies even if there are no direct impacts (e.g.
through proper stormwater protection measures)
o Air quality analysis (including understanding how to run claimed calcs for the
proposed project to evaluate air quality emissions and GHG emissions)
o Noise modeling (including analysis of potential impacts on nearby sensitive
receptors from construction noise and vibrations)
o Hazardous materials analysis (including evaluation and mitigation if necessary, of
potential impacts to construction workers and sensitive receptors especially if any
of the dark fiber runs through areas of the city runs through a plume)
Replacement of Jointly-Owned Poles
The City jointly owns 5,550 poles with AT&T. The current pole intent process (including billing)
for managing joint pole replacements operates under a joint pole agreement executed between
the City and AT&T in 1918. This process may not be feasible to accommodate the increased
volume of pole transactions expected with the grid modernization and Fiber Expansion Plan.
CPAU began discussing with AT&T effective ways to coordinate and collaborate on the
anticipated surge in pole replacement work and mitigating the impact to the community. One
potential improvement is to identify third party resources authorized to work on both AT&T and
CPAU facilities during pole replacement, make ready work, and/or inspection.
As part of the effort to streamline processes, CPAU also reevaluated the benefits of joining the
Northern California Joint Pole Association (NCJPA). Members have “joint pole equity” and
standardized cost-sharing methodologies for pole ownership, maintenance, use, setting,
replacement, dismantling, relinquishment or removal of jointly owned poles. CPAU has operated
without being an NCJPA member as the volume of pole replacements were manageable under
the existing process. The main objectives for considering membership with the NCJPA were to a)
streamline the pole intent and billing process; and b) improve the process of recovering AT&T’s
costs for joint poles replaced by CPAU. After further evaluation, staff concluded neither
objectives would be met by joining NCJPA as lead times are longer under NCJPA’s pole intent
process, and there are more administrative steps for limited cost recovery. For example, the
current joint agreement with AT&T requires a response within 10 days vs. 45 days according to
the NCJPA handbook, and the current agreement is based on actual replacement costs while
NCPJA joint pole costs are based on average unit costs for all members.
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Design and Construction Contracts for Pilot Area
Given the anticipated increase in pole work, CPAU will need to add resources to manage and
perform a high volume of pole make-ready work and replacements. In the meantime, staff is
evaluating how to leverage existing on-call construction and engineering contracts to perform
the engineering design, overhead and underground construction, and installation for the pilot
area (approximately 409 poles and 1,224 homes). This will reduce the construction timeline by 6
– 9 months, which would otherwise be prolonged in the process of issuing multiple invitation for
bids (IFBs) to perform the work for FTTP and grid modernization. The pilot area will be treated as
a testbed to design and construct both projects in parallel to minimize community disruption and
reduce shared construction costs. The pilot will inform CPAU how to most effectively bid out the
engineering, construction and installation services required for FTTP and grid modernization for
the remaining phase 1 area (additional 1,241 poles and 5,560 customers).
•VIP Powerline provides electric construction services including pole replacements,
facilities upgrade on the electric distribution system, and customer connections. VIP also
has some fiber construction experience such as installation of fiber cable and messenger
wires. (Staff Report 2303-1119)3
•MP Nexlevel provides electric and fiber substructure installation and trenching services.
MP Nexlevel is also qualified to provide fiber construction and installation services
including fiber installation, splicing, and testing. (Staff Report #13953)4
•Magellan provides multiple facets of implementing municipal fiber and broadband
networks including business planning, engineering, program management, integration,
and operations. In 2022, Magellan was acquired by Entrust Solutions, an experienced
provider of engineering, consulting, data analytics, and automation services to the
electric, gas, and telecom markets. (Staff Report #2303-1215)5
After staff identifies the specific build of materials (BOM) for electric and fiber in the pilot area,
staff will submit the BOM to the existing vendors to receive quotes. Staff will evaluate the bids
and return to Council with contract amendments for the additional scope of work and updated
not-to-exceed dollar amounts.
Other Updates
Fiber Make-Ready Engineering
Magellan completed the survey of approximately 6,000 utility poles in Palo Alto. The survey
identified the current load and condition of each pole in preparation for the new fiber backbone
and FTTP. The survey included detailed fielding and walk-out of all routes to validate running
3 https://cityofpaloalto.primegov.com/meeting/document/1862.pdf?name=Item%2010%20Staff%20Report
4
https://cityofpaloalto.primegov.com/Public/CompiledDocument?meetingTemplateId=3685&compileOutputType=
1
5 https://cityofpaloalto.primegov.com/meeting/document/1960.pdf?name=Item%208%20Staff%20Report
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lines, existing utilities, and constructability. For aerial construction, Magellan provided make-
ready engineering pole data to determine pole preparation and pole replacement, as well as
timeframes for the work to be completed. For phase one of FTTP and grid modernization, CPAU
will be passing 1,650 existing poles, attaching fiber to 1,300 poles, replacing 200 to 300 poles,
and coordinating with third parties to move their telecom equipment lower on 325 poles. In
addition to the fiber expansion project, CPAU has a recurring Wood Pole Replacement capital
improvement project to replace approximately 100 deteriorated wood poles annually. Wood
poles are used to support overhead utility lines throughout the City of Palo Alto. Though poles
are inspected, tested, and treated to maintain their integrity, over time poles will deteriorate to
the point that they are no longer in compliance with GO 95 requirements or safe for community
and utility workers.
