HomeMy WebLinkAbout2025-11-20 Climate Action and Sustainability Committee Agenda PacketCLIMATE ACTION AND SUSTAINABILITY COMMITTEE
Special Meeting
Thursday, November 20, 2025
Community Meeting Room & Hybrid
2:00 PM
Amended Agenda
Amended agenda items appear below in RED
Climate Action and Sustainability Committee meetings will be held as “hybrid” meetings with the
option to attend by teleconference/video conference or in person. Information on how the
public may observe and participate in the meeting is located at the end of the agenda. The
meeting will be broadcast live on YouTube https://www.youtube.com/c/cityofpaloalto.
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Meeting ID: 853 8091 8387 Phone: 1(669)900-6833
PUBLIC COMMENTS
General Public Comment for items not on the agenda will be accepted in person for up to three
minutes or an amount of time determind by the Chair. General public comment will be heard
for 30 minutes. Additional public comments, if any, will be heard at the end of the agenda.
Public comments for agendized items will be accepted both in person and via Zoom for up to
three minutes or an amount of time determined by the Chair. Requests to speak will be taken
until 5 minutes after the staff’s presentation or as determind by the Chair. Written public
comments can be submitted in advance to city.council@PaloAlto.gov and will be provided to
the Council and available for inspection on the City’s website. Please clearly indicate which
agenda item you are referencing in your subject line.
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1 November 20, 2025
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CALL TO ORDER
PUBLIC COMMENT
Members of the public may speak in-person ONLY to any item NOT on the agenda. 1-3 minutes depending on number of
speakers. Public Comment is limited to 30 minutes. Additional public comments, if any, will be heard at the end of the agenda.
STANDING VERBAL REPORTS
A.Staff Comments
B.Committee Member Comments and Announcements
ACTION ITEMS
1.Status Update on Sustainability and Climate Action Plan Mobility Goals and Key
Actions and Request for Feedback on Tentative 2026-2027 Work Plan Items. CEQA
Status - Not a project. Late Packet Report Added
2.Recommendation that the City Council Accept the “Evaluation of Local Energy
Resources to Lower Costs and Improve Reliability and Resiliency” Report to
Complete Reliability and Resiliency Strategic Plan Strategies Four and Five, and
that the City Council Direct Staff to Pursue Various Activities Related to Flexible
Energy Resource and Efficient Electrification to Improve Reliability and Resiliency;
CEQA Status - Not a Project New Item Added
FUTURE MEETINGS AND AGENDAS
Members of the public may not speak to the item(s)
ADJOURNMENT
2 November 20, 2025
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PUBLIC COMMENT INSTRUCTIONS
Members of the Public may provide public comments to teleconference meetings via email,
teleconference, or by phone.
1.Written public comments may be submitted by email to city.council@PaloAlto.gov.
2.For in person public comments please complete a speaker request card located on the
table at the entrance to the Council Chambers and deliver it to the Clerk prior to
discussion of the item.
3.Spoken public comments for agendized items using a computer or smart phone will be
accepted through the teleconference meeting. To address the Council, click on the link
below to access a Zoom-based meeting. Please read the following instructions carefully.
◦You may download the Zoom client or connect to the meeting in- browser. If using
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activate and unmute speakers in turn. Speakers will be notified shortly before they
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shown on the computer to help keep track of your comments.
4.Spoken public comments for agendized items using a phone use the telephone number
listed below. When you wish to speak on an agenda item hit *9 on your phone so we
know that you wish to speak. You will be asked to provide your first and last name before
addressing the Council. You will be advised how long you have to speak. When called
please limit your remarks to the agenda item and time limit allotted.
CLICK HERE TO JOIN Meeting ID: 853 8091 8387 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
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3 November 20, 2025
Materials submitted after distribution of the agenda packet are available for public inspection at www.paloalto.gov/agendas.
California Government Code §84308, commonly referred to as the "Levine Act," prohibits an
elected official of a local government agency from participating in a proceeding involving a
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exceeding $500 from a party or participant, including their agents, to the proceeding within the
last 12 months. A “license, permit, or other entitlement for use” includes most land use and
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procedures and have a value over $50,000. A “party” is a person who files an application for, or
is the subject of, a proceeding involving a license, permit, or other entitlement for use. A
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decision. The Levine Act incorporates the definition of “financial interest” in the Political Reform
Act, which encompasses interests in business entities, real property, sources of income, sources
of gifts, and personal finances that may be affected by the Council’s actions. If you qualify as a
“party” or “participant” to a proceeding, and you have made a campaign contribution to a
Council Member exceeding $500 made within the last 12 months, you must disclose the
campaign contribution before making your comments.
4 November 20, 2025
Materials submitted after distribution of the agenda packet are available for public inspection at www.paloalto.gov/agendas.
Climate Action and Sustainability Committee
Staff Report
Report Type: ACTION ITEMS
Lead Department: Transportation
Meeting Date: November 20, 2025
Report #:2511-5416
TITLE
Status Update on Sustainability and Climate Action Plan Mobility Goals and Key Actions and
Request for Feedback on Tentative 2026-2027 Work Plan Items. CEQA Status - Not a project.
This report will be a late packet report published on November 13, 2025
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Climate Action and Sustainability Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Public Works
Meeting Date: November 20, 2025
Report #:2507-5028
TITLE
Recommendation that the City Council Accept the “Evaluation of Local Energy Resources to
Lower Costs and Improve Reliability and Resiliency” Report to Complete Reliability and
Resiliency Strategic Plan Strategies Four and Five, and that the City Council Direct Staff to
Pursue Various Activities Related to Flexible Energy Resource and Efficient Electrification to
Improve Reliability and Resiliency; CEQA Status - Not a Project
RECOMMENDATION
Staff requests that the Climate Action and Sustainability Committee recommend that the City
Council:
1. Accept the “Evaluation of Local Energy Resources to Lower Costs and Improve Reliability
and Resiliency” report to complete Reliability and Resiliency Strategic Plan Strategies
Four and Five, and;
2. Direct staff to:
a. Promote City of Palo Alto Utilities (CPAU) customer’s use of energy in off-peak
periods to reduce both greenhouse gas emissions and strain on the electric grid,
and lower energy costs;
b. Promote demand response, solar photovoltaics (PV), battery energy storage
system (BESS), thermal storage, and vehicle to load, home, and grid technologies
and reduce barriers to their adoption, including, but not limited to:
i. Regular outreach as opportunities present themselves;
ii. Posting available educational materials on the City’s website;
iii. Facilitating regulatory and process changes as staff becomes aware of
issues and as staff time is available; and
iv. Integrating flexible energy technologies and efficient electrification into
energy programs as staff time is available;
c. Within two years, update cost-benefit analysis for demand response, solar PV,
batteries, thermal storage, and vehicle to load, home, and grid technologies;
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d. As opportunities present themselves, and to the extent staff time is available,
evaluate large scale solar and battery opportunities in Palo Alto, either at
publicly owned facilities or through partnerships with private land owners; and
e. Engage the Utilities Advisory Commission, Climate Action and Sustainability
Committee, and Council in an additional discussion on microgrids and long-term
resiliency in 2026.
In addition to the above recommendations, staff is offering the following alternative
recommendation if the Climate Action and Sustainability Committee wishes to recommend that
the City Council direct staff to pursue a higher level of effort for outreach and barrier reduction:
Optional alternative to recommendation 2b above: 2. b. Promote demand response, solar PV,
batteries, thermal storage, and vehicle to load, home, and grid technologies and reduce
barriers to their adoption, including, but not limited to:
i. Recurring and widespread outreach;
ii. Developing educational materials, online decision tools, and other
resources to help community members evaluate these technologies for
themselves;
iii. Actively auditing regulations and processes for streamlining
opportunities; and
iv. Actively and continuously integrating flexible energy technologies and
efficient electrification into energy programs
The optional alternative above would require additional resources as detailed in the Fiscal
Impact section below.
EXECUTIVE SUMMARY
The technologies and strategies discussed in the attached report (Attachment A) benefit the
electric grid and the community when voluntarily installed and properly operated. Strategy 3 of
the Reliability and Resiliency Strategic Plan (RRSP), which is already being implemented, focuses
on promoting these technologies and strategies, helping people learn to operate them well,
and reducing barriers to adoption. These activities can be performed with existing staff.
Strategies 4 and 5 ask whether the City should be going further and providing incentives or
more intensive programs to actively drive greater participation, which would require additional
funding and resources. While the attached report is not a cost of service analysis that will be
used to determine utility rates, it does evaluate potential utility-provided incentives, and finds
no cost/benefit ratio that supports providing City or ratepayer-funded incentives or more
intensive programs. Staff recommends continuing to do outreach and reducing barriers to
adoption, as described in this report, while also monitoring and analyzing the cost-effectiveness
of these technologies periodically, evaluating larger commercial projects as opportunities arise,
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and pursuing further discussion of the policy options for long-term resiliency and microgrids
described in the attached report. This staff report and the attached consultant report complete
Strategies 4 and 5 of the RRSP.
BACKGROUND
1 resulted from discussions with the UAC and the Council’s Sustainability and Climate
Action (S/CAP) Committee and its Working Group leading up to and following the June 5, 2023,
adoption of the S/CAP and the 2023-2025 S/CAP Work Plan2. Included in the S/CAP Work Plan
were work items 1.B and 1.C to create and implement the Electric RRSP. At its December 6,
2023, meeting the UAC discussed the elements and scope of the RRSP and recommended
Council approval3. The City Council approved the Reliability and Resiliency Strategic Plan (RRSP)
on April 15, 20244. In September 2024, the UAC reviewed the scope for a consultant study to
implement Strategies 4 and 5 of the RRSP.5 In February 2025, the UAC provided feedback on
some preliminary insights and results from the study.6 In July 20257 and August 20258 staff
1 Reliability and Resiliency Strategic Plan, Approved by the City Council April 14, 2024: https://cityofpaloalto.prime
gov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=f90b4733-eb24-
4699b4f1229af03f8fd5
2 Adopted 2023-2025 S/CAP Work Plan: https://www.cityofpaloalto.org/files/assets/public/v/1/sustainability/repo
rts/2023-2025-scap-work-plan_final.pdf
3 UAC, Staff report 2311-2263, December 6, 2023, S/CAP Strategic Plan on the Reliability and Resiliency for the Elec
tric Distribution Utility. https://www.cityofpaloalto.org/files/assets/public/v/3/agendas-minutesreports/agendas-
minutes/utilities-advisory-commission/archived-agenda-and-minutes/agendas-and-minutes-/12-dec-2023/12-06-
2023-packet-v2.pdf
4 City Council, Staff Report 2401-2496, April 15, 2024, Approve the Reliability and Resiliency Strategic Plan as Reco
mmended by the Utilities Advisory Commission, https://cityofpaloalto.primegov.com/meetings/ItemWithTemplate
Type?id=4485&meetingTemplateType=2&compiledMeetingDocumentId=9592
5 UAC, Staff Report 2405-2984, September 4, 2024, Discussion of Implementation of Reliability and Resiliency Strate
gic Plan – Review of Consulting Scope of Work to Scope Projects to Enhance Resiliency, Staff report: https://cityofp
aloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=71a87cda639b441d9
06991ee5b89e717 Attachments: https://cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=5416
&meetingTemplateType=2&compiledMeetingDocumentId=11628
6 UAC, Staff Report 2501-4058, February 5, 2025, Reliability and Resiliency Strategic Plan: Update on Studies, https:
//cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=7116&meetingTemplateType=2&compiledM
eetingDocumentId=13041
7 UAC, Staff Report 2505-4687, July 9, 2025, Status Update on Studies Related to the Electric Utility’s Reliability and
Resiliency Strategic Plan (RRSP) Strategies 4 and 5 and Request for Feedback on Draft Proposals for Implementation
, https://cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=8400&meetingTemplateType=2&comp
iledMeetingDocumentId=15055
8 CASC, Staff Report 2507-4944, August 22, 2025, Status Update on Studies Related to the Electric Utility’s Reliabilit
y and Resiliency Strategic Plan (RRSP) Strategies 4 and 5 and Request for Feedback on Draft Proposals for Implemen
tation, https://cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=9006&meetingTemplateType=2
&compiledMeetingDocumentId=15478
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provided the UAC and CASC, respectively, with near-final results and requested additional
feedback to enable completion of the final report.
Attachment On Strategy 1, Action 6, Reliability Metrics, a report on Council’s June 16, 2025
consent calendar recommended acceptance of reliability metrics and goals. The report was
pulled from consent and is now planned to be included with a comprehensive Council
discussion of the RRSP tentatively scheduled for December 2025.17
ANALYSIS
The attached consultant report titled “Evaluation of Local Energy Resources to Lower Costs and
Improve Reliability and Resiliency” contains the results of several analyses to evaluate the
electric utility supply cost savings, short-term reliability benefits, and potential for deferral of
distribution investment. The analyses found that benefits exceeded costs at a community level
(the combination of costs and benefits for both the utility and its customers, analogous to the
“Total Resource Cost Test” commonly used in analysis of energy efficiency and other demand-
side management programs)18 only for commercial solar plus batteries, and that benefits would
no longer exceed costs for that category of projects once the Federal Investment Tax Credit
(ITC) expires. They found that using batteries to defer distribution investment was not cost-
effective at a community level. They found that commercial solar and batteries could become
cost-effective (at a community level) by 2030, but that residential-scale projects were not
projected to become cost-effective (at a community level) until 2040. However, both
residential-scale and commercial-scale solar and battery projects could be viable for the
building owner if the building owner valued long-term resiliency higher than the cost of
mitigating an outage (as described in the report, Attachment A, Section 7.3, page 43). The
report lays out a framework for considering how to approach the value of long-term resiliency
and potential policies the community could adopt.
Based on the report, staff developed several follow-up recommendations for implementation,
organized under five categories:
1)time of use promotion
2)technology promotion and barrier reduction
3)cost-benefit monitoring and projection
17 City Council, Staff Report 2506-4769, June 16, 2025, Item 11, Accept Electric System Reliability Key Performance I
ndices, https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=6448
d8eb3b3-4fc2-8b0f-0e53df677bdf
18 A good definition of the Total Resource Cost Test is included on page 18 of the California Public Utilities
Commission “California Standard Practice Manual for Economic Analysis of Demand-Side Programs and Projects,”
October 2001, which is still used for investor-owned utilities. Publicly-owned utilities use similar analytical
methods for their energy efficiency and demand-side cost-effectiveness analyses. https://www.cpuc.ca.gov/-
/media/cpuc-website/files/uploadedfiles/cpuc_public_website/content/utilities_and_industries/energy_-
_electricity_and_natural_gas/cpuc-standard-practice-manual.pdf
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4) case by case commercial scale project evaluations
5) policy review of microgrids and long-term resiliency
These are summarized below:
1. Time of Use Promotion
As the City’s Advanced Metering Infrastructure (AMI) project is completed, the City’s Utilities
Department will provide customers a time of use billing option for customers that can shift
energy use to off-peak periods that reduces emissions and passes through lower energy import
costs to the customer. Outreach will include mailers, utility bill inserts, and information on the
City’s website.
2. Technology Promotion and Barrier Reduction
Staff currently encourages adoption of demand response, solar PV, BESS, thermal storage, and
vehicle to load, home, and grid technologies as staff becomes aware of them, such as recent
changes to Fire Department regulations recognizing the lower fire risk of lithium-ferrous-
phosphate battery technologies or the City’s adoption of SolarApp+ for solar permitting.
Information on these technologies is also available on the City’s website. Staff currently has a
Guide to Electrification posted on its website detailing approaches to efficient electrification.
Staff integrates these technologies into its programs, such as including a rebate in its Advanced
Single Family Electrification Pilot Program that can be applied to circuit sharing technologies, or
the inclusion of managed charging technologies in the design guidelines for its next generation
multi-family electric vehicle charging program. This level of effort would continue, seeking
opportunities to increase efficiencies to scale programs, promote and incorporate these
technologies as staff time and opportunities present themselves. Staff would also investigate
low-cost technical assistance for these technologies when developing programs.
If a higher level of effort were desired, staff could bring on hourly assistance for a few years to
make a focused effort to actively review and identify streamlining opportunities in City
regulations and processes to make it easier to install these technologies (including outreach to
contractors), to track the state of the technologies, and to develop material for an outreach
campaign focused specifically on these technologies. Any staff augmentation and funding
requirements would be incorporated into the City’s budget approval process.
3. Monitoring Cost-Benefit of Various Technologies
With the creation of the cost-benefit model used to generate this report, staff now has a
manageable way to regularly update the analysis results. Staff would update the model
periodically as opportunities presented themselves, such as when a summer intern were
available or when workload permitted full-time staff to update the model, but not less than
every two years. This may require consulting expenditures, but these could be absorbed within
the existing budget.
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4. Commercial Facility Partnerships – Case by Case Evaluation
FISCAL/RESOURCE IMPACT
•A $213,250 contract with Buro Happold for evaluation of supply and short-term
resiliency, research and recommendations on potential programs, and development of
the final Reliability and Resiliency Cost-Benefit Study and Program Inventory. All funding
was utilized, and an additional $10,500 was required for additional analysis based on
UAC and CASC feedback.
•A $32,185 contract with Energeia to complete the preliminary analysis of deferring
distribution investment, which was completed for $28,676.
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•A contract with Burns-McDonnell for evaluation of solar and storage at the airport for
$208,000, of which $178,000 is for evaluation of microgrid options and use of the
energy and $30,000 is estimated for site evaluations to enhance planned Federal
Aviation Administration filings for the airport to enable this project in the future. To
date, $193,000 has been expended.
Pursuing additional analysis of the potential for deferring distribution investment would require
an additional $150,000 to $200,000 in consultant costs and 0.5 FTE in staff time, though there is
uncertainty about the amount of staff time needed. If Council directed staff to pursue this
approach, staff would return with firmer numbers and a proposed funding source. The City has
received a $75,000 grant from the American Public Power Association (APPA) for this work.
Staff is in discussions with APPA to explore reducing the grant and applying it to the preliminary
study instead.
The recommended actions above require resources as follows:
Promoting the voluntary use of energy in off-peak periods to reduce both greenhouse
gas emissions and strain on the electric grid, and lower energy costs will be performed
as part of the rollout of time of use rates through utility bill inserts and information on
the web site and will require less than 0.1 FTE of staff time, absorbed from existing staff.
Promoting demand response, solar PV, BESS, thermal storage, and vehicle to load,
home, and grid technologies and reducing barriers to their adoption will be done as staff
time is available and as issues arise. Staff is expecting this will require less than 0.1 FTE
of work from existing staff capacity as time is available. If a higher level of effort is
desired (see optional alternative recommendation 2b) an 0.5 FTE hourly budget and 0.1
to 0.2 FTE in hourly or permanent communications staff time would be needed.
As staff time is available, staff will update cost-benefit analysis for demand response,
solar PV, BESS, thermal storage, and vehicle to load, home, and grid technologies. This
could be done using summer interns for around $15,000 in staff costs, or as staff time is
available (about 0.1 to 0.2 FTE of work) or through about $14,000 in consulting budget
from existing Utilities consulting budgets.
As opportunities present themselves, and to the extent staff time is available, staff can
evaluate large scale solar and BESS opportunities in Palo Alto, either at publicly owned
facilities/properties or through partnerships with private landowners. Staff would
restrict these efforts to 0.1 to 0.2 FTE of work per year.
Engaging the UAC, CASC, and City Council in an additional discussion on microgrids and
long-term resiliency in calendar year 2026. This is expected to take 0.1 to 0.2 FTE of staff
time, one time, though additional work may be needed depending on Council direction.
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STAKEHOLDER ENGAGEMENT
21 The feedback from the July 9, 2025 UAC
meeting on the preliminary results of the attached study was also summarized in the
Stakeholder Engagement section of the August 22, 2025 CASC staff report.21 On August 22,
2025 staff presented the preliminary results of the attached study to the CASC.
21 CASC, Staff Report 2507-4944, August 22, 2025, Status Update on Studies Related to the Electric Utility’s Reliabili
ty and Resiliency Strategic Plan (RRSP) Strategies 4 and 5 and Request for Feedback on Draft Proposals for Impleme
ntation, https://cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=9006&meetingTemplateType=
2&compiledMeetingDocumentId=15478
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6. Monitor opportunities for distribution investment deferral using flexible technologies
and efficient electrification but do not pursue additional analysis or new policies or
programs at this time.
7. Maintain the City’s current policies on microgrids and backup power at this time, but
bring forward additional discussion on long-term resiliency, highlighting community-
level planning and equity considerations.
8. Explore backup power needs at the Regional Water Quality Control Plant (RWQCP) and
airport to determine the most economically feasible backup power alternatives to
determine whether an electric utility / treatment plant partnership for a solar and
storage microgrid at the airport can be made economically feasible.
At the CASC’s August 22, 2025 meeting, there was a question about the electric capacity needs
for electric aviation and whether microgrids could support that need. Staff noted that a
microgrid was one of several potential approaches to providing electricity for electric aviation.
Staff plans to consider this item in the context of the 2026-2027 S/CAP Work Plan rather than
the RRSP.
ENVIRONMENTAL REVIEW
The Council’s acceptance of the Evaluation of Local Energy Resources to Lower Costs and
Improve Reliability and Resiliency” Report to Complete Reliability and Resiliency Strategic Plan
Strategies Four and Five does not require California Environmental Quality Act review, because
the plan does not meet the definition of a project under CEQA Guidelines Section 15378(b)(5),
as an administrative governmental activity which will not cause a direct or indirect physical
change in the environment.
ATTACHMENTS
Attachment A: Consultant Report, “Evaluation of Local Energy Resources to Lower Costs and
Improve Reliability and Resiliency”
Attachment B: Status Update on RRSP Implementation
APPROVED BY:
Brad Eggleston, Director Public Works/City Engineer
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Evaluation of Local Energy Resources to
Lower Costs and Improve Reliability and
Resiliency
Valuing Flexible Energy Technologies and Efficient Electrification
Strategies for Electric Supply Cost Reduction, Distribution Investment
Deferral, and Reliability and Resiliency: Cost/Benefit Analysis and
Potential Local Programs
City of Palo Alto Utilities Department
DRAFT November 11, 2025
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Attachment A - Consultant
Report, Evaluation of Local
Energy Resources to Lower
Costs and Improve
Reliability and Resiliency
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Local Energy Resources to Lower Costs and Improve Reliability and Resiliency 2
Executive Summary
This study assesses customer programs for flexible energy technologies that enhance customer reliability and
resilience in the City of Palo Alto. Customer programs were identified through an extended inventory of
programs, pilots, and customer-scale projects throughout the United States, with an emphasis on the California
context, that support resilience and electrification with technologies such as battery energy storage systems,
solar, vehicle to grid & vehicle to home, thermal energy storage, and demand response technologies. The
analysis considered the technological viability of each technology, avoided supply costs, value of short-term
resilience, as well as program feasibility, accessibility, and community impacts.
