HomeMy WebLinkAbout2025-11-18 Finance Committee Agenda PacketFINANCE COMMITTEE
Regular Meeting
Tuesday, November 18, 2025
Community Meeting Room & Hybrid
5:30 PM
Amended Agenda
Amended Agenda Items Appear Below in RED
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1 November 18, 2025
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CALL TO ORDER
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ACTION ITEMS
1.Recommendation City Council Adopt a Resolution Approving the 2026 Natural Gas Cost
of Service Analysis Report, Amending Rate Schedules G-1 (Residential Gas Service), G-2
(Residential Master-Metered and Commercial Gas Service), G-3 (Large Commercial Gas
Service) and repealing G-10 (Compressed Natural Gas Service) as Recommended by the
Utilities Advisory Commission.
2.General Fund Major Tax Revenues Review and Retiree Benefit Funding Policy Update.
CEQA Status – Not a Project.
3.Discussion and Update on the Fiscal Year 2027 Preliminary Utilities Financial Forecast and
Rate Projections
4.Status Update on Calendar Year (CY) 2025 Finance Committee Referrals. CEQA Status --
Not a Project.
FUTURE MEETINGS AND AGENDAS
Members of the public may not speak to the item(s)
ADJOURNMENT
2 November 18, 2025
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3 November 18, 2025
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4 November 18, 2025
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public inspection at www.paloalto.gov/agendas.
Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Utilities
Meeting Date: November 18, 2025
Report #:2506-4907
TITLE
Recommendation City Council Adopt a Resolution Approving the 2026 Natural Gas Cost of
Service Analysis Report, Amending Rate Schedules G-1 (Residential Gas Service), G-2
(Residential Master-Metered and Commercial Gas Service), G-3 (Large Commercial Gas Service)
and repealing G-10 (Compressed Natural Gas Service) as Recommended by the Utilities
Advisory Commission. CEQA Status: Not a Project under Public Resources Code Section 21065.
RECOMMENDATION
The Utilities Advisory Commission and staff recommends the Finance Committee recommend
that the City Council adopt a resolution (Attachment A) that:
1. Approves the 2026 Natural Gas Cost of Service Analysis Report (Attachment B); and
2. Amends Rate Schedules (Attachment C) effective for gas usage beginning February 1,
2026 (FY 2026):
a. G-1 (Residential Gas Service)
b. G-2 (Residential Master-Metered and Commercial Gas Service)
c. G-3 (Large Commercial Gas Service)
3. Repeals Rate Schedule G-10 (Compressed Natural Gas Service)1
EXECUTIVE SUMMARY
Staff revised the Natural Gas Cost of Service Analysis from the version reviewed in May and
June 2025 in collaboration with the Utilities Advisory Commission as directed by the City
Council. Council approval of this report and resolution would approve the 2026 Natural Gas
Cost of Service Analysis Report (2026 Report) shown in Attachment B and adopt revised gas
rate schedules shown in Attachment C, resulting in revised Gas rates for customers effective
February 1, 2026.
1 Rate Schedule G-10 (Compressed Natural Gas Service)
https://www.paloalto.gov/files/assets/public/v/10/utilities/rates-schedules-for-utilities/city-facility-utility-rates/g-
10-effective-2025-07-01.pdf
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The 2026 Report does not propose any budget or overall revenue increase; instead, the focus of
the 2026 Report is on a proportional rebalancing through rate design changes. Specifically,
updates to the allocation of costs among customer classes and a refined G-2 rate schedule
better reflect the cost to serve customers with different meter capacities. The proposed rate
adjustments are designed to ensure equity among rate classes, maintain compliance with cost-
of-service principles under California law, and align with the City’s financial and policy
objectives for affordability, transparency, and long-term sustainability. The proposed rate
adjustments are also consistent with the City Council-approved design principles.3
The Gas Utility implemented an across-the-board rate increase on July 1, 2025 to meet the
higher costs of providing service to its customers. These rebalanced rates are proposed to be
effective on February 1, 2026, and the 2026 Report also provides the analytical basis for
allocating costs among classes to meet revenue requirements in future years. In summary, key
changes from the last cost of service study adopted by City Council in 2020 include:
1) Updating the weighted meter cost - the 2026 Report refreshes the Gas Utility’s rates
with the best possible cost information, which is necessary to achieve fair and cost-
based rates.
2) Updating the Average & Excess (A&E) Method – the 2026 Report’s cost allocation
approach better aligns rates with how the distribution system is designed and built in
light of declining average gas use. Infrastructure is sized based on energy usage and
peak demand which supports the A&E classification as both “demand” and “energy.”
This change is necessary to develop a fair and appropriate allocation of expenses across
customer classes.
3) Applying the Base & Excess Method for Residential Tier Rate – the 2026 Report’s
calculations present the best method for the G1 tiered rate design because the usage
profile supports measuring excess demand using the highest peak month and because
system infrastructure is designed to meet a single January peak.
4) Refining the G-2 (Multi-family Master-Metered and Commercial) Rate Schedule – the
2026 Report recommends separating this class into three meter capacity groupings by
Standard Cubic Feet per Hour (scfh), because the larger meters require a higher cost to
serve. This refinement results in a higher monthly service charge for larger capacity
meters to better reflect customer-related fixed costs in the fixed monthly service
charge.
The overall bill impact to the median use residential customer from the recommendations in
the 2026 Report is an 8% increase, while the bill impact for commercial customers ranges from
a 58% decrease for small commercial customers to a 7% increase for the largest G-2
commercial customers. Table 6 below shows additional bill impact details.
3 Staff Report 2507-4958, September 15, 2025 outlines the five design principles:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=043ab
d5a-f59f-4702-ad04-845541a8133f
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Staff worked closely with guidance from the Utilities Advisory Commission Gas COSA
Subcommittee on developing the recommendations in the 2026 Report. Staff appreciates the
extensive efforts of the Subcommittee members including meeting four times between August
and October 2025. Gas COSA Subcommittee members provided a verbal report to the full UAC
at the November 5, 2025 meeting. Ultimately, after much discussion, a majority of the UAC
recommended approval of the resolution and corresponding rates (5 approved, 1 dissent, 1
absent).
BACKGROUND
In June 2025, the City Council (Council) approved the overall gas utility rate increase for FY 2026
but deferred approval of the Cost of Service Analysis (COSA) pending further UAC review.5 On
July 9, 2025, the Utilities Advisory Commission (UAC) considered Design Principles for the Gas
and Electric Cost of Service Rates and voted to move forward with Proposition 26 as the Gas
COSA design principles and to form a UAC Subcommittee to work with staff and the consultant
to develop a new 2026 gas COSA and provide regular report-outs to the full UAC.6
Subsequently, staff worked closely with the UAC Gas COSA Subcommittee to review key study
assumptions and recommendations.
On September 15, 2025, the Council directed staff to follow the reasonable-cost analysis
required by Proposition 26 and to collaborate with the UAC to develop revised gas rates to be
effective in January 2026, based on the following design principles:
1. Rates must be based on the reasonable cost to serve customers. This is the
overriding principle for the cost-of-service analysis (COSA); all other rate design
considerations are subsidiary to this basic premise.
2. The COSA should involve a review of all existing rate schedules for applicability in
the COSA.
3. The impact of any proposed changes on low-income customers should be evaluated
in alignment with state law, including, without limitation, Public Utilities Code
sections 890 and 898.
4. Determine the proper allocation of fixed and variable costs and how those can be
implemented in various rate designs.
5. Review non-rate revenue sources that may be available for rate discounts or
rebates.
5 On June 16, 2025, the City Council voted 5-1-1, (Lythcott-Haims no, Stone absent) to return the updated COSA to
the UAC for further review. See June 16, 2025 action minutes for action item 22, Gas Utility item e:
https://cityofpaloalto.primegov.com/Public/CompiledDocument?meetingTemplateId=16148&compileOutputType
=1
6 July 9, 2025, UAC voted 6-1 with Gupta voting no; see action minutes
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=40dc6
4ea-7e0c-4dca-9235-61e1a6516b07
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These design principles form the basis for the 2026 Gas Cost of Service Analysis Report
presented as Attachment B to this staff report. Each design principle is discussed below in the
“Analysis - Gas COSA Design Principles” section.
The Utilities Advisory Commission (UAC) considered this item at its November 5, 2025 meeting,
agenda item 49. Ultimately, a 5-1 majority of the UAC recommended Finance Committee and
City Council approval. The UAC Subcommittee reported that staff and the cost-of-service
consultant had met multiple times over several months, and answered every question the UAC
Subcommittee members had, which built confidence in the process and resulted in a clear and
transparent staff report and cost-of-service report that achieves a reasonable cost allocation.
Additionally, the UAC Subcommittee members noted that by updating the mechanics of the
cost-of-service analysis, the resulting rates are more affordable for residential customers than if
the mechanics of the 2020 cost-of-service study were retained. The UAC Subcommittee
members also approved of the fact that the use of “green” funds10 are no longer being
proposed to subsidize gas service. The UAC Subcommittee members raised a question for
discussion in the context of future potential gas decommissioning about what the reductions in
the G2 service charges means for the city’s decarbonization and electrification efforts. A
minority of commissioners articulated concern with a lack of understanding of reducing the
small G2 meter charge by approximately 80% and one commissioner expressed a concern that
this disincentivizes electrification measures for small businesses. A representative from the UAC
Subcommittee will be available to aid in the Finance Committee discussion as well.
ANALYSIS
This project is a study to update the City’s Natural Gas Cost of Service Analysis (2026 Report),
which provides the analytical foundation for and recommends adopting new City gas rates that
continue to be fair and legally compliant. The 2026 Report evaluates the gas utility’s revenue
requirements, allocates costs among customer classes based on cost-causation principles, and
proposes updated rate designs for each class based on the most up-to-date information
available to the City.
The 2026 COSA includes an updated financial forecast (consistent with the Council-approved
FY2026 Gas Utility Financial Forecast),11 refined cost allocation methodologies, and new meter
capacity groupings for the G-2 rate schedule. The proposed rate changes ensure rates are
aligned with actual service costs.
9 November 5, 2025 UAC meeting item 4,
https://cityofpaloalto.primegov.com/Portal/Meeting?meetingTemplateId=17466
10 By “green” funds the Commissioner was referring to Cap and Trade auction revenue.
11 Staff Report 2411-3776, June 16, 2025,
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=35104f
06-6925-4fe3-89c7-b0e53e6eec42;
Resolution 10232 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62153
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Natural Gas Cost of Service Analysis
The Gas Utility’s rates are evaluated and implemented in compliance with cost-of-service
requirements set forth in the California Constitution and applicable statutory law. Staff engaged
the services of EES Consulting (EES) to review and revise the Gas Utility’s Cost of Service (COS)
for FY 2026.15 A copy of the FY 2026 COS study titled “City of Palo Alto 2026 Natural Gas Cost of
Service Analysis Report,” (2026 Report), October 2025 is included as Attachment B to this
report. The study examines and allocates the Gas Utility’s costs to each rate class to develop
proposed FY 2026 distribution rates and includes a recommendation to refine the G-2 rate
schedule as explained below.
Distribution Revenue Requirement
The 2026 Report contains gas sales forecasts and estimates for Gas Utility assets and expenses
(including estimated contributions to reserves). The 2026 Report allocates these assets and
expenses estimates using updated classification and allocation factors to ensure that the Gas
Utility’s costs are properly assigned to each rate class. The 2026 Report uses the same estimate
of total distribution revenue requirement of $41.3 million for FY 2026 that was approved by
Council on June 16, 2026 as part of the FY 2026 Gas Utility Financial Forecast.16 This distribution
revenue requirement includes operating expenses, capital costs and reserve contributions. At
current rates, projected revenues also equal $41.3 million for FY 2026, so there is no overall
rate or revenue increase required as part of the 2026 Report for the Gas Utility as a whole.
However, individual customer class rates will change as a result the realignments as
summarized in Table 1.
Table 1 illustrates the projected revenue collected from each customer class using current
distribution rates (for the full year of FY 2025-2026 assuming the rates were effective all year)
and using the rates resulting from the 2026 Report. The total revenue requirement is the same
as that shown in the Council-approved FY 2026 Gas Utility Financial Forecast. This revenue
requirement estimate includes distribution costs, certain supply costs (such as administrative
charges allocated to gas supply), and additional reserve contributions required to restore the
Gas Utility’s operations reserve to within the guideline range in FY 2026. Supply-related costs
that are collected via a pass-through charge are not included.
The 2026 Report updates and adjusts the cost-of-service classification and allocation factors,
which leads to revenue requirements for the rate classes that differ from the projected FY 2026
revenues at current rates. The percentage of revenue increase needed varies by customer class
—ranging from -10.6% for G-2 to 8.3% for G-1 and 7.9% for G-3.
15 Since FY 2021, the City adjusted its distribution rates annually based on the COS study for FY 2020, which was
also conducted by EES.
16 Resolution 10232 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62153
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Table 1: Projected Revenues, Revenue Requirement and Revenue Changes Needed
During the development of the 2026 Report, staff worked collaboratively with EES to update
the Gas Utility’s costs and usage information and refresh the model inputs with current data.
Some of the key changes described in more detail below are:
1) Updates to the customer weighting factors for meter costs;
2) Updates to the Average & Excess classification and allocation factor for G2 and G3
customers, while changing some of the methods used to calculate that factor and
changing some of the cost categories it is applied to for improved consistency;
3) The use of the Base & Excess Methodology to develop residential (G1) tiered rates;
4) Refinement of the G2 (Residential Master-Metered and Commercial Gas Service) rate
schedule; and
5) Elimination of the supply charge ranges for the Cap-and-Trade Compliance Charge and
the Transportation Charge.
During 2025 public meetings on the Gas COSA before the UAC, Finance Committee, and
Council, and in letters from the public, the February 2025 draft of the Gas Utility’s cost-of-
service study was critiqued, and stakeholders suggested that the 2026 Report retain prior cost-
of-service calculation methods. The UAC’s Gas COSA Subcommittee guided staff and EES to
examine this closely. Under this approach (retaining prior study methods and only updating
costs and revenues to current levels) the median residential monthly bill would be
approximately $80.88, which is $1.55 (or 2%) higher than the median bill under the 2026 Report
method shown in Table 1. Staff and EES do not recommend retaining the existing rate model
because it is not updated with relevant cost updates and is not updated with recent load, usage
and other relevant information); it would also result in a higher median residential customer
bill.
The 2026 Report ensures that the fixed portion of rates more accurately reflects customer
related costs, such as metering, by including the cost of each customer’s meter and accounting
for it in a comprehensive calculation of weighted average meter cost. The 2026 Report updates
the number of customers weighed by meter costs, which determine how certain costs are
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assigned among customer classes. The weighting factors are based on current replacement cost
of meters, including materials and installation costs. The weighted average meter cost
calculation is appropriate because it considers all of the meter types used by customers in each
customer class and the total costs for each class.
Table 2: Customer Weighting for Meter Costs: FY 202619
G1 G2 G3
PRIOR VALUES (MAY 2019)
Meter Costs (Materials)$72.84 $888.00 $1,505.00
Weighting $1,549,452 $2,029,080 $52,675
Resulting Allocator 42.7%55.9%1.5%
UPDATED VALUES (OCT 2025)
Meter Costs (Materials and Labor)$414 $1,262 $10,473
Weighting $8,761,310 $2,772,869 $308,954
Resulting Allocator 74.0%23.4%2.6%
20 This customer weighting
for meter costs update is one of the primary drivers for the rate rebalancing recommended in
this study. This update is necessary to refresh the Gas Utility’s rates using the best available
information and to reflect the latest costs so that rates remain fair and cost-based.
Average & Excess (A&E) Method for G2 and G3 Rates
19 This table has been updated here and in the 2026 Report (Attachment B) to correct a typographical error in the
resulting allocator. This correction does not impact the cost allocation or rates.
20 The representative meters for the G1, G2, and G3 used in the 2020 COSA study were the CL250 House, 8C/175
Rotary and 5000 Rotary meters, respectively.
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factors in considering capacity investments in the system and supports the A&E classification as
both demand and energy. In previous studies, costs assigned to the A&E allocation and
classification factor were distributed primarily based on demand. This is appropriate for
systems experiencing growth. Now that the system is experiencing declining use, and because
capacity sizing is determined based on both energy and demand, the 2026 Report A&E method
modifications are appropriate and result in a fair allocation of expenses across customer
classes.
Base & Excess Methodology for Residential Tiered G1 Rates
Refinement of G-2 (Residential Master-Metered and Commercial Gas Service) Rate Schedule
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Table 3 presents the meter capacity groupings recommended for G-2 monthly service charge
application. EES analyzed average consumption for various meter capacities in the G-2 rate
class and developed three meter capacity ranges and customer-related costs for each range.
Table 3: G-2 Service by Maximum Meter Capacity23
G-2 Service by Maximum
Meter Capacity Range # of
Services
G-2: ≤ 220 scfh
G-2: ≥ 4,000 scfh
Review of Multi-Family Analysis
Supply Charge Ranges
23 Meter capacities in this staff report are all at an assumed pressure of 7 inches of water column (equivalent to
0.25 pounds per square inch).
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Proposed Rates
Table 4 shows the current and proposed monthly service charges, while Table 5 shows the
volumetric charges related to distribution for all rate schedules. As previously noted, supply-
related charges are pass-through charges that update periodically. The latest charges are
shown in the City’s Rates website25. The proposed rates reflect the 2026 Report adjustments.
G-1 (Residential)$18.40 $19.58 $1.18 6%
G-2 (Residential Master-Metered and Commercial)
G-2 (≤ 220 scfh)$170.55 $29.24 $(141.31)(83%)
G-2 (> 220 and < 4,000 scfh)$170.55 $94.56 $(75.99)(45%)
G-2 (≥ 4,000 scfh)$170.55 $419.08 $248.53 146%
G-3 (Large Commercial)$780.34 $1,712.36 $932.02 119%
(Residential)
Tier 1 Rates ($/therm)$0.8944 $1.0456 $0.15 17%
Tier 2 Rates ($/therm)$2.2873 $2.5203 $0.23 10%
(Residential Master-Metered and Commercial)
Uniform Rate $1.1749 $1.2204 $0.05 4%
(Large Commercial)
Uniform Rate $1.1633 $1.1874 $0.02 2%
Table 6 shows the impact of the proposed February 1, 2026 rate changes on the median
monthly residential bill for representative average winter and summer bills, excluding supply-
related cost changes.
25 City’s Rates Website https://www.cityofpaloalto.org/files/assets/public/v/25/utilities/rates-schedules-for-
utilities/residential-utility-rates/monthly-gas-volumetric-and-service-charges-residential-3.pdf
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Table 6: Bill Impacts of Proposed Rebalancing and Rate Design in 2026 Report
Monthly Bill1
Rate Schedule Monthly Usage (Therms)Current
Rates
Recommended
FY2026 Rate
Bill
Impact
RESIDENTIAL
Summer: 10; Winter: 30 $50.78 $54.73 8%
Summer: 17; Winter: 51
(median)
$73.44 $79.33 8%
Summer: 30; Winter: 80 $127.24 $134.60 6%
G-1
Summer: 45; Winter: 150 $247.31 $263.50 7%
COMMERCIAL AND RESIDENTIAL MASTER METER
Small: 35 $242.74 $103.05 (58%)
Medium: 280 $739.59 $676.33 (9%)
G-2
Large: 2,648 $5,558.74 $5,927.83 7%
G-3 20,834 $42,696.69 $44,131.74 3%
The annual gas bill for the median residential customer is projected to be 8% higher due to the
cost-of-service adjustments. The actual impact may be different because customer gas usage
varies and commodity price changes monthly.
Table 7 presents the median residential bills for Palo Alto and PG&E customers from FY 2022 to
FY 2026. The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area
which includes Palo Alto’s surrounding communities.
In FY 2025, the estimated annual gas bill for the median Palo Alto residential customer was
about 16% lower than that of a PG&E customer with equivalent consumption. With the
implementation of the 2026 Report, Palo Alto median residential bills are expected to be about
8% lower than PG&E bills in FY 2026. This projection assumes PG&E does not implement
additional rate increases between now and July 2026.
FY 2022 $657.83 $724.24 (9%)
FY 2023 $891.89 $845.03 6%
FY 2024 $753.28 $764.70 (1%)
FY 2025 $836.93 $991.24 (16%)
FY 2026 Current $881.31 $1,040.18 (15%)
FY 2026 Recommended
Annual
(374 Therms)
$952.02 $1,040.18 (8%)
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Table 8 presents the median commercial bills for Palo Alto and PG&E customers from FY 2022
to FY 2026. Palo Alto bills have been higher than PG&E’s bills over the years, mainly due to
higher customer charges. With the recommendations from the 2026 Report, commercial
customer charges have been adjusted downward for the majority of commercial customers,
making bills more competitive with PG&E. With the implementation of the 2026 Report and the
proposed rate increases, Palo Alto median commercial bills are expected to be about 16%
higher than PG&E bills in FY 2026, assuming PG&E does not implement additional rate
increases.
Table 8: Commercial Annual Natural Gas Bill Comparison ($/year)
Time Period Median Usage*Palo Alto PG&E Zone X % Difference
FY 2026 Current $8,875.07 $6,989.03 27%
FY 2026 Recommended $ 8,115.89 $6,989.03 16%
*Calculated based on G-2 with meter capacity of >220 and <4,000 scfh
Gas COSA Design Principles
Design Principle 1: Rates must be based on the reasonable cost to serve customers. This is the
overriding principle for the cost-of-service analysis (COSA); all other rate design
considerations are subsidiary to this basic premise.