Fiber Hut Sites:
Fiber huts are usually a prefabricated building (10’ x 20’) containing electronics and network
equipment that connects fiber to neighborhoods. The hut also has backup generators and HVAC
systems to maintain equipment within its operating environmental specifications. Two fiber huts
are recommended for the citywide network for Palo Alto Fiber. Staff and Magellan evaluated
potential fiber hut sites and considered their proximity to strategic areas, planning/land use
requirements, and existing infrastructure. As a result, staff narrowed down the potential
locations to the Colorado substation and anticipated space at City Hall. The Colorado substation
was previously identified as an ideal location due to its proximity to the area it serves and its
current use for utilities. City Hall is anticipated to have vacated space after the Police Department
moves to the new Public Safety Building. City Hall would be an ideal location for a secondary hut.
Due to the centralized location and potential square footage, this site may also be considered for
a future data center, further securing the future of the City‘s data infrastructure.
Equinix Fiber Data Center:
Equinix is currently the hub for the City’s dark fiber service. The Equinix datacenter is a vendor-
neutral site where numerous internet service providers and content delivery networks can
interconnect and exchange internet traffic between their networks. As the City expands its fiber
footprint, more data center space will be needed. For FTTP, the City will have to increase the
number of leasing cabinets (vertical racks sited next to each other, each capable of holding
multiple termination/switching boxes in stacked configurations) from five to 12 cabinets. The City
is undergoing discussions with Equinix to lease additional space available in their Palo Alto
location and to explore other Equinix locations. The City may also consider increasing the size of
the data center at City Hall.
Invitation for Bid (IFB) Construction Package:
When opportunities arise to align FTTP and grid modernization, CPAU and Magellan may gather
and consolidate all supporting documents to bid out construction of FTTP and grid
modernization. The consolidated IFB package will include construction-ready prints for fiber and
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power, construction details, splice details, pole make-ready details, construction standards as
well as all documentation needed to complete the bid package. This shall include a written
summary and scope of work, estimated costs to construct, as well as labor estimates, bill of
materials, and the vendor list.
Staffing:
As the City solidifies staffing plans in parallel with contracted services, the Director of Information
Technology will take on the responsibilities of an Assistant Director for Palo Alto Fiber on an
interim basis. In the FY 2024 adopted budget, four (4) new FTE positions for the dark fiber
expansion and implementation of FTTP were created. These positions will be recruited and filled
as needed during the various stages of the project.
•Assistant Director - To provide the vision and strategy for the new fiber business and lead
a high-performance team to quickly execute. Responsibilities include and are not limited
to: overseeing fiber enterprise fund budget timelines and milestones (including the dark
fiber optic business), managing the roll out and expansion of the fiber optic network,
Internet Service Provider (ISP) operations, customer service operations, and business
development.
•Manager Utilities Telecommunications / "Outside Plant Manager" - To lead the
construction process, installation and repair service technicians, and ensure the outside
plant processes run efficiently and smoothly. Responsibilities include and are not limited
to: overseeing construction, managing engineers and contractors, achieving construction
budget timelines and milestones.
•Manager Information Technology / "Sr. Network Engineer/Architect" – To lead the
development process of the overall architecture of the broadband system and manage
the system. Responsibilities include and are not limited to: managing the network and
supporting technical needs across the organization.
•Manager Utilities Telecommunications / "Sales and Marketing Manager" - To develop
the marketing strategy and lead marketing initiatives. Responsibilities include and are
not limited to: meeting revenue objectives, cultivating strong partnerships, and
maintaining retention rates.
FISCAL/RESOURCE IMPACT
This report is for informational purposes so there is no resource impact. Based on Council and
UAC input, staff will return with specific actions associated with efforts to align the fiber
expansion and electric grid modernization projects.
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STAKEHOLDER ENGAGEMENT
On November 2, 2022, the UAC unanimously recommended to build fiber backbone and FTTP
under a phased approach with existing funds ($34 million from Fiber and $13 million from
Electric). The UAC expressed the goal of FTTP is to provide ubiquitous or citywide high-speed
internet access to all residents and businesses in Palo Alto. If financially self-sustaining, and
deemed successful, the first phase of FTTP can become a springboard to a citywide FTTP
deployment within five years.