The baseline results indicate that most programs currently yield a negative net value for the Palo Alto community
unless additional benefits such as avoided distribution system investment or long-term resiliency are valued, or
program characteristics are adjusted to improve performance. By analyzing at a community level first (the
combination of costs and benefits for both the utility and its customers together, analogous to the “Total
Resource Cost Test” commonly used in analysis of energy efficiency and other demand-side management
programs)1 the City can see whether these programs would increase or decrease costs at a community level
before doing more in-depth analysis on the costs and benefits for the utility alone, program participants, or non-
participating ratepayers.
On a supply cost and short-term resiliency basis, at a community-level, none of the technologies demonstrated a
positive cost-benefit except for commercial solar plus battery, which narrowly broke even at a 1:1 benefit to cost
ratio. Commercial standalone battery, commercial demand response, and residential solar plus battery came
closest to achieving a positive net benefit. These results are based on current technology costs, the continuation
of Palo Alto’s existing electric outage reliability, and the expiration of the 30% federal tax credits for solar and
residential battery projects that expires after December 31, 2025.
In the near term, the cost benefit for solar plus storage will remain negative unless adequate benefits can be
derived from the deferral of distribution investments or long-term resiliency. In a separate study conducted by
City staff and another City consultant, the preliminary results do not find a net benefit to deferral of distribution
investments using batteries, and that opportunities were limited due to a variety of factors. Quantifying the
benefits of long-term resiliency is beyond the scope of this report, but a qualitative discussion is included and
the City is pursuing separate discussions on this topic.
In the long-term, reductions in technology costs are likely to improve the cost-benefit results, particularly for
commercial solar plus battery, commercial solar, and residential solar plus battery programs. With sufficient cost
reductions, such programs could present a potentially worthwhile investment to enhance reliability and
resilience.
Time of Use rates were not analyzed for cost-effectiveness, only analyzed for the potential savings they might
yield, but are assumed to be cost-effective due to their potential wide scale adoption and low cost of
implementation once advanced metering infrastructure (smart meters) are installed.
1 A good definition of the Total Resource Cost Test is included on page 18 of the California Public Utilities Commission “California Standard
Practice Manual for Economic Analysis of Demand-Side Programs and Projects,” October 2001, which is still used for investor-owned utilities.
Publicly-owned utilities use similar analytical methods for their energy efficiency and demand-side cost-effectiveness analyses.
https://www.cpuc.ca.gov/-/media/cpuc-website/files/uploadedfiles/cpuc_public_website/content/utilities_and_industries/energy_-
_electricity_and_natural_gas/cpuc-standard-practice-manual.pdf
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The results of this assessment show that technical assistance programs or incentives for flexible energy
technologies would not generate savings for the community – costs exceed the benefits. As an alternative, the
City could consider low-cost strategies for promoting flexible energy technologies and further explore alternative
cost-effective measures for local commercial and utility-scale solar plus battery programs. The following
programs may result in a positive benefit to cost ratio in the future, though, and the cost-benefit analysis should
be updated periodically:
• Commercial solar plus storage, evaluated on a project-by-project basis;
• Commercial battery projects or solar plus battery projects where commercial partners value long-term
resiliency highly enough to make the project cost-effective;
• Residential solar plus storage projects or standalone batteries where residents value long-term resiliency
highly enough to make the project cost-effective; and
• Commercial demand response, paired with time of use rates, which could deliver net benefits with
sufficient scale and program design.
The report that follows provides detailed coverage of the analysis. It begins with the Objectives and Background,
establishing the purpose, scope, and context of the analysis. The Result section summarizes key findings and
recommendations across all valuation criteria, with a sensitivity analysis that supports considerations for future
customer program adoption. The sections that follow delve further into specific areas of analysis, including a
Customer Programs Survey, Supply Cost Valuation, Distribution Cost Valuation, Customer Short-Term Resiliency
Valuation, and a discussion on Long-Term Resiliency and Microgrids. Appendix A, B, and C provide supporting
data, methodologies, and supplement materials referenced throughout the analysis.
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Table of Contents
Executive Summary .................................................................................................................................................................................... 2
Table of Contents ........................................................................................................................................................................................ 4
List Of Figures .............................................................................................................................................................................................. 6
List Of Tables................................................................................................................................................................................................. 7
1 Introduction and Background ...................................................................................................................................................... 8
1.1 Purpose and Scope of the Study - Utility Supply Costs, Customer Resiliency, & Customer Programs . 8
1.2 Associated Studies – Distribution Capacity & Investment, Long Duration Airport Microgrid .................. 8
1.3 Defining Reliability & Resilience ........................................................................................................................................ 8
1.4 Flexible Energy Technologies .............................................................................................................................................. 9
1.5 Palo Alto Context ..................................................................................................................................................................... 9
2 Results .................................................................................................................................................................................................. 12
2.1 Methodology for Valuing Flexible Energy Technologies and Efficient Electrification Strategies............ 12
2.2 Summary of Results - Customer Program Prioritization Framework ................................................................ 14
2.2.1 Qualitative Results ........................................................................................................................................................ 14
2.2.2 Quantitative Results and Sensitivity Analysis – Utility Supply and Short-term Resiliency Benefits15
2.2.3 Quantitative Results – Distribution Investment Deferral ............................................................................... 18
2.2.4 Qualitative Results – Long-term Resiliency and Microgrids ........................................................................ 18
2.2.5 Takeaways & Conclusions .......................................................................................................................................... 19
3 Customer Programs Survey ......................................................................................................................................................... 21
4 Supply Cost Valuation ................................................................................................................................................................... 27
4.1 CPAU Avoided Cost ............................................................................................................................................................... 27
4.2 Customer Savings ....................................................................................................... Error! Bookmark not defined.
4.3 CPAU Distribution & Commodity Impacts and Net Benefits ..................... Error! Bookmark not defined.
4.4 Statewide Avoided Cost ...................................................................................................................................................... 29
4.5 Time of Use Rates .................................................................................................................................................................. 31
5 Distribution Cost Valuation ......................................................................................................................................................... 33
5.1 Results......................................................................................................................................................................................... 33
5.2 Additional Considerations .................................................................................................................................................. 33
5.3 Methodology ........................................................................................................................................................................... 33
5.4 Efficient Electrification Strategies..................................................................................................................................... 35
6 Short-Term Resiliency Valuation ................................................................................................................................................ 35
6.1 Valuing Reliability and Resilience ..................................................................................................................................... 35
6.1.1 Literature Review ........................................................................................................................................................... 35
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6.1.2 Distribution of City Outages – reasons, # customers, duration of outages (outage response) -
Reliability ............................................................................................................................................................................................ 37
6.2 Approach to Valuing Resiliency in Palo Alto ............................................................................................................... 39
6.2.1 Model Selection & Parameters ................................................................................................................................ 39
6.2.2 Interruption Costs for SFR, MFR, Small Commercial, and Large Commercial Customers ............... 41
6.2.3 Quantitative & Qualitative Components of Resilience (Direct, Indirect, Societal Metrics) .............. 41
6.2.4 Adjustments, Limitations, and Uncertainty in the ICE Calculator .............................................................. 42
7 Long-Term Resiliency and Microgrids ..................................................................................................................................... 43
7.1 Microgrids Overview ............................................................................................................................................................. 43
7.2 Valuing Long-term Resiliency ............................................................................................................................................ 43
7.3 Value of Long-term Resiliency Needed for Benefits to Exceed Costs ............................................................... 44
7.4 Community-scale Long-term Resiliency Planning .................................................................................................... 44
7.5 Community-scale Microgrids ............................................................................................................................................ 45
7.6 Incentives for Individual or Community-Scale Microgrids .................................................................................... 46
Appendix A – Flexible Energy Technologies .................................................................................................................................. 47
Batteries ................................................................................................................................................................................................... 47
Vehicle-to-Home .................................................................................................................................................................................. 50
Generators .............................................................................................................................................................................................. 53
Heat Pump Water Heaters ................................................................................................................................................................ 54
Enabling Technologies ....................................................................................................................................................................... 56
Appendix B – Customer Program Precedents ............................................................................................................................... 59
Appendix C – Supply Cost Valuation Assumptions ..................................................................................................................... 65
Battery Energy Storage System (BESS) ........................................................................................................................................ 65
Demand Response (DR)..................................................................................................................................................................... 71
Thermal Energy Storage System (TESS) ...................................................................................................................................... 73
Vehicle to Everything (V2X) .............................................................................................................................................................. 74
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List Of Figures
Figure 1. Cost-Benefit Results for Commercial Programs ........................................................................................................ 16
Figure 2. Cost-Benefit Results for Residential Programs........................................................................................................... 16
Figure 3. Benefit Cost-Ratio Forecast ............................................................................................................................................... 18
Figure 4. Cost per MWh Delivered Example: Winter Month (January 2026) and Summer Month (August 2026).28
Figure 5. Example Supply Cost Arbitrage for Residential Standalone BESS (per 100 installations) ......................... 29
Figure 6. Example Customer TOU Arbitrage for Residential Standalone BESS (per 100 installations) ........... Error!
Bookmark not defined.
Figure 7. Example Customer Commodity and Distribution Revenue Impacts for Residential Standalone BESS (per
100 installations) ............................................................................................................................ Error! Bookmark not defined.
Figure 8. Avoided Cost Calculator Input Parameters .................................................................................................................. 30
Figure 9. Example of Avoided Cost Disparity for Residential Standalone BESS (per 100 installations) .................. 31
Figure 11. Reliability vs. Resilience ..................................................................................................................................................... 36
Figure 12. Natural hazards and power interruption cost components ............................................................................... 37
Figure 13. Sustained Outages by Cause - Sept 2023 - June 2025 ........................................................................................ 39
Figure 14. Changes in Projected Component Costs for Residential BESS (also used for commercial systems) . 50
Figure 15. ConecctDER meter socket adapter .............................................................................................................................. 56
Figure 16. Span and Savant Product Examples ............................................................................................................................ 57
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List Of Tables
Table 1. Customer Program Summary .............................................................................................................................................. 12
Table 2. Quantitative & Qualitative Assessment Parameters Overview .............................................................................. 13
Table 3. Qualitative Results Summary ............................................................................................................................................... 14
Table 4. Community Cost-Benefit Summary .................................................................................................................................. 15
Table 5. Sensitivity Analysis - Customer Adoption & Program Costs .................................................................................. 17
Table 6. Sensitivity Analysis - Technology Costs ........................................................................................................................... 18
Table 7. Resilience Technology categories included in program directory ........................................................................ 21
Table 8. Program Inventory Summary .............................................................................................................................................. 23
Table 9. Program Research Framework ................................................................................. Error! Bookmark not defined.
Table 10. Customer Program Designs .............................................................................................................................................. 26
Table 11. Residential TOU Rate Structure, Effective January 2026.............................. Error! Bookmark not defined.
Table 12. Non-Residential TOU Rate Structure, Current ................................................. Error! Bookmark not defined.
Table 13. Number of transformers by nameplate capacity and number of homes served ......................................... 34
Table 14. Modeling Assumptions ....................................................................................................................................................... 34
Table 15. Electric Outage Reliability, FY 2019 through FY 2025 ............................................................................................. 38
Table 16: Tools for Short Duration Outage Impacts .................................................................................................................... 39
Table 17. ICE Calculator Parameters & Inputs ............................................................................................................................... 40
Table 18. Resilience Benefits per Customer (2025$) ................................................................................................................... 41
Table 19. Annual Resiliency Value Needed for Breakeven Costs ........................................................................................... 44
Table 20. Portable Batteries - Residential Options ...................................................................................................................... 48
Table 21. Stationary Batteries - Residential Options ................................................................................................................... 48
Table 22. Stationary Batteries - Commercial Options ................................................................................................................. 49
Table 23. Residential Generators - Product Examples ................................................................................................................ 53
Table 24. Commercial Generators - Product Examples.............................................................................................................. 54
Table 25. Heat Pump Water Heater - Product Examples .......................................................................................................... 55
Table 26. California Program Inventory Summary ....................................................................................................................... 59
Table 27. CPAU Peers Grid ..................................................................................................................................................................... 60
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1 Introduction and Background
1.1 Purpose and Scope of the Study - Utility Supply Costs, Customer Resiliency, & Customer Programs
Flexible energy technologies such as solar generation, batteries, vehicle to grid, and more are becoming
increasingly common as new innovations enable localized production and capacity integrated within power
systems. These shifts are coinciding with rising electricity demand, driven by increased demand for cooling
resulting from extreme temperatures, electrification of buildings and transport, growing consumption by
industry, and expansion of the data center sector. Together, these trends present new challenges to Palo Alto’s
electric grid.
This study and associated companion studies will evaluate flexible energy technologies and efficient
electrification strategies that enhance customer reliability and resilience in Palo Alto. Based on the outcomes of
this assessment, potential utility customer programs to leverage these technologies will be prioritized, and
recommendations will be provided to inform future planning, operation, and investment decisions for Palo Alto.
These efforts are driven by Strategies 4 and 5 of the City of Palo Alto Utilities’ (CPAU’s) Reliability and Resiliency
Strategic Plan (RRSP), which calls for quantifying the value of various distributed technologies, and estimating the
resource needs to promote various projects and utility programs.
This report provides a qualitative and quantitative assessment of customer programs for flexible technologies
that incorporates the avoided supply costs, distribution costs, the value of resilience, and the technological
viability of each technology. This assessment also considers technology adoption and maturity as well as
program feasibility, accessibility, and community impacts. The results are synthesized into a customer program
prioritization framework with corresponding recommendations, which will be considered alongside concurrent
studies to inform CPAU’s future planning and operations.
1.2 Associated Studies – Distribution Capacity & Investment, Long Duration Airport Microgrid
Palo Alto staff undertook two separate studies, with the help of other consultants, to examine the merits of
utilizing battery energy storage systems (BESS) placed at homes to defer distribution transformer investments by
the utility, and the merits of installing a 6.6MW/26.4MWh Solar PV + BESS microgrid at the airport to serve
critical loads at the adjacent Water Quality Control Plant (WQCP). The relevant results from these studies are
summarized later in this report.
1.3 Defining Reliability & Resilience
Reliability and resilience are central concepts for this study, and they are widely used in the power sector with
distinct yet interrelated definitions that are critical for measuring and valuing resilience. Resilience is typically
defined as “a system’s ability to anticipate, prepare for, and adapt to changing conditions and withstand,
respond to, and recover rapidly from disruptions.”2 Reliability pertains to maintaining power delivery to
customers in the face of routine uncertainty in operating conditions such as fluctuating load and generation, fuel
availability, and outage of assets under normal operating conditions. While resilience and reliability are
interrelated concepts, and resilience is often conflated with reliability, resilience is an expansive concept that
includes and extends to reliability.3 Reliability issues are often seconds to hours, whereas resilience issues come
from low-probability, high-consequence disruptive events that may last hours, and days to months.
2 Resilience Roadmap: A Collaborative Approach to Multi-Jurisdictional Resilience Planning
3 Measuring and Valuing Resilience: A Literature Review for the Power Sector
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Resilience is inherently contextual and goes beyond reliability considerations by incorporating a wide set of
characteristics such as operational and resource flexibility, climate-readiness, and economic resilience.4 Resilience
also emphasizes the importance of transition time between a disruption and ultimate recovery , with a focus on
mitigating higher-level consequences to infrastructure, human-wellbeing, and the economy.
The scope of this study is focused on short-term reliability and resilience for outages within the 24-hour range as
opposed to long-term resiliency for multi-day power interruptions. But many of the technologies being
considered for customer programs in this study can support long-term resiliency in varying capacities. A
residential solar plus storage installation, for example, could provide indefinite power capacity depending on
energy consumption. While long-term resilience benefits aren’t quantified in this analysis, they are considered
qualitatively against other factors to comprehensively capture the full range of potential benefits from customer
programs.
1.4 Flexible Energy Technologies
Flexible energy technologies enhance the adaptability and responsiveness of grid systems, and can help address
reliability and resilience issues, especially in the face of fluctuating renewable energy sources. Palo Alto also has
unique characteristics that should be considered when valuing/implementing flexible energy technologies. Buro
Happold performed a technology assessment (see Appendix A) that includes several technologies currently
available to Palo Alto residents, collating information on product accessibility, implementation feasibility, and
costs. The technology assessment informed the development of program recommendations by confirming which
products are realistic for customer implementation and CPAU budgetary needs. The assessment also highlights
which technologies are best suited to provide resilience and/or cost and sustainability benefits. The relevant
technologies are included below:
• Battery energy storage systems (BESS) and solar
• Generators
• Vehicle to load, grid, and home (V2L, V2X, and VTH)
• Thermal energy storage
• Enabling technologies (including meter collars and demand response technology)
This technology assessment builds on previous research completed by CPAU, encapsulated within the City of
Palo Alto Guide to Electrification 5. The Appendix provides additional context on each technology, with specific
product examples, cost, and sizing information for each technology, with the exception of enabling technologies.
1.5 Palo Alto Context
This study focuses on the use of flexible energy technologies like solar and batteries to provide added reliability
and resiliency for community members. It is driven by several trends leading to increased community focus on
electric reliability and resiliency, and the study of flexible energy technologies is only one action being taken to
improve community reliability and resiliency. These trends and parallel activities are summarized in this section.
4 Power Sector Resilience Planning Guidebook
5 City of Palo Alto Guide to Electrification
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1.5.1.1 GHG Reduction, Electrification, and Greater Reliance on Electricity
The Palo Alto community has ambitious Greenhouse gas (GHG) reduction goals, including a goal to achieve 80%
reductions in community emissions compared to 1990 levels by 2030 and a goal of community carbon neutrality
by 2030. The City is actively promoting the adoption of electric vehicles and the electrification of natural gas
appliances at homes and businesses. As the community continues to adopt more electric vehicles and building
equipment, there has been a call from the community to place a greater emphasis on maintaining a high levels
of reliability and resiliency of the electricity supply systems.
1.5.1.2 Central Generation and Transmission Reliability
A 2009 airplane accident in Palo Alto severed the only transmission corridor connecting the community to the
broader electric transmission system, leading to a full day citywide outage. In August 2020 a combination of
factors led to severe energy constraints and brief rolling blackouts throughout California. Both of these factors
led the community to focus on the reliability of the statewide electric system and Palo Alto’s transmission
interconnection.
The City of Palo Alto Utilities (CPAU) has access to reliable central generation resources from hydroelectric, solar,
wind, landfill and market resources. These supplies are transmitted through the CAISO transmission system for
delivery at the Palo Alto’s high-voltage substation. A number of initiatives are underway to maintain the
reliability of these systems. In addition, through regulatory interventions at the State and Federal level, Palo Alto
participates in ensuring sufficient generation and transmission exists to serve all the electric loads in California.
Within this broader context Palo Alto ensures that the City has adequate capacity to serve the local electrical
demand.
The City has advocated for and received approval from the CAISO for PG&E to construct a second corridor to
receive transmission services – this, when implemented in 2034 or sooner will increase the reliability of the City’s
transmission interconnection.
1.5.1.3 Existing Flexible Distributed Energy Resource Technologies in Palo Alto
There are approximately 1,700 PV systems with a total capacity of 19 MW in Palo Alto, which is estimated to
meet about 2.5% of the community’s electrical loads. There are approximately 150 BESS systems with a capacity
of 1.3MW in Palo Alto, and 9,700 EVs (82% BEV and 18% PHEV). The EV charging load is estimated at ~3% of the
community’s total annual loads (8-15% of the residential load and 1% of commercial load).
Unless required by law, CPAU has mostly refrained from providing rebates or incentives for DERs that are not
economical to do so from a community perspective 6 (the combination of costs and benefits for both the utility
and its customers together, analogous to the “Total Resource Cost Test” commonly used in analysis of energy
efficiency and other demand-side management programs).7 This is to ensure that customer retail rates are
maintained at the lowest possible level. The only DER rebates CPAU has provided in the past is for Solar PV
6 An exception is the first 3 MW of capacity for the Palo Alto CLEAN feed-in tariff program, which provided additional incentives in the form
of a higher feed-in tariff rate. Subsequent capacity does not include additional incentives. Only 100 kW remain available in this first 3 MW of
capacity.
7 A good definition of the Total Resource Cost Test is included on page 18 of the California Public Utilities Commission “California Standard
Practice Manual for Economic Analysis of Demand-Side Programs and Projects,” October 2001, which is still used for investor-owned utilities.
Publicly-owned utilities use similar analytical methods for their energy efficiency and demand-side cost-effectiveness analyses.
https://www.cpuc.ca.gov/-/media/cpuc-website/files/uploadedfiles/cpuc_public_website/content/utilities_and_industries/energy_-
_electricity_and_natural_gas/cpuc-standard-practice-manual.pdf
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system that were required by law – but these rebates ended a decade ago. CPAU continues to provide incentives
for cost-effective energy efficiency programs and has achieved ~5% of electrical load reductions over the past 10
years.8
1.5.1.4 Factors Affecting Customer Programs in Palo Alto
Due to Palo Alto’s low-cost electric supply and low electric retail rates (~50% lower than the IOUs or CCAs in
California), many of the customer programs that are economical in adjoining areas become uneconomical in Palo
Alto. In addition, because the number of customers and electrical load is small in Palo Alto, Palo Alto lacks
economies of scale to absorb the costs of more expensive incentive programs. This has led, for example, to Palo
Alto not having BESS incentives even when investor-owned utilities and some publicly-owned utilities provided
them.
In the past, about 10 years ago, CPAU had implemented a commercial customer summer demand response
program that had about 6 commercial customers participating and achieved 200-500kW of demand reduction.
The program was discontinued after 5 years because the cost and effort was greater than the value.
8 As estimated using data from annual SB 1037 reports. https://www.cmua.org/sb1037-reports
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2 Results
2.1 Methodology for Valuing Flexible Energy Technologies and Efficient Electrification Strategies
In this study, flexible energy technologies and electrification strategies are evaluated within the context of
customer program design and implementation. Customer programs chosen to analyze were informed by
research of an extended inventory of programs nationwide that support resilience and electrification through
various programs, pilots, and customer-scale projects. This inventory also informed each program’s structure,
deployment, and implementation mechanics. The selected programs, summarized in Table 1, include battery,
demand response, vehicle-to-grid, managed electric vehicle charging, and commercial thermal energy storage. A
more detailed description of customer program research and design is provided in Section 0.
Table 1. Customer Program Summary
Components Category
Battery, Solar + Battery • Residential battery incentive
• Residential solar and storage leasing option
• Commercial battery
Interventions • Third-party (contractor) upfront one-time incentive/rebate
• Third-party leasing option or performance-based incentive
Response (DR)
•
demand response
• Commercial battery Response
•
• Email based alerts
Home/Grid (V2X) • Residential V2X
• Commercial V2X Technologies •
• Performance incentive
Managed EV • App-based Managed EV Charging Response • Third-party managed EV charging app
• Enrollment incentives plus monthly bill credit
•
Thermal Energy
•
equipment incentive Interventions
•
• Demand response program
and Microgrids • Direct project support
• Competitive grant funding
• CPAU led project management &
execution
Resilience • CPAU provides limited support via reimbursement for activities like federal grant application development or interconnection expenses
• CPAU distributes funds to community led resilience projects via competitive applications
• CPAU conducts study to identify critical facilities for
Awareness
•
• Incentive directory Outreach
•
on resilience strategies and available incentives
•
Enabling Technology Incentives
• incentives Technology Adoption
• including meter socket adapters, generators/portable power stations, smart panels, socket splitters, energy management devices, and EV meter adapters.