Design Principle 2: The COSA should involve a review of all existing rate schedules for
applicability in the COSA.
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distribution system, rather it is directly connected to the City’s intertie with PG&E. Since the
sole customer is the Public Works department, it is more efficient to recover fueling costs via an
interdepartmental cost recovery transfer than a separate rate schedule, and the City is
separately developing a cost-based fee for service administration.27 Changes in this fee do not
materially impact the COSA results.
Design Principle 3: The impact of any proposed changes on low-income customers should be
evaluated in alignment with state law, including, without limitation, Public Utilities Code
sections 890 and 898.
The study evaluated rate impacts on low-income residential customers. Approximately 400
customers participate in the City’s low-income program which is ratepayer funded, consistent
with Public Utilities Code Sections 890 and 898, with average monthly usage of 30 therms. Most
customers would see bill impacts under $5 per month, and the total cost to mitigate all bill
impacts of the 2026 Report on low-income customers who are enrolled in the Low-Income Rate
Assistance program or the Low Income Home Energy Assistance Program would be
approximately $30,000 per year.
Design Principle 4: Determine the proper allocation of fixed and variable costs and how those
can be implemented in various rate designs.
All rate classes include a fixed monthly charge to recover customer-related costs such as
metering, billing, and service connections. The 2026 Report recommends a scaled fixed charge
in the G-2 customer class to reflect the diversity within that class. The G-1 class includes a
tiered variable rate structure that distributes capacity costs between Tier 1 and Tier 2 using the
base and excess method to appropriately collect demand costs from customers impacting
system capacity costs. The G-2 and G-3 classes recover capacity costs through uniform
volumetric charges, maintaining simplicity while reflecting consistent cost drivers.
Design Principle 5: Review non-rate revenue sources that may be available for rate discounts
or rebates
The 2026 Report also reviewed non-rate revenue sources that could potentially fund rate
discounts or rebates. In FY 2025, an estimated $0.399 million in interest income was available
for this purpose. At the end of FY 2025 there was $15.046 million available in the gas utility’s
Cap & Trade Reserve. The Cap & Trade Reserve holds revenues from the auction of freely
allocated Gas Utility greenhouse gas emission allowances. Cap & Trade reserve funds must be
spent in accordance with California Air Resources Board regulations as well as with the City
Council’s policies in Resolution 9487 and 10077.28 CARB’s regulations require that the City
utilize the auction sale proceeds exclusively for the benefit of the City’s natural gas retail
ratepayers and consistent with the goals of AB 32.29 The City Council’s policy allows for the use
27 The CNG station has a public station that is currently non-operational and a CNG station for refueling City
vehicles. Both portions of the station are operated by the Public Works department.
28 Resolution 9487 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=53850 ; Resolution
10077 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=61567
29 Title 17 California Code of Regulations Sections 95892 (d)(2) and 95893 (d)(3).
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of Gas Cap and Trade revenue for investment in energy efficiency programs for the natural gas
portfolio and retail customers, purchases or investment in cost-effective renewable biogas
resources for the gas portfolio, fuel switching from natural gas to electricity that reduces
greenhouse gas emissions, investment in other carbon reduction activities for the natural gas
utility, including system maintenance or replacement to reduce fugitive gas emissions; and
rebates to natural gas retail ratepayers. The policy expresses a preference for greenhouse gas
reduction activities over rebates.
FISCAL/RESOURCE IMPACT
STAKEHOLDER ENGAGEMENT
33 The
Commissioner who voted against the climate credit option said that green funds should not be
used to subsidize the use of fossil fuels. The video of the meeting is available on the City’s
website at the following link: https://www.youtube.com/watch?v=021zJQHLADI
34
33 The Gas Utility is a covered entity under California’s Cap-and-Trade program. California Air Resources Board’s
Cap-and-Trade regulations authorize utilities to distribute Cap-and-Trade auction proceeds to some or all
ratepayers in a non-volumetric manner. (See CA. Code of Regs. Tit. 17 Sec. 95893(d)(3)(C)).
34 Staff presented the 2025 City of Palo Alto Natural Gas Cost of Service and Rate Study to the UAC and Finance
Committee.
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additional information to the Finance Committee, including an interim alternative
recommendation to continue the current FY 2025 rate structure based on the 2020 Cost Study,
with rate increases to meet FY 2026 revenue requirements, and provide a climate credit to
some of the G-2 small commercial customers (small and medium meter capacities), using
approximately $1.1 million in funding from the City’s Cap and Trade program revenue37
If the 2025 COSA had been implemented July 1, 2025, G-2 small and medium customers would
have received a reduction in their monthly service charges, as well as an increase in the
distribution charge per therm. The climate credit amount was calculated to make the G-2 small
and medium customer groups pay the same net amount as a result of retaining the current FY
2025 rate structure from July through December 2025, relative to what G-2 small and medium
customers would have paid under the 2025 COSA rates. The total cost of this climate credit is
$1.1 million. After discussion, the Committee voted unanimously to recommend the City
Council: 1) Revise the proposed FY 2026 rates to retain the current FY 2025 rate structure, with
rate increases to meet the revenue requirement for FY 2026 in the gas utility; 2) In FY 2026
only, apply a combination of climate credit (using Cap and Trade auction revenues) and FY 2025
gas utility interest income to G-2 customers (small and medium meter capacities) in the total
amount of $1.1 million and 3) Refer staff to return to the Utilities Advisory Commission (UAC) to
further review the FY 2025 Cost of Service Study (COSA) assumptions and principles.
On May 12, 2025 staff briefed the City Council on this topic and Council members asked
questions and discussed the item but did not take any action.
On June 16, 2025 the City Council returned the issue of a one-time credit to the UAC to be
considered at the time they review the updated COSA.
On September 2, 2025, the Finance Committee considered the UAC’s recommendation to direct
staff to use Proposition 26 as the Design Principle for the Gas Cost of Service Analysis and work
with the UAC on review of a recommended gas rate schedule effective by January 2026. The
Finance Committee voted unanimously to recommend the City Council direct staff to follow the
reasonable-cost analysis required by Proposition 26, and that staff work with the UAC on a
recommendation to the Council on revised gas rates effective January 2026.
On September 15, 2025, (Staff Report 2507-4958) the City Council directed staff to follow the
reasonable-cost analysis required by Proposition 26, and that staff collaborate with the UAC to
develop revised gas rates effective January 2026, based on the following design principles: (1)
Rates must be based on the reasonable cost to serve customers. This is the overriding principle
for the cost of service analysis (COSA); all other rate design considerations are subsidiary to this
basic premise; (2) The COSA should involve a review of all existing rate schedules for
37 May 7, 2025 Finance Committee Meeting
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=530a4f
25-5455-4cec-a95c-5190d95d9a4f; Video: https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Item
2.a., 3.b. Supplemental Report https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Video
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applicability in the COSA; (3) The impact of any proposed changes on low-income customers
should be evaluated in alignment with state law, including, without limitation, Public Utilities
Code sections 890 and 898; (4) Determine the proper allocation of fixed and variable costs and
how those can be implemented in various rate designs; (5) Review non-rate revenue sources
that may be available for rate discounts or rebates.
39. Ultimately, a majority of the UAC recommend Finance Committee and City
Council approval. More details are described above in the “Background” section and a video
recording of the meeting is available here: https://www.youtube.com/watch?v=1e6NrB2KDCw.
ENVIRONMENTAL REVIEW
ATTACHMENTS
APPROVED BY:
39 November 5, 2025 UAC meeting item 4,
https://cityofpaloalto.primegov.com/Portal/Meeting?meetingTemplateId=17466
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Attachment A
* NOT YET APPROVED *
1
6059692
Resolution No.
Resolution of the Council of the City of Palo Alto Approving the 2026
Natural Gas Cost of Service Analysis Report, Amending Rate Schedules
G-1 (Residential Gas Service), G-2 (Residential Master-Metered and
Commercial Gas Service), and G-3 (Large Commercial Gas Service), and
repealing G-10 (Compressed Natural Gas Service).
R E C I T A L S
A. The City of Palo Alto (“City”) periodically conducts a Natural Gas Cost of Service
Analysis to follow the reasonable-cost analysis required by Proposition 26.
B. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
C. On December ___, 2025, the City Council heard and approved the proposed
rate increase at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the 2026 Natural Gas Cost of Service Analysis
Report (Attachment B to the staff report presented to the City Council on December __ 2025);
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule G-1 (Residential Gas Service) is hereby amended to read as attached and incorporated.
Utility Rate Schedule G-1, as amended, shall become effective February 1, 2026 (Attachment C to
the staff report presented to the City Council on December __ 2025);
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-2 (Residential Master-Metered and Commercial Gas Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule G-2, as amended, shall
become effective February 1, 2026 (Attachment C to the staff report presented to the City
Council on December __ 2025);
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-3 (Large Commercial Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-3, as amended, shall become effective February 1, 2026
(Attachment C to the staff report presented to the City Council on December __ 2025);
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule Rate Schedule G-10 (Compressed Natural Gas Service) is hereby repealed,
effective February 1, 2026.
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Attachment A
* NOT YET APPROVED *
2
6059692
SECTION 6. The City Council finds as follows:
a. Revenues derived from the gas rates approved by this resolution do not exceed the
funds required to provide gas service.
b. Revenues derived from the gas rates approved by this resolution shall not be used
for any purpose other than providing gas service, and the purposes set forth in
Article VII, Section 2, of the Charter of the City of Palo Alto.
SECTION 7. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
//
//
//
//
//
//
//
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Attachment A
* NOT YET APPROVED *
3
6059692
SECTION 8. The Council finds that approving the FY 2026 Natural Gas Cost of Service
Analysis Report does not meet the California Environmental Quality Act’s (CEQA) definition of a
project under Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(5),
because it is an administrative governmental activity which will not cause a direct or indirect
physical change in the environment, and therefore, no environmental assessment is required.
The Council finds that changing gas rates to meet operating expenses, purchase supplies and
materials, meet financial reserve needs and obtain funds for capital improvements necessary to
maintain service is not subject to the California Environmental Quality Act (CEQA), pursuant to
California Public Resources Code Sec. 21080(b)(8) and Title 14 of the California Code of
Regulations Sec. 15273(a). After reviewing the staff report and all attachments presented to
Council, the Council incorporates these documents herein and finds that sufficient evidence has
been presented setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
Assistant City Attorney City Manager
Director of Utilities
Director of Administrative Services
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22213852.2
Natural Gas Cost of Service
Analysis Report
City of Palo Alto
P R E P A R E D B Y E E S C O N S U L T I N G
November 6 , 202 5
Item 1
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Natural Gas Cost of Service
Analysis Report
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16701 NE 80th Street Suite 102 Redmond, WA 980 52 425-889 -2700 Fax 866-611-3791 www.eesconsulting.com
G e o r g i a Te x a s A l a b a m a N e w H a m p s h i r e Wi s c o n s i n Mai n e Wa s h i n g t o n C a l i f o r n i a
Amber Gschwend, Director
amber.gschwend@gdsassociates.com
direct 425-655-1042
November 6, 2025
Lisa Bilir, Senior Resource Planner
City of Palo Alto
250 Hamilton Avenue
Palo Alto, CA 94301
SUBJECT: Draft 2026 Natural Gas Cost of Service Analysis Report
Dear Ms. Bilir:
Attached please find the draft 2026 Natural Gas Cost of Service Analysis (2026 Report) for the City of Palo
Alto (City) prepared by EES Consulting (EES), a GDS Associates company.
We based the conclusions and recommendations contained within this report on industry practice and
accepted rate setting principles consistent with California law. The assumptions are based upon the
financial and metering data provided by the City. The results are consistent with the cost of service and
rate making principles considered by the City.
EES developed this study in consultation with the City’s staff and legal counsel, and we appreciate the
internal efforts that have helped to refine the study. We also would like to thank the Utility Advisory
Commission subcommittee members for their input and feedback. Collaboration among all these
stakeholders has improved the recommendations and strengthened the foundation in this utility planning
effort. The findings, conclusions, and recommendations of this report supply the basis for the
recommended, fair and equitable rates.
Very truly yours,
Amber Gschwend
Director, EES Consulting Director, EES Consulting
amber.gschwend@gdsassociates.com russ.schneider@gdsassociates.com
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CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING i
TABLE OF CONTENTS
1 EXECUTIVE SUMMARY ................................................................................................... 1
1.1 System Description ............................................................................................................................................. 2
1.2 Rate Study Overview .......................................................................................................................................... 3
1.2.1 Revenue Requirement .................................................................................................................. 3
1.2.2 Cost of Service Analysis ............................................................................................................... 5
1.2.3 Rate Design Recommendations .................................................................................................. 5
1.2.4 Rate Change Recommendations ............................................................................................... 10
2 REVENUE REQUIREMENT DEVELOPMENT ................................................................. 12
2.1 Overview of the City’s Revenue Requirement Methodology........................................................... 12
2.2 Supply Costs ....................................................................................................................................................... 12
2.3 Distribution Costs ............................................................................................................................................. 13
2.4 Debt Service and Rate-Funded Capital Improvement Program (CIP) .......................................... 13
2.5 General Fund Transfer .................................................................................................................................... 14
2.6 Miscellaneous/Other Revenues .................................................................................................................. 14
2.7 Transfers to/from Reserves ........................................................................................................................... 14
2.8 Summary of Revenue Requirement........................................................................................................... 14
3 COST OF SERVICE ANALYSIS ....................................................................................... 16
3.1 COSA Definition and General Principles .................................................................................................. 16
3.2 City Natural GAs Distribution COSA Methodology ............................................................................. 17
3.2.1 Functionalization ........................................................................................................................ 17
3.2.2 Classification and Allocation of Costs ..................................................................................... 17
3.3 Average & Excess (A&E) ................................................................................................................................ 22
3.3.1 Average & Excess Calculation ................................................................................................... 23
3.4 Customer Weighting for Meter Costs ...................................................................................................... 26
3.5 Customer Classes of Service ......................................................................................................................... 27
3.6 Cost of Service Results ................................................................................................................................... 27
4 RATE DESIGN ................................................................................................................ 32
4.1 Recommended Rate Design: Distribution ............................................................................................... 32
4.1.1 Residential (G1) .......................................................................................................................... 32
4.1.2 Small Commercial and Residential Master-Metered (G2) ..................................................... 35
4.1.3 Large Commercial (G3) .............................................................................................................. 37
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4.2 Supply Charges ................................................................................................................................................. 38
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CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 1
1 Executive Summary
The City of Palo Alto (City) retained EES Consulting (EES), a GDS Associates company, to perform a natural
gas cost of service analysis (COSA) and rate study for Fiscal Year 2025-2026 (FY 2025-2026)1 (2026 Report)
as part of its ongoing efforts to maintain fiscally prudent, fair, cost-based rates for its natural gas
customers. This 2026 Report is primarily concerned with the development of natural gas distribution
rates.
While distribution rates are the primary focus of this study, the City also charges four supply-related rates.
These supply-related rates recover the costs that are outside of the immediate control of the City, such
as the cost of purchasing gas and transporting it to the City’s distribution system. These four rates are: 1)
the gas commodity rate, which represents the cost of buying gas in the markets, 2) the gas transportation
rate, which represents the cost of transporting purchased gas to Palo Alto, 3) the Cap and Trade
compliance rate, which represents the cost of mandated participation in the State’s cap and trade
program, and 4) the carbon offset rate, which represents the cost of buying offsets for the City’s Carbon
Neutral Gas Portfolio. These four charges are discussed at the end of this report.
The recommendations from this report are the second step in a 2-step rate adjustment process. The City
adopted this 2-step approach as a phase-in of rate changes. The first adjustment was an 8.7% across the
board rate increase effective July 1, 2025. This second adjustment is a rebalancing adjustment across rate
classes based on the results of this study.
The starting point for this analysis was the study completed for FY 2019-2020 (2020 Study). The City
updated the 2020 COSA model for FY 2020-2021 period (2021 Study), with some assistance by EES. Since
then, the City has implemented distribution system rate adjustments by uniformly adjusting distribution
rates using the percent change in the distribution revenue requirement; thus, distribution rates since 2021
have reflected the 2020 Study framework with an 8.7% increase to all rate schedules in July of 2025 based
on the City’s budget increase.
This 2026 Report is a comprehensive update to the 2020 Study. All assumptions and inputs have been
updated and new rate designs incorporated into the recommendations. This 2026 Report also
incorporates the City’s design principles in its recommendations.2
EES worked closely with the City’s technical staff, management, and Utility Advisory subcommittee
members to refine data inputs for gas sales, expenses, and assets. EES had no issues obtaining appropriate
1 July 2025 through June 2026.
2On September 15, 2025, (Staff Report 2507-4958) the City Council directed staff to follow the reasonable-cost
analysis required by Proposition 26, and that staff collaborate with the UAC to develop revised gas rates effective
January 2026, based on the following design principles: (1) Rates must be based on the reasonable cost to serve
customers. This is the overriding principle for the cost of service analysis (COSA); all other rate design considerations
are subsidiary to this basic premise.; (2) The COSA should involve a review of all existing rate schedules for
applicability in the COSA; (3) The impact of any proposed changes on low-income customers should be evaluated in
alignment with state law, including, without limitation, Public Utilities Code sections 890 and 898; (4) Determine the
proper allocation of fixed and variable costs and how those can be implemented in various rate designs; (5) Review
non-rate revenue sources that may be available for rate discounts or rebates.
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CITY OF PALO ALTO Natural Gas Cost of Service Analysis
prepared by EES CONSULTING 2
data responses or clarification when necessary and commends the transparency of the process and the
capability of internal resources.
1.1 SYSTEM DESCRIPTION
The City’s gas utility serves approximately 23,386 customer accounts over an area of approximately 26
square miles. The gas utility is responsible for the operations and maintenance of the distribution system,
and it purchases all gas from outside suppliers. Total gas consumption in the City forecasted for FY 2025-
2026 is 25.8 million therms. It is expected for sales to continue near their current weather-adjusted level
of 25 to 26 million therms per year and near the current volume of services. Table 1-1 shows the number
of services and annual gas use for each rate class.
TABLE 1-1: NUMBER OF SERVICES UNDER CURRENT RATE SCHEDULES AND
FORECASTED ANNUAL USE IN FY 2025-2026
Rate Schedule Services Annual Use, therms
G1 Residential 21,163 9,762,524
G2 Residential Master Metered and Commercial 2,193 11,506,051
G3 Large Commercial 30 4,510,914
Total 23,386 25,779,489
Gas utility rate schedules consist of a fixed Monthly Service Charge ($/meter/month) and a volumetric
Distribution Charge ($/therm), which vary by rate class. Volumetric charges recover the proportional costs
of both commodity purchases and variable distribution (infrastructure) costs.
Table 1-2 summarizes the rate classes and current rate design for the distribution portion of the rate
schedule. It does not include these volumetric supply charges: Commodity Charge (Monthly Market
Based), Cap and Trade Compliance Charge, Transportation Charge, and Carbon Offset Charge.
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TABLE 1-2: CURRENT DISTRIBUTION RATE DESIGN
Utility Rate Schedule Description Current Rate Design
G1: Residential Separately metered:
Single-family residential customers
Multi-family residential customers
2-Tier Volumetric Charge with seasonal
lower-cost tier 1 quantities
Tier 1 Summer:1 20 therms/30-day-billing
Tier 1 Winter: 60 therms/30-day-billing
G2: Residential Master-
Metered and
Commercial (“Small
Commercial”)
Commercial customers who use less
than 250,000 therms per year at one
site, and master-metered residential
customers in multifamily residential
Volumetric Charge, $/therm
G3: Large Commercial
least 250,000 therms per year at one
3
Volumetric Charge, $/therm
1. Summer rates are effective April 1 through October 31. Winter rates are effective November 1 through March
31.
1.2 RATE STUDY OVERVIEW
The purpose of this report is to discuss the data inputs, assumptions, and results that were part of
developing the rate study. A comprehensive rate study generally consists of three separate, yet
interrelated analyses. These three analyses include a revenue requirement, COSA, and rate design.
1. Revenue Requirement Analysis: This analysis examines the various sources and uses of funds for the
utility, and it determines the overall revenue required to operate the utility.
2. Cost-of-Service Analysis (COSA): COSA is used to determine the fair allocation of the total revenue
requirement to the various customer classes of service (e.g., residential, small commercial, large
commercial). This analysis provides a determination of the level of revenue responsibility of each class
of service and the adjustments from current revenues required to meet the cost of service.
3. Rate Design Analysis: The third analysis involves evaluating the rate design options available and
designing rate schedules that can be applied to each rate class to collect revenues to cover the cost
to serve customers in that class.
1.2.1 Revenue Requirement
The first step in completing a rate study is to develop the revenue required from rates. A revenue
requirement analysis compares the overall rate revenue demands of the utility based on its forecasted or
budgeted expenses less any sources of non-rate revenue. Over the course of the study period, the City
prepared several financial analyses that included a forecast of FY 2025-2026 sales, revenues, and
expenses. The City has an in-depth accounting and data system that keeps track of ongoing and budgeted
or approved expenditures. EES based the forecasts on projected FY 2026 expenses and sales estimates for
the natural gas utility. The 2026 Report uses a cash-basis method for determining the City’s revenue
3 In addition to these standard rate classes, City of Palo Alto Utilities (CPAU) provides service to its CNG facility. This
facility does not utilize the distribution system, rather it is directly connected to the intertie with PG&E. As such, the
City is separately developing a cost-based fee for service administration. Changes in this fee do not materially impact
the COSA results.
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requirement based on the City’s financial forecast. The cash-basis revenue requirement is appropriate
because it is consistent with how the City forecasts expenses for the natural gas utility.