On December 19, 2022, City Council directed staff to proceed with the Fiber Expansion Plan to
implement the Fiber Rebuild project and Phase 1 of the Fiber-to-the-Premises (FTTP) project
without debt financing. Included in the Council’s motion was direction to: a) maximize number
of homes and businesses passed; b) consider promotional rates to increase take rate; c) define
leading indicators and metrics to determine success; and d) recommend future Council action to
accelerate expansion if metrics are positive, including a potential bond to streamline construction
and compress construction time as much as feasible.
ENVIRONMENTAL REVIEW
The Finance Committee’s discussion of the Fiber Expansion Plan project and its potential
alignment with the grid electrification project is not a project requiring California Environmental
Quality Act review, because it is an administrative governmental activity which will not cause a
direct or indirect physical change in the environment. CEQA Guidelines Section 15378(b)(5).
ATTACHMENTS
Attachment A: Presentation
APPROVED BY:
Dean Batchelor, Director of Utilities
Staff: Dave Yuan, Strategic Business Manager
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Palo Alto Fiber Project and
Construction Alignment
with Electric Grid
Modernization
November 7, 2023
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AGENDA
•Project(s) Recap
•Fiber Expansion Plan
•Fiber Backbone Expansion “Rebuild” Project
•Fiber-to-the-Premises (FTTP) Project
•Electrification
•Grid Modernization for Electrification Project
•Informational Updates
•Alignment of Fiber Expansion Plan and Grid Modernization
•California Environmental Quality Act (CEQA) Initial Study
•Joint Pole Ownership Coordination with AT&T
•Contract Amendments
•Other Updates
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HOW DID WE GET HERE?
•What has Council Approved?
•Dec 19, 2022 Council Approved to
•Proceed with dark fiber backbone
expansion “rebuild”
•Build FTTP Phase 01 in multi-
phased approach without debt
financing
•Jun 19,2023 Council Approved
•New Grid Modernization for Electrification project in FY24 Budget
•New Fiber-to-the-Premises project in FY24 Budget
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RECAP OF PROJECTS
FIBER BACKBONE REBUILD FIBER-TO-THE-PREMISES GRID MODERNIZATION
Estimated cost $25.6M (FO-16000)Estimated cost for Phase 1 $20M;
Citywide $102M (FO-24000)
Estimated cost $220M to $306M
(EL-24000)
Funded by Electric and Fiber funds Funded by Fiber Fund Funded by the Electric Fund; debt
financing and/or grants
Supports the City’s fiber licensing
service and internal needs:
Improve fiber and electric
system reliability, security
and capacity
Enable more connectivity for
City departments
Internal communication
needs for SCADA, AMI, DA
and other critical
infrastructure
Supports the City’s high speed
broadband internet needs:
Provides City-owned
high-speed internet
service
Provides new capacity for
dark fiber licensing
Community investment in
its own broadband
network
Supports City’s S/CAP goals and
future demand
100% residential
electrification
Upgrade existing
substations,
replace transformers,
convert existing 4 kVa lines
to 12 kVa to increase
capacity and meet
future demand.
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INFORMATIONAL UPDATES
Topics to address prior to construction
Pilot aligning fiber and grid modernization project to inform on
•Pole make-ready and replacement
•Material lead time and warehousing
•Internal resources to implement and coordinate projects
Initial Study for CEQA in progress to evaluate potential impacts
•Identify physical, biological, social and economic factors
•Provide mitigation efforts
Joint Pole Ownership Coordination with AT&T in progress
•Approximately 5,550 poles shared with AT&T
•Upcoming replacements and coordination will overwhelm staff
•Eliminated Northern California Joint Pole Association membership option
Contract Amendments
•VIP Powerline –power and fiber construction
•MP Nexlevel–substructure and fiber construction
•Magellan/Entrust–power and fiber engineering design
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Pilot Map Overlay with Phase 1 & Areas of Interest
Pilot Area Map to align Grid Modernization with FTTP
(1,224 customers and 409 poles)
Proposed Phase 1 FTTP Map (Additional 5,560
customers and 1,241 poles)
Areas of Interest Map based on Lower Construction
Cost, Higher Density, Less Competition, Higher
Customer Interest
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Pilot Project Plan (draft outline subject to change)
Pre-construction
•Aerial Power Make Ready Engineering - Feb 2024
•Materials Ordering/Warehousing - Feb 2024
•CEQA Approval - Apr 2024
•Fiber Hut at Colorado Power Station - Oct 2024
Construction
•Power: Mar 2024 - Oct 2024
•Fiber: Jun 2024 - Feb 2025
Operations & Customer Outreach
•Operations Support Systems “OSS”
•Business Support Systems “BSS”
•Marketing/Event(s)
•Community Meeting(s)
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-8
Q&A
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