Together, these programs provide a framework to assess the value of flexible energy technologies and
electrification strategies. Several key parameters are considered, including supply costs, the value of short-term
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resilience, distribution costs, program implementation costs, participant cost savings, long-term resilience
potential, program precedents, community impact, and carbon reduction potential. These parameters,
summarized in Table 2, establish quantitative and qualitative customer, utility, and society-scale considerations
for customer program adoption. Additional details on each parameter are also provided in corresponding
sections throughout the report, as listed below.
Table 2. Quantitative & Qualitative Assessment Parameters Overview
Transmission access charge and
commodity impacts that can enable
Distribution
Investment Deferral
Utility savings from deferring
distribution equipment upgrades
Value of Short-Term
Resilience
Avoided interruption costs to
customers according to a customer
Technology Viability
Program
Implementation
Long-term Resilience
Potential
The range and extent to which
customer energy needs are met for a Low duration
Program Precedents
for similar programs across Low
Community Impact
resilience and/or provide equity
benefits through increased access for
Low
Carbon Reduction
Potential
While all programs are considered through a qualitative lens, quantitative parameters are not applicable for all
customer programs, particularly those focused on education, outreach, and community-scale resilience projects.
For this reason, the quantitative evaluation only includes battery, solar plus battery, demand response, V2X,
managed EV charging, and thermal energy storage programs. An Excel-based Program Typology Matrix,
provided as a separate attachment to this report, is the basis for the qualitative assessment and comparison tool
for customer programs identified during the Customer Programs Survey.
An Excel-based Technology Valuation Tool, also provided as a separate attachment to this report, integrates the
quantitative parameters into a cost-benefit analysis that provides the net present value and benefit-cost ratios of
each customer program. Detailed discussion of the underlying mechanics and inputs of this tool can be found in
Section 4. The cost-benefit analysis also includes a sensitivity analysis that considers the range of outcomes
based on program scale, implementation costs, as well as future declines in technology costs.
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2.2 Summary of Results - Customer Program Prioritization Framework
The qualitative and quantitative results from these assessments are summarized in the following sections:
• Section 2.2.1 provides a high-level summary of qualitative results
• Section 2.2.2 provides quantitative results from the cost-benefit and sensitivity analysis
• Section 2.2.3 covers the impact of distribution investment deferrals, which is included as a supplement to
the cost-benefit analysis results
• Section 2.2.4 covers long-term resilience potential, which is included as a separate qualitative
supplement to the cost-benefit analysis results
2.2.1 Qualitative Results
The qualitative results, summarized in Table 3 suggest that grid scale interventions (solar and battery energy
storage systems), demand response, and emerging technology programs (V2X) generally perform better relative
to programs focused on community resilience, education, and enabling technologies. This is due in part to the
former’s ability to support long-term resilience while providing cost-savings to program participants, as well as
greater carbon reduction potential. However, programs for grid scale interventions and emerging technologies
may favor higher-income, property-owning customers due to installation costs and barriers for renters, thereby
creating inequities depending on program design. Incentives provided for solar and battery programs or V2X
therefore have limited community impact in comparison to resilience awareness programs or resilience hubs,
which are generally more accessible and widespread in their impact. Careful program design is needed in either
case to consider customer adoption and the impacts on residents of varying income levels.
There are numerous precedents for most of these programs across California and the United States, highlighting
how utilities are employing a variety of approaches to address resilience and electrification in various capacities.
Apart from thermal energy storage and vehicle-to-grid/home technologies, there is a substantial level of
program demonstration that that can inform potential adoption in Palo Alto. Qualitative parameters alone,
however, insufficiently enumerate the impacts of these programs on the City and its residents. The qualitative
outlook is also dependent on the weighting and prioritization of each parameter, which requires further
deliberation beyond the scope of this analysis. The section that follows explores the impacts of these programs
qunatitatively based on utility supply cost savings and the value of short-term resiliency during utility outages.
Table 3. Qualitative Results Summary
Participant Cost-Resilience Program Community Reduction
Battery Low Medium High Medium Medium
Solar + Battery High High High Medium High
Demand Response Medium Low High High Low
V2X Low-Medium Medium Low Medium Medium
Residential Managed
EV Charging Medium N/A Medium Medium Medium
Low N/A Low Low Low
N/A Low Medium High Low
Low/Medium N/A High High Low
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2.2.2 Quantitative Results and Sensitivity Analysis – Utility Supply and Short-term Resiliency Benefits
The quantitative results in Table 4 indicate that in most cases the benefits of customer programs for flexible
energy technologies do not exceed the costs. One exception is solar plus battery systems, which provide a
positive net present value for commercial customers. Commercial battery systems are nearly cost effective, and
they outperform residential battery systems due to economies of scale, lower capital costs, and a higher value of
resilience for commercial customers. These cost-benefit calculations do not include the investment tax credit.
Vehicle to grid programs differ from battery energy storage systems due to varying charging schedules that limit
energy arbitrage, as well as other factors like reserve depths and program adoption rates. Demand response
programs require little up-front investment from customers, but the benefits are still exceeded by costs because
they require high levels of customer participation for utility programs to be cost effective. Lastly, programs for
thermal storage are not cost effective at the scale of system considered most applicable for a broad program.
Table 4. Community Cost-Benefit Summary
9 10
100 Residential Battery
Installations $650,127 $2,224,335 -$1,574,208 0.29
100 Residential Solar +
Battery $3,118,274 $4,411,335 -$1,293,061 0.69
35 Commercial Battery
250 Demand Response
Figure 1 and Figure 2 visualize the costs and benefits of each program, highlighting which component of each
program is most influential in determining program performance as well as the additional value needed to reach
break-even costs. For example, solar plus battery programs require large capital expenditures but also generate
significant customer savings. Capital expenditures for VTX and Demand Response programs on the other hand
are quite low and far outweighed by program administration costs.
9 This includes all of the benefits calculated using the methodologies in Sections 4 and 6 of this report.
10 This includes both the capital cost of the equipment and the cost of program administration, as shown in Appendix C
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Figure 1. Cost-Benefit Results for Commercial Programs
Figure 2. Cost-Benefit Results for Residential Programs
These figures highlight how changes in assumptions could markedly improve program performance. In turn, the
sensitivity analysis in Table 5 demonstrates how scaling the programs (increasing adoption) and reducing upfront
administrative and operational costs can improve program performance and the corresponding benefit-cost
ratios, particularly for VTX and demand response where program costs are proportionally much larger than
technology installation costs. At sufficient scale, demand response programs for residential and customer
programs have a nearly net positive value and net positive value, respectively. Meanwhile, the performance of
solar and battery programs is only marginally impacted by changes in program scale and administration costs.
Supply Cost Benefits
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Table 5. Sensitivity Analysis - Customer Adoption & Program Costs
Residential Battery
Battery
Residential VTX
Response
Commercial Battery
Battery
Response
Sensitivity analyses of technology costs in Table 6 demonstrate how future price reductions could result in a net
positive value for solar and battery customer programs. These projections are based on moderate scenario
estimates by the National Renewable Energy Laboratory’s Annual Technology Baseline (ATB), providing potential
percentage reductions by year. The benefits of residential battery programs are unlikely to outweigh the costs
under current projections and would have to fall over 90% to reach breakeven. Commercial battery and
residential solar plus battery programs could be net positive with a 14% reduction and a 40% reduction in costs,
respectively. Commercial solar plus battery already provides a net positive value and can be expected to improve
with future cost reductions. Vehicle to grid/home technologies do not currently have reliable forecasted price
reductions. Even so, any reduction in installation costs isn’t sufficiently large enough improve program feasibility,
given the relative program administration costs.
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Table 6. Sensitivity Analysis - Technology Costs
2025 0.29 0.71 0.90 1.00
2030 0.32 12.8% 0.81 14.8% 1.03 18.0% 1.17 15.8%
2035 0.34 18.2% 0.92 26.1% 1.08 23.1% 1.33 26.9%
2040 0.36 23.6% 0.99 32.3% 1.13 28.3% 1.43 32.7%
2045 0.38 29.1% 1.07 38.4% 1.19 33.4% 1.55 38.3%
Figure 3. Benefit Cost-Ratio Forecast
2.2.3 Quantitative Results – Distribution Investment Deferral
Palo Alto’s grid modernization program includes upgrading 4kV circuits to 12 kV circuits, replacing aging
substation transformers, and upgrading distribution transformers. The primary driver for upgrading distribution
transformers and associated secondary circuits is to meet projected increase in electrification loads in single
family homes due to EV charging and electrification of natural gas appliances.
City staff, in partnership with a separate consultant, did a preliminary assessment of the economics of utilizing
small residential batteries to defer the replacement of distribution transformers. It was estimated 362 of the
1,750 distribution transformers slated for replacement could be deferred by installation of 2,400 residential
batteries. The annualized cost of batteries was estimated to be $1.3 million compared to saving of $1 million
from deferral of transformer upgrades, thus making such an investment uneconomical. In addition to being
uneconomical, implementing such a customer program with controllers to dispatch the batteries at customer
homes when the transformer is overloaded poses logistical and technological hurdles too, making such a
program infeasible at this time.
Based on the above analysis, flexible DER technologies do not appear to offer economic opportunities to defer
distribution system investments, and City staff recommend no further analysis of this strategy.
2.2.4 Qualitative Results – Long-term Resiliency and Microgrids
While this study was not intended to do a quantitative study of solar and batteries (or vehicle to home) for long-
term resiliency City staff performed a qualitative assessment. Staff assessed that while solar plus battery systems
are currently not cost-effective, additional benefits from long-term resiliency could make it worthwhile for a
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customer to invest. Currently the City passes on the supply-related benefits to the utility on to the solar customer
through net energy metering and its feed-in tariff program, but this is not enough value to pay for a solar and
battery investment. Community members who value short-term and long-term resiliency highly enough,
however, may be willing to pay extra for solar and storage on their property. The City does not currently provide
incentives for solar and battery systems, and if the City Council wants to provide such incentives for the long-
term resiliency value, City staff outlined some potential approaches in Section 7. If incentives were provided for
facilities that would be of value to the community during a major emergency, some level of community
emergency power disaster planning would be needed, and City staff outlines this need in Section 7 as well. Lastly,
staff also assessed the long-term resiliency value and generally economics of microgrids, including community-
scale microgrids, through a study of a potential microgrid encompassing Palo Alto’s airport and wastewater
treatment plant. The insights from this study are summarized in Section 1.
2.2.5 Takeaways & Conclusions
While most customer programs assessed in this study are not currently cost effective, there are additional
benefits that could justify future investment. These benefits may be derived from long-term resiliency, changes in
program scale, reductions in administrative costs, or declining technology costs, and could provide a net positive
value for the City of Palo Alto.
For all program designs, the smaller scale of Palo Alto is a particular challenge as administrative costs risk being a
significant portion of the overall costs and benefits. Reducing program costs could be achieved by leveraging
alternative funding sources (such as grants or State or Federal incentives, if available) or by integrating
technologies into existing programs. Further evaluation of program design and implementation may help
increase adoption rates (which may be especially beneficial for demand response programs) thereby improving
overall cost-effectiveness.
Cost projections for solar and battery technologies suggest that future reductions could further improve
commercial solar plus battery programs and yield positive benefit-cost ratios for commercial battery and
residential solar plus battery programs. Continued monitoring of these trends is recommended, as future shifts in
market conditions or policy could make these technologies more viable. In the meantime, technical assistance
programs or incentives are not recommended, but the City could still play a proactive role in promoting flexible
energy technologies to its customer base and further evaluating the feasibility of larger utility-scale and
commercial solar and storage programs in parallel. Additional considerations for long-term resiliency may also
be applicable on a case-by-case basis for microgrids and backup power circumstances.
Scaling incentives for, or specifically targeting, low-income residents may also be necessary to address inherent
equity issues associated with programs. These groups are less likely to adopt flexible energy technologies
without targeted support, which risks exacerbating existing disparities in access to and adoption of flexible
energy technologies. More broadly, strategic communication and outreach efforts could help raise awareness
and encourage adoption of enabling technologies across the Palo Alto community. Such efforts would not only
support equitable access but also enhance overall community resilience, especially to the extent that these
efforts improve participation among vulnerable populations.
Based on these findings, one reasonable policy choice would be to have the City continue current practices while
evaluating the feasibility of customer programs for flexible energy technologies on an ongoing basis. The City
should explore alternative cost-effective strategies for building community-scale resilience while continuing to
monitor cost-benefit ratios. Under this policy approach, the following approaches could be pursued for each
respective technology and customer program:
1. Promote ways community members can reduce emissions by reducing peak period load (helping the
electric grid) and, once time of use (TOU) rates are launched, potentially save money by doing so as well.
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The TOU Implementation and Communication Plan discussed at the UAC’s October 1 meeting
incorporates this messaging.
2. Monitor demand response technologies for positive benefit-cost opportunities, but do not pursue a
demand response program at this time (which continues existing City policies). Project changes to
benefit to cost ratios and identify actions to take at the point benefits exceed costs.
3. Promote residential solar and battery adoption, standalone batteries, and thermal storage, but do not
provide incentives at this time (which continues existing City policies). Project changes to benefit to cost
ratios and identify actions to take at the point benefits exceed costs. Explore low-cost technical
assistance programs if feasible.
4. Promote electric vehicle to home or grid as it becomes more available, but do not provide incentives at
this time (which continues existing City policies). Project changes to benefit to cost ratios and identify
actions to take at the point benefits exceed costs. Explore low-cost technical assistance programs if
feasible.
5. Explore opportunities for larger-scale solar + battery projects on commercial or community facilities on a
case-by-case basis and bring forward for consideration if cost-effective options can be identified, while
continuing to pursue utility-scale solar and storage and other renewables in parallel.
6. Monitor opportunities for distribution investment deferral using flexible technologies and efficient
electrification but do not pursue additional analysis or new policies or programs at this time.
7. Maintain the City’s current policies on microgrids and backup power at this time, but bring forward
additional discussion on long-term resiliency, highlighting community-level planning and equity
considerations.
Explore backup power needs at the Regional Water Quality Control Plant (RWQCP) and airport to determine the
most economically feasible backup power alternatives to determine whether an electric utility / treatment plant
partnership for a solar and storage microgrid at the airport can be made economically feasible.
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3 Customer Programs Survey
Utility programs promoting resilience technologies are emerging across the country, particularly in California. To
inform program design considerations, the team conducted research to develop an inventory of existing
resilience technology programs including details such as the utility/funder, location, sector, incentive amounts
and equity elements. The resulting inventory includes 100 programs, pilots and projects designed to promote or
support the adoption of one of the resilience technologies or approaches listed in Table 7.
Table 7. Resilience Technology categories included in program directory
Electric energy storage system; includes residential, commercial and industrial
applications.
Thermal Storage
conditioning, water heating or refrigeration. Includes both C&I and residential
applications.
Generator
natural gas or diesel. Also includes portable electric generators.
Solar and Storage
Managed EV Charging
Vehicle-to-Home & Vehicle-
to-Grid (V2X)
Practices leveraging bidirectional charging technology to either power a home or
discharge to the electric grid using electric vehicle (EV) batteries.
EV Time of Use (TOU) Rates
higher when load is high and lower when load is low, to incentivize off-peak
charging.
Microgrid
can be operated separately from the rest of the grid for short or long duration
outages.
Resilience Hub
operation during a resiliency event.
Smart Panels
circuits/loads to be monitored and controlled independently. Particularly
advantageous for homeowners with battery so that critical loads can be assigned
and adjusted.
Meter Socket Adapters
interface where additional devices can be installed such as remote disconnects and
DERs. Also referred to as “Meter Collar”, "Backup power transfer switch" and "Tesla
Back-up Switch (BUS)".
Other
present within the identified programs.
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The identified programs range from large established IOU programs like California’s Self Generation Incentive
Program (SGIP),11 which provides incentives for a wide range of self-generation equipment including energy
storage systems, to innovative pilots implemented by small publicly owned utilities (POUs) like Cape Light
Compact’s Cape and Vineyard Electrification Offering,12 which provides solar, storage and heat pump
installations from low to no cost for income qualified residents. At least one program was identified within each
of the listed technology categories. However, there were some clear market leaders among the technologies, and
several that remain in the pilot stage. summarizes the offerings listed in the program directory. This directory is
not intended to be a comprehensive directory of equity programs offered nationwide but is intended to capture
a reasonable sample of resilience-oriented offerings that exist across the country. For this analysis, offerings were
placed in one of the following three categories, intended to represent the design of each offering.
• “Programs" are categorized as offerings that provide a financial incentive, service or product to
customers and are recurring or considered as part of a standard offering for the funder.
• "Projects/Pilots" are defined as programs or projects with a limited duration or budget intended to test
or demonstrate a program or technology concept.
• "Policies/Plans" are categorized as enabling policies or rate plans available to customers that do not
neatly fall into the categories of programs, pilots or projects but enable the installation of emerging
technology or offer other resilience benefits to customers.
Offerings that include an equity component are flagged in the directory and are summarized in this table in the
columns labeled “w/ equity”. The sum of the offerings listed by technology may not equal the subcategory totals
because several offerings include more than one listed technology.
11 Participating in Self-Generation Incentive Program (SGIP)
12 CVEO - Cape Light Compact
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Table 8. Program Inventory Summary
Qt
y
.
Qt
y
Qt
y
Battery programs quickly became a leader among identified offerings with 22 identified programs, seven
identified pilots/projects, and one identified policy or plan. Solar and storage programs were also prevalent and
had a much higher portion of offerings with an equity component, with almost half of the identified offerings
containing some sort of equity focused component. Other technologies with a notable presence among existing
offerings include Managed EV Charging, V2X Pilot projects, EV TOU rates, Generators and Thermal Storage.
Technologies with less presence in the market included V2X programs, Resilience Hubs, Meter Socket Adapters,
Microgrid, and Smart Panels. Vehicle to Home and/or Grid offerings almost exclusively fell into the Pilot category,
with several small-scale offerings identified that intended to test this emerging technology. While meter socket
adapter enabling policies were found at six utilities, only one offering, administered by PPL electric utilities,13
actively incentivizes the technology by providing it to customers at no upfront cost.
Among the identified offerings, 13% include some equity component. Most offerings with this characteristic
provide larger financial incentives to customers that meet an income qualification or a geographic qualification
such as residing in a designated disadvantaged community (DAC) per the U.S. Environmental Protection Agency.
These incentives range from incremental increases from the base rates to large incentives covering up to 100% of
the project cost. Microgrid and resilience hub programs and projects with an equity consideration typically target
sites within communities where larger portions of residents live below the poverty line, or in a DAC. Some more
unique offerings with an equity consideration included a Green Mountain Power battery program that features a
no-interest leasing option,14 reducing the up-front capital investment required for participation, and the
13 Meter Collar Devices
14 Home Energy Storage - Green Mountain Power
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previously mentioned Cape and Vineyard Electrification Offering,15 that provides solar and storage and heat
pump installations at low to no cost for residents depending on income qualifications.
The methods used by utilities to deploy resilience technologies vary. While some programs or pilots are
presented as independent offerings, others are combined with larger offerings or grouped with electrification
measures. For example, solar and storage are commonly paired among utility programs, where batteries are
presented as an adder to an existing solar incentive program. Batteries are also seen grouped with generation
technologies like electric or gas generators and presented as back-up power or “self-generation” programs. Only
one program was identified that provides incentives for smart panels; Silicon Valley Power’s offering is embedded
within their standard incentive program.16 Offerings like this one may indicate that there are additional smart
panel rebates available that were not identified in this research, because they are embedded within larger
program offerings and therefore less searchable. Alternatively, V2X programs were most often presented as an
independent offering, except for Portland General Electric’s (PGE) Smart Grid Test Bed.17
While the surveyed technologies were selected based on their applicability to resilience, very few offerings were
presented as resilience programs. Instead, offerings were often linked to electrification efforts or presented
without resilience or electrification emphasis. Programs that did have a resilience emphasis were typically
offerings supporting microgrids, resilience hubs or generators. Two generator programs in California only
provided incentives for residents located in California Public Utility (CPUC) High Fire Threat District Tiers 2 or 3.18
19
After completing the program research, the team concluded that utilities are adopting resilience programs
through diverse design approaches within each technology type. To guide the city's next steps, the team
reviewed the program research which informed a variety of program designs for consideration. The team
determined that most programs fell into one of six program categories, as described in Table 9. These program
categories were then used to inform the development of program designs for the cost effectiveness valuation.
During the analysis of existing programs, the team evaluated various factors, including the size of the
implementing utility, the apparent success or longevity of the programs, and the prevalence of similar programs
in the market. To provide the city with a diverse representation of program categories and implementation
approaches, the team also sought to include as many program categories as possible, while considering
suitability for program scale deployment supporting of resilience goals. Based on these considerations, the
program team proposed eight program designs for cost-effectiveness analysis, summarized in Table 10. The
proposed programs were ultimately selected with the intention of providing a variety of design options that
encompass a majority of approaches observed in the market. These programs were assumed to be funded from
utility ratepayer funds, with the cost-effectiveness analysis (using the methodology described elsewhere in this
report) determining whether the programs would be cost-effective for the community as a whole on that basis,
and therefore viable for implementation using ratepayer funding.
15 CVEO - Cape Light Compact
16 Rebates | Silicon Valley Power
17 Smart Grid Test Bed | PGE
18 Rebates & Incentives | Rebates, Incentives, & Savings Tips | Your Home | Home - SCE
19 Generator & Battery Rebate Program
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Table 9. Program Research Framework
Interventions Investments in widespread, grid-scale technologies to enhance resilience across the
• Utility-scale generator
• Microgrids
• Solar and Storage
•
form the basis for a cost-effectiveness analysis .
Demand Response (DR) Programs to encourage, incentivize, and enable demand shifts or reductions
at specific times to prevent
•
• Residential DR
• Commercial DR
• Managed EV Charging
•
form the basis for a cost-effectiveness analysis
Emerging Technologies Focused on piloting, scaling, and deploying emerging technologies to enhance grid
• V2X
• V2H form the basis for a cost-effectiveness analysis
Mass Market Technology Adoption
Incentives or rebates provided to customers to install low-tech resilience
interventions or improve
efficiency.
• Portable Solar and Storage
• Smart Panels
• Meter Socket Adapter
• Efficient Electrification
suitable for resilience program cost-effectiveness
analysis, but could be
considered as part of
Community Resilience Targeted investments for communities in need to build community resilience.