FY 2025-2026 natural gas commodity costs are included in City’s financial plan. However, these costs are
adjusted monthly to pass through actual commodity rates charged to the City by its wholesaler. Therefore,
commodity charges are not set based on the 2026 Report; the 2026 Report only evaluates appropriate
distribution charges for the year.
Table 1-3 summarizes the FY 2025-2026 distribution revenue requirement totaling $41.3 million. Rates
were adjusted on July 1, 2025 to meet this requirement using the straight-line inflator approach. Because
the rate levels have been adjusted to collect the FY2026 revenue required from rates, the proposed
rebalancing and rate design changes recommended in the 2026 Report do not require an overall increase
in rate revenue. The 2026 Report recommends rebalancing between rate classes based on the COSA
results, and this rebalancing has rate and bill impacts to individual customers and across rate classes, as
summarized in Table 1-4.
TABLE 1-3: GAS DISTRIBUTION SYSTEM REVENUE REQUIREMENT: FY 2025-2026 Revenue Requirement
Distribution O&M $9,797,408
Customer Accounts and Services $3,208,008
Administration and General $5,002,927
Debt Service & CIP from Rates $8,339,643
General Fund Transfer $9,734,580
Total Expenses $36,082,566
Transfers to Reserves $5,874,887
Other Revenues ($689,111)
Total Revenue Required from Rates (Revenue Requirement) $41,268,342
Revenues Based on Rates Currently in Effect $41,268,342
Total Required Rate Revenue Increase (Decrease) 0%
TABLE 1-4 BILL IMPACTS OF PROPOSED REBALANCING AND RATE DESIGN
Rate Schedule Monthly Usage (Therms)
Current
Rates
Recommended
FY2025-2026 Rate
Bill
Impact
Residential
G-1 Summer: 10; Winter: 30 $50.78 $54.73 8%
Summer: 17; Winter: 51 $73.44 $79.33 8%
Summer: 30; Winter: 80 $127.24 $134.60 6%
Summer: 45; Winter: 150 $247.31 $263.50 7%
Commercial
G-2 Small: 35 $242.74 $103.05 (58%)
Medium: 280 $739.59 $676.33 (9%)
Large: 2,648 $5,558.74 $5,927.83 7%
G-3 20,834 $42,696.69 $44,131.74 3%
1. Includes supply-related costs; assumes 12-month impact.
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CITY OF PALO ALTO Natural Gas Cost of Service Analysis
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1.2.2 Cost of Service Analysis
Cost-of-service is important for the fair allocation of the revenue requirement to the various customer
classes of service. The revenue requirement shown in Table 1-3 for the City was functionalized, classified
and allocated.
Functionalization is the attribution of each cost line-item to one of four different functional parts of
gas service: (1) production (commodity), (2) transportation, (3) distribution, or (4) shared services.
This 2026 Report evaluates only distribution costs and distribution-related overhead (shared services).
Classification is the determination of whether the costs associated with a functionalized line item are
most appropriately allocated based on energy use (therms), demand (maximum system capacity), or
customer (simply having a service).
Allocation is the process of using the classification for each functionalized line item to assign costs to
each customer class. For example, a cost item classified as “energy use” might be allocated based on
annual therm use. This means that the line-item cost is directly correlated to the quantity of energy
used by each customer class annually. This process is described in more detail in the section titled
“Cost of Service Analysis.”
Ultimately, the COSA process requires analysis of how each customer class contributes to the expenses
incurred by the utility to provide service. Table 1-5 shows, by customer class, the revenue requirement
and revenue change needed for FY 2025-2026.
TABLE 1-5: DISTRIBUTION COSA RESULTS: FY 2025-2026
Projected FY 2025-
Revenue
FY 2025-2026
Deficiency/
Revenue
G1 – Residential $17,738,316 $19,210,223 ($1,471,907) 8.3%
$18,006,240 $16,095,484 $1,910,756 (10.6%)
$5,523,787 $5,962,635 ($438,848) 7.9%
Total $41,268,342 $41,268,342 $0 0.0%
1.2.3 Rate Design Recommendations
The final step in the rate study process is to design rates for each class of service. In California, local
governments are subject to Article XIII C of the California Constitution, as amended by Proposition 26,
which requires that gas rates and charges must not exceed the reasonable costs of providing gas service,
and requires that the City’s costs of gas service are allocated to each customer in a manner that bears a
fair or reasonable relationship to the customer’s burdens on, or benefits received from, the gas utility. As
a result, the City sets rates based on COSA results. The goal of rate design is to create rates that recover
costs from customers within each class based on the utility’s cost of providing service. The basis for each
rate design recommendation is provided in this section followed by the recommended rates.
All rate classes are charged a monthly service charge and volumetric charge to recover distribution costs.
EES does not recommend changes to this basic rate design structure, except for a refinement in the
development of the Monthly Service Charge for G2 customers. The refinement is based on additional
analysis of G2 class usage and costs. Section 1.2.3.2, Commercial provides more details on this change.
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1.2.3.1 Residential
The G1 distribution rates consist of a monthly service charge and a 2-tiered volumetric rate: the Tier 1
rate applies to usage up to the baseline quantity and the Tier 2 rate applies to all usage above the baseline.
The G1 rate structure proportionately recovers energy and demand (capacity) costs incurred by the class.
Specifically, individual residential customers have usage characteristics that are similar in both usage
profile and baseline usage. For the purposes of this 2026 Report, “Baseline” usage is defined as average
use and “usage profile” is defined as the shape of energy use over time. Figure 1-1 shows that the daily
usage profiles for residential customers are consistent between individual customers despite different
overall usage level (low, low-medium, medium-high, and high). Second, seasonal baseline usage within
the residential class is relatively uniform across individual customers. As such, a tier threshold can be
applied to customers without being discriminatory toward customers with higher use, because higher-use
customers only pay their proportional fair share of the incremental cost of serving that 2nd tier of use.
FIGURE 1-1: RESIDENTIAL DAILY GAS USE BY USAGE LEVEL:
DAILY SHARE (%) OF ANNUAL USE 4
While the tier rates do not change between seasons, the baseline quantity above which Tier 2 rates apply
does change and is higher in winter than in the summer because natural gas-based heating is used more
in the winter and causes higher gas consumption.5 Therefore, the class average therms are higher in the
winter than in the summer. This tiered structure ensures that all G1 customers pay for their Tier 1 demand,
but that all the costs of Tier 2 service are only borne by the customers that have Tier 2 demand. EES
calculated the G1 tiered rates using the Base and Excess method (discussed in more detail in Section 4.1)
and proposes a modest increase of summer baseline from 20 to 23 therms per thirty-day billing period.
4 CALMAC Customer Load Shapes - PG&E. https://www.calmac.org/customer_load_shapes_pge.asp
5 Usage above the Tier 1 baseline quantity is charged Tier 2 rate. The current quantity is 20 therms/30-day-billing in
summer and 60 therms/30-day-billing in winter.
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Table 1-6 summarizes the costs to be recovered in each rate component for G1.
TABLE 1-6: G1 RATES AND COST RECOVERY
Rate Component Recovers The Following Costs:
Monthly Service Charge Customer-related costs such as customer service, billing, and overhead adders
Tier 1 Volumetric Rate Energy-related costs plus 21% of demand-related distribution unit costs1
Tier 2 Volumetric Rate Energy-related costs plus 79% of demand-related distribution unit costs1
1See calculations in Section 4.1.1. Residential (G1) Rate Design, Table 4-3.
G1 usage patterns are distinguishable from G2 and G3 usage, and that difference in usage patterns is the
cause for a tiered approach to allocate costs among customers in the G1 (residential) class, but not in the
G2 or G3 classes. Average use is much more consistent (less variable) among all individually metered
residential customers in comparison to G2 or G3 customers. As shown in Table 1-7 below, G1 therm
consumption has a small variation between the median (midpoint consumption) and the average, and the
spread across all the data is relatively low compared with G2 and G3. To illustrate the relative variability,
the average is divided by the spread to produce 0.88 for G1. A higher value indicates that data is more
closely centered around the average value. The spread around G2 and G3 average use is much greater
(showing more variability), as indicated by the lower values of 0.33 and 0.41, respectively.
TABLE 1-7: AVERAGE THERMS/MONTH BY SERVICE ACCOUNT
G1
Residential
G2
Small Commercial
G3
Large Commercial
Average 33 462 13,534
Median 27 78 3,530
% Difference between Average and Median 23% 494% 85%
Spread (Standard deviation) 38 1,382 33,362
Average/Spread (coefficient of variation) 0.88 0.33 0.41
When average usage across individual customers in a class is similar, a certain threshold is associated with
a consistent or baseline share of system capacity that is used relatively proportionately by all customers;
usage above that threshold creates additional system capacity costs that are caused by only a small
portion of the customer base. Average use is an equitable threshold in a relatively low-spread
environment because it identifies the average consistent demand placed on the system by all users. Use
that exceeds the average creates a demand for additional capacity used by only a fraction of the
customers. A tiered system then allocates the additional (“excess”) capacity costs only among the
customers that placed the Tier 2 excess demands on the system. By structuring the rate this way, average
users are not forced to subsidize the costs of larger infrastructure they do not use. At the same time, the
initial average increment of usage is charged identically – so all users pay the same rate for usage up to
the baseline.
Natural gas is a service. Customers must pay not only for the commodity (the natural gas itself) that is
served to their property, but also for all of the infrastructure necessary to distribute the natural gas to the
property. For example, when all houses are the same size and have the same end-use systems, customers
who use an average or below-average amount of natural gas should not only pay proportionally less for
the commodity than high users because they are using proportionally fewer molecules of natural gas; they
should also pay proportionally less of the additional costs incurred by the utility to serve the customers
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who use excess energy at peak times (such as the incremental additional cost of a larger pipeline). A tiered
rate ensures that the City’s incremental additional costs to serve Tier 2 demands are charged to the cause
of those costs. Higher users therefore pay a marginally higher rate – but only for the portion of their use
that exceeds the average or baseline threshold.
1.2.3.2 Commercial
EES does not recommend changing the volumetric rate structure for G2 and G3 because the current
structure reasonably recovers individual customer energy and demand components according to how
each customer uses the system. While there are inherent differences in consumption across individual
customers within the G2 and G3 rate classes, the shape of these consumption profiles within each class
are relatively consistent as illustrated in Figure 1-2. Figure 1-2 illustrates the annual usage profiles for
different types of businesses. The differences in average consumption between customers are due
primarily to the type of business operation (end-use of natural gas i.e., refrigeration, heating, etc.) and
building footprint (square footage). Grocery store use averages 8 therms per day during the summer,
whereas government buildings average approximately 2 therms per day in the summer. Winter usage is
also significantly different between these business types, where grocery stores average 14 therms per day
and government buildings average closer to 8 therms per day. These differences in baseline usage mean
that a tiered rate applied to all customers within the class would result in subsidies between customers
with different baseline use. Because customers with higher baseline use would more often exceed the
threshold, those customers would pay more than their fair share of costs.
FIGURE 1-2: COMMERCIAL DAILY GAS USE BY BUILDING TYPE6
While these customers vary significantly in total gas usage, the usage profiles for commercial and
industrial customers are similar within each class (G2 or G3), as shown in Figure 1-2. Because customers
6 CALMAC Customer Load Shapes - PG&E. https://www.calmac.org/customer_load_shapes_pge.asp. The above
example profiles are included in G2 and G3 classes according to Table 3-4.
0
2
4
6
8
10
12
14
16
18
20
Th
e
r
m
s
Retail Religious Construction Office Government Grocery Health
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within each class have similar usage profiles, the cost to serve individual customers within each class is
similar from a volumetric perspective ($/therm). The similar cost of service is determined from the COSA
methodology which allocates costs based on class usage profile. Therefore, a uniform variable charge is
an equitable rate design for both G2 and G3 classes.
This 2026 Report updated input, assumptions, and calculations of fixed charges. The methodology and
supporting assumptions are detailed in Section 3. In addition to the methodology review, the 2026 Report
provides additional analysis for G2 meter capacity-related costs by comparing the average consumption
for various meter capacities. Fixed costs are higher for customers with larger capacity service because of
the larger and more expensive equipment required to provide higher capacity service. Three G2
subclasses are defined based on meter capacity, as shown in Table 1-8. The recommended monthly
service charge is developed based on the COSA methodology which, in part, allocates costs to each
customer class based on meter costs.
With the recommended rates, G2 customers would be charged a Monthly Service Charge based on
maximum meter capacity; customers with lower-capacity meters would pay a lower Monthly Service
Charge than those with higher capacity meters. For example, a customer with a meter capacity of 200
standard cubic feet per hour (scfh) would pay the lowest Monthly Service Charge, at $29.24.
TABLE 1-8: G2 MONTHLY SERVICE CHARGES: FY 2025-2026
CPAU Approved Maximum
7
Number of
Current Monthly
Service Charge
Monthly Service
Charge
1,136 $170.55 $29.24
940 $170.55 $94.56
117 $170.55 $419.08
While Table 1-8 shows the lower Monthly Service Charge for smaller G2 customers (defined as customers
with meter capacity up to 220 scfh), Table 1-9 illustrates that this same group of customers should also
receive an overall rate decrease. The rate decrease is primarily achieved through the lower monthly
service charge. The column “Revenue Requirement” in Table 1-9 presents the total revenue requirement
amounts (including fixed and variable costs) that correspond to the recommended Monthly Service
Charges shown in Table 1-8 above. The recommended rates for G2 are provided in Section 1.2.4.
7 All meters have a manufacturer-rated capacity and an approved for engineering maximum capacity. The CPAU
approved capacity is typically slightly lower than the manufacturer maximum capacity due to connected
characteristics and other variable conditions.
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TABLE 1-9: G2 REVENUES AND REVENUE REQUIREMENT: FY 2025-2026
CPAU Approved Maximum
2026 Revenues
at Current
Monthly Service
Revenue
Projected
FY 2026
Revenue
Change
$3,251,805 $1,740,448 ($1,511,358) (46.5%)
Above 220 but Below 4,000 $8,235,944 $7,630,668 ($605,276) (7.3%)
4,000 and Above $6,518,490 $6,724,368 $205,878 3.2%
Total G2 $18,006,240 $16,095,484 ($1,910,756) (10.6%)
Customers that exceed 250,000 therms per year in consumption are placed on the G3 rate schedule. For
this level of consumption, the service sizes and meter costs are much more uniform within the class
compared with G2. For example, the cost for the smallest meters in G3 is 56% of the cost for the largest
capacity meters. The same comparison for G2 results in the smallest capacity meter cost at less than 2%
of the cost of the largest capacity meter. Meter cost uniformity within a customer class is a factor in
determining a cost-based rate design for each class. Customers with larger meters are charged a higher
monthly Service Charge. Because individual customers within G3 have relatively uniform meter sizes and
costs, it is reasonable to charge the same monthly service charge to all G3 customers.
1.2.4 Rate Change Recommendations
Table 1-10 provides a comparison of current rates and recommended rates for FY 2026, including the
newly developed G2 Monthly Service Charge by meter capacity.
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TABLE 1-10: CURRENT AND RECOMMENDED RATES
Current FY 2025-2026 Percent
$18.40 $19.58 $1.18 6.4%
Distribution Charge ($/therm)
Tier 1
For Winter: first 60 therms/30-day-billing
For Summer: first 20 therms/30-day-billing
(current); first 23 therms/30-day-billing
$0.8944 $1.0456 $0.1512 16.9%
Tier 2
For Winter: over 60 therms/30-day-billing
For Summer: over 20 therms/30-day-billing
(current); over 23 therms/30-day-billing
$2.2873 $2.5203 $0.2330 10.2%
G2: Small Commercial (Total)
Monthly Service Charge $170.55 $78.03 ($92.52) (54.2%)
Distribution Charge ($/therm)
G2: Meter Capacity ≤ 220 scfh
Monthly Service Charge $170.55 $29.24 ($141.31) (82.9%)
Distribution Charge ($/therm) $1.1749 $1.2204 $0.0455 3.9%
G2: Meter Capacity > 220 scfh and < 4,000 scfh
Monthly Service Charge $170.55 $94.56 ($75.99) (44.6%)
Distribution Charge ($/therm) $1.1749 $1.2204 $0.0455 3.9%
G2: Meter Capacity ≥ 4,000 scfh
Monthly Service Charge $170.55 $419.08 $248.53 145.7%
Distribution Charge ($/therm) $1.1749 $1.2204 $0.0455 3.9%
G3 Large Commercial
Monthly Service Charge $780.34 $1,712.36 $932.02 119.4%
Distribution Charge ($/therm)
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2 Revenue Requirement Development
This section presents the development of the natural gas revenue requirement in the 2026 Report. A
revenue requirement analysis compares the overall revenues of the utility to its projected expenses and
determines the overall adjustment to rate levels required for the utility’s revenues to meet those
expenses.
2.1 OVERVIEW OF THE CITY’S REVENUE REQUIREMENT METHODOLOGY
The City utilizes the cash basis approach for determining its revenue requirement. The revenue
requirement for the City’s natural gas utility includes the elements shown in Table 2-1.
TABLE 2-1: ELEMENTS OF A CASH BASIS REVENUE REQUIREMENT
+ Operating Expenses
Natural Gas Supply Expense
Distribution O&M Expense
Customer Accounting Expenses
Administrative and General Expense
+ Capital Improvements Funded from Rates
+ General Fund Transfer
= Total Revenue Requirement
- Transfers from Reserves
- Miscellaneous Revenue Sources
= Net Revenues Required From Rates (or Net Revenue Requirement)
In this basic analytical framework, the first step in determining the revenue requirement is to select a
period over which to review revenues and expenses. This 2026 Report uses a future fiscal year test period
to correspond with the City’s budget year. The revenue requirement in this 2026 Report reflects the City-
provided financial forecast (budget) for FY 2025-2026.
The next step in the analysis was to translate the City-budgeted costs into the system of accounts used by
a natural gas utility.
2.2 SUPPLY COSTS
While this 2026 Report does not include an analysis for gas supply costs, a summary of these costs is
provided here for reference. As with most natural gas utilities, a major expense associated with operating
the utility is the cost of natural gas supply. The City is projecting FY 2025-2026 gas supply costs at $29.2
million or 42 percent of the total FY 2025-2026 revenue requirement. Supply costs are charged to
customers via four pass-through rate components. The following rate components are adjusted monthly
to reflect actual costs:
1. Gas commodity: This represents the cost of buying gas in the market.
2. Gas transportation: This reflects the cost of transporting purchased gas from the delivery points
to Palo Alto.
3. Cap and Trade compliance: This covers the cost of mandated participation in the State’s cap and
trade program.
4. Carbon offset charge: This accounts for the cost of buying offsets needed to comply with the City’s
Carbon Neutral Gas Portfolio Program.
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While the cost of natural gas supply is included in the 2026 Report, it is treated as a separate category
because the cost of natural gas supply is collected through separate rate components. A description of
these separate rates is provided in Section 4.2.
2.3 DISTRIBUTION COSTS
Total FY 2025-2026 revenue requirement for distribution is projected to be $41.3 million. Distribution
operating expenses include the following (other expenses are discussed in Sections 2.4 through 2.7):
Physical system costs of $9.8 million. These costs include the operation and maintenance of
distribution system infrastructure such as distribution mains, regulators, and meters.
Customer service-related costs of $3.2 million. These costs include meter reading, billing, key account
representatives and general customer service.
Administrative and general costs of $5.0 million. These costs include functions like accounting,
purchasing, legal, and other administrative functions provided by the City’s General Fund staff, as well
as Utilities Department administrative overhead, insurance, rent, and transfers to city non-enterprise
funds for items such as utility building improvements and to other enterprise funds for items such as
the gas utility’s share of Geographic Information System project costs.
The customer service category includes $0.5 million in expenses for energy efficiency, conservation
(demand side management), and low-income assistance programs. These expenses are incurred by the
gas enterprise as part of a program established by the City pursuant to California Public Utilities Code
Section 898. By virtue of this program, gas customers are exempted from a state surcharge that would
otherwise be collected on utility bills pursuant to Public Utilities Code Section 890. The City’s energy
efficiency and demand-side management programs reduce customer gas demand and are designed to
reduce the need for capital expenditures that would otherwise be needed to expand the capacity of the
gas distribution system.
2.4 DEBT SERVICE AND RATE-FUNDED CAPITAL IMPROVEMENT PROGRAM (CIP)
The City must cover its capital improvement projects (CIP) through either debt, cash from rates, or
external sources such as grants or loans.
For FY 2025-2026, the City has debt service payments of $0.8 million for past borrowings to fund CIP,
specifically the 2011 Series A Utility Revenue Refunding Bonds. This bond issuance was to refinance the
$18 million principal remaining on the Utility Revenue Bonds, 2002 Series A issued for the Gas and Water
Utilities to finance various improvements to the distribution systems.
The majority of CIP is funded from rate revenues. For FY 2026, the budgeted CIP is $7.5 million. This
amount is partially offset by contributions made by new customers in the form of connection fees. The
$0.7 million in connection fees is included in other revenues, which is further discussed below. Total FY
2025-2026 debt service and rate-funded CIP is $8.3 million before customer contributions.
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2.5 GENERAL FUND TRANSFER
The City calculates the equity transfer from its natural gas utility based on a methodology approved by
voters in November 2022.8 The General Fund Transfer is estimated to be $9.7 million in FY 2025-2026.
2.6 MISCELLANEOUS/OTHER REVENUES
The City receives additional operating and non-operating revenues. These revenues include interest
earned on City reserves, connection fees (customer charges that recover the cost of capital facilities
necessary to accommodate increased demand on the system) and other miscellaneous service revenues.