•
• Solar and Storage
• V2X resilience, less suitable for a scalable program for target outcomes, recommended for
Education & Outreach Communication strategies to improve customer
awareness, adoption of
technologies, and enrollment
• Varies by program Enabling function, to encourage private adoption
taking advantage of
voluntary TOU rates coming
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Table 10. Customer Program Designs
Components Category Application Analyzed for Cost-Effectiveness Opportunities
• Residential battery
incentive
• Residential solar
and storage leasing
option
• Commercial battery
Interventions
(1) & Non-
residential
•
• Solar and storage leasing option: customers may
lease battery or solar and storage from third-party.
• Set a # of discharge events per year, cannot be
only used for backup.
• Higher rebates for
income eligible
customers
• Leasing option is only
available to income
qualified customers.
Demand
Response
(DR)
• Residential battery
demand response
• Commercial battery
demand response
& Non-
residential • Performance: $/kWh discharged during peak
events
• Participation: Enrollment incentive plus monthly
V2X • Residential V2X
• Commercial V2X Technologies
(3)
& Non-
residential
of the following:
• Performance: $/kWh discharged during peak
events
• Participation: Monthly bill credit for participation
charger incentive for
income qualified
customers
Residential
Managed EV
Charging
App-based
Managed EV
Charging
EV Charging
• Participants must download custom CPAU
managed EV charging app.
• Participation incentives: enrollment incentive plus
monthly bill credit
• Additional one-time incentive for compatible
Commercial
Thermal
Energy
Storage
Commercial Thermal
Energy Storage Interventions Storage size)
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4 Supply Cost Valuation
4.1 CPAU Avoided Cost
The calculation to estimate CPAU’s avoided cost for each of the technologies included within the Technology
Valuation Tool uses data provided by CPAU from their avoided electric supply cost projection model. This model
provides the cost ($) per unit of energy (MWh) delivered within the CPAU network in an hourly format for each
month spanning calendar years 2025 through 2035. As many technologies and load shifting/reduction strategies
have useful lives exceeding this timeframe, an observed linear trend was extrapolated to 2050. Various sub-costs
are factored into the data source, including:
• Energy Cost
• Resource Adequacy (RA) System Capacity Cost
• RA Local Capacity Cost
• California Independent System Operator (CAISO) Ancillary Service Cost Allocation
• CAISO Grid Management Charge (GMC) Cost Allocation
• Locational Marginal Pricing (LMP) Differential Between Load Aggregation Points (LAP) and NP-15
• Low Voltage Transmission Access Charge
• High Voltage Transmission Access Charge
• Renewable Energy Certificate Value
• Distribution System Losses
A yearly (8,760 hour) model was developed given the raw input data, to account for technologies and strategies
that could be implemented multiple days per month during different time periods. An example of the load
profile for a sample winter month (January 2026) and summer month (August 2026) are provided in Figure 4
below. As demonstrated, the cost of energy ($/MWh) delivered within CPAU’s network fluctuates throughout the
day, as well as throughout the months of the year. This disparity is the key component in understanding the
benefit (or non-benefit) of the simulated technologies and strategies on the total supply cost attributable to
CPAU. Many of the technologies (battery energy storage, vehicle-to-everything, thermal energy storage) aim to
reduce the City’s supply costs by charging during low-cost times of day and discharging during higher cost times
of day, while load reduction strategies (demand response, distributed generation) aim to mitigate supply costs
through the displacement of energy use. While the technologies aiming to reduce supply costs overall have the
need to charge, increasing supply costs during that period (coupled with losses associated with roundtrip
efficiency, noted in the Assumptions section), it is the goal to have these periods coincide with times when
energy delivery costs are lower. Conversely, it is the goal to have the discharge periods coincide with times at
which delivery costs are higher, thus creating a net-positive benefit to CPAU.
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Figure 4. Cost per MWh Delivered Example: Winter Month (January 2026) and Summer Month (August 2026).
For each of the technologies and reduction strategies, a few key variables are developed to simulate the benefit
to CPAU’s supply cost. An overview of these key variables is described below with a full account of assumptions
for each technology and strategy in the Assumptions section.
• Total Energy Demand, typically expressed in kilowatts (kW) or megawatts (MW)
• Charge/Discharge Duration, expressed in hours
• Charge/Discharge Start Time, noted as a specific time of day
• Frequency, which varies daily (battery energy storage, vehicle-to-everything) and seasonally (demand
response, thermal energy storage)
• System Degradation, as applicable based on technology
The simulation is then conducted on an annual basis, across the time horizon specified which ranges from 15
years to 20 years. The sum of the net benefit is then determined for each year and a net present value (NPV) of
the lifetime expected savings is calculated using a rate of 5% to determine a comparative current value of the
future savings. It should be noted that the value determined as part of this exercise does not portray the total
benefits to CPAU, as there will often be negative impacts to CPAU’s distribution and commodity revenue streams
that are discussed in the subsequent sections.
An example of the daily arbitrage associated with a standalone battery energy storage system (per 100
installations) in a residential application is provided in Figure 5 below. As shown in the figure, when the system is
charging there is a negative impact on CPAU’s supply cost, while there is a positive impact when the system is
discharging. In total, the discharging benefit ($166.58) outweighs the charging negative benefit (-$135.47), for a
net positive benefit of $31.11. This same methodology is determined for each day and summed for a full year.
This example also highlights the efficiency losses, with a difference in energy that's delivered back to the grid
after being stored, compared to the energy put into the system for charging.
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Figure 5. Example Supply Cost Net Savings for Residential Standalone BESS (per 100 installations)
4.2 Statewide Avoided Cost
The final simulation performed is an assessment of the technologies and strategies impact on the statewide grid.
For this, the statewide Avoided Cost Calculator (ACC) Electric Model v1bfor the same climate zone (CZ4) was
developed, as shown in Figure 8 below. Like the hourly data provided by CPAU, this tool provides an insight into
the valuation of energy at the statewide level on an hourly basis for the same time period of evaluation as the
CPAU avoided cost.
Month Day Hour
Discharge Energy
(MWh)
Charge Energy
(MWh)
Total Energy
(MWh)
Avoided Cost of
1 MWh
Delivered
1 1 1 0.000 0.000 0.000 -$
1 1 2 0.000 0.000 0.000 -$
1 1 3 0.000 0.000 0.000 -$
1 1 4 0.000 0.000 0.000 -$
1 1 5 0.000 0.000 0.000 -$
1 1 6 0.000 0.000 0.000 -$
1 1 7 0.000 0.000 0.000 -$
1 1 8 0.000 0.000 0.000 -$
1 1 9 0.000 0.000 0.000 -$
1 1 10 0.000 -0.275 -0.275 (34.95)$
1 1 11 0.000 -0.275 -0.275 (34.22)$
1 1 12 0.000 -0.275 -0.275 (33.64)$
1 1 13 0.000 -0.275 -0.275 (32.66)$
1 1 14 0.000 0.000 0.000 -$
1 1 15 0.000 0.000 0.000 -$
1 1 16 0.000 0.000 0.000 -$
1 1 17 0.248 0.000 0.248 41.29$
1 1 18 0.248 0.000 0.248 42.02$
1 1 19 0.248 0.000 0.248 41.78$
1 1 20 0.248 0.000 0.248 41.49$
1 1 21 0.248 0.000 0.248 -$
1 1 22 0.000 0.000 0.000 -$
1 1 23 0.000 0.000 0.000 -$
1 1 24 0.000 0.000 0.000 -$
Net Benefit 31.11$
166.58$
(135.47)$
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Figure 6. Avoided Cost Calculator Input Parameters
The same example from the previous sections is provided in Figure 9 below to highlight the disparity between
the value of energy at the local (CPAU) level versus the statewide level. While the local avoided cost values the
technology in this example as a benefit of $31.11, the statewide valuation of this same period is $14.89. This
demonstrates the need to evaluate the technologies and strategies at a local level, to truly understand the
benefits to CPAU and make informed decisions regarding implementation of cost-effective programs. While
certain technologies may not present a significant benefit when evaluated at the statewide level, they may
present an opportunity locally to the City, and vice versa. While the statewide avoided cost is not included in the
cost-effectiveness analysis, this analysis is included for context to help illuminate why programs with economics
that work in one California service territory may not work in Palo Alto.
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Figure 7. Example of Avoided Cost Disparity for Residential Standalone BESS (per 100 installations)
4.3 Time of Use Rates
Time of use (TOU) rates are a key enabling factor for flexible energy technologies and demand response
programs, as they provide incentives to shift or shed end-use load. In addition to enabling demand flexibility,
grid reliability, and efficient use of electricity, price-based signals can provide cost savings for some groups of
participating customers while creating a net benefit to utilities implementing them. Time of Use (TOU) pricing is a
common program employed to send price-based signals, where customers pay different prices at various times
of the day, based on the actual costs to deliver service at those times of day.
Demand response programs, enabled by price-based signals such as TOU, are increasingly being considered for
their technical potential to provide additional resource capacity for utilities through future load forecasting and
integrated resource planning. However, the current lack of data and experience with TOU programs limits their
broader application in utility distribution system plans. Currently, there is no widespread consensus of how
assumptions of price-based demand response load reductions from TOU should be incorporated into resource
planning.
Recent studies shed light on the technical potential of TOU rates and demand response programs. California’s
2018 TOU pilot (including PG&E, SCE, and SDG&E) averaged 4.6% in energy demand peak period load reduction.
Of nearly 150 programs assessed by the Lawrence Berkeley National Laboratory, 20% reported outcomes on
demand reductions, and 14% reported outcomes on program spending:
• Utilities realized an estimated average demand reduction of 0.06 to 0.9 kW/participant/event
Month Day Hour
Discharge Energy
(MWh)
Charge Energy
(MWh)
Total Energy
(MWh)
CPAU Avoided
Cost Statewide ACC
1 1 1 0.0000000 0.0000000 0.0000000 -$ -$
1 1 2 0.0000000 0.0000000 0.0000000 -$ -$
1 1 3 0.0000000 0.0000000 0.0000000 -$ -$
1 1 4 0.0000000 0.0000000 0.0000000 -$ -$
1 1 5 0.0000000 0.0000000 0.0000000 -$ -$
1 1 6 0.0000000 0.0000000 0.0000000 -$ -$
1 1 7 0.0000000 0.0000000 0.0000000 -$ -$
1 1 8 0.0000000 0.0000000 0.0000000 -$ -$
1 1 9 0.0000000 0.0000000 0.0000000 -$ -$
1 1 10 0.0000000 -0.2750000 -0.2750000 (34.95)$ (19.18)$
1 1 11 0.0000000 -0.2750000 -0.2750000 (34.22)$ (18.25)$
1 1 12 0.0000000 -0.2750000 -0.2750000 (33.64)$ (20.30)$
1 1 13 0.0000000 -0.2750000 -0.2750000 (32.66)$ (20.30)$
1 1 14 0.0000000 0.0000000 0.0000000 -$ -$
1 1 15 0.0000000 0.0000000 0.0000000 -$ -$
1 1 16 0.0000000 0.0000000 0.0000000 -$ -$
1 1 17 0.2475000 0.0000000 0.2475000 41.29$ 22.98$
1 1 18 0.2475000 0.0000000 0.2475000 42.02$ 23.65$
1 1 19 0.2475000 0.0000000 0.2475000 41.77$ 23.14$
1 1 20 0.2475000 0.0000000 0.2475000 41.49$ 23.14$
1 1 21 0.0000000 0.0000000 0.0000000 -$ -$
1 1 22 0.0000000 0.0000000 0.0000000 -$ -$
1 1 23 0.0000000 0.0000000 0.0000000 -$ -$
1 1 24 0.0000000 0.0000000 0.0000000 -$ -$
Net Benefit 31.11$ 14.89$
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• Residential reductions for TOU programs ranged from 1-6% per participant.
• Commercial and Industrial TOU reductions ranged from 1.5-5%.
• Utilities spent approximately $40-100 per kW for first-year costs
CPAU already has voluntary TOU rate designs for medium and large commercial customers and will be
implementing voluntary TOU rates for residential and small-scale non-residential customers in the upcoming
year. In relation to the cost-effectiveness study used for this report, TOU rate implementation is assumed when
analyzing the cost-effectiveness of customer demand response programs, for both residential and non-
residential customers. Furthermore, they can help integrate renewable energy sources into the grid, particularly
for customer programs focused on distributed energy resources.
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5 Distribution Cost Valuation
City staff partnered with other consultants to complete a distribution cost valuation. City staff considered
building a complete model of the electric system under a complete electrification scenario to identify which
transformers would need upgrading and whether batteries, vehicle to grid, and efficient electrification could
defer transformer replacements. Before committing to a complete model, though, City staff partnered with a
consultant to complete a preliminary analysis to determine the need for the full analysis. That analysis,
summarized below, found that the potential for deferring capital investment was limited and very likely not cost
effective.
5.1 Results
In one scenario, staff identified potential savings from deferral of infrastructure investment from 326
transformers out of over 1,700 in Palo Alto. If these could be deferred without cost the savings would be equal to
about $1 million per year in avoided debt service costs or about a 0.55% reduction in rates. However, staff
estimated that 2,400 utility-funded energy storage systems at well over 1,000 homes would be required to
achieve this deferral, at a debt service cost of about $1.3 million per year, exceeding the potential savings. When
combined with the additional considerations below, especially those related to the legality, novelty and
complexity of such a program, the analysis points to there being negative value to pursuing deferral through
utility-controlled flexible energy technologies.
5.2 Additional Considerations
Beside the lack of cost effectiveness, several additional factors would make implementing such a program
difficult:
• This program depends on the use of transformer-level microgrid controllers that are not extensively used
in the utility world at this time, leading to some operational risk due to use of an earlier-stage
technology, and likely staff time and ongoing cost impacts that may not be accounted for in the
estimates above. It would require very rapid launch of a major program effort to deploy utility-controlled
batteries at homes
• It also results in less efficient infrastructure investment and may involve higher operational costs from
maintaining a diversity of equipment
• And lastly, if construction inflation continues to exceed general inflation, deferring investments in
infrastructure could mean the real cost is greater later on, meaning higher rates for future Palo Altans.
5.3 Methodology
Staff did a simple calculation to estimate the number of 13.5 kWh, 3.375 kW four-hour batteries needed to
manage any grouping of homes that exists on the City’s electric system. Staff used the Grid Modernization Study
coincident peak load assumption of 6 kVA per home to evaluate the peak transformer loading, then calculated
the number of batteries needed to reduce the total loading below the transformer limit (which is 80% of
nameplate capacity). An underlying assumption of this method is that the energy capacity of the batteries is
sufficient to discharge at all hours needed to keep the transformer loading below the load limits. A Monte Carlo
simulation using actual AMI data found that this assumption did not hold in all scenarios, meaning this
methodology yields an optimistic outcome, and in reality, more batteries would likely be needed to achieve the
program’s goals.
Staff then identified candidate transformers for deferral: those less than 20 years old and that are not being
replaced as part of a 4 kV -> 12 kV upgrade, 326 transformers. Staff ran the calculation for each transformer and
found the following:
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Table 11. Number of transformers by nameplate capacity and number of homes served
homes size and number of homes)
4 22
5 24 11
6 33 5
7 30 21
8 32 15
9 21 16
10 11 31
11 13
12 30
13 11
173 153
In this preliminary analysis, the City is assumed to pay for these batteries because they are used exclusively for
distribution management. Staff estimated the total up-front cost of the batteries needed, then calculated the
cost of debt financing those costs over 20 years. Staff then compared that to the debt service cost of upgrading
the transformers instead of doing the program. The modelling assumptions and results are shown below:
Table 12. Modeling Assumptions
Average cost per transformer upgrade $50,000
Avoided upgrades 326
Total avoided capital investment $16.3 million
Debt service (30 years, 4.5% interest rate) $1.0 million per year savings
Cost per battery $5,900
Batteries 2,400
Total required capital investment $14.3 million
Debt service (20 years, 6.5% interest rate) $1.3 million per year cost
The ongoing debt service for the batteries in this case exceeds the savings generated by deferring distribution
investment. In addition, this preliminary analysis does not include the cost of battery controllers to match battery
charge and discharge to transformer loading, program costs to deploy the batteries, and staffing for ongoing
maintenance of the battery controller system. Battery systems may not last the full 20 years assumed in this
analysis (most have only 10-15 year warranties), and capacity declines with age, which is also not accounted for.
With these included, the total cost of the program would exceed the savings by far more. The preliminary
analysis also does not account for degraded battery performance overtime, losses incurred during battery
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charging cycles, possible benefits from shifting consumption (thru battery charging/discharging) to periods of
lower cost and/or cleaner energy production, potential of higher customer peak demands due to electrification,
and changes in construction pricing. In general, further sensitivity analysis is expected to result in a higher cost to
pursue the battery storage alternative, and no further analysis is recommended.
5.4 Efficient Electrification Strategies
Efficient electrification strategies are tools that will result in lowering customers peak load, which will also enable
customers to electrify their homes without having to upgrade their electrical panel. Electrical panel upgrades,
which may also trigger utility upgrades will be costly and could potentially delay customer’s electrification
projects.
Tools such as smart electrical panels, circuit splitters, circuit sharers could enable homeowners to serve their
electrification needs with their current electric panel or lower the upgrade needs. For example, enable a customer
to electrify with their current 200A panel, without having to upgrade it to 400A or enable to upgrade their 100A
panel to a 200A panel and not having to increase it further. City’s guide for such techniques is linked here:
www.paloalto.gov/electrifymyhome#ElectricGuide
City’s customer programs publicize these tools and have anecdotal examples of how customers have used
efficient electrification technologies to electrify their homes without upgrading their 200A panel to 400A.
Utilizing such techniques will enable grid mod projects to be methodically implemented by neighborhood and
minimize the need to do one-off transformer upgrade projects in different neighborhoods.
6 Short-Term Resiliency Valuation
6.1 Valuing Reliability and Resilience
6.1.1 Literature Review
To incorporate the value of reliability and resiliency in the cost-benefit analysis, the consultant team conducted a
literature review of the latest research from authoritative sources, including the National Renewable Energy
Laboratory (NREL), Lawrence Berkeley National Laboratory (LBNL), Pacific Northwest National Laboratory (PNNL),
the North American Electric Reliability Corporation (NERC), and the Energy Systems Integration Group (ESIG). The
insights from this research established definitions for reliability and resilience (as outlined in the background
section of this report), and a corresponding framework with metrics and methodologies to assess the
quantitative and qualitative values of resilience within Palo Alto’s electricity system.
The methods for valuing reliability and resilience in the electric grid are distinguished by the duration and scale
of a power disruption event, with resilience covering long-duration, large-scale impacts beyond 24 hours.
Conversely, reliability measures are associated with short-duration, small-scale impacts below 24 hours. Figure 1
summarizes these distinctions. There are multiple methods for valuing reliability and resilience, but in both
approaches the benefit of reliability and/or resilience is typically conceptualized as the present value of the
avoided costs from disruptive events, and the avoided costs of alternative investments.
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Figure 8. Reliability vs. Resilience
Figure by NREL 20
The costs imposed by power disruption events are numerous, extending from customers to utilities and society.
Figure 111112 provides a summary of these costs and the potential impacts from power interruptions. At the
customer level, there are direct costs to residential and commercial customers, including lost production and any
assets or perishables lost due to power interruption. Utilities bear the costs of lost revenue, damaged energy
infrastructure, the cost of recovery and risk reduction, and potential legal liabilities (Leddy et al. 2023). At a
broader scale, there are indirect costs to the local and regional economy and intangible impacts from increased
health risks and environmental damages linked to power outages. Lastly, there are social consequences from
power disruption due to interdependencies in critical infrastructure and disparate impacts on vulnerable
communities.
20 Measuring and Valuing Resilience: A Literature Review for the Power Sector
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Figure 9. Natural hazards and power interruption cost components
Figure by NREL, adapted from Baik et al. (2021)
The methods for assessing the costs of localized, short-duration (below 24 hours) power interruptions associated
with reliability are generally well understood, whereas the costs from wide-spread, long-duration (above 24
hours) power interruptions associated with resilience are relatively new and have not been studied as completely.
Measuring the costs of short-duration outages for reliability are generalized using customer damage functions
(CDFs), which define outage costs as a function of duration of the outage, customer characteristics, and outage
attributes (time of day, season). CDFs can be determined through bottom-up methods such as stated preference
surveys assessing customer’s willingness to pay, or directly assessing the costs to a business associated with an
outage. The Value of Lost Load (VOLL) is the most common monetary metric that defines a customer’s
willingness to pay for avoiding power disruption, expressed as a $/kWh or $/MWh value.
Measuring the costs of long-duration outages build on the direct costs captured by CDFs and include the
indirect costs of outages associated with spillover effects to the wider economy. Regional economic models, such
as Input-Output (IO) models or Computer General Equilibrium (CGE), estimate economy-wide impacts and
account for interdependencies between various economic sectors and supply demand relationships. Regional
economic models are sometimes calibrated by stated preference surveys (a hybrid model approach), although
there are limited studies available for long duration outages. There are also methodological concerns about
customers’ ability to accurately assess long-term outages. Implementing economy wide models of power
interruptions is still an emerging research area, and existing studies are often specific to a single event or
location, creating limitations to generalizability.
6.1.2 Distribution of City Outages – reasons, # customers, duration of outages (outage response) -
Reliability
CPAU tracks electric power outages through industry recognized indices. A summary chart of these outage
indices can be found below. Staff is presenting both outage indices with and without the impacts of “major event
days” (MED). For Palo Alto a MED is defined as a 24-hour period that impacts more than 10% of Palo Alto’s
electric customers, irrespective of the cause of impact.
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Table 13. Electric Outage Reliability, FY 2019 through FY 2025
Major Event Days Included Major Event Days Excluded
21 SAIFI22 CAIDI 23 SAIDI SAIFI CAIDI
2019 114.7 0.935 122.7 44.4 0.330 134.6
2020 63.9 0.486 131.4 26.2 0.248 105.6
2021 70.6 0.720 98.1 14.7 0.053 279.9
2022 7.2 0.159 45.4 1.2 0.009 132.8
2023 148.9 1.378 108.0 26.1 0.164 159.6
2024 153.1 0.786 194.7 72.3 0.362 199.7
2025 95.4 0.779 122.5 44.5 0.283 157.4
The above Palo Alto reliability indices are far superior to comparable reliability indices of neighbouring DeAnza
Division in PG&E’s service territory. Palo Alto reliability indices are slightly better compared to the top performing
utilities nationally (top quartile).
The pie chart below separates unplanned power outages occurring between September 2023 through June 2025
by their primary cause. In September 2023 CPAU staff implemented a robust outage tracking tool that provided
improved tracking of outage durations, frequencies, and causes. Over this period, the largest number of
unplanned outages (by count) was due to equipment-related failures (failure, damage, or worn). The next largest
contributor to unplanned outages were trees contacting power lines. Being the leading cause of unplanned
outages, continued equipment failures indicates an aging system that requires additional and/or continued
funding for planned infrastructure replacements. To address equipment failures, the City has committed
significant funding to rebuild the City’s electric system while simultaneously increasing capacity to serve new
electric loads (transportation and building space and water heating). Additionally, CPAU staff are implementing
new operational procedures (staffing, emphasis on customer restoration, etc.) and seeking additional isolation
points (e.g. fuses) to limit the scope of power outages and speed restoration when they do occur.
21System Average Interruption Duration Index (SAIDI) - Measure of the total duration of an interruption for the average customer during a
given time frame. SAIDI = (Sum of Customer Minutes Interrupted) / (Total Customers Served)
22System Average Interruption Frequency Index (SAIFI) - the average number of times a customer will experience an interruption during a
given time frame. SAIFI = (Total Customers Interrupted) / (Total Customers Served)
23Customer Average Interruption Duration Index (CAIDI) - the average time to restore service. CAIDI = (Sum of Customer Minutes
Interrupted) / (Total Customers Interrupted)
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Figure 10. Sustained Outages by Cause - Sept 2023 - June 2025
Based upon recent reliability indices, the Palo Alto community enjoys a relatively high level of distribution system
reliability.
6.2 Approach to Valuing Resiliency in Palo Alto
6.2.1 Model Selection & Parameters
The focus of the resilience valuation in this study is on short-duration power disruptions in the 24-hour range.
The customer programs being evaluated are associated with behind-the-meter customer technologies, which
narrows the resilience valuation to the cost of interruptions for electricity customers. Broader impacts to utility
infrastructure and community-scale impacts are considered qualitatively, while direct customer impacts are
quantified. The consultant team identified and evaluated several existing tools according to these criteria to
measure the direct impacts from short-duration power disruptions, and selected the Interruption Cost Estimate
(ICE) Calculator as the most suitable tool for the analysis. Compared to the other tools, the ICE Calculator offers
the most extensive customization for adapting estimates to community and utility system characteristics in Palo
Alto, while providing separate estimates for different customer types (whereas some tools focus only on facility-
scale estimates). Furthermore, the ICE Calculator is informed by the largest dataset and is being more actively
managed and updated relative to the other tools considered for this study. A summary of the tools identified is
provided below in Table 16.
Table 14: Tools for Short Duration Outage Impacts
Function (CDF)
National Renewable
Energy Laboratory for discrete outage lengths. Based on fixed cost, spoilage cost, and
Interruption Cost
Estimate (ICE)
Lawrence Berkeley
National Laboratory
Estimates interruption costs and/or benefits associated with reliability
improvements for electric reliability planners, utilizing customer
Social Burden
Method
FEMA Benefit-Cost
Analysis
VOR123
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The ICE Calculator is developed by LBNL and relies on a comprehensive meta-analysis of 34 datasets from
surveys fielded by 10 different utility companies from 1989-2012, totalling over 105,000 observations. The
surveys ask representative samples of customers to estimate costs they would experience given a number of
hypothetical outage scenarios with different sets of characteristics (see Sullivan et al. 2018 24 for additional details
on the sampling strategy and survey design).
Responses are aggregated to generate CDFs, which can be applied to calculate customer a weighted average of
interruption costs for industrial, commercial, and residential customers. The results of the model can be
statistically generalized to costs for specific outage durations and customer populations of interest, and the
online interface for the tool allows users to adjust the model parameters for these specific conditions. Table 17
provides a summary of the available model parameters and the inputs used for this study.
Table 15. ICE Calculator Parameters & Inputs
25,783
CPAU Annual Average of Rate Groups Small C&I Customers
Medium/Large C&I
Customers
Reliability Statistics
System Average Interruption Index
Historical Reliability Statistics for FY18-FY23
System Average Interruption Frequency Index
Customer Average Interruption
Duration Index
Annual Usage (MWh)
Residential Consumption for Building End Uses Small C&I
M/L C&I
Median Household Income
Power Interruption Distribution
% Summer
Sept. 2013 thru. June 2023 Historical Outage Data
% Morning
% Afternoon
% Evening
% Night
Industry Percentage
Construction
Customer NAICS Codes Manufacturing
All Other
Backup Generation
24 Estimating Power System Interruption Costs: A Guidebook for Electric Utilities
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6.2.2 Interruption Costs for SFR, MFR, Small Commercial, and Large Commercial Customers
Interruption costs reported by the ICE Calculator for residential and non-residential customers differ in important
ways. Residential costs are based on a survey respondent’s willingness to pay whereas direct cost estimates are
used for commercial and industrial customers. In other words, residential values are reported under the
assumption that much of the “cost” of interruptions is associated the hassle, inconvenience, and personal
disruption of an outage, as opposed to direct out-of-pocket expenses. Commercial and industrial customers
report direct costs associated with their business operations and revenue structure. Due to these differences,
interruption costs for residential customers tend to be more homogenous than business customers, while
business customer costs are more variable and comprise a much larger portion of a utility’s outage costs.
6.2.3 Quantitative & Qualitative Components of Resilience (Direct, Indirect, Societal Metrics)
Using inputs provided by CPAU, the consultant team tailored the ICE Calculator parameters to fit Palo Alto’s
utility characteristics, generating estimates of $/event, $/kW, $/kWh, and total annual costs from outages for
residential and non-residential customer types. The ICE Calculator is based on outage durations up to 16 hours,
and these costs were estimated for Palo Alto by adjusting the ICE Calculator’s SAIDI inputs while holding all other
parameters constant. Estimates were calculated for outages up to 24 hours, assuming the cost per unserved kWh
is constant, and by interpolating missing values that were not calculated with the ICE Calculator. Altogether,
these values generate a customer damage function for residential, small commercial & industrial, and
medium/large commercial & industrial customers in Palo Alto.
To estimate resilience benefits from flexible energy technologies, the consultant team calculated the present
value of avoided outage costs across a 20-year time horizon, using a 3% escalation rate for customer costs and a
5% discount rate. Two separate calculations for each customer type were conducted for a baseline and long-term
resilience scenario:
• The baseline estimate assumes Palo Alto sustains current reliability characteristics, where average
interruption durations reflect the previous 5-year average of 1.66 hours.
• The high estimate assumes a scenario of more frequent extreme weather as well as capacity challenges
induced by grid electrification, increasing the frequency and probability of long-duration outages. Using
NREL’s (2022) Estimated Recurrence Intervals for 12 to 24-hour outages in the Western U.S.,25 the long-
term resilience scenario conservatively assumes a 2-year recurrence interval of 24-hour outages. In Palo
Alto, only three of 156 sustained outages were greater than 24 hours and only 16 of the 156 were
greater than 12 hours during the period from September 2023 through June 2025.
Table 16. Resilience Benefits per Customer (2025$)
Residential $156 $434
Small C&I $17,780 $26,692
M/L C&I $277,187 $966,123
The baseline and high scenarios respectively provide status quo and conservative/low-probability estimates for
direct benefits from avoided power interruptions. The specific magnitude of benefits is differentiated by
customer type and estimated adoption levels for each program. For example, residential batteries (assuming
25 Exceedance Probabilities and Recurrence Intervals for Extended Power Outages in the United States
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typical design for off-grid operation) and V2X bidirectional chargers (assuming design for grid isolation) can
provide backup generation for up to a 24-hour outage, so the direct benefits per customer are the same across
technologies, varying by customer adoption. Commercial solar and battery storage systems provide backup
storage for shorter durations due to larger demand and the general inability of a solar system to fully recharge a
battery within the time needed to maintain commercial operations. The estimated level of adoption for each
program is multiplied by resilience benefits per customer to generate aggregated resilience benefits, which are
incorporated in the quantitative component of the cost-benefit analysis.
From a qualitative perspective, the technologies in this study can confer many of the indirect benefits cited in the
literature review - benefits to the local and regional economy by maintaining business continuity, risk reductions
for CPAU, and broader health and environmental benefits to Palo Alto from the reduced likelihood of future
outages. These qualitative benefits are contingent on the extent to which the technologies can be coordinated
and managed to mitigate power interruptions. Otherwise, these technologies may not support broader grid
reliability and resiliency in the same way that distribution and transmission investments, and may induce
negligible qualitative benefits as a result.
6.2.4 Adjustments, Limitations, and Uncertainty in the ICE Calculator
There are notable limitations and uncertainties associated with the model that should be considered in the
interpretation of ICE Calculator estimates:
• Half of the data in the ICE Calculator’s meta-database are from surveys that are 15 or more years old, so
there may be concerns around the precision of older data.
• Statistical uncertainty is not modelled in the ICE Calculator, so the potential variance of interruption costs
is not quantitatively modelled.
• All of the surveys used in the meta-analysis measure economic costs of a single interruption, not for
additional interruptions. As a result, changes in the costs of interruption if the frequency of interruptions
increase or decrease are not well understood.
• The ICE Calculator only estimates interruptions up to 16 hours, and only 2-3% of survey observations for
all customer classes account for interruptions over 12 hours.
While the survey data may be older, previous updates to the ICE Calculator included an intertemporal analysis,
demonstrating that costs have not changed significantly over the years. Technology trends in the past decade
may also lead to an increase in interruption costs, particularly as home and business life increasingly rely on
electricity reliability for internet connected technologies as well as connecting to data centers and cloud
computing. These costs may rise further due to forecasted increases in electricity demand, extreme weather
events, and greater awareness of resilience challenges, all of which could increase customer’s valuation of
reliability. It is therefore reasonable to anticipate that ICE Calculator estimates provide a lower bound to current
outage costs, and that these estimates will increase in the future.
Given the limitations of survey data available for outages over 12 hours, and the extrapolation method used to
generate estimates up to 24 hours in this study, the upper bounds of resilience benefits should be interpreted
with some caution. Within the ICE Calculator model, the marginal cost ($/kWh) of an outage decreases with
increasing outage durations, suggesting a limit to customer willingness to pay, especially if incremental costs
from an outage are negligible at a certain point in time. Beyond the ICE Calculator model, the nature of impacts
and indirect spillover effects to the broader community change as the duration of power interruptions
approaches 24 hours or more. The quantitative estimates should therefore be considered as conservative lower
bounds, particularly for longer duration power interruptions.
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At the time this portion of the analysis was completed, the ICE Calculator had last been updated in March 2018,
and the outputs provided were in USD 2016$. These values have been adjusted in this study to USD 2025$ using
the GDP Deflator Index. An updated ICE Calculator 2.0 was released in April 2025 and the previous ICE Calculator
was retired. The current estimates from the original ICE Calculator capture the stated intent for this study and are
deemed sufficient. If at any point this analysis is updated for future studies, the results could be updated to
incorporate new estimates from ICE Calculator 2.0.
7 Long-Term Resiliency and Microgrids
This study was not scoped to include a quantitative analysis of long-term resiliency, but as part of this study City
of Palo Alto staff framed the qualitative considerations in considering the value of long-term resiliency and
microgrids to the community. This section represents their work.
7.1 Microgrids Overview
A microgrid is any group of electric generators and electric loads that can operate both as part of the broader
electric grid and independently of it during an electric grid power outage or shortage. It provides both electric
power under normal operating circumstances and acts as a backup generator, and can be valued by comparing it
to the cost of utility provided power plus the cost of traditional backup generation. A microgrid can include both
fossil fuel and renewable generators, but in Palo Alto the most common type of microgrid discussed is a solar
plus battery microgrid. This is the only type that will be discussed in this section.
Staff identified two alternatives to a solar plus battery microgrid in Palo Alto:
1. Utility power plus a diesel backup generator
2. Utility power plus a dual fuel diesel / natural gas generator
Diesel backup generators are generally easier to install from a regulatory compliance standpoint, but their
benefit during a long-term outage is limited to the amount of diesel fuel available. A dual fuel diesel and natural
gas generator, on the other hand, can have a virtually unlimited fuel supply so long as the natural gas supply has
not been damaged, but the permitting for these types of units under Air District regulations can be challenging.
Natural gas systems are less likely to be damaged in a natural disaster than electric systems, but take longer to
restore. If considering natural gas generators, the long-term viability of the natural gas connections serving the
generator must also be considered. If the generator is in a location that would be costly for a gas utility to serve
in a future high electrification scenario, gas system retirements could raise the costs or even make it impossible
to use a dual fuel generator in that location.
Solar and batter microgrids also have a virtually unlimited fuel supply (the sun) that is not subject to interruption
in a natural disaster, but they are limited by the amount of surface area on the site and the available sunlight
varies seasonally and with the weather, so careful planning and evaluation is needed to compare them to fossil
fuel backup generators, which do not have annual variability in their generating capacity.
7.2 Valuing Long-term Resiliency
Long-term resiliency can be challenging to value, both at the individual and societal level. Valuing long-term
resiliency at the societal level requires complex models estimating natural disaster damage, including
macroeconomic models estimating continuing economic effects. It requires assessing vulnerable infrastructure at
a regional level and what systems and infrastructure are needed to mitigate the impacts of an emergency. At an
individual level, valuing long-term resiliency requires assessing personal circumstances and vulnerabilities in a
natural disaster as well as specific vulnerabilities of an individual’s home, livelihood, and other things, people, and
conditions the individual values. Quantitatively estimating individual or societal value of long-term resiliency is
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beyond the scope of this study. However, it is possible to create a framework for making qualitative judgements
of individual and societal resiliency and the resources the community or individual community members are
willing to commit to it.
7.3 Value of Long-term Resiliency Needed for Benefits to Exceed Costs
Some technologies considered in this study can help relieve the impacts of short-term outages. Vehicle to load,
vehicle to home, and standalone batteries can all provide power in these situations, but only when combined
with solar panels can they provide longer-term resiliency for multiple days or even weeks. As noted in Section
2.2.2 (Quantitative Results), residential solar and batteries combined do not have benefits exceeding costs at a
community level (the combination of utility and customer benefits) just based on the utility supply cost savings
(avoided imported energy from utility-scale power plants and avoided resource adequacy requirements)
combined with the benefit of avoiding short-term outages. These utility supply cost savings are passed directly
through to customers through the City’s net energy metering rates and Palo Alto Clean Local Energy Accessible
Now (CLEAN) feed-in tariff program. Only commercial solar and battery benefits exceed costs right now on this
basis, but they will not once the Investment Tax Credit expires.
Having calculated the benefits utility customers can realize due to utility supply cost benefits, and taking into
account the benefit to them of short-term outage protection, we can then calculate how much additional long-
term resiliency value is needed to make benefits exceed costs. This amount is shown in Table 19 for both
commercial and residential solar and battery projects in terms of first year dollars per year.
Table 17. Annual Resiliency Value Needed for Breakeven Costs
Residential Solar +
Battery (with ITC)
-$131,269 $10,533 $105
Residential Solar +
Battery (without ITC)
-$1,293,061 $103,759 $1,038
Commercial Solar +
Battery (with ITC) benefit without long-term benefit without long-term
This table (the rightmost column) essentially estimates the amount of money a residential or commercial
customer would hypothetically be willing to pay each year for extra long-term resiliency. If they value long-term
resiliency as much as or higher than this amount of money, a solar and battery project would have benefits that
exceed costs for them. If benefits exceed costs, the community member would then need to compare the cost of
solar and batteries as a solution to the cost of fossil fuel backup generation, and also consider the qualitative
differences between fossil fuel backup generation and solar and batteries, as described above in 7.1.
7.4 Community-scale Long-term Resiliency Planning
Currently the City plans backup power needs for City facilities, especially public-facing facilities that have a role in
City emergency response. But it does not have the staff capacity allocated to facilitate community wide backup
power planning to provide long term resiliency at private facilities, even if those facilities may be helpful during
an emergency (e.g. grocery stores). Some private facilities (e.g. hospitals) are subject to State regulations that
drive backup power planning. At the individual readiness level, community members who value resiliency highly
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enough install their own backup power systems can do so, as described above. But a similar analysis can be done
at the community level to determine the amount of value a particular City or private facility needs to have during
an emergency to make it worthwhile to spend additional community resources to make a solar and battery
project at that site worthwhile.
Staff performed this analysis for a hypothetical solar and battery microgrid at the Palo Alto Airport providing
resiliency services to the Airport and Regional Water Quality Control Plant (RWQCP). The RWQCP has diesel
backup generators, but these are limited to a few days of fuel, so a longer-duration backup solution would be
beneficial. Preliminary results of this study were summarized for the City’s Utilities Advisory Commission at its
July 9, 2025 meeting.26 The analysis found that a solar and battery microgrid at the Palo Alto Airport required
$2.5 to $3.7 million per year 27 in additional resiliency value 28 for the project to be economical. In other words, the
electricity supplied by a 6.6MW/26.4 MWh Solar + BESS microgrid at the airport is more expensive than the City
importing corresponding amounts of electricity from the California electrical grid (City’s avoided cost of
electricity supply). The costs were also analyzed comparing the airport microgrid to electricity supplied to the
City from a large Solar + BESS project located in the Central Valley with power delivered via transmission lines to
Palo Alto - this analysis found the airport microgrid to be $3.1 million per year more expensive.
The City intends to compare the cost of this approach to the cost of backup power to other options such as a
dual fuel generator or increasing diesel fuel storage, taking into consideration the qualitative differences
between the different approaches as described in 7.1.
This analysis was not replicated for other sites as part of this study but could be performed in the future if
directed, either on a site-by-site basis or systematically. To do a systematic analysis of public- and privately-
owned facilities would require staff and consultant resources with skills in disaster planning to work with
stakeholders and the Council to identify sites to be analyzed and to perform a planning level analysis to
determine the best solution for each site and the cost of implementation.
7.5 Community-scale Microgrids
Occasionally a community member has suggested integrating multiple sites into a single neighborhood-scale or
community-scale microgrid. City staff considered this as part of the airport microgrid study cited above in 7.7.
City staff identified several insights about community-scale microgrids as part of that study. Most importantly, it
became apparent that a community-scale microgrid only provides additional value when all of the following
conditions apply:
• A site has a critical electricity use that requires long duration backup power capability
26 Utilities Advisory Commission, July 9, 2025, Status Update on Studies Related to the Electric Utility’s Reliability and Resiliency Strategic Plan
(RRSP) Strategies 4 and 5 and Request for Feedback on Draft Proposals for Implementation. Attachment D, https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=61774
27 The range is dependent on whether the capital cost of the project was amortized over a 15 or 25-year period.
28 The WQCP diesel generation units have diesel fuel to meet the plant load for three days. The large microgrid could provide three additional
days of back-up power during the winter months (when solar generation is the least) and 45 additional days of back-up power during the
summer period (when solar generation is high). However, the incremental backup duration could be as low as 1 day if the battery is depleted
when the initial outage occurs.
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• Lack of availability of diesel fuel in an extended emergency is a concern
• The site may not be prioritized by emergency planners for limited diesel supplies (e.g. a high priority use
like a hospital trauma center may have fewer concerns about diesel availability than a medium priority
use)
• The critical electricity use cannot be served adequately just using solar on the property
• Site is near other parcels with roof and/or land space for solar panels in excess of that needed for any
critical electric uses on those parcels
• Site owner is able and willing to pay for additional solar + storage and the physical
• Infrastructure to connect across parcels to supplement diesel backup is available
Dual-fuel backup generation (natural gas + diesel) should be considered as an alternative to cross-property solar
+ storage microgrids when addressing diesel fuel concerns.
City staff intends to use these criteria going forward when evaluating the utility of a community-scale microgrid.
In staff’s estimation, the Airport and RWQCP combined meet these criteria.
7.6 Incentives for Individual or Community-Scale Microgrids
The City does not currently provide incentives for individual community members to put in solar and battery
microgrids or for those microgrids to be added to City or privately-owned facilities that would be valuable to
have powered during an emergency. As described in 7.2, the City’s electric utility passes through the utility value
of solar and batteries to customers through its net energy metering and feed-in tariff programs, and if utility
customers value long-term resiliency highly enough, they will proceed with a project. If the Council wanted to
change that policy and add subsidies for local solar and battery projects to promote local resiliency, a detailed
cost of service study would be needed to determine whether these projects can legally be funded by ratepayers.
Otherwise, non-ratepayer funds would be required to comply with California constitutional limits on utility
ratemaking. Council would also need to determine who would be eligible to receive those subsidies. Some
possibilities include:
• Incentives available to everybody. Incentives at this scale would require a funding source beyond existing
special revenues typically used for renewable energy incentives projects. This would require increased
taxes or utility rates, either of which would raise household expenses, essentially forcing all community
members to value resiliency identically.
• A “first come, first served” program with limited funding. This type of program could be implemented
using special utility revenues that can be used for renewable energy incentives, such as Public Benefits
and Electric Cap and Trade, though any use of these funds for that purpose would need to be balanced
against their use for energy efficiency and electrification programs.
• Incentives for critical community facilities in an emergency (e.g. grocery stores, City facilities). Depending
on the number of facilities receiving incentives, this could potentially be funded by special utility
revenues as described above.
• Incentives for income-qualified community members. The scale of the program would need to be
defined to determine whether additional funding sources would be needed.
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Appendix A – Flexible Energy Technologies
Batteries
Batteries, also referred to as battery energy storage systems (BESS), provide backup power in the case of outages
and enable load shaving during peak hours to alleviate grid stress and reduce energy bills. Batteries can provide
extended off-grid operation when paired with a solar system, and depending on-size, can support activities for
hours to days when deployed alone. This technology is generally accessible and well-regulated to optimize on-
site safety – products range from portable options to utility-scale and can often be purchased on a retail basis
(although larger batteries require consultation with the selected manufacturer).
Application and Operational Considerations
Several battery options exist with varying purchase prices. Operations and maintenance costs for stationary
batteries are generally consistent across applications at around $50 to $100 per kWh over 10 years.29
Portable Batteries
Portable batteries require no permanent infrastructure, reducing maintenance costs. Portable batteries can
support small loads, like laptops and microwaves – the amount of power or the available support duration is
dependent on the type of appliance. For example, the Goal Zero YETI 500X can charge a 12Wh smart phone 42
times and support a 25W portable fridge for 20 hours. The products listed in Table 20can be charged from
several sources, including solar, wall outlets, and vehicles.30 In addition to their adaptable charging capabilities,
most of the products can adapt to demand via their respective smart phone applications, enabling owners to
select when battery charging and discharging occurs.31 These products are shown as examples, not
recommendations, neither the City nor its consultants have reviewed or vetted these products..
Portable batteries generally last between 3 to 10 years, depending on what they are used to power and how
often.32 The products listed in Table 20have warranties between 2 to 5 years although most can be extended up
to five years. The technology is likely better suited to support niche resilience needs (e.g. medical devices).