Miscellaneous revenues include customer discounts and uncollectible bills. These are recovered from non-
rate revenues, including interest income from investments. For FY 2025-2026, the projection for the total
miscellaneous/other revenues is $0.7 million. The miscellaneous/other revenues are separate from fixed
and volumetric charges for natural gas service and are therefore considered an offset to the total revenue
required from retail rates.
2.7 TRANSFERS TO/FROM RESERVES
In its FY 2025-2026 natural gas financial forecast, the City is anticipating that $5.9 million of rate revenues
will need to be added to the reserves in FY 2025-2026 to restore both the operating and CIP reserves. The
operating reserve balance is adjusted to meet future debt service requirements as projected from the
City’s financial plan. Additionally, the City plans to make contributions to the CIP reserve fund to balance
year-to-year fluctuations in CIP expenditures. The use of the reserve fund allows the City to have more
stable and gradual rate increases over time.
2.8 SUMMARY OF REVENUE REQUIREMENT
The City’s Distribution revenue requirement for the FY 2025-2026 test period is summarized in Table 2-2.
No overall rate increase is required to meet projected FY 2025-2026 costs, due to current overall rate
levels.
8 In November 2022, voters approved Measure L, amending the Municipal Code, Section 2.28.185, “Natural Gas
Utility Transfer” states: “Each fiscal year the City Council may transfer from the natural gas utility to the general fund
an amount equal to 18% of the gross revenues of the gas utility received during the fiscal year two fiscal years before
the fiscal year of the transfer. At its discretion, the City Council may decide to transfer a lesser amount. The projected
cost of the transfer shall be included in the City’s retail natural gas rates as part of the cost of providing gas service.”
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TABLE 2-2: SUMMARY OF NATURAL GAS DISTRIBUTION REVENUE REQUIREMENT: FY 2025-2026 Revenue Requirement
Distribution O&M $9,797,408
Total Expenses $36,082,566
$5,874,887
Total Revenue Required from Rates (Revenue Requirement) $41,268,342
Additional Rate Revenue Needed without Gas Supply $0
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3 Cost of Service Analysis
The objective of the cost-of-service analysis (COSA) is to allocate the costs in the revenue requirement to
each customer class of service to determine the cost to serve those customers. An essential principle of
cost allocation is the concept of cost-causation. Cost-causation evaluates which customer or group of
customers causes the utility to incur certain costs by linking system facility investments and the operating
costs to serve certain facilities to the way customers use those facilities and services. This section of the
report discusses the general approach used to allocate the City’s costs and presents a summary of the
results.
3.1 COSA DEFINITION AND GENERAL PRINCIPLES
A COSA study allocates the costs of providing utility service to the various customer classes served by the
utility based upon the cost-causal relationship associated with specific expense items. This approach is
taken to develop a fair and equitable designation of costs to each class of service. The COSA allocates joint
and common costs among the various classes using factors appropriate to each type of expense. The COSA
is the second step in a traditional three-step process for developing natural gas service rates, after
development of the revenue requirement but before designing rates.
This COSA study is an embedded cost analysis. Embedded costs generally reflect the actual costs incurred
by the utility and closely track the costs kept in its accounting records.
There are three basic steps to follow in developing a COSA: functionalization; classification; and allocation.
Functionalization separates costs into major categories that reflect the different services provided to
customers and the types of assets used to provide those services. The primary functional categories for
the City’s natural gas utility are supply and distribution.
Classification determines the portion of each cost that is related to specific cost-causal factors, or
“classifiers.” These classifiers might be demand-related (related to the class of service’s peak energy usage
over a given period), energy-related (related to the total energy used by the class of service over a given
period), or customer-related (costs incurred as a result of receiving service, regardless of the energy use
or peak demand). Natural gas supply or commodity costs are related to the amount of natural gas
purchased and are therefore considered energy-related. The distribution system is designed to extend
service to all customers attached to the system and to meet both the peak day demand and the annual
energy requirement of each customer, meaning that costs are both demand-related and energy-related.
Some operational costs, such as billing, are generally customer-related. Costs can also be classified based
on whether they are system-wide or specifically assigned to a customer or group of customers, if
appropriate.
Allocation of costs to specific classes of service happens after those costs have been classified. Allocation
factors are chosen to allocate the costs assigned to each classification, and the share of costs allocated to
each class of service are based on the class’s contribution to the specific allocation factor selected. For
example, certain distribution costs might be classified as partially demand-related and partially energy-
related. The demand-related costs could be allocated to the classes of service using each class’s
contribution to the annual system peak day demand (the highest day for the system as a whole at any
time during the year), while the energy-related costs would be allocated to classes based on their annual
energy usage. In this example, the allocation factors are 1) each class of service’s contribution to the
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annual system peak day demand, and 2) the annual energy usage of each class of service. An analysis of
customer requirements and usage characteristics is completed to develop allocation factors reflecting
each of the classifiers employed within the COSA.
3.2 CITY NATURAL GAS DISTRIBUTION COSA METHODOLOGY
3.2.1 Functionalization
As mentioned previously, this rate study addresses only the distribution portion of the City’s gas utility.
As such, all costs included in the revenue requirement have already been functionalized as Distribution.
Distribution costs include are allocated based on the depreciated value of all the physical assets (“rate
base”) and all operating costs required to transport the natural gas commodity from the point of
interconnection across the City’s distribution system to customers at their meters.
3.2.2 Classification and Allocation of Costs
The classification and allocation factors used for each component of the rate base and revenue
requirement are shown in Table 3-1 and Table 3-2 and are discussed in more detail below. The purpose
of looking at the rate base in the COSA is to set the cost causation associated with the physical assets,
which are then used to guide the allocation of the annual expenses. The rate base for the City’s natural
gas utility consists of the net value of its physical assets – both the distribution system itself (“Distribution
Plant”) and the natural gas utility’s fair share of general City facilities, equipment, and other capital such
as software that provide for the administration and general costs of the utility (“General Plant”). The rate
base is taken from audited fiscal 2025 physical asset/plant values. The revenue requirement is a
forecasted future year.
Descriptions of each factor are included in Table 3-3. In general, this COSA employs the same methodology
used in the 2020 Study but with changes to allocation factors based on updated cost-causation.
Specifically, the distribution rate base classification was updated as discussed in Section 4.3 below.
Distribution costs are classified into the following components: demand, energy, customer, and direct
assignments. The demand component reflects the portion of costs driven by peak demand for natural gas.
The energy component is related to costs incurred to provide the annual amount of gas to customers or
groups of customers. The customer component covers the facility and operating costs that vary with the
number of customers, such as meters and billing. Directly assigned costs are costs that can be attributed
to just one or more rate classes. The following are the specific classifiers used for the City’s distribution
function:
Demand. Demand-related costs are those that vary with the peak demand or the maximum rates of
natural gas supply to classes of service. Customer and system demands for this analysis are measured
in peak day therms. Demand costs are generally related to the size of facilities needed to meet a
customer’s maximum daily demand. Generally, the rate base is allocated based on the Average &
Excess method which involves a demand component (see Section 3.3). The allocated rate base is then
used to allocate certain revenue requirement expenses.
Energy. Energy-related costs are those that vary with the total amount of natural gas consumed by
customer class. Usage measured in therms is used in this portion of the analysis. Energy costs are the
costs of consumption over a specified period, such as a month or year. Reserve fund contributions are
an example of a cost item that is allocated to customer classes based on therms used. This ensures
that each customer contributes to the reserve fund based on their proportional use of the system.
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Customer. Customer-related costs are those that vary with the number of customers. Customer costs
are weighted to account for differences in the cost of providing services to those customers. For
example, the service line and metering associated with serving a large commercial customer is larger
and more costly and requires substantially more work and material than the service line and meter
for a small residential customer. Customer service expenses are typically allocated to customers based
on some measure of number of customers or weighted customer service factors based on the amount
of time and complexity to provide service to different types of customers.
Direct Assignment. Some costs are directly assigned to specific classes of service. For example, costs
associated with specific account representatives to large commercial customers are allocated directly
to the G3 rate class. In exchange, G3 does not share in other customer service costs incurred by the
other classes.
The methodology for classification and allocation of the City’s rate base is summarized in Table 3-1. All
line items in this table are functionalized as Distribution.
Note that the rate base does not reflect the annual expenses associated with running the utility but
instead reflects the capital investments made by the utility for the physical assets in the distribution
system or that are part of the general administration of the utility. The purpose of looking at the rate base
in the COSA is to set the cost causation associated with the physical assets, which are then used to guide
the allocation of the annual expenses.
Working capital is traditionally added to cover the cash on hand needed to run the utility. An estimate of
1/8th of operating costs is typically used to reflect the lag time between revenue collections and accounts
payable. This metric, 1/8th of annual expenses, or 45 days,9 is common because it accounts for the
operating expenses that need to be paid prior to the collection of revenues after metering and billing.
9 One eighth of 365 days is 45.
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TABLE 3-1: DISTRIBUTION RATE BASE
Asset Description
Asset Value
FY 2021-2022 10
and Allocation
Equipment-Meters
$12,334,716 CUSTM Weighted by Meters and
Total Distribution Plant $155,578,873
General Plant
$1,910,425 GPLT Plant
$2,911,310 GPLT Plant
Total General Plant $4,821,735
Total Gross Plant in Service $160,400,608
Less: Accumulated Depreciation
Total Accumulated Depreciation
Total Net Plant
Working Capital: 1/8 Operating Costs
$2,251,043 OMWOP Expense
TOTAL RATE BASE
Constructions Working in Progress
(CWIP)
Total CWIP
TOTAL RATE BASE plus CWIP $117,034,679
Next, the methodology for classification and allocation for the City’s Natural Gas Distribution revenue
requirement can be found in Table 3-2. More detail on the classification and allocation factor codes used
in the classification and allocation process can be found in Table 3-3. Two changes were made to the
allocation factor assumptions since the prior study:
1. The general fund transfer allocation was updated from net plant to revenue. This update reflects
a policy change approved by the voters via Measure L, approved in 2022 where the transfer is
calculated as a share of rate revenue.
10 Fiscal year ending June 30, 2022 was the audited asset values available for the study period.
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2. Reserves contributions or transfers are allocated based on therms. The reserves are used to
stabilize supply costs. Supply costs are 100% energy related; therefore, this line item should be
classified and allocated based on energy.
TABLE 3-2: DISTRIBUTION REVENUE REQUIREMENT
FY 2025-2026
Classification
and Allocation
Engineering Support 768,861 RBD Distribution Rate Base
Operations & Maintenance 9,028,547 RBD Distribution Rate Base
9,797,408
Admin - Customer & Marketing
$227,967 CUSTW Weighted for
$485,915 CUSTM
$543,152 CUSTW Weighted for
$9,850 CUSTW Weighted for
$155,106 DA1
$1,266,689 CUSTW2 Weighted for
Total Customer Service, Accounts &
Sales $3,208,008
Administrative & General
Administrative & General Salaries 11 $1,451,715 OMAG
Allocated Charges 12 $2,735,638 OMAG
Rents $574,830 OMAG
Transfers to Non-Enterprise Funds $59,411 OMAG
11 Administrative and General Salaries includes salaries and benefits for staff assigned directly to Gas Utility
Administration.
12 Allocated charges are general costs incurred on behalf of all of the City’s utilities (water, wastewater, fiber, electric
and gas) that are individually determined and allocated to each business line, as well as salaries and benefits
allocated based on Capital Improvement Project cost centers.
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FY 2025-2026
Classification
and Allocation
Transfers to Enterprise Funds $181,333 OMAG
Administrative & General Salaries
Total Costs with A&G
Interest and Debt Service Expense
Total Debt Service /Capital
Improvement $8,339,643
Revenue Requirement Before Other
Revenues $41,957,453
Other (Revenues) & Expenses
$449,823 NETPLT
($625,693) NETPLT
Total Other Revenues
REVENUE REQUIREMENT for COST
ALLOCATION $41,268,342
Table 3-3 shows how each factor code classifies then allocates the costs to classes of service. The Average
& Excess (AE) allocator is described in greater detail below the table.
13 This includes uncollectible accounts for bad debt, low-income rate assistance discounts, and pre-1970s retired
employee discounts on utility bills at a primary residence. These are funded through non-rate revenues and Public
Utilities Code 890 revenues.
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TABLE 3-3: NATURAL GAS DISTRIBUTION REVENUE REQUIREMENT
Factor Code Factor Name Classification Allocation Basis
AE Average and Excess 63% Demand
37% Energy and Above Average (Excess) coincident
peak demand. Energy portion is remaining
share of A&E attributed to average
Accounting/Metering w/o G3 accounting and metering but excluding G3
Rate Base 34% Energy
8% Customer
based on the net book value of all shared
services assets and other capital assets
Gas Supply and A&G) 30% Energy Gas Supply and A&G expenses
Rate Base 34% Energy based on the book value of all general plant
(w/o General Plant & 34% Energy value of all capital assets (initial cost)
34% Energy
8% Customer
value of all capital assets (initial cost less
accumulated depreciation) assigned to
Purchased Gas Supply) 30% Energy the cost of Purchased Gas Supply
3.3 AVERAGE & EXCESS (A&E)
The classification and allocation of several rate base line items in Table 3-1 are based on the Average &
Excess (A&E) method. This 2026 Report improves the A&E methodology to better align with how the
distribution system is designed and built for reliable service. The 2020 Study classified A&E costs as 100%
demand-related and then used each customer’s share of demand to allocate those distribution costs
across customer classes. In this study, A&E is classified as both energy and demand to more accurately
reflect how the City’s distribution system is designed and built. The previous A&E method primarily
attributed system costs entirely to demand, which is an appropriate option for systems experiencing
growth. Now that the system is expected to exhibit declining use, and because capacity sizing is
determined based on both energy and demand, the revised A&E method is recommended. The system
planning criteria and the associated recommended A&E method are described below.
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The natural gas utility’s capital plan is primarily focused on upgrading and maintaining aging infrastructure
rather than expanding the system for growth. When evaluating the sizing of mains, City engineers model
the annual maximum demand (i.e., highest gas consumption during a January cold spell) to determine the
optimal system size to meet customers’ peak demand. The modeling also incorporates an analysis of
energy usage depending on the physical structure of the distribution system. The energy component is
particularly important to analyze when a network of mains result in endogenous impacts when one or
more of the pipes is replaced or resized. For example, the City’s engineers evaluate main sizing when
planning for replacement projects. In areas where a portion of the system has more than one main
providing service, engineers model the sizing of the main being replaced based on locational energy use
and available capacity of adjacent mains. Depending on the capacity and energy available from the other
mains, the replacement main can be resized to minimize cost on the system. This is particularly important
where usage has declined (or expected to decline) since the system was originally put into service.
Because both demand and energy use are important factors in considering current and future capacity
investments in the system, the distribution rate base is classified as both demand and energy under the
revised A&E method. Demand-related costs are then allocated to customer classes based on each class’s
contribution to peak demand. Energy-related costs are allocated to customer classes based on therms.
The revised A&E classification to demand and energy is based on a comparison of the energy used (the
“average”) against the maximum demand (the “excess”). Maximum demand is equal to the highest daily
usage for the class in each month or the non-coincident peak (NCP). The NCP is the sum of individual
customer peaks within the class independent of the system peak timing.
Overall, the A&E method makes the following assumptions:
1. Average energy represents the capital investment needed to serve the average customer in each class;
2. Excess use is the additional investment needed to serve customers with demands that vary by season.
Those customers with higher excess use require a larger investment in the system compared with
customers whose usage remains close to the average use year-round.14 Allocating excess use costs only to
excess users reasonably places those increased costs on only the customers that created the need for
capacity above their average use; otherwise, customers with lower use would arguably be subsidizing
customers higher use.
3.3.1 Average & Excess Calculation
As explained above, the A&E method classifies (splits) distribution costs between energy and demand
components. This classification recognizes that a portion of the distribution system is engineered to serve
a customer with average energy. In addition, another portion of the distribution system investment is
needed to meet customer maximum use (excess demand).
In order to develop the A&E calculation, daily or hourly load profile data is needed to calculate class load
factors. A load factor is the ratio of average use to peak use over a given time period. A low load factor
(for example 30%) indicates that average natural gas usage for that customer is relatively low compared
14 A good example of this type of customer is an individually metered multi-family unit. These customers have low
average use and the services needed for each unit are lower in cost compared with services needed to serve a single
family home (not shared).
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to that customer’s peak usage. A low load factor customer is more costly to serve on a $/therm basis since
there are fewer therms over which to spread system capacity costs. Due to the relationship between load
factors and cost of service, these factors are key components of the recommended cost allocation
methodology from the COSA.
The City does not yet have hourly or daily meter data from which to calculate load factors. In lieu of specific
Palo Alto data, daily load profiles were developed using public data available from California Management
Advisory Council (CALMAC).15 These load profiles are a good approximation for Palo Alto customers
because they are developed by a neighboring utility for the portion of its service area that has similar
weather conditions to Palo Alto as well as similar building attributes (based on California building codes
for example).
The overall method applies Palo Alto monthly usage data by class to the daily curves from CALMAC. The
CALMAC data is based on PG&E load research data for calendar year 2024 and specifically for the coastal
region. This data is applied to the City’s FY2026 load data. Next, maximum day demands are calculated
for each rate class and for the system as a whole.
For the G1 class, several residential load shapes were aggregated to produce a class load curve. Figure 3-
1 illustrates the sample daily load curves for 4 usage groups ranging from low annual use (less than 235.4
therms) to high annual use (above 575.7 therms). The curves are similar in shape and differ primarily in
magnitude.
FIGURE 3-1: PG&E AVERAGE RESIDENTIAL DAILY LOAD BY HOME TYPE
Commercial building load shapes were aggregated to develop G2 and G3 class load shapes. In many cases,
building/business types can range in usage level; therefore, profiles may be included in more than one
class. Table 3-4 details the building segments included for each class.
15 CALMAC Customer Load Shapes - PG&E. https://www.calmac.org/customer_load_shapes_pge.asp
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
Th
e
r
m
s
0 - 235.37 therms 235.37 - 378.83 therms 378.83 - 575.72 therms > 575.72 therms
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TABLE 3-4: COMMERCIAL INDUSTRY SEGMENT ASSIGNMENT TO CLASSES
Segment
G2 –
Small
G2 –
Medium
G2 –
Large
G3 –
Large Commercial
Multifamily Included Included Included
Automotive and Repair Included Included Included Included
Construction Included Included Included Included
Education Included Included Included Included
Full Service Restaurants Included Included
Gas Station & Convenience Stores Included Included
Government (Institutional) Included Included Included Included
Grocery Included Included Included Included
Health Included Included Included Included
Limited Service Restaurants Included Included
Lodging Included Included Included Included
Manufacturing Included
Office Included Included Included Included
Personal Care Services Included Included
Religious Included Included Included Included
Retail Included Included Included Included
Transportation & Utilities Included Included Included Included
Warehouse Included
Figure 3-2 compares the resulting daily therm usage by class after the class profiles are applied to monthly
Palo Alto use. Notably, the G1 profile is characterized by a much larger increase in peak winter demand
compared with G2 and G3 classes. This relationship is observed even after adjusting for relative load sizes
across classes.
FIGURE 3-2: PALO ALTO CLASS LOAD
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
7 8 9 10 11 12 1 2 3 4 5 6
Th
e
r
m
s
/
d
a
y
Month
G1 G2 Small G2 Medium G2 Large G3 Total System
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3.3.1.1 Load Factor Calculations
Monthly class load factors were calculated from monthly usage, each month’s individual maximum day
usage (demand or non-coincident peak) and the number of days per month. Load factors are calculated
for each month according to the equation below where usage is the total therms per month, demand is
the maximum daily therms in that month, and days is the number of days in the month. So, a residential
customer who uses 60 therms in January, and has a maximum daily use of 2.74 therms, has a load factor
of 70.6% for January.16
𝑳𝑳𝑳𝑳𝑳𝑳𝑳𝑳 𝑭𝑭𝑳𝑳𝑭𝑭𝑭𝑭𝑳𝑳𝑭𝑭= 𝑼𝑼𝑼𝑼𝑳𝑳𝑼𝑼𝑼𝑼(𝑫𝑫𝑼𝑼𝑫𝑫𝑳𝑳𝑫𝑫𝑳𝑳∗𝑫𝑫𝑳𝑳𝑫𝑫𝑼𝑼)
Table 3-5 contains the monthly load factor results by class. A lower load factor indicates that peak daily
use is relatively high compared to the average use over the same period. These customers typically have
a higher cost to serve because more capacity is needed to serve them, but energy use is relatively lower,
all else equal. The G1 rate class has the lowest average monthly load factor. The lower load factor is also
illustrated in Figure 3-2 where there is a larger difference in winter use compared with summer use. Lower
load factors result in higher volumetric rates because costs associated with the required system capacity
are spread over a lower number of therms. For example, two customers groups with the same maximum
consumption but different load factors will have different $/therm rates. Both groups use the same share
of system capacity; however, the customer group with lower energy use will have a higher rate in $/therm.
TABLE 3-5: LOAD FACTOR BY CLASS
CY Month G1 G2 – Small G2 – Medium G2 – Large G3
2025 7 70.6% 89.8% 90.0% 87.9% 87.6%
2025 8 73.8% 89.0% 89.1% 86.1% 90.6%
2025 9 74.8% 82.1% 82.1% 79.0% 83.2%
2025 10 55.7% 68.5% 68.3% 60.5% 68.8%
2025 11 59.5% 72.6% 72.4% 67.7% 72.1%
2025 12 65.1% 74.8% 74.5% 70.1% 74.0%
2026 1 75.4% 81.8% 81.8% 79.1% 81.9%
2026 2 59.7% 72.4% 72.2% 68.5% 71.7%
2026 3 63.2% 72.4% 72.3% 69.4% 71.8%
2026 4 58.7% 75.9% 75.6% 70.8% 75.5%
2026 5 65.0% 78.2% 78.2% 74.3% 78.7%
2026 6 75.5% 86.8% 86.8% 83.2% 87.1%
The load factors are used to calculate each class’s NCP (sum of individual customer peaks). The NCP is
used to measure the “excess” demand portion in the A&E calculation. The NCP is appropriate because the
system sizing is based on the sum of individual customer peaks regardless of when the peaks occur.
3.4 CUSTOMER WEIGHTING FOR METER COSTS
The number of customers weighted by meter costs is used in the study to allocate meter asset value in
the rate base. Weighted meter costs are appropriate for allocating meter asset values in the rate base
because they represent the relative cost of replacing meters for each class as infrastructure ages. “Meter
16 Load factor = 60 therms divided by (31 days x 2.74 therms) = 70.6%.
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costs” for each customer class are equal to the current replacement cost of the meters (equipment) plus
labor costs for installation. Utilities typically do not record original meter and installation costs by
customer or location; therefore, the next best measure for service cost is the current replacement cost.
Table 3-6 compares the resulting meter costs. This 2026 Report uses an average of meter replacement
costs based on the count of all meter types currently in service within each class. This weighted average
cost is most appropriate because it considers all of the meter types and requisite costs used by each class
of service.
TABLE 3-6: CUSTOMER WEIGHTING FOR METER COSTS: FY2026 G1 G2 G3
Meter Costs1 $414 $1,262 $10,473
Weighting $8,761,310 $2,772,869 $308,954
1. Meter Costs include both the cost of the assets and labor costs for installation. Costs are based on current
replacement costs and labor rates.
The meter cost weighting from Table 3-6 results in a larger share of meter values from the rate base being
allocated to G1 and a relatively smaller share of meter rate base allocated to G2 compared with the 2020
Study. This update is one of the primary drivers for the rate rebalancing recommended in this study. Note
that the G2 class is later disaggregated into 3 subgroups based on meter size and usage. Meter costs for
G2 small, medium, and large are $313, $1,709, and $6,935, respectively. Taken together, the average G2
meter cost is $1,262 as shown in Table 3-6.
3.5 CUSTOMER CLASSES OF SERVICE
Customer classes of service refer to the arrangement of customers into groups that reflect common usage
characteristics or facility requirements.17 The classes of service used within this 2026 Report were as
follows: Residential (G1); Small Commercial (G2); and Large Commercial (G3). The City also serves its own
Compressed Natural Gas (CNG) meter. The costs for the CNG service are paid by the City’s Public Works
department. The City is developing a cost-based fee to recover the CNG service’s fair share of metering
costs, service administration, and directly assigned costs. The estimated fee revenue is small (0.01% of
the total revenue requirement), and changes do not materially impact the results of this study.
3.6 COST OF SERVICE RESULTS
Given the key assumptions and updates discussed above, the COSA was completed. Tables 3-7 and 3-8
provide a summary of the Rate Base and Revenue Requirement amounts allocated to the various
customer classes.18 These schedules are calculated by multiplying the applicable classification and
allocation factors to each cost in the rate base and revenue requirement.
17 Breakpoints between or within rate classes are sometimes referred to as segmentation in rate making.
18 The rate base and revenue requirement tabs of the COSA model also show the rate base and revenue requirement
allocated to each class of service.
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TABLE 3-7: DISTRIBUTION RATE BASE ALLOCATION RESULTS: FY 2025-2026
Asset Description Total G1 Residential
G2 Small
G3 Large
Equipment-Meters $12,334,716 $9,124,973 $2,364,799 $844,943
Equipment-Services $59,109,371 $25,762,073 $22,504,632 $10,842,665
Equipment-Misc. $2,729,148 $1,189,465 $1,039,065 $500,618
Equipment-Regulators $976,067 $425,406 $371,617 $179,044
Equipment-Distribution Mains $77,559,779 $33,803,451 $29,529,232 $14,227,096
Equipment-Measuring $2,869,793 $1,250,763 $1,092,612 $526,417
Building $1,910,425 $878,671 $698,726 $333,029
Equipment $2,911,310 $1,339,013 $1,064,793 $507,505
($49,833,503) ($22,920,160) ($18,226,279) ($8,687,064)
($3,812,789) ($1,753,634) ($1,394,503) ($664,652)
$2,251,043 $1,160,297 $761,319 $329,427
TOTAL RATE BASE
$8,029,320 $3,692,963 $2,936,671 $1,399,685
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TABLE 3-8: DISTRIBUTION REVENUE REQUIREMENT ALLOCATION RESULTS: FY 2025-2026
Plant Description FY 2026 Total G1 Residential
G2 Small
G3 Large
Engineering Support $768,861 $353,626 $297,780 $117,455
Operations & Maintenance $9,028,547 $4,152,543 $3,496,760 $1,379,245
Total Distribution $9,797,408 $4,506,169 $3,794,540 $1,496,700
$465,537 $176,305 $207,750 $81,482
Total Customer Service $3,208,008 $2,197,456 $728,749 $281,803
Transfers to Non-Enterprise Funds
Total Administrative & General $5,002,927 $2,578,752 $1,740,020 $684,155
Total Costs with A&G $18,008,343 $9,282,376 $6,263,309 $2,462,658
Interest and Debt Service Expense
$23,348 $10,738 $9,042 $3,567
$778,250 $357,944 $301,417 $118,889
Total Debt Service /CIP Expense $8,339,643 $3,835,692 $3,229,947 $1,274,004
General Fund Transfer
Reserves Contribution
Revenue Requirement Before Other
Revenues $41,957,453 $19,527,169 $16,362,377 $6,067,907
Customer Discounts $318,105 $146,308 $123,202 $48,595
Connection Fees ($700,000) ($321,954) ($271,110) ($106,935)
$449,823 $206,889 $174,217 $68,717
($131,346) ($60,411) ($50,870) ($20,065)
Total Other Revenues ($689,111) ($316,946) ($266,893) ($105,272)
NET REVENUE REQUIREMENT $41,268,342 $19,210,223 $16,095,484 $5,962,635
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Table 3-9 provides a summary of the COSA results with the recommended revenue changes. These results
are the basis for the recommended distribution charges provided in the next section.
TABLE 3-9: DISTRIBUTION COSA RESULTS: FY 2025-2026
Projected FY 2026
Revenues
Revenue
Requirement
Projected FY
2026 Deficiency
Revenue
Change
Needed
G1 – Residential $17,738,316 $19,210,223 ($1,471,907) 8.3%
G2 – Small Commercial $18,006,240 $16,095,484 $1,910,756 (10.6%)
G3 – Large Commercial $5,523,787 $5,962,635 ($438,848) 7.9%
Total $41,268,342 $41,268,342 $0 0.0%
Residential and Large Commercial classes require rate increases and the Small Commercial class requires
a rate decrease. EES compared this study with the previous analysis (FY 2019-2020) and found the
following significant drivers for these results:
1. Overall, the FY 2025-2026 Distribution revenue requirement is 171% of the FY 2019-2020 revenue
requirement. The increase is due to multiple years of significant inflationary pressures and
planned reserve fund contributions.19 However, because the rate was adjusted on July 1, 2025,
the overall revenue level does not need to be increased at this time.
2. The allocation of the General Fund Transfer was updated from Net Plant to Revenue. As a result,
G1 is being allocated a larger share of the General Fund Transfer. Despite the adverse impact on
G1 rates, this update better aligns the expense item with cost since the General Fund Transfer is
calculated based on gross revenues.20
3. Customer allocators, such as customers weighted for meter costs, were updated to reflect current
meter cost and billing cost information. More detail on this analysis can be found in Section 3.3.2.
Further, the method for calculating the meter costs for each class was changed from using a
representative meter to using a weighted average for all meters in each class. These updates
resulted in larger shares of expenses allocated to G1 and G3. The development of these allocators
included a detailed analysis of the average cost of the average capacity meter for each rate class
and rate class grouping.
4. Previous studies relied on Average & Excess for some aspects of Distribution System Allocation,
and that is maintained in the current revision. However, the Rate Base Allocation of Distribution
assets was updated to reflect updated Average & Excess calculations. This change moved some
asset value from G1 to G2 and G3 based on the classes relative share of total sales. The
19 Resolution 10232 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62153 approving the
Reserves Management Practices (Exhibit 3 to Resolution 10232)
https://www.paloalto.gov/files/assets/public/v/3/agendas-minutes-reports/agendas-minutes/city-council-
agendas-minutes/2025/june-16/rates-attachments/finalized-attachment-c-exhibit-3-fy26-gas-reserve-
management-practices.pdf)
20 In November 2022, voters approved Measure L, amending the Municipal Code, Section 2.28.185, “Natural Gas
Utility Transfer” states: “Each fiscal year the City Council may transfer from the natural gas utility to the general fund
an amount equal to 18% of the gross revenues of the gas utility received during the fiscal year two fiscal years before
the fiscal year of the transfer. At its discretion, the City Council may decide to transfer a lesser amount. The projected
cost of the transfer shall be included in the City’s retail natural gas rates as part of the cost of providing gas service.”
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classification to both energy and demand better reflects how the system is planned and its current
operation, as discussed previously in the report. More detail on this update can be found in
Section 3.3.1.
5. Total use for all classes is lower in FY 2025-2026 compared with FY 2019-2020. Total G1 use
declined from 10.3 million therms to 9.8 million therms, G2 usage declined from 12.5 million
therms to 11.5 million therms, and G3 use declined from 5.6 million to 4.5 million therms. When
total use declines, fixed costs are spread across a smaller number of therms impacting the
$/therm rate.
In addition, all rate change aspects in this report are for distribution charges only and do not include
changes to supply. When considering overall rate impacts, it is important to note that most of these rate
changes are forecasted to be less than a 10% impact when considering combined commodity and
distribution charges.
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4 Rate Design
The final step in the rate study process is to design rates for each class of service or customer class. In
California, local governments are subject to Article XIII C of the California Constitution, amended by
Proposition 26 (2010), which requires gas rates and charges to not exceed the reasonable costs of
providing gas service, and requires that the City’s costs of gas service are allocated to each customer in a
manner that bears a fair or reasonable relationship to the customer’s burdens on, or benefits received
from, the gas utility. As a result, the City has set rates to match the COSA results for each customer class.
The results of the revenue requirement and COSA study are based on forecasted load data estimates and
usage pattern assumptions. Actual load and usage patterns may differ from the forecast. For this 2026
Report, rates are developed based on the forecast loads and observed historical usage patterns for each
customer class.
The rates for the Residential and Commercial customers are designed to reflect the differences in costs
among the various customer classes. The costs per customer class differ based on the seasonal shape of
consumption (referred to as energy use) as well as the daily peak demand for each customer class.
Differences in energy use by season and the level of peak demand have an impact on the utility’s need for
distribution facilities and the costs to operate and maintain those facilities.
4.1 RECOMMENDED RATE DESIGN: DISTRIBUTION
This section of the report reviews the present rate structures for the City and provides a comparison with
the recommended rates based on this cost of service study. Table 4-1 summarizes the current rate design
for each rate schedule and recommended rate design updates. As mentioned previously, the
recommended rate design is the same as the current rate design with the exception of some updates and
refinement as described below.
TABLE 4-1: NATURAL GAS DISTRIBUTION RATE DESIGN RECOMMENDATION OVERVIEW
Rate Schedule Current Rate Design Recommended Rate Design
Residential G1 Fixed Monthly Charge
Seasonal Tiered Rate with
Inclining Blocks
Update fixed and volumetric charges to cost of service unit costs
Calculate tiered rates based on Base and Excess methodology
Update Tier 1 summer baseline quantity
Small Commercial G2 Fixed Monthly Charge
Volumetric Charge
Update fixed and volumetric charges to cost of service
Implement three separate fixed monthly charges based on
Large Commercial G3 Update fixed and volumetric charges to cost of service unit costs
Table 1-10 in Section 1.2.3, Rate Recommendations, summarizes the current and FY 2025-2026
recommended rates for each class. The rate recommendations and bill impacts by rate class are provided
below.
4.1.1 Residential (G1)
The G1 distribution rates consist of a monthly service charge and volumetric tier rates: The Tier 1 rate
applies to usage up to the baseline quantity and the Tier 2 rate applies to all usage above the baseline.
While the tier rates do not change between seasons, the baseline quantity varies by season and is higher
in winter than in the summer because natural gas-based heating is used more in the winter. Therefore,
the class average therms are higher in the winter than in the summer. The tiered rate structure ensures
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that those customers contributing to higher seasonal demand are paying appropriately for their share of
the demand-related cost.
The current G1 Tier breakpoints (baselines) were evaluated using sales data for several test periods. Based
on average winter monthly use for 2022-2024, the winter baseline of 60 therms/30-day-billing is
appropriate. However, the most recent data supports increasing the summer baseline from 20 to 23
therms/30-day-billing. Table 4-2 shows the current baseline and average consumption values supporting
the recommendation.
TABLE 4-2: BASELINE QUANTITY ASSESSMENT
Tier 1 Baseline Assessment Therms/30-Day-Billing
Summer Winter
Current Baseline 20 60
Average Consumption
FY 2022 Actual 22 60
FY 2023 Actual 24 70
FY 2024 Actual 21 53
Gas Forecast FY 2026 24 56
Average of 3 Historical Years and 1 Forecast Year 23 60
Summer Winter
Recommended Baseline 23 60
The recommended baselines are used in the tiered rate calculations. The tiered rates recover all energy-
related distribution costs plus a share of demand-related distribution costs from each tier. The Base and
Excess capacity methodology is used to determine the portion of distribution demand costs collected from
each tier.21 The Base and Excess method first calculates G1 maximum annual use by applying G1 peak day
usage over the entire year. This assumes that the full capacity of the system is utilized year-round, which
is the basis for apportioning annual system capacity costs to Base use (Tier 1) and Excess use (Tier 2). If all
customers used this maximum amount of therms per day for the entire year, then the $/therm rate would
be a uniform rate. Because customers do not use the full capacity of the system year-round, the portion
of system capacity costs needed to serve demands above the base use level, are apportioned to the Tier
2 rate. Base level demand is thus collected in the Tier 1 rate by dividing distribution demand costs by the
annual use calculated at full capacity. The resulting $/therm is included in the Tier 1 rate. All excess
(remaining) demand costs are included in the Tier 2 rate. Table 4-3 illustrates the calculation of first tier
rate. Table 4-4 illustrates the calculation of the Tier 2 rate.
21 The Average & Excess methodology is used to apportion system costs to each rate class. The Base & Excess is used
only in the G1 tiered rate design.
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TABLE 4-3: G1 RATE CLASS TIER 1 RATE CALCULATION: BASE & EXCESS CAPACITY
Formula/Line Value Cost Share
Tier 1 Therms A 7,029,018
Distribution Demand Costs B $5,742,961 100%
Class Peak, therms/day C 89,733
Annualized Usage based on Peak
Demand, Therms
d = 365 × c 32,752,486
Tier 1 Demand Component, $/therm e = b ÷ d $0.1753
Tier 1 Demand Cost f = a × e $1,237,498 21%
Distribution Energy Costs g $8,495,630
Total Therms h 9,762,524
Energy, $/therm i = g ÷ h $0.8702
Tier 1 Total, $/therm j = e + i $1.0456
TABLE 4-4: TIER 2 RATE CALCULATION: BASE & EXCESS CAPACITY Formula/Line Value Cost Share
Tier 2 Therms k 2,733,507
Excess Demand Costs l = b – f (Table 4-3) $4,510,463 79%
Tier 2 Demand
Component, $/therm
m =l ÷ k $1.6501
Energy, $/therm i (Table 4-3) $0.8702
Tier 2 Total, $/therm n = m + i $2.5203
Table 4-5 shows the distribution bill impacts for average customer use in summer and winter.
TABLE 4-5: G1 BILL IMPACTS AT AVERAGE CUSTOMER USE, DISTRIBUTION ONLY
At Current Recommended Average Use
$40.86 $42.58 $1.72 4.2% 22.0
$74.58 $85.08 $10.50 14.1% 61.1
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Table 4-6 shows the impacts for a range of customer bills under various low, median and high usage levels.
TABLE 4-6: G1 BILL IMPACTS AT VARIOUS USAGE LEVELS, DISTRIBUTION ONLY
Season
Usage At
Current FY 26 Rates
At
Recommended
Distribution
Bill Impact
$/Month
Distribution
Bill Impact
$27.34 $30.03 $2.69 9.8%
$33.60 $37.35 $3.75 11.2%
30
45 $89.29 $99.07 $9.78 11.0%
Winter 30
(Median) 51 $64.01 $72.90 $8.89 13.9%
80
150 $277.92 $309.14 $31.22 11.2%
Annual (Median) 31
4.1.2 Small Commercial and Residential Master-Metered (G2)
The current G2 distribution rate design is composed of a fixed monthly service charge and a volumetric
charge. The fixed monthly service charge for a given rate schedule (customer class) is set to recover the
customer-related costs allocated to that schedule. As described in Section 1.2, Rate Study Overview, EES
recommends refinement in the development of the Monthly Service Charge for G2. Due to the diversity
in G2 meters and service sizes, and the methodology in the COSA that allocates fixed customer costs based
on meter costs, it is recommended to implement three separate Monthly Service Charges for G2 based
on service size. These service charges more precisely reflect the different services provided and the
associated costs for each of the three subclasses.
The creation of G2 subclasses (Small, Medium, and Large – defined below) is necessary to avoid intra-class
subsidies that exist from a single monthly service charge applied to customers that range in size from 36
therms per month to over 11,000 therms per month. G2 is unique in that the types of meters (and meter
costs) and customer usage represents a much wider range. To address the potential subsidies within the
class, G2 meter types and corresponding usage data is analyzed to determine G2 monthly service charges
that more precisely reflect customer-related fixed costs among differentiated subclasses within the class.
Figure 4-1 shows G2 meter capacity and associated average consumption. Meter size is positively
correlated with average use. This finding is expected and indicates that larger meters have higher average
use.22 Larger capacity meters also require larger service lines (connecting the meter to the distribution
system) and generally impose greater demand on the system. Recall that usage for commercial buildings
are uniform in shape but differ in relative size (Figure 1-3).
22 This is expected because meter capacity is sized to match the customer’s demand. City of Palo Alto, Utility Rule
and Regulation 15, Section B.6: Meter Installations, Capacity of Meters, April 2023.pdf
https://www.cityofpaloalto.org/files/assets/public/v/2/utilities/rules-and-regulations/rule-15-metering-april-
2023.pdf
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FIGURE 4-1: AVERAGE MONTHLY USAGE BY METER CAPACITY
Figure 4-1 shows distinct patterns and separations in average usage levels that support 3 G2 meter
groupings based on maximum meter capacity. Figure 4-2 shows the distinct average usage levels
associated with the following three groupings by maximum meter capacity (in standard cubic feet per
hour or scfh).
1. Up to 220 scfh (≤ 220 scfh)
2. Above 220 scfh and below 4,000 scfh (> 200 scfh and < 4,000 scfh)
3. 4,000 scfh and above (≥ 4,000 scfh)
FIGURE 4-2: G2 – AVERAGE MONTHLY USAGE BY METER CATEGORY
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The above G2 meter ranges were chosen based on a detailed examination of the use across different
meter types and capacities, according to summary data in Figures 4-1 and 4-2. This same rigor was also
applied to determine appropriate meter costs for G1 and G3.
The calculation for the G2 volumetric charge remains unchanged. As mentioned previously, the uniform
shape in G2 usage profiles supports a uniform volumetric rate. Recommended rates for G2 can be found
in Table 1-6, G2 Monthly Service Charges: FY 2025-2026, and Table 1-10, Current and Recommended
Rates.
Table 4-7 shows the G2 bill impacts for representative accounts in each G2 subgroup. Impacts for average
use and for 50% of average use are provided.
TABLE 4-7: G2 BILL IMPACTS, DISTRIBUTION ONLY
At Current
FY 2026-2027
FY 2025-2026
Average
# of
$684.29 $628.21 -$56.08 -8.2% 437 2,193
≤ 1,136
Average Use $235.17 $96.36 -$138.81 -59.0% 55
50% of Average Use $202.86 $62.80 -$140.06 -69.0% 28
˂ 940
Average Use $739.20 $685.24 -$53.96 -7.3% 484
50% of Average Use $454.88 $389.90 -$64.97 -14.3% 242
≥ 117
Average Use $4,615.20 $5,035.93 $420.74 9.1% 3,783
50% of Average Use $2,392.87 $2,727.51 $334.63 14.0% 1,892
4.1.3 Large Commercial (G3)
The present G3 rate design is composed of a monthly service charge and a volumetric charge. As noted
earlier, this class generally has large capacity meters and a high consumption threshold for service. G3
rate schedule applies to commercial customers who use at least 250,000 therms per year at one site.23
This threshold, which defines the rate class, results in a group of customers with similar services and usage
characteristics, but very different usage levels. The service size and service cost uniformity means that
fixed customer-related costs are also uniform within the rate class. Therefore, as a single charge fairly
recovers the fixed customer-related charges from each customer. And, for tiered rates to be
nondiscriminatory, the class would need to be both uniform in usage profile and average use. Individual
customer baseline use is not uniform within this rate class. Therefore, tiered rates are not appropriate as
they would result in higher-use customers subsidizing lower-use customers. No change is recommended
in the overall design of these charges.