29 BESS Costs Analysis: Understanding the True Costs of Battery Energy Storage Systems
30 Goal Zero Yeti 500X Portable Power Station | New Lower Price!
31 Download EcoFlow App for Portable Power Stations | EcoFlow US
32 How Long Does a Portable Power Station Battery Last?
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Table 18. Portable Batteries - Residential Options
Product
E600LFP
YETI 500X
River 2 Pro
YETI 1500x
E3600LFP
YETI 6000x
DELTA Pro 3 Yes Yes Yes Yes Yes Yes Yes
Capacity 0.614 kWh 0.497 kWh 1.8 kWh 1.615 kWh 15.36kWh 6.071 kWh 4 to 48 kWh
(expandable)
Size (LxWxD)
(in)11.7x7.8x8.5 7.5x11.25x5.8 10.6x10.2x8.9 15.3x10.2x10.4 17.5x12.1x13.8 15.3x10.1x17 27.3x13.4x16.1
Retail Price ($)
Stationary Batteries
Table 19. Stationary Batteries - Residential Options
Product
Encharge 10 LG
Resu Prime 16H Tesla
Powerwall
Solar Charging
Capacity 10 kWh 16 kWh 13.5 kWh
Size (LxWxD)
(in) 26.4x42.1x12.6 19.8x42.8x11.6 43.5x24x7.6
Retail Price ($)
Residential customers requiring more energy capacity may seek to purchase an on-site stationary battery – these
can vary in size and are often modular, allowing for flexible storage options. Stationary batteries with larger
capacities may support whole home energy consumption and enable full off-grid operation when paired with
solar. Newer batteries can be controlled via mobile application or can be paired with a home energy
management system, enabling customers to monitor and control their energy consumption.33 This functionality
is particularly useful in the case of an outage, when customers may prefer to prioritize more critical loads.
The Tesla Powerwall is a highly rated product on the market today – the Tesla website allows customers to size
and model product benefits prior to completing their purchase. This exercise was completed for a home in Palo
33 Encharge-10-DS-EN-US.pdf
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Alto with an estimated roof area of 2,000 square feet and an average monthly energy consumption of 504 kWh.34
With one Powerwall 3 and a 4.10 kW solar array, customers fitting this profile will have seven or more days of
backup power in the summer and 1.5 days of backup power in the winter. This scenario assumes that most
customers will reduce their energy use to 72% of their overall consumption during an outage.35 A Powerwall
paired with a Tesla solar product cost approximately $23,000 with no incentives and $16,000 if the customer is
eligible to receive federal IRA credits. This example is provided for context only, and the City and its consultants
have not reviewed or endorsed this or any other battery products. Other products may have higher or lower
pricing.
The battery examples listed in Table 21all have 10-year warranties and will last anywhere from 5 to 15 years,
where useful life depends on customer charging and discharging patterns.36
Stationary batteries can provide more comprehensive resilience opportunities than portable batteries and act as
demand management tools to reduce utility bills.
Commercial Batteries
Table 20. Stationary Batteries - Commercial Options
Product
EcoStructure Microgrid Flex
eStorage Flex
xStorage Gen2 MG Series Yes Yes Yes Yes 246 – 1720 kWh 550 – 1210 kWh 279 – 1117 kWh 1376 – 8256 kWh
7 ft BESS: 82.8x50.4x92.4 20 ft BESS: 238.8x96x114 Flex 20-550: 236.2x96.5x114.8 Flex 40-1210: 472.4x96.5x114.8 53.5x58.5x68.9 126 x 59 x 108
Retail Price ($)
Stationary commercial batteries serve the same purposes as stationary residential batteries but are defined by
their larger capacities to serve larger commercial loads. Although some customers may be considered
commercial, their business operations may only require batteries with smaller capacities as represented in Table
21. The products listed in Table 22are best suited for larger-scale applications, those with energy intensive end-
uses, or those that would severely suffer in the case of an outage, like data centers.
Cost information for these products is not publicly available since they require consultation with the
manufacturer or supplier prior to purchase. However, a 2022 report published by NREL estimates that a 1,200-
kWh system, including “battery packs, containers, thermal management system, and fire suppression system”
34 Energy Consumption Data from CPAU
35 Powerwall Direct | Tesla
36 How Long Do Solar Batteries Last? | Solar Battery Life | Sunrun
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costs about $393 per kWh.37 Market research indicates that larger batteries cost less on a per kWh than smaller
batteries.
Commercial batteries have expected lifespans of 10 to 20 years 38, although this is heavily dependent on their
storage conditions and applications. Warranties vary based on battery size and configuration but typically sit at
around 10 years.
Adoption and Market Maturity
Portable batteries are generally more accessible than stationary batteries – they are affordable in comparison and
do not have space limitations, enabling their use in multifamily buildings that may not be suitable for stationary
battery implementation. Residential stationary batteries are becoming more readily accessible, with the Tesla
Powerwall leading in marketability. Commercial battery options require contacting the manufacturer to discuss
production options and purchase price.
Figure 11. Changes in Projected Component Costs for Residential BESS (also used for commercial systems)
Source: Commercial Battery Storage | Electricity | 2024 | ATB | NREL
The cost reduction potentials generated in 2019 and featured in Figure 131314 were applied to the latest battery
cost projections published by NREL in 2024. Battery costs are projected to decrease drastically year-over-year,
increasing accessibility for customers even as installation and other soft costs are slower to decrease.
Vehicle-to-Home
Summary
Vehicle-to-Everything (V2X) technology allows EVs to power other loads in addition to enabling the vehicle
charging process. V2X encompasses the following technology categories:
• Vehicle-to-Load (V2L): Allows EVs to supply power to smaller loads, like laptops, and requires little
additional infrastructure to support. Most EVs currently on the market support this capability.
• Vehicle-to-Home (V2H): Allows EVs to supply power to homes and vice versa. More EV models are
beginning to enable this capability. Additional infrastructure is required to support this capability.
37 U.S. Solar Photovoltaic System and Energy Storage Cost Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022
38 What’s The Life Expectancy of Battery Storage Systems? | Eco Affect
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• Vehicle-to-Grid (V2G): Requires additional infrastructure that can communicate between the vehicle and
the utility, often with the purpose of providing demand response services to the utility.
V2H and V2G technology enhances energy resilience during outages or peak demand periods. With this
emerging technology, homeowners can use their existing EVs as a two-in-one product – harnessing their
capabilities for both transportation and home energy storage. Although the concept itself is efficient, utilizing an
EV as energy storage requires the integration of on-site bidirectional chargers and a home energy management
(HEM) system. The HEM should allow users to monitor vehicle charge and depending on the system, select
where and when energy will flow from the vehicle battery to end-uses.
V2L technology exists as another resiliency solution enabled by EV technology – however, V2L only enables the
use of EV power for one appliance or device at a time and limits the loads that can be served 39. Most EVs
currently on the market have V2L capabilities.
Application and Operational Considerations
Electric vehicles and associated bidirectional charging infrastructure should function properly for 12 to 15 years –
however, consistently using the vehicle battery for peak load shaving will impact battery degradation and
shorten its useful life.40 All automakers offer at least an eight-year warranty – amounting to approximately
100,000 miles on batteries.41 As more V2H technology emerges, product useful life will likely increase to allow for
more functionality across transportation and energy storage.
To benefit from their bidirectional charging capable vehicles, users simply need to plug their specialty chargers
into their EVs and control energy dispersion via an integrated home energy management system.
Vehicle battery back-up duration is dependent on which end uses customers want to prioritize. Based on a study
completed by the Schultz Fellows for CPAU in 2021, a fully charged vehicle with a capacity of 60 kWh should be
able to support the average Palo Alto home for 3 to 4 days. Ford claims that the Ford F-150 Lightning standard
range can power a home for 2 days and 3 days with extended range.42 Implementing V2H technology is most
beneficial during outage events rather than for day-to-day peak load shaving – this is especially true without the
application of TOU rates that can incentivize customers to use their technology and provide reliability benefits to
the grid during peak demand hours. In terms of providing reliability at the grid distribution level, V2H and V2G
technology offers limited opportunity if sparsely employed rather than consistently implemented in regions
where grid stress is most prevalent.
V2H technology is most used amongst residential utility customers but may expand to commercial and industrial
applications as larger vehicles electrify and pilot projects provide proof of concept. PG&E is taking the lead on
incentivizing V2H and V2G technology by sponsoring a program that provides funding for customers to
purchase EVs and bidirectional charging technologies. The program currently offers incentives to three customer
types: residential, commercial, and customers currently participating in a microgrid plan. As an example,
39 Bidirectional Charging EVs: V2G, V2H, And V2L Explained
40 Vehicle-to-Home (V2H): Everything You Need to Know – iEVPower
41 Electric Car Battery Life: How Long They Last and What to Know
42 What_Can_IBP_Power.pdf
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residential customers may receive $2,500, or $3,000 if income eligible, to purchase a Ford F-150 Lightning (2022
or newer).43
Adoption and Market Maturity
Several vehicles with bidirectional charging capabilities exist on the market today. The following are highly
ranked vehicles that can support multiple home end-uses during a power outage or for demand management
purposes. They are provided as examples only, the City and its consultants has not vetted these products:
• Ford F-150 Lightning Flash
• Nissan Leaf
• Kia EV9
• Mitsubishi Outlander
• Hyundai Ioniq 5
• Volkswagen ID.3 & ID.4
• BM@ i3
• Audi e-tron
• Rivian R1T
• Lucid Air
• RAM 1500 EV
• Chevy Silverado EV
The listed options vary in price as well as capacity, where hybrid options have at least 13 kWh and the more
powerful EVs have over 130 kWh of capacity. However, costs are still relatively elevated when compared to other
EVs as users must purchase the home charging infrastructure that safely enables V2H charging. More vehicles
with V2H capabilities are expected to enter that market in 2025 and 2026 44, which will likely decrease the costs of
both the vehicles and the additional home charging infrastructure.
V2H charging infrastructure is currently scarcer than the typical EV charger, with less regulations than regular
batteries and EV chargers.45 V2H charging infrastructure is also more complex than regular chargers since a
home management/integration system is required to manage the flow of electricity to or from the vehicle. The
following are examples of available bidirectional infrastructure:
• GM Energy V2H Bundle 46: Includes the GM Energy PowerShift Charger and GM Energy V2H
Enablement Kit. The Enablement Kit is composed of a Home Hub to control energy flow to and from the
EV, an inverter, and a Dark Start Battery to initiate the charging process. The Bundle costs $7,300 and is
compatible with GM vehicles that support bidirectional charging.
• Ford Charge Station Pro 47: Bidirectional charger compatible with the Ford F-150 Lightning – Ford sells
the charger ($1,310) exclusively and recommends purchasing the required home integration system from
Sunrun (cost not publicly available, must request quote).
43 Vehicle to Everything (V2X) Pilot Programs
44 Everything You Need to Know About Bidirectional Charging and the EVs That Support It - CNET
45 Bidirectional EV Chargers Review — Clean Energy Reviews
46 GM Energy V2H Bundle | Comprehensive Home Energy Solutions
47 Ford Charge Station Pro | Chargers.Ford.com
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Generators
Summary
Generators are currently the most common backup power generation solution, deployed for both residential and
commercial applications. If large enough, generators can support end uses for weeks at a time – however, they
require a steady fuel supply which may not be accessible in the case of an extended outage. For example, natural
gas-fuelled generators are less reliable during severe earthquakes where gas lines have been damaged.
Generators, although reliable and highly available in the market, are not considered to be at the forefront of
energy storage due to their dependency on fuel (which may be in short supply during a major regional disaster
event) and the associated fugitive emissions.
Application and Operational Considerations
Fuel-powered generators range from gasoline to diesel-powered, where most residential generators can
consume either propane or natural gas, and commercial generators offer more variety in diesel-powered
products. Fuel-powered generators release fugitive emissions and air pollutants during the combustion process
(during which energy is generated). 48 Due to this harmful release of emissions and the need to refuel,
sometimes manually, generators are not often considered ideal for demand management and are used for
backup power instead.
Table 21. Residential Generators - Product Examples
Product Guardian Wifi Enabled Dual Fuel
Briggs & Stratton Power Protect 12000-Watt 200-
Champion 14 kW Whole House Home
Kohler 20 kW Home Standby Generator
Size 10 kW 12 kW 14 kW 20 kW
Size (LxWxD)
(in)48x25x29 28x24.5x37.2 49x28x28 48x26x29
Fuel
Retail Price ($)
Warranty
The length and amount of support that a generator can provide during an outage varies depending on size. For
example, Generac estimates that a 0 to 1,500 square-foot home requires 7.5 kW to support essential functions
and 10 kW to support the whole home for about 24 hours while a 2,500+ square-foot home requires 22 kW to
support essential functions and 24 to 25 kW to support all functions. Essential end uses for a smaller home are
determined to be a small percent air conditioning, kitchen, furnace, sump pump, one bathroom and bedroom,
and living areas. This excludes the well pump or water heater, home office, and garage that a larger generator
48 Emissions for Standby Generators
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can support.49 Scaling up generator size for commercial purposes increases support potential – however,
commercial end-uses are likely more energy intensive than those of a large home.
Residential generator inspections and maintenance may cost between $160 and $600 annually, assuming
services are pursued twice a year. Larger generators likely necessitate larger service. Forbes also estimates that a
20-kW natural gas generator costs $90 a day to fuel while “diesel and propane generators of the same size cost
around $200 per day” and “a portable 5kW [gasoline] generator costs around $100 per day to run”.50
Residential generators have a lifespan of about 5 to 10 years while Industrial generators typically last 20 to 25
years – commercial generators can last somewhere in between these ranges. 51, 52
Table 22. Commercial Generators - Product Examples
Product Generac Standby Generator, 48kW
Cummins C30D6 30kW QuietConnect
Kohler 30RCLA 30kW Generator
Caterpillar C175-20 (60 HZ)
48 kW 30 kW 30 kW 4 MW
Size (LxWxD)
(in) 83.4x33.5x46 93.8x34x60.5 74x32.9x46.0 Min.: 261.5x85.4x87.6
Fuel
Retail Price ($)
Warranty
Adoption and Market Maturity
Generators are perhaps to the most accessible backup power generator solution on the market today with
products available for order online and pickup in stores like Home Depot. Although residential products are the
most available, commercial products may also be found at select retailers.
Heat Pump Water Heaters
Summary
Water heaters are a type of thermal energy storage – water is heated and stored for future use. Water heaters
can act as a demand management strategy in that water is heated during off-peak hours and then ready for use
during peak hours, effectively lowering strain on the grid and decreasing utility costs. Heat pump water heaters
49 Generac Guardian WIFI Enabled Dual Fuel (Liquid Propane/Natural Gas) Home Standby Generator 7171 at Lowes.com
50 Average Generator Cost – Forbes Home
51 What Is The Life Expectancy Of Industrial Generators? » Turnkey Industries
52 How Long Does a Generator Last? (+ 3 Maintenance Tips) - Assurance Electrical
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(HPWH) are a type if water heater and per Energy Star, they “extract heat from the surrounding environment and
transfer it into the water inside the tank. They are electrically powered and deliver hot water up to five times
more efficiently than standard electric resistance, gas, and propane water heaters.”53
Application and Operational Considerations
A household or entity that consumes 80 million BTU annually might expect to spend $1,700 in operating costs.54
Table 23. Heat Pump Water Heater - Product Examples
Product Various Models
Various Model
Accelera
Bradford White AeroTherm GS5-45HPC
Type Shared, dedicated circuit Shared circuit 240V Hybrid HPWH 240 Hybrid HPWH 240V HPWH
40, 50, 65, 80 66, 80 58, 80 50, 65, 80 43, 83
Size (HxD) 63 to 7 5x 21 to 55 62 to 69 x 27 61 to 76 x 28 60 to 71 x 22 to 25
Refrigerant Type
First Hour Delivery (gal) 45, 55, 63, 84 76, 93 50, 74 65, 79, 88 69, 121
Uniform Energy Factor 2.8, 3.0, 3.3, 3.5 3.2, 3.0 3.12, 3.61 3.44, 3.64, 3.59
Retail Price ($)
Source: CPAU Electrification Guide
HPWHs are about 70% more efficient than electric resistance or gas water heaters.55 A presentation published by
the National Resources Defence Council (NRDC) indicates that electric water heater consumption peaks cost the
utility between $50 to $100 more per MWh than uncontrolled HPWHs during peak hours – these savings are the
direct result of equipment energy efficiency. Controlled HPWHs, those that have demand management and load
shifting capabilities, almost completely reduce costs per MWh during peak hours.56 HPWHs ultimately provide
substantial savings when compared to electric resistance water heaters, and there are additional savings
provided by adding controls.
Many HPWHs current on the market are compatible with the CTA-2045 protocol or have a built in CTA-2045 port
(also called an EcoPort) – this compatibility enables utilities to communicate directly with the product. Utilities
can tell the HPWH to load up during certain times, shed load, and resume normal operations, all to reduce strain
53 Heat Pump Water Heater Guide
54 Comparing Water Heater Operating Costs - NY Engineers
55 Costs and Helpful Tips for Your Home Electrification Project
56 Load Shifting with ENERGY STAR Connected Water Heaters
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on the grid.57 In addition to a CTA 2045 port, most HPWHs can connect to mobile application that provides
consumption data and allows customers to schedule operating modes and set points – for example, Rheem heat
pump water heaters can connect to the EcoNet mobile app.58
Enabling Technologies
Meter Socket Adapters
Meter socket adapters (MSAs) are devices that are installed between a home or business’s meter socket and
utility meter, allowing additional loads such as solar generation systems to be plugged in safely. Collar placement
enables the utility to meter the energy used by the home or business from on-site generation or electrical
demands, potentially without a more costly panel upgrade. Installing a collar for EV charging is beneficial since a
Level 2 charger might require customer electrical panel upgrades.
ConnectDER is a popular meter socket adpater manufacturer on the market today, selling a product that enables
the integration of battery storage, solar generation, and EV charging to the home with “plug-and-play”
functionality.59 However, ConnectDER products are currently only available in California via Pacific Power, as
utilities must approve the product to enable deployment in their service areas.60 San Diego Gas & Electric
(SDG&E) produces and sells their own Renewable Meter Adapter (RMA), marketed specifically for residential
solar integration.61 SDG&E customers may request this product directly via the utility while customers across
other regions must find and purchase approved products individually. A variation on this product is the Tesla
Back-up switch, the purpose of which is to facilitate disconnect from the grid for off-grid operation.
Figure 12. ConecctDER meter socket adapter
Smart Panels
Smart panels are enhanced circuit breakers – they keep home circuits organized and prevent electrical fires.
However, they differ from traditional electrical panels with the added benefit of energy consumption tracking
57 https://www.energy.ca.gov/sites/default/files/2022-12/JA13_2022_Qualification_Requirement_HPWH_DM_ADA.pdf
58 RCW-HPE-100_0303C_Final.pdf
59 Home - ConnectDER
60 Check Availability - ConnectDER
61 Renewable Meter Adapter | San Diego Gas & Electric
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and control capabilities via a mobile application, ultimately providing resilience services and energy cost savings.
62 Span is a highly ranked full electrical panel that encapsulates these capabilities – however, the panel itself costs
$3,500 where the added cost of installation labour sits at around $6,000.63
Cost saving products in this realm include those typically lumped into the smart panel category that are not
actually full panels. These are sub-panels that can be attached to existing breaker boxes for enhanced control
capabilities. Savant offers modules that can fit into a standard breaker panel and control circuits individually –
this product can also be controlled via mobile application.64 Before installation, Savant modules cost $120-$240
each.65
Figure 13. Span and Savant Product Examples
AutoDR
Automated Demand Response (AutoDR) is the concept of utility communication with relevant customer end-
uses. This communication is facilitated by Open Automated Demand Response (OpenADR), an internet
messaging protocol already employed by several utilities. To participate in automated demand response
programs, customers must have OpenADR certified appliances that can receive communication from the
utility.66 67 Examples of such appliances include the Rheem HPWHs and Siemens building automation systems.
SmartAC
PG&E offers a SmartAC program in which a SmartAC switch is installed on or near the customer’s AC unit – the
switch is activated during events only from May 1st through October 31st. During an event, the customer’s air
conditioner compressor cycles on and off in short increments for no longer than six hours, and often just for two
hours. This technology enables to utility to reduce demand on the grid during hot summer months when
62 Smart Electrical Panels: What You Should Know | EnergySage
63 SPAN® Panel | Lower your energy bill
64 Get Savant - Savant
65 The Best Smart Panels 2024 | EnergySage
66 26824_AutoDR_FAQ_Bv4.pdf
67 Auto-DR Express Control Incentives
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customers use their air conditioning the most. New customers receive a fifty dollar check for participating and
device installation plus AC check-up are free of charge.68
EV Telematics Based Managed EV Charging
A telematics device can be described as a sort of “smart computer” within a vehicle that collects key performance
and driving pattern data – telematics is ultimately the integration of this device with data processing and
management capabilities.69 The data collected by the device, a series of internal sensors, is transmitted to a
centralized system which is typically a cloud-based platform. Using telematics can optimize EV charging by
informing when the battery needs to be charged and aligning charging and discharging times with TOU rate
structures.7071
68 SmartAC™
69 What is Electric Vehicle Telematics? What You Need to Know
70 Telematics and EV Fleet Management [Report] – Ampcontrol
71 Set it and Forget it: The Future of EV Charging | SEPA
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Appendix B – Customer Program Precedents
To further tailor the results of the program precedent research to the city of Palo Alto, the research team
dedicated additional time to look for offerings within the state of California, paying close attention to small
POUs. The California research included offerings identified through web-based searches for the priority
technologies and detailed review of utility websites for a subset of utilities. Detailed research was completed for
100% of California IOUs and 21% of California POUs, Rural Electric Co-ops and Community Choice Aggregators
(CCAs). The California exclusive results are summarized in the following table.
Table 24. California Program Inventory Summary
Pr
o
g
r
a
m
s
While the California analysis still demonstrated many battery offerings, resilience hub offerings and meter socket
adapter policies held a significant share of the documented offerings. Alternatively, the quantity of thermal
storage program offerings were found to be less prevalent in the state. This however is not indicative of the
customers reached by these offerings, as the Self Generation Incentive Program (SGIP) is implemented by four
large IOU’s and serves a large volume of customers every year.
Table 26 also breaks down the resilience programs found in California by utility type. This breakdown illustrates
where POUs, CCAs and IOUs are dedicating their resources within each technology group. While no dramatic
variations were identified, it was found that programs supporting Microgrids were exclusively supported by IOUs,
which are predominantly to support communities impacted by outages, public safety power shutoffs, and other
natural hazard events driven by climate change. This is likely due to the large financial investment required to
support microgrid projects. IOUs were also the only utilities with programs providing incentives for generators.
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CCAs lead the group for offerings supporting solar and storage and Managed EV Charging. Notably, no IOUs
were identified with a Managed EV charging offering.
While POUs, like the City of Palo Alto, appear to be prioritizing Battery programs, there is no strong trend
towards any other technology group. The information may indicate that POUs are experimenting with a variety
of resilience technologies within their portfolios. To further illustrate the activity of utilities and CCAs similar to
CPAU, the research team plotted existing programs among a subset of POUs (represented in blue) and CCAs
(represented in green) that the CPAU team identified as “peers”. The results of this exercise are shown in Table 27.