For illustrative purposes, Table 4-8 presents the G3 bill impact at 20,833 therms, which is 1/12 of the
annual threshold level for G3 service.
23 Utility Rate Schedule G-3.
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TABLE 4-8: G3 BILL IMPACTS, DISTRIBUTION ONLY
At Current FY FY 2025-2026
G3 Large Commercial $25,015.37 $26,450.39 $1,435.02 5.7%
4.2 SUPPLY CHARGES
The primary focus of the rate study was the distribution charges which vary based on budgets and
operating needs. The City also must pass through costs that vary based on external factors and market
conditions. These appear in the rate schedules as Supply Charges. Supply charges include the Commodity,
Cap and Trade Compliance, Carbon Offset, and Transportation Charges. These charges are on a $/therm
basis and require frequent updates due to the variable nature of the underlying costs.
Currently, the City has a range included in the rate schedules. Table 4-9 shows the current ranges.
TABLE 4-9: SUPPLY CHARGES
Supply Charges $/therm
1. Commodity (Monthly Market Based) $0.10-$4.00
2. Cap and Trade Compliance Charges $0.00-$0.25
3. Transportation Charge $0.00-$0.30
4. Carbon Offset Charge $0.00-$0.10
EES examined both the current calculation of each charge and the basis for that calculation, as well as
whether the charge should remain a pass-through and whether or not a range of values is appropriate.
EES does not recommend any changes to the Commodity charge range. For the Commodity supply charge,
Council amended the Gas Utility Long-term Plan (GULP) Objectives, Strategies and Implementation Plan
including collecting funds via a gas price mitigation adder to manage potential future short-term natural
gas price spikes above the $4.00 per therm maximum charge (Resolution 101187, August 9, 2024). The
Commodity charge range, therefore, is consistent with the Council-approved strategy.
The City’s gas utility is a covered entity under the California Air Resources Board (CARB) Cap-and-Trade
program, under which the City is obligated to purchase allowances to cover all greenhouse gas emissions
resulting from natural gas use within Palo Alto’s service territory. EES recommends eliminating the ranges
for the Cap and Trade Compliance charge and instead converting this charge to a pass-through of the
City’s actual costs because the City has little to no control over them, and they are largely non-
discretionary. The Cap and Trade Compliance Charge is calculated based on the Cap-and-Trade program
quarterly auction allowance closing prices.
Likewise, EES recommends eliminating the ranges for the Transportation Charge and passing through
these charges. The Transportation charge is the rate the City pays Pacific Gas and Electric Company (PG&E)
to transport gas from the PG&E Citygate to the City of Palo Alto distribution system. PG&E is regulated by
the California Public Utilities Commission. Palo Alto has no control over these charges and no alternatives
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for transporting gas to its distribution system. The Transportation Charge is based on PG&E’s wholesale
tariff (G-WSL)24.
Recently, the transportation charge exceeded the published range and the Council increased the upper
limit on the Transportation Charge.25 This is likely to occur for both the Transportation Charge and the
Cap and Trade Compliance Charges in the future. Because the true costs can vary outside of the ranges
provided, the ranges do not appear to provide material value to customers. If the costs vary outside the
upper limit of the range the costs above the limit are paid for by the gas utility’s reserves unless the Council
increased the upper limit. Updating the ranges with a wider spread would also provide less practical
information to customers. Therefore, EES recommends eliminating the ranges for the Cap and Trade
Compliance and Transportation charges. Two years of historical monthly values for the Transportation
Charge and Cap and Trade Compliance Charge are posted publicly on the City’s website for reference.26
EES does not recommend changes to the Carbon Offset Charge range. In December 2020 Council adopted
Resolution 99303, amending the Carbon Neutral Gas Plan. This program is voluntary in the sense that it is
a local program approved by the City Council rather than a compliance obligation imposed by the state or
another governing body. The amended plan limited the purchase price of offsets to $19 per ton CO2e,
consistent with the original maximum 10 cents per therm rate impact, therefore the range is consistent
with the Council-approved program.
Second, EES recommends providing more detailed information on the source costs and calculation for all
four of the supply charges. Recommended additions include language in Table 4-10.
24 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
25 On October 7, 2024, Council adopted resolution 10190 increasing the upper limit on the Transportation Charge on
all of the City’s gas rate schedules from $0.25 per therm to $0.30 per therm effective November 1, 2024.
26 Residential: https://www.cityofpaloalto.org/files/assets/public/v/25/utilities/rates-schedules-for-
utilities/residential-utility-rates/monthly-gas-volumetric-and-service-charges-residential-3.pdf and
Non-Residential and Residential Master-Metered:
https://www.cityofpaloalto.org/files/assets/public/v/24/utilities/business/business-rates/monthly-gas-volumetric-
and-service-charges-commercial-3.pdf
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TABLE 4-10: SUPPLY LANGUAGE
Supply Charges Description
1. Commodity (Monthly Market Based) This charge is based on the monthly natural gas Bidweek Price Index for delivery at
PG&E Citygate, adjusted to account for delivery losses to the customer’s meter. The
Commodity Charge also includes adjustments to account for Council-approved
programs implemented to reduce the cost of Gas, including a municipal purchase
discount (Adopted via Resolution 9451, on September 15, 2014), and $0.055 per therm
for mitigating the impact of short-term natural gas market price spikes.
The Commodity Charge calculation formula is:
PG&E Citygate Monthly Bidweek Price ($/MMBtu)
+ Gas Supplier Adder ($/MMBtu)
– Municipal Gas Discount ($/MMBtu)
× (1+ Distribution Loss Multiplier)
+ Gas Price Spike Mitigation Charge ($/MMBtu)
÷ 10 (conversion from MMBtu to therm) (MMBtu/therm)
= Commodity Rate ($/therm)
Where :
PG&E Citygate Monthly Bidweek Price is the monthly price for PG&E Citygate as
reported in the first issue of the month of Natural Gas Intelligence’s Bidweek Survey
as published by Intelligence Press Inc.
The Gas Supplier Adder is the premium or discount applied to the Bidweek Price Index,
based on the City's actual transactions with its natural gas suppliers.
The Distribution Loss Multiplier, updated annually, is calculated by the variances of gas
supply purchases and gas retail sales for the past three fiscal years.
2. Cap and Trade Compliance Charge
with the State’s Cap and Trade Program, including the cost of acquiring compliance
instruments sufficient to cover the Gas Utility’s compliance obligations. The Cap and
Trade Compliance Charge is adjusted in response to market conditions, retail sales
volumes, and the quantity of allowances required. The calculation formula is based on
carbon allowance auction prices and allowances needed to comply with state law. One
allowance is equal to 1 metric ton (MT) of CO2.
The Cap and Trade Compliance Charge calculation formula is:
Most Recent Auction Price ($/MT CO2)
x Number of Allowances Required (%)
x (conversion from MT CO2 to therm) (MT CO2/therm)
= $/Therm
Where:
Number of Allowances Required (%) =
(Projected Emissions for Current Year- Palo Alto’s Allocated Allowances for Current
Year)
÷ Projected Emissions for Current Year
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3. Transportation Charge The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to Customer Meters. The current rates are shown in
this tariff https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-
WSL.pdf, provided by PG&E. Additionally, there is a distribution loss factor (updated
annually), which is calculated by the variances of gas supply purchases and gas retail
sales for the past three fiscal years.
The Transportation Charge calculation formula is:
PG&E G-WSL Transportation Charges ($/therm)
- Cap and Trade Cost Exemption ($/therm)
× (1+ Distribution Losses Multiplier)
= Transportation Charge ($/therm)
Where:
The Distribution Loss Multiplier, updated annually, is calculated by the variances of gas
supply purchases and gas retail sales for the past three fiscal years.
4. Carbon Offset Charge
gases produced when Gas is burned. The Carbon Offset Charge will change in response
to market conditions, sales volumes, and the quantity of offsets purchased within the
Council-approved cap of $19 per MT CO2e, calculated annually.
The Carbon Offset Charge calculation formula is:
Weighted Average Cost of Carbon Offset ($/MT CO2)
x (conversion from MT CO2 to therms) (MT CO2/therms)
= Carbon Offset Charge ($/therm)
Where:
Purchase Price of Carbon Offset ≤ $19/MT CO2e
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RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-1 Effective 27-1-20265
dated 0711-1-20254 Sheet No G-1-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from City of Palo Alto
Utilities:
1. Separately-metered single-family residential Customers;
2. Separately-metered multi-family residential Customers in multi-family residential
facilities.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ..............................................................................................$ 19.5818.40
Tier 1 Rates: Per Therm
Supply Charges:
1. Commodity (Monthly Market-Based) ......................................... $0.10-$4.00
2. Cap and Trade Compliance Charge ............................................ $0.00-
$0.25Pass-through
3. Transportation Charge ................................................................. Pass-
through$0.00-$0.30
4. Carbon Offset Charge .................................................................. $0.00-$0.10
Distribution Charge:....................................................................................... $
1.04560.8944
Tier 2 Rates: (All usage over 100% of Tier 1)
Supply Charges:
1. Commodity (Monthly Market-Based) ......................................... $0.10-$4.00
2. Cap and Trade Compliance Charge ............................................. $0.00-
$0.25Pass-through
3. Transportation Charge ................................................................. $0.00-
$0.30Pass-through
4. Carbon Offset Charge .................................................................. $0.00-$0.10
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RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-2 Effective 27-1-20265
dated 0711-1-20254 Sheet No G-1-2
Distribution Charge:............................................................................................. $
2.52032.2873
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
purchase discount 1 and $0.055 per tTherm for mitigating the impact of short-term natural
gas market price spikes2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s
compliance obligations. The Cap and Trade Compliance Charge changes in response to
changing market conditions, retail sales volumes and the quantity of allowances required,
and is calculated based on the Cap-and-Trade Program’s quarterly auction allowance
closing prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse
gases produced when Gas is burned. The Carbon Offset Charge changes in response to
changing market conditions, sales volumes and the quantity of offsets purchased within
the Council-approved per Ttherm cap.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
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RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-3 Effective 27-1-20265
dated 0711-1-20254 Sheet No G-1-3
The Transportation Charge is a pass-through charge based on the current PG&E G-WSL 3
(Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity and, Cap and Trade Compliance, Carbon Offset and Transportation
Charges will fall within the minimum/maximum ranges set forth in Section C. Current
and historic per tTherm rates for the Commodity, Cap and Trade Compliance, Carbon
Offset and Transportation Charges are posted on the City Utilities website.4
2. Seasonal Rate Changes:
The Summer period is effective April 1 to October 31 and the Winter period is effective
from November 1 to March 31. When the Bbilling Pperiod includes use in both the
Summer and the Winter periods, the usage will be prorated based on the number of days in
each seasonal period, and the charges based on the applicable rates for each period. For
further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Calculation of Usage Tiers
Tier 1 Nnatural Ggas usage is calculated and billed based upon a level of 0.667 therms per
day23 Ttherms per 30 day Billing Period during the Summer period, and 60 tTherms per
30 day Billing Period during the Winter period, based on Meter reading days of Service,
and rounded to the nearest whole tTherm. As an example, Tier 1 Natural Gas is calculated
at 0.767 tTherms per day during the Summer period (.767 tTherms per day x 30 days = 23
tTherms) and 2.0 tTherms per day during the Winter period (2 tTherms per day x 30 days
= 60 tTherms). , rounded to the nearest whole therm, based on meter reading days of
service. As an example, for a 30 day bill, the Tier 1 level would be 20 therms during the
Summer period and 60 therms during the Winter period months. For further discussion of
bill calculation and proration, refer to Rule and Regulation 11.
{End}
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.paloalto.gov/files/assets/public/utilities/rates-schedules-for-utilities/residential-utility-rates/monthly-gas-
volumetric-and-service-charges-residential.pdf
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RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-1 Effective 27-1-20265
dated 711-1-20245 Sheet No G-2-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use less than 250,000 tTherms per year at one site;
2. Master-Mmetered residential Customers in multi-family residential facilities.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Gas Service. C. UNBUNDLED RATES: Per Service
Monthly Service Charge:
For Meters with maximum capacity:
1. Up to 220 Standard Cubic Feet per Hour (scfh) .......................................................$ 29.24
2. Above 220 scfh and less than 4,000 scfh ................................................................$ 94.56
3. 4,000 scfh and above ...................................................................................$ 419.08170.55
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) ......................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges ........................................................... $0.00-
$0.25Pass-through
3. Transportation Charge .................................................................................. $0.00-
$0.30Pass-through
4. Carbon Offset Charge ................................................................................... $0.00-$0.10
Distribution Charge: .................................................................................................. $
1.17491.2204
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
The Mmeter’s maximum capacity used to determine the applicable Monthly Service
Charge for G-2 Gas Service is the installed Meter’s City of Palo Alto-approved
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RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-2 Effective 27-1-20265
dated 711-1-20245 Sheet No G-2-2
maximum capacity in standard cubic feet per hour (scfh), measured at 7 inches of water
column or equivalent to 0.25 pounds per square inch.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
purchase discount 1 and $0.055 per tTherm for mitigating the impact of short-term natural
gas market price spikes2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge changes in response to changing
market conditions, retail sales volumes and the quantity of allowances required, and is
calculated based on the Cap-and-Trade Program’s quarterly auction allowance closing
prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced when Gas is burned. The Carbon Offset Charge changes in response to changing
market conditions, sales volumes and the quantity of offsets purchased within the Council-
approved per Ttherm cap.
The Transportation Charge is a pass-through charge based on the current PG&E G-WSL 3
(Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, and Carbon Offset and Transportation
Charges will fall within the minimum/maximum ranges set forth in Section C. Current
and historic per Ttherm rates for the Commodity, Cap and Trade Compliance, Carbon
Offset and Transportation Charges are posted on the City Utilities website.4
{End}
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.paloalto.gov/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-charges-
commercial.pdf
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LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-1 Effective 27-1-20265
dated 711-1-20254 Sheet No G-3-1
A. APPLICABILITY:
This schedule applies to the following Customers Commercial Customers receiving Gas Service
from the City of Palo Alto Utilities, who use at least 250,000 Ttherms per year at one site.:
1. Commercial Customers who use at least 250,000 therms per year at one site;
2. Customers at City-owned generation facilities including the City’s Natural Gas fueling
station at the Municipal Services Center.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: $ 780.341,712.36
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges ................................ $0.00-$0.25Pass-through
3. Transportation Charge .......................................................................... $0.00-
$0.30Pass-through
4. Carbon Offset Charge ........................................................................... $0.00-$0.10
Distribution Charge: .................................................................................................$ 1.16331.1874
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
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LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-2 Effective 27-1-20265
dated 711-1-20254 Sheet No G-3-2
purchase discount 1 and $0.055 per Ttherm for mitigating the impact of short-term natural
gas market price spikes2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge changes in response to changing
market conditions, retail sales volumes and the quantity of allowances required, and is
calculated based on the Cap-and-Trade Program’s quarterly auction allowance closing
prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced when Gas is burned. The Carbon Offset Charge changes in response to changing
market conditions, sales volumes and the quantity of offsets purchased within the Council-
approved per Ttherm cap.
The Transportation Charge is a pass-through charge based on the current PG&E G-WSL 3
(Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity and , Cap and Trade Compliance, Carbon Offset and Transportation
Charges will fall within the minimum/maximum ranges set forth in Section C. Current
and historic per Ttherm rates for the Commodity, Cap and Trade Compliance, Carbon
Offset and Transportation Charges are posted on the City Utilities website.4
2. Request for Service
A qualifying Customer may request Sservice under this schedule for more than one
Aaccount or Mmeter if the Aaccounts are located on one site. A site consists of one or
more contiguous parcels of land with no intervening public right-of- ways (e.g. streets).
3. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable City of Palo
Alto full-service rate schedule.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.paloalto.gov/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-charges-
commercial.pdf
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LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-3 Effective 27-1-20265
dated 711-1-20254 Sheet No G-3-3
{End}
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Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Administrative Services
Meeting Date: November 18, 2025
Report #:2511-5392
TITLE
General Fund Major Tax Revenues Review and Retiree Benefit Funding Policy Update. CEQA
Status – Not a Project.
RECOMMENDATION
Staff recommend that the Finance Committee review and accept the General Fund major tax
revenues update and forward to the City Council with additional recommendations to transmit
funding from PARS Pension Trust to CalPERS and incorporate into the long-range financial
forecast.
EXECUTIVE SUMMARY
This staff report is a continuation of the Finance Committee and Council conversations about
the City’s financial position and budget balancing strategies, noting changes in major revenues,
setting the foundation for upcoming fiscal actions including the Finance Committee review of
the Long-Range Financial Forecast on December 2, and Council consideration of Mid-year
budget actions and pension updates in early 2026.
This report focuses on General Fund major tax revenues, that continue to evolve, especially
sales tax, due to consumer activity, modernization and state regulations. Notably, FY 2026 sales
tax is projected to decline by approximately $8 million to $9 million (over 20%) due to a
combination of potential one-time adjustments and lower allocations to the City. Sales tax
projections for FY 2027 and onwards indicate decrease of approximately $4 million annually
(over 10%). This staff report transmits more details about this evolving major revenue to help
inform the FY 2027 budget process, budget balancing strategy and help inform changes to the
City’s Long-Range Financial Forecast.
Additionally, prior to the development of the next long-range financial forecast (LRFF) and as
prescribed in the Retiree Benefit Policy, periodic reviews inform funding transmission to
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CalPERS and responses to the City’s financial position. Staff recommendations contained in this
report continue to implement the policy and advance the planned progress.
Continue contributions into the PARS Pension Trust in accordance with the City
Retiree Benefit Policy;
Transmit $10 million, representing excess of one-year required employer
contribution (REC) balance, from PARS Pension Trust to CalPERS before June 30,
2026 for Additional Discretionary Payment (ADP) as part of the FY 2026 Mid-Year
Budget;
Transmit $20 million, representing excess of one-year REC balance, from PARS
Pension Trust Fund to CalPERS for FY 2027 for Additional Discretionary Payment
(ADP) and include this change in development of the 2027-2036 LRFF; and
Balance General Fund FY 2027 budget with on-going appropriations reductions of $6
to $8 million and transmitting excess of one-year REC balance from PARS Pension
Trust to CalPERS to offset Actuarial Determined Contribution (ADC) in the amount of
$6 million Citywide and include the General Fund portion (approximately $3.6
million) in the 2027-2036 LRFF.
Continue to monitor major revenues and advance discussions at the State level
regarding City sales tax allocations and should significant one-time sales tax
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reduction occur in FY2026, Staff will further update the FY2026 Mid-Year Budget for
PARS Pension Trust transmittal towards ADC to reduce pension costs.
These recommendations support timely transmission of funding from the PARS Pension Trust to
CalPERS, noting a favorable impact on pension costs and liabilities. It also continues thoughtful
planning and deliberations in addressing budget gaps that seek to balance community impacts
while continuing to advance Council priorities.
BACKGROUND
The City General Fund major taxes represent $175.6 million or 65% of the General Fund budget.
Overall General Fund revenue is diverse and proactively managed. Revenue monitoring and
projections throughout the year inform budget tracking and long-range forecasting. In
particular, sales tax is the second largest General Fund revenue stream after property taxes,
representing approximately $36.4 million or 13.5% of the adopted FY 2026 budget. Sales tax
revenue continues to evolve based on consumer activity and changes in the state’s
methodology for allocating tax revenue. These factors suggest a significant decline in sales tax
revenue for the City.
The City has taken strategic steps to address rising pension costs and long-term liabilities;
including cost-sharing in labor agreements; implementing State Public Employees’ Pension
Reform Act (PEPRA) lower benefit plans; establishing an irrevocable Section 115 Pension Trust,
administered by PARS1 (“PARS Pension Trust”); and adopting the Retiree Benefit Funding
PolicyError! Bookmark not defined.. The Retiree Benefit Funding Policy is an evergreen policy that
automatically renews until goals are complete, subject to modification at the City Council’s
direction. The policy identifies a path forward for the City to address its pension obligations on
an ongoing basis, ensures prudent and proactive financial planning, and avoids significant
impacts to service delivery. Staff manages and validates the City pension plan with its CalPERS
actuary, CalPERS ALM studies, and TrueComp (formerly GovInvest) experts and forecasting
tools, and Foster & Foster actuaries and actuarial reports. The CalPERS first reading of the 2025
ALM was presented on September 15, 2025 to the CalPERS Board2. Future CalPERS
measurements and results may be different from this report as actuarial models rely upon
estimates and are sensitive to change. Once CalPERS completes the ALM process, staff will
perform another in-depth review of the progress towards its goals. Each year, staff continues
1 City Council, January 23, 2017: https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=76701
2 CalPERS Asset Liability Management: First Reading of the Public Employees’ Retirement Fund Recommendations,
September 15, 2025: https://www.calpers.ca.gov/documents/202509-invest-agenda-item05c-01-
a/download?inline#:~:text=Page%201,2
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to provide annual pension plan updates and incorporate changes into the annual budget
development.
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The current Retiree Benefit Funding Policy sets the following goals and principles:
Funding Goal and Timeframe:
Funding Components:
Use of Funds:
Reporting:
Service Delivery Outcomes:
Fiscal Impacts:
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addressing the implications for the City’s proactive funding contributions for the coming
year through the budget development process.
The City continues to manage local pensions as planned, demonstrating foresight and effective
policy implementation in line with the key metrics and recommendations detailed in this
report.
ANALYSIS
General Fund Major Tax Revenues
The City General Fund major taxes total $175.6 million, or 65% of the General Fund FY 2026
total revenues (excluding transfers-in and use of reserves). Overall General Fund revenue is
diverse including property tax, sales tax, transient occupancy tax, utility user tax and business
tax. Revenues are proactively managed with stakeholder outreach, compliance and collection
programs, analytics and forecasting with regulatory agencies and subject matter experts. This is
an abbreviated, high-level update as the completion of the FY 2026 first quarter financial status
report will be forthcoming to Finance Committee in December.
Below is a summary of the General Fund major taxes by source with a red, amber, and green
color-coding status to provide a quick visual overview of revenue projections:
• Green means the revenue is on track to achieve budget
• Amber means there are minor potential risk that require closer monitoring,
• Red indicates significant projected shortfall, and
• Grey indicates no status or insufficient information to assess.
City revenues have uneven collection cycles and seasonality, where first quarter actuals are not
representative of 25% of the fiscal year budget.
Table 1: FY 2026 General Fund Major Taxes ($ million)
Tax Category
FY 2025
Actual
FY 2026
Adopted
Budget
Q1 FY
2026
Actual Status Comments
Property Taxes $69.4 $73.6 $0.1 Monitoring ERAF legislation, housing
sales and valuation.
Sales Taxes 35.2 36.4 2.8 Consumer activity, modernization,
State regulations
Transient Occupancy
Tax (TOT)
29.0 29.1 3.2
Utility Users Tax 20.4 21.4 4.6
Doc Transfer Tax 8.3 8.5 2.1 Unpredictable property sales
Business Tax 5.7 6.5 0.1
Total GF Major Taxes,
% of GF Revenues
168.0
57%
175.6
65%
12.9
Total GF Revenues $294.7 $269.8 $33.5 Total GF Revenue excludes transfers-
in and use of reserves*
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*Adopted FY 2026 Total GF Revenues, $306.9 million, includes transfer-in of $31.5 million and
use of reserves of $19.3 million
Sales tax revenue of $36.4 million or 13.5% of the General Fund FY 2026 budget is the second
largest General Fund revenue stream. Sales tax revenue is driven by the changing landscape of
consumer activity, growth and modernization of the digital economy including the effects of
online sales and retail operations, and state regulations. Consumer activity is sensitive to
marketplace options, price sensitive (i.e. tariff, inflation, discretionary income), and online
platforms, while retailer practices and intake procedures have also modernized. Another
significant development is that the California Department of Tax & Fee Administration (CDTFA),
which administers sales tax, continues to adopt new regulations which drastically impact
county pool allocations and direct sales tax allocations to public agencies.
The City has experienced a sales tax decline in the past twelve months, and the most recent
quarter-ended June 30, 2025 sales tax digest report shows business-to-business and
transportations sectors driving major declines. For the twelve-month period ending June 30,
2025, the business-to-business sector, primarily leasing, decreased by 41.6%, and represents
12.7% of total sales tax. For the same period, the transportation sector, primarily new autos,
decreased by 32.2% and represents 11.7% of total sales tax. These two segments account for
over 20% of Palo Alto’s total sales tax for the period and were the primary drivers of the overall
decline. Due to the lag in CDTFA reporting, the Q2 sales tax digest is being published
concurrent with this report, refer to the November 17, 2025 Council packet.
The FY 2026 sales tax is projected to decline by approximately $8 million to $9 million (over
20%) due to a combination of potential one-time adjustments by the CDTFA and lower
allocations to the City. Sales tax revenues for FY 2027 and onwards are projected to decrease by
approximately $4 million annually or over 10%. When Council adopted the FY 2026 budget in
June, it was followed by General Fund reductions of $6 million or approximately 2% in
September5, where budget reductions targeted defunding vacant positions and delaying capital
spending. This reduction in sales tax revenue, combined with the projected FY 2027 budget
shortfall that was included in the FY 2026-2036 LRFF, will require additional budget reductions
and use of reserves beyond the General Fund reductions of $6 million (approximately 2%) in
September6 realized by defunding vacant positions and delaying capital spending. Recognizing
that some of the budget reduction will be derived from savings and alternative service delivery,
significant budget reductions will likely have an impact on the community that will require
thoughtful planning, deliberation and implementation for careful modifications. Timely
transmission of funds from PARS Pension Trust to CalPERS, in accordance with City policy will
have a favorable impact on pension costs, budget balancing and fiscal strategies.
6 City Council, September 8, 2025: https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=83564
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Retiree Benefit Funding and PARS Pension Trust
The Retiree Benefit Funding Policy provides direction regarding annual contributions into PARS
pension trust, pension liability funded target and timeframe to achieve that target, transmission
from PARS Pension Trust to CalPERS and contingencies to ensure the policy is responsive to
other significant circumstances. Staff must identify the impacts on the funding goal and
timeframe to modify the transmission of the additional contributions to the PARS Pension Trust
and include funding recommendations from PARS Pension Trust to CalPERS as part of the
annual budget process.
The policy recognizes the contributions into PARS Pension Trust and funding transmitted from
PARS Pension Trust Fund to CalPERS will vary year to year depending on the circumstances,
level of funding accumulated, revenue declines and potential service delivery crowd-out by the
increased costs of pension obligations. If the City’s effort to proactively contribute to the long-
term pension obligations would result in service delivery impacts in the short-term, staff will
identify those impacts and recommendations to mitigate them, as appropriate, through the
budget development process.
In accordance with the policy, accumulated savings in excess of one-year REC are transmitted
from PARS pension trust to CalPERS. As of June 30, 2025, the PARS pension trust balance of
$110 million exceeded the FY25-26 one-year REC of $70 million by $40 million. PARS pension
trust accumulated savings from higher contributions and investment returns, as illustrated in
Table 2.
Taking into consideration the risk of large lump sum investments and timing the market,
smoothing the required employer contribution and mitigating pension cost spikes, and avoiding
service delivery crowd-out by the increased costs of pension obligations, staff recommend a
multi-year transmission of funds from PARS pension trust to CalPERS with short- and long-bases
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amortization and a combination of application towards actuarial determined contribution (ADC)
and additional discretionary payment (ADP). These recommendations adhere to the policy and
sustain the planned outcomes and timeframe, in particular target 90% funded status within 15
years (by 2036). These recommendations are based upon pension cost models by TrueComp
and their experts, in conjunction with Foster & Foster actuaries. The assumed discount rate of
6.8% is based upon the CalPERS 2025 ALM report capital market assumptions and
recommendations (pending CalPERS Board approval in November) and PARS investment return
of 4.5%. Moreover, in April 2025, the CalPERS Board approved a change to the Funding Risk
Mitigation Policy to remove the automatic change to the discount rate, trigger when
investment returns exceed the adopted discount rate by certain margins. Refer to model
assumptions and in-depth detail within Attachment A (TrueComp) and Attachment B (Foster &
Foster). In 2026, a more in-depth actuarial report of the City’s pension will follow the
completed ALM.
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Chart 1: Projected Funded Percentage (All City Pension Plans)
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Chart 2 summarizes the reduced, smoother projected required employer contribution of all city
pension plans based upon the recommended transmissions from PARS Pension Trust to
CalPERS. This mitigates the anticipated required employer contribution spike in FY 2031 and
ultimately flattening around FY2040 onwards. Attachment A TrueComp presents multiple
models. Attachment B Foster & Foster actuarial report confirms similar employer contribution
projections.
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Staff recommends pacing the transmission from PARS Pension Trust to CalPERS for additional
discretionary payment (ADP) in FY 2026 of $10 million, FY 2027 of $20 million, FY2028 of $30
million and thereafter, transmit balances in excess of REC.
The City elected the PARS Pension Trust Balanced Index Strategy with an asset mix of equity
(50%-70%), fixed income (10-30%) and cash (0-20%). Whereas the CalPERS Public Employees’
Retirement Fund (PERF) investment strategy asset mix is equity (75%) and bonds (25%) asset.
Alternative cashflow transmission from PARS Pension Trust to CalPERS may be considered while
balancing the general lower risks and lower earnings return of PARS Pension Trust against the
general higher risk and potential returns of CalPERS PERF.
For short-term cashflow strategy, staff recommends using $10 million planned for FY 2026 and
$20 million planned for FY 2027 ADP to be applied towards the shortest amortization bases,
and funding transmissions thereafter may be applied towards the longest amortization bases.
To avoid service delivery impacts by the increased costs of pension obligations and decline in
General Fund major taxes, staff recommends transmission of excess of one-year REC balance
from PARS Pension Trust to CalPERS to offset the ADC in the amount of $6 million for All Funds
and include the General Fund portion (approximately $3.6 million) in the upcoming long range
financial forecast for the next five years. This will utilize excess PARS Pension Trust funds to
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offset pension cost (ADC) while also balancing the budget through cost reductions including
service delivery efficiencies and exploring new revenues with the goal of minimizing near term
impacts to community service levels.
FISCAL/RESOURCE IMPACT
STAKEHOLDER ENGAGEMENT
ENVIRONMENTAL REVIEW
ATTACHMENTS
APPROVED BY:
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TrueComp (GovInvest) tool was used to create multiple scenarios. Details were applied to the
appropriate individual plans. Illustrations are for consolidated ALL city pension plans.
Scenario V3b includes:
-$30M ADP on shortest bases, then longest bases
-Payroll growth 2.8%
-Inflation rate 2.3%
-Discount rate 6.8%
-CalPERS Actuarial Valuation of 6/30/2024
-PARS Pension Trust Fund 6/30/2024 balance of $110 million
-ADC as shown in the table below.
Projections for Scenario V3b are illustrated on the next three pages.
Terms of Use
Use of the model is subject to acceptance of these Terms of Use.
The model is intended to be used solely as an educational resource. The results presented by the model are hypothetical and are not
intended to be estimates of future contribution rates or investment growth. Your plan’s contribution rates and funded status will be based
most recent valuation report, the assumptions used therein and the information that you input into the model. Projections obtained using
the model will not automatically incorporate adjustments to the discount rate required under the CalPERS’ Funding Risk Mitigation Policy,
which generally requires a reduction in the discount rate if CalPERS investment performance significantly outperforms the current discount
The actuarial calculations performed by the model are based on a number of assumptions about very long-term demographic and economic
behavior. Unless these assumptions (e.g., termination, death, disability, retirement, salary growth, and investment return) are exactly
realized each year, there will be differences between the projections obtained using the model and your plan’s actual required contribution
raise your rates from one year to the next. Your plan’s actual contribution rate will inevitably fluctuate over time, especially due to the ups
Attachment A Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 15 Packet Pg. 91 of 144
11/1/2025 1:46 am (UTC)This report produced using
Palo Alto, CA
Pension-2024
Required Employer Contribution
Official Preliminary 2025
IR +11.6% (current)
$75.25M
V3b $30M Short then
Long, DR 6.8%
$65.60M
from $75.25M
$9.65M
24-25 26-27 28-29 30-31 32-33 34-35 36-37 38-39 40-41 42-43 44-45
Fiscal Year Ending June 30
$0
$20M
$40M
$60M
Parameters
Information projected to future years assuming experience matches default demographic and economic assumptions, with the following changes:
Global Adjustments
Payroll Growth (%) : 2024:2.8, 2025:2.8, 2026:2.8, 2027:2.8, 2028:3, 2029:3, 2030:3, 2031:3, 2032:3, 2033:3, 2034:3, 2035:3, 2036:3, 2037:3, 2038:3, 2039:3, 2040:3, 2041:3,
2042:3, 2043:3, 2044:3, 2045:3, 2046:3, 2047:3, 2048:3, 2049:3, 2050:3, 2051:3, 2052:3, 2053:3,
Investment Returns (%) : 2024:11.5,
Total Employer Required
Contribution
Annual Amortization
Payment
Employer Normal
Cost
Employee
Contribution
Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 16 Packet Pg. 92 of 144
11/1/2025 1:43 am (UTC)This report produced using
Palo Alto, CA
Pension-2024
Unfunded Accrued Liability
Official Preliminary 2025
IR +11.6% (current)
$159.78M
V3b $30M Short then
Long, DR 6.8%
$16.76M
from $159.78M
$143.02M
2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
As of July 1
$0
$100M
$200M
$300M
$400M
$500M
Parameters
Information projected to future years assuming experience matches default demographic and economic assumptions, with the following changes:
Global Adjustments
Payroll Growth (%) : 2024:2.8, 2025:2.8, 2026:2.8, 2027:2.8, 2028:3, 2029:3, 2030:3, 2031:3, 2032:3, 2033:3, 2034:3, 2035:3, 2036:3, 2037:3, 2038:3, 2039:3, 2040:3, 2041:3,
2042:3, 2043:3, 2044:3, 2045:3, 2046:3, 2047:3, 2048:3, 2049:3, 2050:3, 2051:3, 2052:3, 2053:3,
Investment Returns (%) : 2024:11.5,
Accrued Liability Valuation Assets Unfunded Accrued Liability
Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 17 Packet Pg. 93 of 144
11/1/2025 1:45 am (UTC)This report produced using
Palo Alto, CA
Pension-2024
Funded Percentage
Official Preliminary 2025
IR +11.6% (current)
92.88%
V3b $30M Short then
Long, DR 6.8%
99.25%
from 92.88%
6.37%
2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
As of July 1
0%
20%
40%
60%
80%
100%
Parameters
Information projected to future years assuming experience matches default demographic and economic assumptions, with the following changes:
Global Adjustments
Payroll Growth (%) : 2024:2.8, 2025:2.8, 2026:2.8, 2027:2.8, 2028:3, 2029:3, 2030:3, 2031:3, 2032:3, 2033:3, 2034:3, 2035:3, 2036:3, 2037:3, 2038:3, 2039:3, 2040:3, 2041:3,
2042:3, 2043:3, 2044:3, 2045:3, 2046:3, 2047:3, 2048:3, 2049:3, 2050:3, 2051:3, 2052:3, 2053:3,
Investment Returns (%) : 2024:11.5,
Funded Percentage (Market Value of Assets)
Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 18 Packet Pg. 94 of 144
TrueComp (GovInvest) tool was used to create multiple scenarios. Details were applied to the
appropriate individual plans. Illustrations are for consolidated ALL city pension plans.
Scenario V3b includes:
-$30M ADP on shortest bases, then longest bases
-Payroll growth 2.8%
-Inflation rate 2.3%
-Discount rate 6.8%
-CalPERS Actuarial Valuation of 6/30/2024
-PARS Pension Trust Fund 6/30/2024 balance of $110 million
-ADC as shown in the table below.
Scenario V3 assumes the same as V3b except:
-All ADPs are shortest bases.
Scenario V3a assumes the same as V3b except:
-$10M shortest bases, then all ADPs are longest bases.
Scenario V3a assumes the same as V3b except:
-$10M shortest bases, then all ADPs are longest bases.
-Discount rate graduating down to 6.0%
Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 19 Packet Pg. 95 of 144
Scenario V3a assumes the same as V3b except:
-$10M shortest bases, then all ADPs are longest bases.
-Discount rate graduating down to 6.0%
Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 20 Packet Pg. 96 of 144
Use of the model is subject to acceptance of these Terms of Use.
The model is intended to be used solely as an educational resource. The results presented by the model are hypothetical and are not
intended to be estimates of future contribution rates or investment growth. Your plan’s contribution rates and funded status will be based
on actual experience, which may not be consistent with the hypothetical scenarios calculated using the model.
All figures obtained using the model are hypothetical projections of your plan’s results based on the information contained in your plan’s
most recent valuation report, the assumptions used therein and the information that you input into the model. Projections obtained using
the model will not automatically incorporate adjustments to the discount rate required under the CalPERS’ Funding Risk Mitigation Policy,
which generally requires a reduction in the discount rate if CalPERS investment performance significantly outperforms the current discount
rate.
The actuarial calculations performed by the model are based on a number of assumptions about very long-term demographic and economic
behavior. Unless these assumptions (e.g., termination, death, disability, retirement, salary growth, and investment return) are exactly
realized each year, there will be differences between the projections obtained using the model and your plan’s actual required contribution
rate and funded status on a year-to-year basis. These year-to-year differences between actual experience and the assumptions are called actuarial gains and losses and serve to lower or
raise your rates from one year to the next. Your plan’s actual contribution rate will inevitably fluctuate over time, especially due to the ups
and downs of investment returns. Such fluctuations may not be consistent with projections obtained using the model. Nothing contained herein or in the model is intended to constitute advice. CalPERS is not responsible for any projections obtained using the
model or any decisions or actions taken in reliance upon such projections.
By use of this data, I acknowledge that I understand, and agree to, these Terms of Use.
Terms of Use
Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 21 Packet Pg. 97 of 144
10/31/2025 7:55 pm (UTC)This report produced using
Palo Alto, CA
Pension-2024
Required Employer Contribution
Official Preliminary
2025 IR +11.6%
(current)
$75.25M
V3 All Short Bases
DR 6.8%
$62.19M
from $75.25M
$13.06M
V3a $10M Short then
Long DR 6.8%
$68.31M
from $75.25M
$6.93M
V3b $30M Short then
Long, DR 6.8%
$65.60M
from $75.25M
$9.65M
V4a $10M Short then
Long DR =>6.0%
$71.98M
from $75.25M
$3.27M
24-25 26-27 28-29 30-31 32-33 34-35 36-37 38-39 40-41 42-43 44-45
Fiscal Year Ending June 30
$0
$20M
$40M
$60M
Parameters
Information projected to future years assuming experience matches default demographic and economic assumptions, with the following changes:
Global Adjustments
Payroll Growth (%) : 2024:2.8, 2025:2.8, 2026:2.8, 2027:2.8, 2028:3, 2029:3, 2030:3, 2031:3, 2032:3, 2033:3, 2034:3, 2035:3, 2036:3, 2037:3, 2038:3, 2039:3, 2040:3, 2041:3,
2042:3, 2043:3, 2044:3, 2045:3, 2046:3, 2047:3, 2048:3, 2049:3, 2050:3, 2051:3, 2052:3, 2053:3,
Investment Returns (%) : 2024:11.5,
Total Employer Required
Contribution
Annual Amortization
Payment
Employer Normal
Cost
Employee
Contribution
Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 22 Packet Pg. 98 of 144
10/31/2025 8:01 pm (UTC)This report produced using
Palo Alto, CA
Pension-2024
Unfunded Accrued Liability
Official Preliminary
2025 IR +11.6%
(current)
$159.78M
V3 All Short Bases
DR 6.8%
$80.05M
from $159.78M
$79.73M
V3a $10M Short then
Long DR 6.8%
$4.02M
from $159.78M
$155.76M
V3b $30M Short then
Long, DR 6.8%
$16.76M
from $159.78M
$143.02M
V4a $10M Short then
Long DR =>6.0%
$188.30M
from $159.78M
$28.52M
2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
As of July 1
$(100M)
$0
$100M
$200M
$300M
$400M
$500M
Parameters
Information projected to future years assuming experience matches default demographic and economic assumptions, with the following changes:
Global Adjustments
Payroll Growth (%) : 2024:2.8, 2025:2.8, 2026:2.8, 2027:2.8, 2028:3, 2029:3, 2030:3, 2031:3, 2032:3, 2033:3, 2034:3, 2035:3, 2036:3, 2037:3, 2038:3, 2039:3, 2040:3, 2041:3,
2042:3, 2043:3, 2044:3, 2045:3, 2046:3, 2047:3, 2048:3, 2049:3, 2050:3, 2051:3, 2052:3, 2053:3,
Investment Returns (%) : 2024:11.5,
Accrued Liability Valuation Assets Unfunded Accrued Liability
Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 23 Packet Pg. 99 of 144
10/31/2025 8:00 pm (UTC)This report produced using
Palo Alto, CA
Pension-2024
Funded Percentage
Official Preliminary
2025 IR +11.6%
(current)
92.88%
V3 All Short Bases
DR 6.8%
96.44%
from 92.88%
3.55%
V3a $10M Short then
Long DR 6.8%
99.82%
from 92.88%
6.94%
V3b $30M Short then
Long, DR 6.8%
99.25%
from 92.88%
6.37%
V4a $10M Short then
Long DR =>6.0%
92.27%
from 92.88%
0.61%
2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
As of July 1
0%
20%
40%
60%
80%
100%
Parameters
Information projected to future years assuming experience matches default demographic and economic assumptions, with the following changes:
Global Adjustments
Payroll Growth (%) : 2024:2.8, 2025:2.8, 2026:2.8, 2027:2.8, 2028:3, 2029:3, 2030:3, 2031:3, 2032:3, 2033:3, 2034:3, 2035:3, 2036:3, 2037:3, 2038:3, 2039:3, 2040:3, 2041:3,
2042:3, 2043:3, 2044:3, 2045:3, 2046:3, 2047:3, 2048:3, 2049:3, 2050:3, 2051:3, 2052:3, 2053:3,
Investment Returns (%) : 2024:11.5,
Funded Percentage (Market Value of Assets)
Item 2
Attachment A - TrueComp
Item 2: Staff Report Pg. 24 Packet Pg. 100 of 144
CITY OF PALO ALTO
CALPERS MISCELLANEOUS & SAFETY PLANS
Independent Actuarial Report – 6/30/24 Valuation
Preliminary Results
Drew Ballard, FSA, EA, MAAA
D. Patrick McDonald, FSA, EA, MAAA
Matthew Childs
Foster & Foster, Inc.
November 5, 2025
Contents
l:\paloaltocity\calpers\6-30-24\f&f_paloaltocity_25-11-05_calpers_misc_safety_24.docx
Topic Page
Background 1
Historical Information 7
Projections 17
Combined Miscellaneous and Safety 27
Additional Discretionary Payment Analysis 29
Actuarial Certification 43
Additional Information 44
Attachment BItem 2
Attachment B - Foster and
Foster Actuarial Analysis
Item 2: Staff Report Pg. 25 Packet Pg. 101 of 144
1
INVESTMENT RETURN
Discount rates are expected returns net of administrative expenses.