Table 25. CPAU Peers Grid
DR
)
Roseville Utilities
Redding Electric Utility
Silicon Valley Power ✔ ✔ ✔
Alameda Municipal Power ✔
Turlock Irrigation District
Burbank Water and Power ✔ ✔
Pasadena Water and
Power
Anaheim Public Utilities ✔ ✔
Riverside Public Utilitie
Sacramento Municipal
Utility District
✔ ✔ ✔ ✔ ✔
Los Angeles Department
of Water and Power
✔ ✔ ✔ ✔
Silicon Valley Clean Energy ✔ ✔ ✔ ✔
Peninsula Clean Energy ✔ ✔
Ava Community Energy ✔ ✔
Sonoma Clean Power ✔ ✔ ✔
Marin Clean Energy ✔ ✔ ✔ ✔
Central Coast Community
Energy
✔
The precedent research results informed the following program designs:
Battery
The proposed battery program design includes the following three components that can be combined or
implemented independently.
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1. The first component is a residential battery incentive, where participants are paid an upfront
$/kWh incentive for enrolling a battery in the program.
2. The second program design component is a residential solar and storage no-interest leasing
option. There are two recommended approaches to implementing the leasing model: (1)
partnering with a third party to facilitate the system sale and leasing agreement or implementing
a feed-in-tariff model where the CPAU pays participant the avoided supply cost for energy and
the customer pays a predetermined Power Purchase Agreement (PPA) rate.
3. The third program design component is a commercial battery incentive with the same structure
as the residential incentive, but with different $/kWh incentive rates.
For all program design components, customers will be required to set a specified number of discharge events
per year, so that the CPAU receives an energy arbitrage benefit. To ensure that CPAU is maximizing supply cost
benefits, enrolled batteries cannot only be used for backup power. This program can also be used to increase
participation in a DR program by requiring that participants also enroll the battery in the DR program to receive
the rebate.
Elements of this program design are well demonstrated among existing utility program portfolios, listed below.
• Silicon Valley Power, another California POU, has a residential battery incentive program that
exists within their energy efficiency rebate portfolio.72
• The CalChoice Power Choice program provides a free solar and storage installation to
participating customers, with the agreement that the customer will then purchase the energy
produced by the system. 73
• Green Mountain Power administers a battery program that includes a leasing option where the
utility leases the system to the customer for $55/month for 10 years.74
• The Los Angelos Department of Water and Power (LADWP) has a FiT+ Pilot program that
employs a Feed-in Tariff model to promote distributed solar installations.75
If cost-justified or if non-ratepayer funds are available, this program can be designed with an equity component
by providing higher $/kWh incentive rates for low-income customers. In addition, the leasing option reduces the
barriers to entry for low-income customers, because of the eliminated or reduced capital investment. The
program design could be modified to only offer the leasing option to customers that meet certain income
criteria or reduce the monthly payments for income qualified customers to further expand the equity impact.
This program design could be launched as an independent resilience offering or could be tied into existing
program frameworks. The standard upfront incentive component could easily be integrated within the City of
Palo Alto’s Electrification Rebate Hub.
Demand Response
72 Rebates | Silicon Valley Power
73 Energy Programs - California Choice Energy Authority
74 Home Energy Storage - Green Mountain Power
75 Feed-in Tariff Plus (FiT+) Pilot Program | Los Angeles Department of Water and Power
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The proposed DR program includes residential and commercial battery components that could be combined or
implemented separately. There are two proposed options for how the battery DR program could be structured.
1. The first option includes providing a $/kWh incentive for each kWh discharged to the grid
during peak events.
2. The second option includes a monthly flat rate bill credit for participation in peak events.
Demand response is well demonstrated in California and across the country. Many DR programs enroll other
devices like smart thermostats to curb demand during peak events. Battery centered DR programs are less
common, but still well demonstrated. The program inventory includes 12 different battery DR programs with
similar designs to what is proposed. A subset are listed below.
• The My Energy Optimizer Partner+ program implemented by Sacramento Municipal Utility
District (SMUD) provides a one-time incentive for the enrollment of up to three batteries, in
addition to an ongoing quarterly incentive. 76 In return, participants allow SMUD to optimize
battery operation by discharging enrolled batteries during peak times.
• Marin Clean Energy (MCE) implements an Energy Storage for Facilities program that provides
$/kWh performance payments and monthly bill credits to enrolled customers who allow MCE to
automatically shift facility demand from the grid to their energy storage system.77
• The City of Anaheim offers a Battery Storage Rebate for customers that agree to enroll in their
broader demand response program and TOU rate structure for at least twelve months.78
Demand response programs are typically launched as independent offerings due to their complex design and
need for ongoing engagement and incentive payments. However, the battery DR program could be integrated
within a broader DR offering that includes smart thermostats, compatible EV chargers, and other technologies.
V2X
The proposed Vehicle to Home and Grid (V2X) program includes both residential and commercial components
that could be combined or implemented separately. There are two proposed options for the implementation
structure of the program, similar to the options proposed for the DR program.
1. The first option is a performance-based incentive payout where customers will receive a $/kWh
incentive for every kWh discharged during peak events.
2. The second option is a monthly flat rate bill credit for participation.
Both options would be combined with an upfront incentive to offset the incremental cost of the bidirectional
charger.
V2X programs are not well demonstrated, with only a few existing in today’s market. The V2X programs
identified in the program inventory were almost all pilot scale programs. Two examples of V2X pilots with similar
design structure are listed below.
76 Battery storage for homeowners
77 Energy Storage for Your Business or Facility
78 Battery Storage | Anaheim, CA - Official Website
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• The Vehicle-to-Everything (V2X) pilot run by PG&E includes incentives for commercial and
residential customers, with higher incentive rates for customers in DAC. Incentives include a one-
time incentive for the purchase of a bi-directional charger, early adopter incentives, a backup
power testing incentive (recurring), an interconnection incentive and several end of pilot
incentives.79
• The Portland General Electric (PGE) Smart Grid Test Bed pilot includes a collection of pilot
programs including a V2X demonstration.80 The V2X demonstration provides a upfront incentive
for a bi-directional charger as well as a monthly bill credit for participation.
In addition, two programs were identified through article source links, but could not be found on utility websites,
indicating that they may have been cancelled or never developed into a full-scale program. Similarly, information
on the PG&E Vehicle to Everything pilot page seems to indicate that there has been very little engagement in the
program, with most of the budgeted incentives still available.
If cost-justified or if non-ratepayer funds are available, the proposed program design can be modified to include
an equity component by providing higher up-front incentive rates for income qualified customers. Similar
incentive structures are used by other V2X pilots in the market, providing higher bidirectional charger incentives
for customers located in DACs or that meet income qualifications.
Commercial Thermal Energy Storage
Commercial thermal energy storage programs aim to reduce energy use during peak hours by leveraging stored
thermal energy within a phase change material to be used at a later time. Typically, the phase change material is
charged during off-peak energy price hours and discharged during peak energy price hours, thus allowing a
customer to arbitrage the time-of-use differential for on-bill savings. The phase change material is typically
installed in-line with the supply duct system of an HVAC system and charged from the existing compressor.
During a cooling demand within the peak energy price window, the phase change material discharges the stored
cooling load, thus alleviating compressor demand to meet the system cooling load without the need for
mechanical cooling. The program design includes an upfront incentive based on the size of enrolled equipment.
Customers will receive a set $/kW of demand saved.
This program design is very similar to a commercial thermal energy storage incentive available at the City of
Burbank 81. The City of Burbank Program provides a $/kW incentive for enrolled commercial air conditioning
equipment. Commercial and residential thermal energy storage programs exist across the country but are still
relatively uncommon compared to traditional energy efficiency program offerings. This technology can be
combined with battery offerings and marketed as an energy storage program such as the Self Generation
Incentive Program (SGIP) offered by PG&E, SCE, SoCalGas, and SDG&E 82.
Resilience Hub and Microgrid
79 Vehicle to Everything (V2X) Pilot Programs
80 Smart Grid Test Bed | PGE
81 City of Burbank Business Rebates
82 Participating in Self-Generation Incentive Program (SGIP)
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Programs supporting the design and development of resilience hubs and microgrids are present across the US,
particularly in California. Most resilience hub programs use general language outlining the use case and rational
hubs for resilience hubs, typically referencing extreme weather events.
A program design may include competitive grant funding, allocated by the utility, for projects related to
resilience hubs and microgrids. Projects may include feasibility studies, resilience hub construction or microgrid
construction. An additional program design may include utility led project management and execution of a
resilience hub or microgrid project. A third program design option may be prescriptive financial support from the
utility for specific activities related to the development of resilience hubs or microgrids, such as state/federal
grant application development or interconnection expenses.
These types of programs are fairly well demonstrated in California and include a unique equity opportunity.
Projects can be prioritized in DACs or communities with a higher concentration of low-income residents. This
ensures that the microgrid or resilience hub is most likely to benefit vulnerable populations. This type of program
or project is also accessible to renters who may otherwise be unable to access prescriptive resilience incentives.
Enabling Technologies
Programs supporting individual enabling technologies such as meter socket adapters, smart panels, generators,
socket splitters, energy management devices or EV meter adapters are well situated to integrate within existing
offerings. One or several of the listed enabling technologies could be incentivized, along with electrification
measures or other energy efficiency measures to reduce administrative costs.
Programs providing incentives for the listed enabling technologies are present to a varying degree within the US.
For example, several programs exist that provide incentives for socket splitters or energy management devices
but are most often paired with electrification programs. While utilities are increasingly releasing policies or
guidance around meter socket adapters, none were found that provide a capital incentive for the installation of
the technology. A resilience focused incentive program could have an equity consideration by providing higher
incentive rates for income qualified customers.
Managed EV Charging
A residential managed EV charging program provides incentives for participants that program their EVs to charge
during off-peak hours. Programs are typically supported by an app that customers download that allows for
charging scheduling. Participants are paid incentives for enrollment and receive a monthly bill credit for
participation. Some designs may also provide an incentive for a compatible EV charger.
Managed EV charging programs appear to be gaining popularity among California utilities, and also with many
CCAs, and are being implemented outside of the state as well. Nearly all managed EV charging programs
included in the program inventory leverage the use of an app. This program design is most effective when paired
with EV-TOU rates to further incentivize customers to shift charging times.
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Appendix C – Supply Cost Valuation Assumptions
Battery Energy Storage System (BESS)
Residential Standalone BESS
Variable Assumption Explanation
Quantity of Installations 100
Nominal BESS Capacity (kWh) 13.2
BESS Round-trip Efficiency 90% the energy put into the system for charging. Lithium-ion batteries have high round-trip efficiencies, often exceeding
BESS Discharge Duration (hrs) 4
BESS Discharge Start Time 4PM
BESS Charge Start Time 9AM
BESS Depth of Battery Reserve 25% varies by technology, with lithium-ion batteries capable of handling discharges up to 80%. The tool assumes a
20
$1,277 The assumption aligns with the average installation cost from Tesla website before incentives and tax credits.
Program Administration Costs $300,000
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Residential BESS Coupled with Solar PV (BESS Charged from Grid)
Variable Assumption Explanation
Quantity of Installations 100
8.1
0.5%
$2.70
Nominal BESS Capacity (kWh) 13.2
BESS Round-trip Efficiency 90%
4
BESS Discharge Start Time 4PM
BESS Charge Start Time 9AM
BESS Depth of Battery Reserve 25% varies by technology, but lithium-ion batteries are capable of handling discharges up to 80%. The tool assumes a
20
Program Administration Costs $300,000
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Residential BESS Coupled with Solar PV (BESS Charged from Excess Solar PV)
Variable Assumption Explanation
Quantity of Installations 100
8.1
0.5%
$2.70
Nominal BESS Capacity (kWh) 13.2
BESS Round-trip Efficiency 90% the energy put into the system for charging. Lithium-ion batteries have high round-trip efficiencies, often exceeding
BESS Discharge Duration (hrs) 4
BESS Discharge Start Time 4PM
BESS Charge Start Time 10AM
BESS Depth of Battery Reserve 25% varies by technology, with lithium-ion batteries capable of handling discharges up to 80%. The tool assumes a
20
Program Administration Costs $300,000
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Non-Residential Standalone BESS
Variable Assumption Explanation
Quantity of Installations 35
Nominal BESS Capacity (kWh) 200 weighted average peak demand is estimated as 49.07 kW. Therefore, a four-hour discharge battery would be, on
BESS Round-trip Efficiency 90% the energy put into the system for charging. Lithium-ion batteries have high round-trip efficiencies, often exceeding
BESS Discharge Duration (hrs) 4
BESS Discharge Start Time 4PM
BESS Charge Start Time 12AM
BESS Depth of Battery Reserve 25% varies by technology, with lithium-ion batteries capable of handling discharges up to 80%. The tool assumes a
20
$1,011 The assumption aligns with average installation cost from a contractor source before incentives and tax credits.
Available (% of Total System 30% The Federal government offers an Investment Tax Credit (ITC) for commercial BESS at 30% of the system's cost. The
credit is available for systems placed in service after December 31, 2021, and before January 1, 2033.
Program Administration Costs $300,000
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Non-Residential BESS Coupled with Solar PV (BESS Charged from Grid)
Variable Assumption Explanation
Quantity of Installations 35 The population of non-residential accounts is 3,783. An installation of 35 units represents 0.93% of the total population
Nominal Solar PV System Size (kW-140 Based on CPAU electrical data provided for Commercial, Industrial, Public Facilities, and City owned properties, the average weighted annual usage
Solar PV System Installation Cost per $2.74 The assumption aligns with the average non-residential installation cost from contractors before tax credits.
Nominal BESS Capacity (kWh) 200
Based on CPAU electrical data provided for Commercial, Industrial, Public Facilities, and City owned properties the average peak demand is
estimated as 49.07 kW. A four-hour discharge battery would be, on average, sized for approximately 196 kWh (4h X 49.07 kW). The tool assumes a
BESS Round-trip Efficiency 90% This variable represents the percentage of energy that's delivered back to the grid after being stored, compared to the energy put into the system
BESS Discharge Duration (hrs) 4 Battery energy storage systems typically have discharge durations ranging from 2 to 6 hours at their maximum power output. 4 hours used as an
BESS Discharge Start Time 4PM The CPAU peak demand period is between 4PM and 9PM. The tool assumes the BESS will discharge when consumer energy prices are
BESS Charge Start Time 12AM Energy prices based on the CPAU non-
BESS Depth of Battery Reserve 25% The depth of discharge (DoD) when discharging is the percentage of the battery's capacity that can be used. This varies by technology, with
Solar PV & BESS Estimated Useful Life 20 Typically, the useful life of a Solar PV and BESS is 15-
st
BESS Investment Tax Credit Available 30% The Federal government offers an Investment Tax Credit (ITC) for commercial BESS at 30% of the system's cost. The credit is available for systems
Program Administration Costs $300,000 $150,000 for setup and $30,000 ongoing annual costs for five years of program duration. This assumption is based on estimated staffing costs in
Item 2
Attachment A - Consultant Report,
Evaluation of Local Energy Resources to
Lower Costs and Improve Reliability
and Resiliency
Item 2: Staff Report Pg. 78 Packet Pg. 83 of 103
Local Energy Resources to Lower Costs and Improve Reliability and Resiliency 70
Non-Residential BESS Coupled with Solar PV (BESS Charged from Excess Solar PV)
Variable Assumption Explanation
Quantity of Installations 35 The population of non-residential accounts is 3,783. An installation of 35 units represents 0.93% of the total population
Nominal Solar PV System Size (kW-140 Based on CPAU electrical data provided for Commercial, Industrial, Public Facilities, and City owned properties the average weighted annual usage
Solar PV System Installation Cost per $2.74 The assumption aligns with the average non-residential installation cost from contractors before tax credits.
Nominal BESS Capacity (kWh) 200
Based on CPAU electrical data provided for Commercial, Industrial, Public Facilities, and City owned properties the average peak demand is
estimated as 49.07 kW. A four-hour discharge battery would be, on average, sized for approximately 196 kWh(4h X 49.07 kW). The tool assumes a
BESS Round-trip Efficiency 90% This variable represents the percentage of energy that's delivered back to the grid after being stored, compared to the energy put into the system
BESS Discharge Duration (hrs) 4 Battery energy storage systems typically have discharge durations ranging from 2 to 6 hours at their maximum power output. 4 hours used as an
BESS Discharge Start Time 4PM The peak demand period is between 4PM and 9PM. The tool assumes the BESS will discharge when consumer energy prices are highest, thus
BESS Charge Start Time 10AM Based on a simulation of solar PV performance, the highest 4-hour period of production is from 10AM-2PM which would be expected to provide
BESS Depth of Battery Reserve 25% The depth of discharge (DoD) when discharging is the percentage of the battery's capacity that can be used This varies by technology, with
Solar PV & BESS Estimated Useful Life 20 Typically, useful life of a Solar PV and BESS is 15-20 years, but can potentially extend to 30 years with proper maintenance. The tool assumes the
st
BESS Investment Tax Credit Available 30% The Federal government offers an Investment Tax Credit (ITC) for commercial BESS at 30% of the system's cost. The credit is available for systems
Program Administration Costs $300,000 $150,000 for setup and $30,000 ongoing annual costs for five years of program duration. This assumption is based on estimated staffing costs in
Item 2
Attachment A - Consultant Report,
Evaluation of Local Energy Resources to
Lower Costs and Improve Reliability
and Resiliency
Item 2: Staff Report Pg. 79 Packet Pg. 84 of 103
Local Energy Resources to Lower Costs and Improve Reliability and Resiliency 71
Demand Response (DR)
Residential DR
Variable Assumption Explanation
Quantity of Participants 250
Nominal Curtailment
Commitment (kWh) 6.25 of electricity per day. Approximately half of this daily usage, approximately 12.5 kWh, is anticipated to fall within the
window of a DR event (4PM-9PM) due to increased HVAC and occupancy demands. A DR event nominal curtailment
DR Event Duration (hrs) 5 warrant a DR curtailment event. The DR event is assumed to be necessary for the duration of the defined 5-hour
Life of Program (yrs) 20 limited to specific technology useful life’s as it is a manual curtailment effort. The tool does not consider Auto-DR
DR Event Timeframe May-October
DR Events per Month 2
Program Administration Costs $300,000
Item 2
Attachment A - Consultant Report,
Evaluation of Local Energy Resources to
Lower Costs and Improve Reliability
and Resiliency
Item 2: Staff Report Pg. 80 Packet Pg. 85 of 103
Local Energy Resources to Lower Costs and Improve Reliability and Resiliency 72
Non-Residential DR
Variable Assumption Explanation
Quantity of Participants 75
Nominal Curtailment
Commitment (kWh) 125 average weighted peak demand is approximately 49.07 kW. A DR event nominal curtailment commitment aims to
DR Event Duration (hrs) 5 warrant a DR curtailment event. The DR event is assumed to be necessary for the duration of the defined 5-hour
Life of Program (yrs) 20 limited to specific technology useful life’s as it is a manual curtailment effort. The tool does not consider Auto-DR
DR Event Timeframe May-October
DR Events per Month 2
Program Administration Costs $300,000
Item 2
Attachment A - Consultant Report,
Evaluation of Local Energy Resources to
Lower Costs and Improve Reliability
and Resiliency
Item 2: Staff Report Pg. 81 Packet Pg. 86 of 103
Local Energy Resources to Lower Costs and Improve Reliability and Resiliency 73
Thermal Energy Storage System (TESS)
Non-Residential TESS
Variable Assumption Explanation
Quantity of Installations 35
Nominal Cooling Capacity per
Site (tons) 20
annual energy usage is approximately 168,000 kWh. From the Diversegy Commercial Energy Advisory, a typical
commercial building (generalized) consumes approximately 22.5 kWh per square foot per year. Using this metric, a
typical non-residential customer in the territory is estimated to be, using a weighted average, approximately 7,500
square feet (excluding industrial applications). An engineering rule of thumb of 400 square feet per ton of cooling is
0.980
Cooling Season Given the climate zone, cooling demand is expected to be realized at the site from May through September.
TESS Discharge Start Time 4PM
TESS Charge Start Time 6AM
15
$3,000 The assumption aligns with the cost estimate provided by a manufacturer for the installation of the technology.
Program Administration Costs $300,000
Item 2
Attachment A - Consultant Report,
Evaluation of Local Energy Resources to
Lower Costs and Improve Reliability
and Resiliency
Item 2: Staff Report Pg. 82 Packet Pg. 87 of 103
Local Energy Resources to Lower Costs and Improve Reliability and Resiliency 74
Vehicle to Everything (V2X)
Residential V2X
Variable Assumption Explanation
Quantity of Installations 50
Nominal Vehicle Capacity
(kWh) 71.4 71.4 kWh. The range of the database spans 21.3 kWh -118.0 kWh. A limited number of electric vehicles, such as the
Vehicle Discharge Duration
(hrs) 4 throughout the year. However, it should be noted that this would not be a fixed realization, reference “Realization
Vehicle Discharge Start Time 6PM consumer energy prices are highest, thus providing the most end-user benefit. However, it is assumed that travel
Vehicle Charge Start Time 12AM
50%
Vehicle Estimated Useful Life
(yrs) 20 Kelley Blue Book, the average miles driven by a consumer is approximately 13,500 miles per year, yielding an
$4,000
Realization Rate 15% assumed. This means that only 15% of the available capacity (kWh) will be available for discharge due to behavioral
Program Administration Costs $300,000
Non-Residential V2X
Variable Assumption Explanation
Item 2
Attachment A - Consultant Report,
Evaluation of Local Energy Resources to
Lower Costs and Improve Reliability
and Resiliency
Item 2: Staff Report Pg. 83 Packet Pg. 88 of 103
Local Energy Resources to Lower Costs and Improve Reliability and Resiliency 75
Quantity of Installations 50
Nominal Vehicle Capacity
(kWh) 130 71.4 kWh. The range of the database spans 21.3 kWh -118.0 kWh. However, fleet vehicles such as school buses can
Vehicle Discharge Duration
(hrs) 4 the year. However, it should be noted that this would not be a fixed realization, reference “Realization Rate”
Vehicle Discharge Start Time 6PM consumer energy prices are highest, thus providing the most end-user benefit. However, it is assumed that travel
Vehicle Charge Start Time 12AM
50%
Vehicle Estimated Useful Life
(yrs) 20
$4,000
Realization Rate 15% assumed. This means that only 15% of the available capacity (kWh) and participants would coincidentally implement
Program Administration Costs $300,000
Item 2
Attachment A - Consultant Report,
Evaluation of Local Energy Resources to
Lower Costs and Improve Reliability
and Resiliency
Item 2: Staff Report Pg. 84 Packet Pg. 89 of 103
Status Update: Reliability and Resiliency Strategic Plan Implementation (November 2025)
Strategy/Action Status Cost
Strategy 1: Replace and Modernize Infrastructure
1.1 Replace aging
infrastructure
1.2 Upgrade capacity to
accommodate new loads
1.3 Improved feeder
switching capabilities
Strategies 1.1 – 1.3, the grid modernization project, will replace aging
infrastructure and install a modern network infrastructure to meet future home
electrification needs. Changes to the equipment on the network will include
replacing/installing transformers, installing new protective devices to improve
reliability, and the installation of system controls to allow for the import and export
of energy from homes on the network. A pilot project to replace and upgrade aging
infrastructure serving approximately 1000 residents was completed in 2025. Staff is
evaluating results from this pilot before moving to the rest of Phase 1 of the
project.
Electric Fund CIP EL-24000
(Grid Modernization): $300
million (of which staff very
preliminarily estimates 40%
- 50% is for existing
infrastructure replacements
that would occur regardless
of electrification)
1.4 Second transmission
connection
Staff, with consultant help, continues to work with the California Independent
System Operator (CAISO) and PG&E to build a second transmission corridor from
the broader electricity grid to Palo Alto. In May 2025 CAISO approved construction
of this second corridor in the form of a new 115 kV line from Ames to Palo Alto to
be completed in 2034 as part of the CAISO transmission planning process. Staff and
consultants are working with PG&E and CAISO to move the completion date to
closer to 2030 as loads are increasing faster than expected.
Electric Fund CIP EL-06001
(115 kV Electric Intertie):
$250,000 for planning and
design work for application to
CAISO
1.5 Foothills undergrounding A key wildfire mitigation activity is undergrounding approximately 49,200 feet of
electric overhead distribution lines and fiber optic cable in the Foothills area. This
iterative project consists of multiple phases 1-5 and is expected to be complete in
2025. Phases 1,2, 3, and 5 were completed May 2025, and 10,000 Feet remaining in
the MidPen Phase 4 area are scheduled for completion by December 2025.
Electric Fund CIP EL-21001
(Foothills Rebuild): $8 million
Item 2
Attachment B - Status Update on RRSP
Implementation
Item 2: Staff Report Pg. 85 Packet Pg. 90 of 103
Strategy/Action Status Cost
1.6 Reliability Metrics Metrics and proposed goals were provided to Council June 16, 2025 (Staff Report
2506-4769 Accept Electric System Reliability Key Performance Indices1) but the
report was pulled from the consent calendar and has not yet been scheduled for
action. Metrics are provided in reports to the UAC, also in the Council packet.
0.05 FTE of staff time for
research and metric
development
Strategy 2: Operational Strategies to Improve Reliability and Manage Outages Effectively
2.1 Strengthen the
workforce
Concerted efforts are currently underway to recruitment, train, and retain
lineworkers, system operators, engineers, inspectors to maintain system and
respond to outages effectively. Staff have also contracted with third-party
contractors to supplement staff to undertake emergency response, maintenance,
and capital improvement projects. In FY 2024, 45 vacancies were filled. Between
January to May 2025, CPAU has 11 new hires and 12 promotions. As of May 2025,
CPAU 38 vacant positions or 14% vacancy rate of the authorized 267 FTEs. 20 of
the vacant positions are in-progress recruitments. Significant progress has been
made in filling critical vacancies like director, assistant director, lineworker, and
engineer.
1.0 FTE (spread among three
people) for additional
recruitment and retention
work
2.2 Wildfire protection
maintenance practices
Staff regularly updates its Wildfire Mitigation Protection Plan to protect power
lines in the Foothills, and is exploring innovative software to make vegetation
management more efficient.
Implementation requires
$150,000 to $200,000 for
vegetation clearance
annually
2.3 Communicate effectively
during outages
The new OMS allows CPAU to more quickly detect and respond to power outages
and provide customers with timely notifications and updates. In FY 2025, OMS sent
approximately 103,500 text messages for planned and unplanned outages and
restorations. Staff has incorporated OMS texting features to support outbound
communications during potential and active PSPS events. Staff will explore other
uses for OMS, such as customer non-payments.
$73,000 was spent to develop
the system. Ongoing
maintenance involves 0.25
FTE and ongoing system costs
of $108,000 per year.
1 https://cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=8431&meetingTemplateType=2&compiledMeetingDocumentId=14843
Item 2
Attachment B - Status Update on RRSP
Implementation
Item 2: Staff Report Pg. 86 Packet Pg. 91 of 103
Strategy/Action Status Cost
Strategy 3: Effectively Integrate and Ease Adoption of New Technologies
3.1 Configure the distribution
system to accommodate high
penetrations of solar,
batteries, and other
technologies
Staff has completed an evaluation of the distribution improvements needed to
accommodate high penetrations of solar and storage and is currently evaluating
whether these same improvements will also accommodate vehicle to grid
technologies, smart panels, and flexible loads.
$30,000 to 50,000 in
consultant studies from
electric utility operating
budgets
3.2 Review, communicate,
and streamline permitting
and other regulatory rules for
efficient and flexible
electrification technologies
3.3 Communicate how to
electrify efficiently
3.4 Communicate how to
use technologies in a
grid-friendly way
Staff completed an inter-departmental internal review of various technologies to
establish clear rules and guidelines for implementation:
•Planning and Development Services updated intake forms for electrical load
calculations were updated. Status: Complete.
•Utilities is updating transformer upgrade fees. Expected completion: Q4 2025
•Utilities transformer upgrade policies for multi-family and non-residential
properties take into account efficient and flexible technologies and strategies.
Status: Complete.
• Time of use (TOU) rates and a transition plan for these rates are currently being
developed in parallel with the City’s rollout of advanced metering
infrastructure. The voluntary residential TOU rates are expected to be approved
by Council in August 2025. Staff plans an update to the UAC on implementation
details in October 2025. Initial Launch Planned: Q1 2026
•Utility staff has developed an electrification guide for single family homes and
posted it on its website. Status: Complete
•Utilities launched an electrification expert service which can provide guidance
to residents on efficient electrification. Status: Complete
0.25 FTE in staff effort from
existing staff resources
Item 2
Attachment B - Status Update on RRSP
Implementation
Item 2: Staff Report Pg. 87 Packet Pg. 92 of 103
Strategy/Action Status Cost
Strategy 4: Value the benefits of flexible technologies to the utility and community
4.1 Value the utility benefit of
flexible technologies on
electric supply costs
4.2 Value the utility benefit of
flexible technologies on
electric distribution costs and
capacity
4.3: Explore estimating the
value of resiliency for the
community
4.4: Estimate the cost of
various community resiliency
approaches
Staff is taking its final recommendations for Council review in December 2025. If
Council approves the staff recommendations, the only actions needed will be
occasional updates to this study as staff time permits.
See staff report for details
Item 2
Attachment B - Status Update on RRSP
Implementation
Item 2: Staff Report Pg. 88 Packet Pg. 93 of 103
Strategy/Action Status Cost
Strategy 5: Evaluate the resource needs for various demand reduction and resiliency programs
5.1: Evaluate utility-driven
programs to enhance
resiliency and lower the
demand on the grid
5.2 Evaluate equity-based
and need-based versions of
the programs
5.3: Evaluate community-
based versions of the
programs
5.4: Evaluate other resiliency
approaches like
neighborhood level
microgrids
Staff is taking its final recommendations for Council review in December 2025. If
Council approves the staff recommendations, some additional work in 2026 related
to long-term resiliency and microgrids will be needed before this item is complete.
See staff report for details
Strategy 6: Implement any demand reduction or resiliency programs chosen by the community
Staff is taking its final recommendations for Strategies 4 and 5 for City Council review in December 2025. If the City
Council accepts the staff recommendations, no specific programs will be needed under this Strategy 6, though
promotion and barrier reduction will continue to take place under Strategy 3, and commercial solar and battery
project evaluations will take place as staff time permits.
See staff report for details
Item 2
Attachment B - Status Update on RRSP
Implementation
Item 2: Staff Report Pg. 89 Packet Pg. 94 of 103
Climate Action and Sustainability Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Public Works
Meeting Date: November 20, 2025
Report #:2510-5311
TITLE
Status Update on Sustainability and Climate Action Plan Mobility Goals and Key Actions and
Request for Feedback on Tentative 2026-2027 Work Plan Items. CEQA Status – Not a project.
RECOMMENDATION
This is a discussion item, and no action is requested. Staff is seeking feedback on the tentative
Mobility-related work items for the 2026-2027 Sustainability and Climate Action Plan (S/CAP)
Work Plan and the City’s current level of effort on Vehicle Miles Traveled (VMT) and mode shift
S/CAP Goals.
EXECUTIVE SUMMARY
This report provides an update on progress on the City’s S/CAP Mobility Goals and tentative
work items for the 2026-2027 S/CAP Work Plan. As of the 2023 community greenhouse gas
(GHG) inventory, the community had exceeded its 2030 VMT reduction goal but had not made
significant progress on its mode shift goal. Many of the gains in VMT reduction were driven by
remote work and vacancies during the pandemic, and there has been some erosion of those
gains. It remains to be seen whether there will be additional increases in VMT in the 2024 GHG
inventory or in future years, but regardless, the City has made significant progress.
Staff has tentatively identified various 2026-2027 S/CAP Work Plan work items to continue to
implement efforts to expand the bicycle and pedestrian transportation system, enhance transit
access, pilot micromobility programs, and improve safety. Although resource needs are
outlined, staff expects needs to be considered in the context of the FY 2027 budget process
which is expected to bring ongoing expense reductions.
BACKGROUND
Item 1.
Item 1 Lake Packet Report
Item 1.: Staff Report Pg. 1 Packet Pg. 95 of 103
The S/CAP adopted in June 20231 has a goal of 80% reductions in transportation emissions from
1990 levels by 2030. As of 2019, transportation represented about 60% of remaining
greenhouse gas emissions. Reducing single-occupancy vehicle travel not only has GHG
reduction benefits, but also improves community sustainability in other ways, as discussed in
the S/CAP Co-Benefits Analysis.2 These impacts are reflected in two key Mobility goals:
Reduce total vehicle miles traveled 12% by 2030, compared to a 2019 baseline
Increase mode share of biking, walking, and transit work trips from 19% to 40% by 2030
3 to achieve the City's
Mobility Goals listed above. The 2021 Impact Memo4 by a City consultant, AECOM, assessed
one possible pathway to achieve those reductions includes about 22,200 metric tons of carbon
dioxide equivalent (MT CO2-e) per year from reductions in vehicle miles traveled (VMT) through
telecommuting and mode shift.
Table 1: VMT and GHG Trends, 2019 to 2023
Methodology 2019 2023
VMT (miles)952 million 598 millionFehr and Peers (2019) +
Google EIE (2023)GHG (MT CO2-e)293,413 225,386
VMT (miles)739 million 598 millionBased on Google EIE only,
both years GHG (MT CO2-e)302,000 225,386
1 https://www.paloalto.gov/files/assets/public/v/1/sustainability/reports/2022-scap-report_final.pdf
2 https://www.paloalto.gov/files/assets/public/v/1/sustainability/reports/palo-alto-action-evaluation-memo-2021-
02-11.pdf
3 See page 53 of the S/CAP: https://www.paloalto.gov/files/assets/public/v/1/sustainability/reports/2022-scap-
report_final.pdf#page=53
4 https://www.paloalto.gov/files/assets/public/v/2/sustainability/reports/aecom-palo-alto-action-impact-
memo_final_rev-210607.pdf
Item 1.
Item 1 Lake Packet Report
Item 1.: Staff Report Pg. 2 Packet Pg. 96 of 103
ANALYSIS
2-e per year in 2023. Based on back of the
envelope estimates by staff (since it is not possible to disaggregate the source of the emissions
reductions using Google EIE data), vehicle electrification and improved fuel efficiency likely
contributed around 30% of that emissions reduction, which would mean close to 48,000 MT
CO2-e per year resulted from VMT reduction, exceeding the assumption in the 2021 impact
analysis.
2-e per year as the 2030
target for emissions reduction from VMT reduction, and the community had achieved a 48,000
MT CO2-e per year reduction as of 2023. Regional VMT models suggest that VMT continues to
increase post-pandemic, and therefore some of these gains may erode, but at minimum, the
community has made progress toward its 2030 VMT goal.
Table 2: OOT Work Plan Items Impacting VMT and Mode Shift
Long-term VMT Reduction / Mode Shift Short-term VMT Reduction / Mode Shift
Implementation of the Bike and Ped Plan
and Safety Action Plan, which will enhance
the attractiveness of transportation options
and provide a complete, connected low-
stress network
South Palo Alto Bike and Pedestrian
Connectivity project
Rail grade separations
Development and implementation of a
Transit Priority Policy
Development, implementation and
monitoring of a Travel Demand
Management (TDM) ordinance for
development
Safe Routes to School (SRTS) and other bicycle and
pedestrian safety programs
Near-term bike and pedestrian capital projects e.g.
Churchill Enhanced Bikeway
Completion of traffic speed surveys and increased
speed enforcement efforts
Traffic calming projects
Bike and pedestrian Municipal Code updates
Short-term reduction pilots or opportunities under study
Traffic calming policy change
Parking policy analysis
Micromobility Feasibility Study
Palo Alto Link
Item 1.
Item 1 Lake Packet Report
Item 1.: Staff Report Pg. 3 Packet Pg. 97 of 103
Because of the challenges of measuring the mode shift and VMT reduction results of individual
programs and investments, especially when multiple programs and investments work in concert
to contribute to VMT reduction, it is unclear how much mode shift these efforts will produce. In
some cases, it is possible to measure results, such as with the Palo Alto Transportation
Management Association (PATMA). PATMA has expanded its activities due to increased Council
funding. VMT reduction associated with PATMA’s work was estimated at 1,540,000 miles in 2024
while estimated GHG reduction was 603.4 tons.
Table 3: Tentative 2026-2027 S/CAP Work Plan Items
Work Item Description Resource Availability
Bicycle and Pedestrian Capital
Projects
Complete three bicycle / pedestrian
projects
Funded, proceed as staff time
available
Implement Micromobility
Feasibility Study
recommendations
Pursue a bike/e-bike/e-scooter share pilot
program or recommendations of the
Micromobility Feasibility Study
Fully staffed and funded (study)
Downtown Parking Pricing and
Management
Develop parking policy options for Council
consideration
Proceed as staff time is
available (advancement within
a year requires 0.5 FTE)
Traffic Signal Upgrades and
Timing Efforts
Upgrade traffic signals to optimize
multimodal performance
Proceed as staff time and
funding are available
Housing Element
Implementation / Land Use
Planning and Policy
Implement the goals, policies, and programs
in the City's 2023-2031 Housing Element of
the Comprehensive Plan to improve the
City's jobs-housing balance and to reduce
vehicle miles traveled (VMT)
Funded
Table 4: Potential Additional Work Items for Higher Level of Effort
Work Item Additional FTE Additional Non -Salary
Advance Downtown Parking Pricing and Management and
Traffic Signal Upgrades and Timing Efforts (see Table 3) by one
year
1 FTE Associate
Engineer
Accelerating infrastructure investment: Accelerate design and
delivery of planned improvements 2 FTE Engineer
Launching and operating a Micromobility Program 0.5 FTE Planner $200,000
Item 1.
Item 1 Lake Packet Report
Item 1.: Staff Report Pg. 4 Packet Pg. 98 of 103
Expanding transit service such as shuttles or Palo Alto Link $2,000,000 per year
Table 4 (continued): Potential Additional Work Items for Higher Level of Effort
Work Item Additional FTE Additional Non -Salary
Conduct a Land Use and Transportation Study: Identify and
utilize a data platform to project scenarios of housing growth
and mobility impacts to inform next CIPs and Comprehensive
Plan
0.5 FTE Planner $300,000
Establish Transportation Demand Management Ordinance
(TDM): Update TDM requirements 1 FTE Planner
Adult-Focused Bike, Walk, Transit Education &
Encouragement Programs: Create education &
encouragement programs for adult commuters and older
adults
0.3 FTE Planner $600,000 per year
FISCAL/RESOURCE IMPACT
The work items included in the 2026-2027 S/CAP Work Plan (Table 3) are funded in the FY 2026
budget, with some additional funding that would be proposed in the FY 2027 budget.
The tentative 2026-2027 S/CAP Work Plan (Table 3) includes items, such as Bicycle and Pedestrian
Capital Projects and Housing Element Implementation, which are funded in the FY 2026 budget
and will proceed as staff time is available.
Table 4 includes items that could be proposed in the FY 2027 budget if the City Council wished to
expand the level of effort on Mobility goals. However, staff are expecting a need to reduce
expenses in FY 2027 and beyond as noted in a recently released Finance Committee staff report.
Therefore, resource needs and funding availability is recommended to proceed in-line with the
FY 2027 citywide budget process and priority setting.
STAKEHOLDER ENGAGEMENT
For non-traffic signal items, typical stakeholder engagement includes outreach via social media
and mailers to local residents, and engagement via community meetings and advisory
committees.
ENVIRONMENTAL REVIEW
The Committee’s discussion of the status of current City efforts on the Mobility element of the
S/CAP is not a project as defined by CEQA because it does not involve any commitment to any
specific project which may result in a potentially significant physical impact on the environment.
CEQA Guidelines section 15378.
ATTACHMENTS
Item 1.
Item 1 Lake Packet Report
Item 1.: Staff Report Pg. 5 Packet Pg. 99 of 103
Attachment A: Tentative 2026-2027 S/CAP Work Plan Mobility Items
APPROVED BY:
Item 1.
Item 1 Lake Packet Report
Item 1.: Staff Report Pg. 6 Packet Pg. 100 of 103
Attachment A
Tentative 2026-2027 S/CAP Work Plan Mobility Items
Mobility
Achieve Benchmarks for Bicycle and Pedestrian Capital Improvement Projects
S/CAP Key Action(s): M1, M2, M3
Target Completion Date: Varying, by 2027
Resource Availability: Varying
Description: South Palo Alto Bikeways Demonstration Project: Upgrade crossings and bicycle
facilities on East Meadow Dr and Fabian Way to improve safety, especially for students
traveling to school. Pilot construction anticipated for summer 2027. Project is fully staffed and
funded.
Churchill Avenue Enhanced Bikeway Project: Improve walking and bicycling on Churchill
Avenue with a multi-use path, intersection improvements, and landscaping. Project work is
focused between the Caltrain tracks and El Camino Real. Construction is scheduled to finish
by fall 2026.
Quarry Road Extension at El Camino Park: Develop underused portion of El Camino Park to
provide a direct connection from El Camino Real to the Palo Alto Transit Center. Project is led
by Stanford. By fall 2027, project will complete the Caltrans process for the Encroachment
Permit and prepare plans, specifications, and estimate construction documents for the project
in both Caltrans and City right-of-way. In addition, the team will perform both a bike and
transit operations assessment and recommend operational scenarios to inform future bikes,
bus and shuttle operations in and around the Transit Center.
South Palo Alto Bike/Ped Connectivity: Identify locations and design concepts for additional
east-west bicycle and pedestrian crossings of the Caltrain railroad tracks in the southern part
of the City. Study will complete following Council adoption of a final report in fall 2026, and
next steps include securing grant funding for final design and construction.
Implement Micromobility Feasibility Study recommendations
S/CAP Key Action(s): M1, M2
Target Completion Date: 2027
Resource Availability: Fully staffed and partially
funded, need to evaluate based on
recommendation.
Description: Pursue a bike/e-bike/e-scooter share pilot program or other recommendation as advised
by the Micromobility Feasibility Study, to be finalized in early 2026.
Conduct a Land Use and Transportation Study
S/CAP Key Action(s): M6
Target Completion Date: Unknown
Resource Availability: Proceed as staff time is
available. Will need staff time and a cross-
departmental committee.
Item 1.
Attachment A - Tentative
2026-2027 SCAP Work Plan
Mobility Items
Item 1.: Staff Report Pg. 7 Packet Pg. 101 of 103
Attachment A
Description: Develop a data platform to project various scenarios of housing growth and
subsequent mobility impacts. This internal study would inform future discussions for the City’s
next comprehensive plan and area plans.
Downtown Parking Pricing and Management
S/CAP Key Action(s): M5, M10
Target Completion Date: 2028
Resource Availability: Proceed as staff time is
available for parking policy and operations.
Description: Explore parking policy and pricing options to manage parking supply and
availability. Work will include engagement of business community, residents and City
Council on options to be developed in conjunction with a new parking permit vendor.
Following Council consideration and selection of preferred options, staff will explore
next steps for implementation
Establish Transportation Demand Management Ordinance (TDM)
S/CAP Key Action(s): M4
Target Completion Date: Ongoing
Resource Availability: Currently unstaffed.
Description: Clarify existing TDM conditions of approval and monitoring procedures.
Formalize TDM requirements by ordinance and require new developments above a certain
size threshold to prepare and implement a TDM Plan to meet specific performance standards.
Require new development projects to pay a Transportation Impact Fee for all those peak-hour
motor vehicle trips that cannot be reduced via TDM measures. Evaluate possible alternatives
to expand voluntary TDM services (e.g. expanding the Transportation Management
Association).
Adult-Focused Bike, Walk, Transit Education/Encouragement Programs
S/CAP Key Action(s): M1, M4
Target Completion Date: 2027
Resource Availability: Proceed as staff time
and funding is available.
Description: Create education and encouragement programs for adult commuters and older
adult residents and visitors. Partner with local organizations with expertise in this area. City
could direct funding to Palo Alto TMA or others to do this work. Utilize HRC or create a
stakeholder committee to understand pain points in mode shift journey for adults.
Traffic Signal Operations and Multimodal Improvements
S/CAP Key Action(s): M8
Target Completion Date: On-going
Resource Availability: Mostly funded, long-
term funding needs being evaluated
Description: Maintain and modernize current traffic signals and central management
systems. Use technology to improve traffic operations and safety. Work with transit providers
on transit signal priority where feasible.
Projects that include operational improvements include the Quarry Road Intelligent
Transportation Systems and Operations Improvement (in-progress), Citywide Central
Item 1.
Attachment A - Tentative
2026-2027 SCAP Work Plan
Mobility Items
Item 1.: Staff Report Pg. 8 Packet Pg. 102 of 103
Attachment A
Management and ITS Updates (Ongoing), Citywide Arterial Operations Optimization (on-
going pending staff resources), and Automated Traffic Signal Performance Measure (ATSPM)
implementation (near-future). Each of these projects includes multimodal improvements and
optimization to improve operations and reduce emissions.
Housing Element Implementation / Land Use Planning and Policy
S/CAP Key Action(s): M7, M9
Target Completion Date: 2030
Resource Availability: Funding via grants and
annual City budget process
Description: Implement the goals, policies, and programs in the City's 2023-2031 Housing
Element of the Comprehensive Plan to improve the City's jobs-housing balance and to reduce
vehicle miles traveled (VMT). Implementation will continue creating a housing density and
land use mix that supports transit and non-SOV (Single Occupancy Vehicle) transportation
modes. Implementation includes efforts on land use and area plans, housing plans,
development standards, and affordable housing projects.
Update City’s Traffic Calming Policy and Process
S/CAP Key Action(s): M1, M2
Target Completion Date: End of 2027
Resource Availability: Proceed as staff time
available
Description: Update the City’s Traffic Calming Process to provide more clarity on traffic calming design
details and criteria for consideration in relation to engineering judgment
Item 1.
Attachment A - Tentative
2026-2027 SCAP Work Plan
Mobility Items
Item 1.: Staff Report Pg. 9 Packet Pg. 103 of 103