2013/14 through 2023/24 “money-weighted” returns reported in CalPERS AFCR (without lags on private equity and
real estate) are 18.3%, 2.2%, 0.5%, 11.2%, 8.4%, 6.5%, 5.0%, 22.4%, -7.5%, 6.1%, and 9.5%, respectively.
20-Year and 30-Year
average return rates on
6/30/25 are 6.7% and
7.5%, respectively
2
INVESTMENT RETURN
Historical Discount Rates
Item 2
Attachment B - Foster and
Foster Actuarial Analysis
Item 2: Staff Report Pg. 26 Packet Pg. 102 of 144
3
DEMOGRAPHICS
Around the State
Large retiree liability compared to actives
State average: 61% for Miscellaneous, 64% for Safety
Declining active population and increasing number of retirees
Higher percentage of retiree liability increases contribution volatility
City of Palo Alto percentage of liability belonging to retirees:
Miscellaneous 62%
Safety 71%
4
CITY BENEFITS
At CalPERS, Enhanced Benefits implemented using all (future & prior) service
Typically not negotiated with cost sharing
City of Palo Alto
Tier 1 Tier 2 PEPRA
Miscellaneous 2.7%@55 FAE1 2%@60 FAE1 2%@62 FAE3
Safety1 3%@50 FAE1 3%@55 FAE3 2.7%@57 FAE3
Benefit = (Years of City Service) x Percentage x FAE
Percentage varies by retirement age (see following charts)
FAE1 is highest one year (typically final) average earnings
FAE3 is highest three years (typically final three) average earnings
PEPRA tier implemented for new employees hired after 1/1/13
Employee pays half of total normal cost
2026 Compensation limit
Social Security participants: $159,733
Non-Social Security participants: $191,679
1 Fire and Police Officer members are combined in this group.
Item 2
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Foster Actuarial Analysis
Item 2: Staff Report Pg. 27 Packet Pg. 103 of 144
5
CITY BENEFITS
Retirement A e
Benefit Multi lie
6
CITY BENEFITS
Retirement A e
Benefit Multi lie
Item 2
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Foster Actuarial Analysis
Item 2: Staff Report Pg. 28 Packet Pg. 104 of 144
7
SUMMARY OF DEMOGRAPHIC INFORMATION
Miscellaneous
2004 2014 2023 2024
Actives
Counts 883 802 757 833
Average
Age 46 46 46 45
City Service 10 11 10 9
PERSable Wages $68,300 $84,500 $121,500 $129,400
Total PERSable Wages 60,300,000 67,800,000 92,000,000 107,800,000
Inactive Members
Counts
Transferred 259 328 392 393
Separated 266 335 488 504
Retired
Service 460 832 1,146 1,162
Disability 63 80 66 65
Beneficiaries 70 99 136 137
Total 593 1,011 1,348 1,364
Average Annual City Provided
Pension for Service Retirees2 $19,300 $34,700 $43,200 $44,300
2 Average pension based on City service & City benefit formula; not representative of long-service employees.
8
SUMMARY OF DEMOGRAPHIC INFORMATION
Safety
2004 2014 2023 2024
Actives
Counts 194 187 164 159
Average
Age 40 40 40 40
City Service 11 11 10 11
PERSable Wages $90,000 $113,800 $170,400 $189,500
Total PERSable Wages 17,500,000 21,300,000 27,900,000 30,100,000
Inactive Members
Counts
Transferred 66 63 61 63
Separated 27 31 65 72
Retired
Service 146 226 261 260
Disability 138 149 143 144
Beneficiaries 34 36 54 60
Total 318 411 458 464
Average Annual City Provided
Pension for Service Retirees3 $36,600 $59,400 $76,700 $79,000
3 Average pension based on City service & City benefit formula; not representative of long-service employees.
Item 2
Attachment B - Foster and
Foster Actuarial Analysis
Item 2: Staff Report Pg. 29 Packet Pg. 105 of 144
9
PLAN FUNDED STATUS
Miscellaneous
June 30, 2023 June 30, 2024
Actuarial Accrued Liability
Active $ 315,500,000 $ 340,000,000
Retiree 653,000,000 670,800,000
Inactive 68,700,000 74,600,000
Total 1,037,200,000 1,085,400,000
Assets 687,400,000 745,600,000
Unfunded Liability 349,800,000 339,800,000
Funded Ratio 66.3% 68.7%
Average funded ratio for
CalPERS Miscellaneous:
Public Agency Plans 73.3% 75.5%
City and Town Plans 73.8% 75.8%
10
PLAN FUNDED STATUS
Safety
June 30, 2023 June 30, 2024
Actuarial Accrued Liability
Active $133,000,000 $146,200,000
Retiree 402,800,000 413,700,000
Inactive 19,600,000 22,500,000
Total 555,400,000 582,400,000
Assets 331,700,000 355,800,000
Unfunded Liability 223,700,000 226,600,000
Funded Ratio 59.7% 61.1%
Average funded ratio for
CalPERS Safet :
Public Agency Plans 70.9% 72.9%
City and Town Plans 70.9% 72.7%
Item 2
Attachment B - Foster and
Foster Actuarial Analysis
Item 2: Staff Report Pg. 30 Packet Pg. 106 of 144
11
PLAN FUNDED STATUS
Miscellaneous
Unfunded Accrued Liability Changes
Unfunded Accrued Liability on 6/30/23 $349,800,000
Expected 6/30/24 Unfunded Accrued Liability 344,000,000
Changes
• Asset Loss (Gain) (9.5% return for FY 2024) (18,300,000)
• Contribution & Experience Loss (Gain) 14,100,000
• Total (4,200,000)
Unfunded Accrued Liability on 6/30/24 339,800,000
Projected Unfunded Accrued Liability on 6/30/254 293,200,000
4 Projected 2025 assets reflect 11.6% preliminary investment return for 2024/25.
12
PLAN FUNDED STATUS
Safety
Unfunded Accrued Liability Changes
Unfunded Accrued Liability on 6/30/23 $223,700,000
Expected 6/30/24 Unfunded Accrued Liability 224,100,000
Changes
• Asset Loss (Gain) (9.5% return for FY 2024) (8,800,000)
• Contribution & Experience Loss (Gain) 11,300,000
• Total 2,500,000
Unfunded Accrued Liability on 6/30/24 226,600,000
Projected Unfunded Accrued Liability on 6/30/255 207,300,000
5 Projected 2025 assets reflect 11.6% preliminary investment return for 2024/25.
Item 2
Attachment B - Foster and
Foster Actuarial Analysis
Item 2: Staff Report Pg. 31 Packet Pg. 107 of 144
13
CONTRIBUTION RATES
Miscellaneous
6/30/23 6/30/24
2025/2026 2026/2027
Total Normal Cost 18.4% 18.0%
Employee Normal Cost 7.5% 7.5%
Employer Normal Cost 10.9% 10.5%
Amortization Payments 32.8% 27.1%
Total Employer Contribution Rate 43.7% 37.6%
2025/26 Employer Contribution Rate 43.7%
6/30/24 investment (gain)/loss (9.5% vs. 6.8%) (0.4%)
Progression of amortization bases (1.7%)
Other/non-investment (Gains)/Losses (4.0%)
2026/27 Employer Contribution Rate 37.6%
14
CONTRIBUTION RATES
Safety
6/30/23 6/30/24
2025/2026 2026/2027
Total Normal Cost 30.8% 29.8%
Employee Normal Cost 10.2% 10.2%
Employer Normal Cost 20.6% 19.6%
Amortization Payments 61.1% 62.8%
Total Employer Contribution Rate 81.7% 82.4%
2025/26 Employer Contribution Rate 81.7%
6/30/24 investment (gain)/loss (9.5% vs. 6.8%) (0.7%)
Progression of amortization bases 3.2%
Other/non-investment (Gains)/Losses (1.8%)
2026/27 Employer Contribution Rate 82.4%
Item 2
Attachment B - Foster and
Foster Actuarial Analysis
Item 2: Staff Report Pg. 32 Packet Pg. 108 of 144
15
CONTRIBUTION RATES
Miscellaneous
2026/27 Amortization Payment
Amortization payment is 10.3% of UAL
(one year interest on UAL is 6.8%)
• Payment exceeds interest on the UAL
• No “negative amortization.”
Amortization payment equivalent to:
• 16.3 years on level dollar amortization schedule
(all payments are the same amount)
• 12.8 years on level percent of payroll schedule
(payments increase 2.8% annually)
16
CONTRIBUTION RATES
Safety
2026/27 Amortization Payment
Amortization payment is 9.6% of UAL
(one year interest on UAL is 6.8%)
• Payment exceeds interest on the UAL
• No “negative amortization.”
Amortization payment equivalent to:
• 18.7 years on level dollar amortization schedule
(all payments are the same amount)
• 14.1 years on level percent of payroll schedule
(payments increase 2.8% annually)
Item 2
Attachment B - Foster and
Foster Actuarial Analysis
Item 2: Staff Report Pg. 33 Packet Pg. 109 of 144
17
BASELINE CONTRIBUTION PROJECTIONS
Investment returns:
June 30, 2025 11.6%6
All future years 6.8%
No Discount Rate decreases due to Risk Mitigation policy – Ultimate rate 6.8%
No Other: Gains/Losses, Method/Assumption Changes, Benefit Improvements
Different from CalPERS projection
6 Gross return based on CalPERS July 14, 2025 news release.
18
BASELINE CONTRIBUTION PROJECTIONS
New hire assumptions:
All new hires assumed PEPRA members and none are Classic members
Miscellaneous 6/30/24 employee distribution:
Benefit Tier Count
% of
Total 23/24 Payroll
% of
Total
2.7%@55 FAE1 232 27.8% $34,593,400 32.1%
2%@60 FAE1 88 10.6% 14,389,800 13.3%
2%@62 FAE3 (PEPRA) 513 61.6% 58,824,100 54.6%
Total 833 100.0% 107,807,300 100.0%
Safety 6/30/24 employee distribution:
Benefit Tier Count
% of
Total 23/24 Payroll
% of
Total
3%@50 FAE1 65 40.9% $14,726,600 48.9%
3%@55 FAE3 10 6.3% 2,119,100 7.0%
2.7%@57 FAE3 (PEPRA) 84 52.8% 13,286,600 44.1%
Total 159 100.0% 30,132,300 100.0%
Item 2
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Foster Actuarial Analysis
Item 2: Staff Report Pg. 34 Packet Pg. 110 of 144
19
BASELINE CONTRIBUTION PROJECTIONS
Miscellaneous employee cost sharing by bargaining group (percentage of pay):
SEIU: 2%
All other Miscellaneous groups: 1%
Payroll split by bargaining group (OPEB data): 58% for SEIU and 42% for
all other groups
Safety employee cost sharing by bargaining group (percentage of pay):
PAPOA: 3.5%
All other Safety groups: 4%
Payroll split by bargaining group (OPEB data): 45% for PAPOA and 55%
for all other groups
Projections include shortest base reduction due to $10 million ADP (allocated
to Miscellaneous and Safety by 6/30/25 projected UAL):
Reduced Miscellaneous 2009 Assumption Change base by $5 million
Reduced Safety 2009 & 2011 Assumption Change bases by $5 million
20
BASELINE CONTRIBUTION PROJECTIONS
City-provided payroll applied to projections (In $Millions):
FY 23/24 24/25 25/26 26/27 27/28 28/29 29/30 30/31 31/32 32/33
Miscellaneous $113 $117 $121 $126 $130 $136 $141 $147 $154 $160
Safety 32 33 34 35 35 36 37 37 38 39
Total 145 150 155 161 165 172 178 184 192 199
FY 33/34 34/35 35/36 36/37 37/38 38/39 39/40 40/41 41/42 42/43
Miscellaneous $168 $175 $183 $192 $199 $206 $212 $218 $224 $230
Safety 39 40 40 41 41 42 43 44 44 45
Total 207 215 223 233 240 248 255 262 268 275
FY 43/44 44/45 45/46 46/47 47/48 48/49 49/50 50/51 51/52 52/53
Miscellaneous $236 $242 $249 $255 $261 $268 $275 $281 $288 $295
Safety 46 47 48 49 50 51 52 54 55 56
Total 282 289 297 304 311 319 327 335 343 351
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21
BASELINE CONTRIBUTION PROJECTIONS
Miscellaneous
22
BASELINE CONTRIBUTION PROJECTIONS
Safety
Item 2
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Foster Actuarial Analysis
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23
BASELINE CONTRIBUTION PROJECTIONS
Miscellaneous
24
BASELINE CONTRIBUTION PROJECTIONS
Safety
Item 2
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Foster Actuarial Analysis
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25
BASELINE FUNDED STATUS
Miscellaneous
26
BASELINE FUNDED STATUS
Safety
Item 2
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Foster Actuarial Analysis
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27
COMBINED MISCELLANEOUS AND SAFETY
Miscellaneous and Safety Baseline
28
COMBINED MISCELLANEOUS AND SAFETY
Miscellaneous and Safety
Funded Status Summary on June 30, 2024
(Amounts in $Millions)
Miscellaneous Safety Total
AAL $1,085.4 $582.4 $1,667.8
Assets 745.6 355.8 1,101.4
Unfunded AAL 339.8 226.6 566.4
Funded Ratio 68.7% 61.1% 66.0%
Projected Funded Status Summary on June 30, 20257
(Amounts in $Millions)
Miscellaneous Safety Total
AAL $1,121.7 $598.3 $1,720.0
Assets 828.5 391.0 1,219.5
Unfunded AAL 293.2 207.3 500.5
Funded Ratio 73.9% 65.4% 70.9%
7 Projected 2025 assets reflect 11.6% preliminary investment return for 2024/25.
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29
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
City of Palo Alto Section 115 Trust
Scheduled 115 trust contributions and disbursements (In $Millions):
FY 25/26 26/27 27/28 28/29 29/30 30/31 31/32 32/33
115 Trust Contribution $14.1 $13.7 $13.4 $13.1 $12.6 $12.1 $11.6 $11.1
CalPERS ADC Withdrawal 0.0 10.0 10.0 6.0 6.0 6.0 0.0 0.0
CalPERS ADP Withdrawal 10.0 20.0 30.0 20.0 14.0 13.0 11.0 17.0
Net Contribution/(Withdrawal) 4.1 (16.3) (26.6) (12.9) (7.4) (6.9) 0.6 (5.9)
FY 33/34 34/35 35/36 36/37
115 Trust Contribution $10.5 $10.0 $ 0.0 $ 0.0
CalPERS ADC Withdrawal 0.0 0.0 0.0 0.0
CalPERS ADP Withdrawal 18.0 17.0 18.0 10.0
Net Contribution/(Withdrawal) (7.5) (7.0) (18.0) (10.0)
2025/26 ADP to CalPERS reduces bases with shortest periods
2026/27 ADP to CalPERS is compared reducing bases with shortest periods
and bases with longest periods
115 trust balance, contributions, and distributions allocated to Miscellaneous
and Safety by 50%/50% split
27/28+ ADP’s reduce bases with longest periods first beginning 27/28
30
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
City of Palo Alto Section 115 Trust (Continued)
Trust Balance at 6/30/25 $109,904,500
Projected Balance at 6/30/268 $118,990,200
Trust Earnings (assumed) – PARS Balanced Index 4.5%
8 Projected with assumed 4.5% interest, $14.1M contribution, and $10M distribution for CalPERS ADP.
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31
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Total Section 115 Trust
32
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
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33
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Miscellaneous
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
34
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Miscellaneous
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
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35
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Safety
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
36
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Safety
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
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37
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Miscellaneous
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
38
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Miscellaneous
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
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39
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Safety
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
40
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Safety
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
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41
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Miscellaneous
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
42
ADDITIONAL DISCRETIONARY PAYMENT ANALYSIS
Safety
* Baseline includes $5 million ADP applied to bases with shortest bases and gain based on 11.6% 24/25 investment return.
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43
ACTUARIAL CERTIFICATION
This report presents analysis of the City of Palo Alto’s CalPERS pension plans. The purpose of this report is to provide
the City:
Historical perspective on the plan investment returns, assets, funded status and contributions.
Projections of likely future contributions and the impact of investment volatility.
The calculations and projections in this report are based on information contained in the City’s June 30, 2024 and earlier
CalPERS actuarial valuation reports. We reviewed this information for reasonableness, but do not make any
representation on the accuracy of the CalPERS reports.
Future investment returns and volatility are based on Foster & Foster’s Capital Market model which results in long term
returns summarized on page 17.
Information provided in this report may be useful to the City for the Plan’s financial management. Future actuarial
measurements may differ significantly from the current measurements presented in this report due to such factors as: plan
experience differing from that anticipated by the assumptions; changes in assumptions; changes expected as part of the
natural progression of the plan; and changes in plan provisions or applicable law. Actuarial models necessarily rely on the
use of estimates and are sensitive to changes. Small variations in estimates may lead to significant changes in actuarial
measurements. Due to the limited scope of this assignment, we did not perform an analysis of the potential range of such
measurements.
To the best of our knowledge, this report is complete and accurate and has been conducted using generally accepted
actuarial principles and practices. As members of the American Academy of Actuaries meeting the Academy
Qualification Standards, we certify the actuarial results and opinions herein.
Respectfully submitted,
DRAFT DRAFT
Drew Ballar , FSA, EA, MAAA
Foster & Foster, Inc.
D. Pa rick McDonald, FSA, EA, MAAA
Foster & Foster, Inc.
44
DEFINITIONS
PVB - Present Value of all Projected
Benefits:
The value now of amounts due to be
paid in the future
Discounted value (at valuation date -
6/30/24), of all future expected benefit
payments based on various (actuarial)
assumptions
Current Normal Cost (NC):
Portion of PVB allocated to (or “earned” during) current year
Value of employee and employer current service benefit
Actuarial Liability (AAL):
Discounted value (at valuation date) of benefits earned through valuation date
[value of past service benefit]
Portion of PVB “earned” at measurement
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45
DEFINITIONS
Target- Have money in the bank to cover Actuarial Liability (past service)
Unfunded Liability (UAAL or UAL) - Money short of target at valuation date
If all actuarial assumptions were always exactly met, then the plan assets would
always equal AAL
Any difference is the unfunded (or overfunded) AAL
Every year, the actuary calculates the difference between the expected UAAL and
Actual UAAL. This is a new layer or amortization base
Each new layer gets amortized (paid off) over a period of time as part of the
contribution [rate]
46
ADDITIONAL ASSUMPTIONS & METHODS
Retiree benefit payments increase at 4%
Tiers 1, 2, and current PEPRA members’ payroll increase/decrease according to
similar large client projected payroll using same mortality, retirement,
withdrawal, and disability assumptions as CalPERS 2000-2019 Experience
Study
PEPRA payroll added to above projected payroll to make aggregate payroll
increase at City-provided payroll
All other assumptions same as CalPERS valuation assumptions
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Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Utilities
Meeting Date: November 18, 2025
Report #:2508-5119
TITLE
Discussion and Update on the Fiscal Year 2027 Preliminary Utilities Financial Forecast and Rate
Projections
RECOMMENDATION
This item is for discussion, and no action is requested. These preliminary calculations reflect an
initial estimate for review and feedback by the Finance Committee and Utilities Advisory
Commission (UAC) on key assumptions for the Electric, Gas, Water, and Wastewater Collection
Utilities to inform recommended Fiscal Year (FY) 2027 financial forecasts and proposed rate
changes for each utility.
EXECUTIVE SUMMARY
The City of Palo Alto Utilities provides electricity, water, wastewater, natural gas, and fiber
optics. The City’s Public Works Department also provides refuse collection and processing for
recycling, compost and garbage, wastewater treatment and stormwater management services.
Customers benefit from the continued safe, reliable, environmentally sustainable, and cost-
effective operations of each of these utilities. FY 2027 preliminary calculations model necessary
rate increases to support upkeep, infrastructure replacements, and replenishment of reserves
to allow the City to continue to provide high quality utility services to the community.
All of the preliminary rate forecasts presented here are unchanged from the forecasts
presented to the City Council in June1, except for the Gas Utility. Last year’s Financial Forecast
projected a 6% increase for the Gas Utility in FY 2027 while staff now propose an 8% overall
revenue increase in FY 2027, which is equivalent to a 9% median impact to the residential
customer’s gas bill. Preliminary forecasts reflect a need for an overall 9% or $37.80 monthly
rate increase in FY 2027 for the median residential utility bill, encompassing six services
(electric, gas, water, sewer, refuse, and stormwater). A Gas Utility cost-of-service study is on a
1 Staff Report 2411-3776, June 16, 2025
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parallel process timeline for Council consideration. This preliminary financial forecast assumes
the gas utility cost allocations in the study are approved by Council and implemented in early
2026. The Refuse Utility is in the process of conducting a cost-of-service study and staff
anticipates the study results will be ready for review in early 2026.
BACKGROUND
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rates while ensuring a modern, reliable, and sustainable utility. A series of rate adjustments
similar to those discussed last year are necessary to restore reserves to within guideline ranges
with the five-year planning period. For the Electric, Water and Wastewater Collection Utilities,
the proposed rate increases are the same as presented to the Council in June 2025. However,
for the gas utility due to declining sales revenues and increasing costs, additional increases are
necessary as described in more detail below.
3. UAC Commissioners
discussed forming a subcommittee to examine FY 2027 rates including comparing Palo Alto’s
rate plans to other utilities plans. This Subcommittee could think creatively and structurally
about how to manage costs. Some of the ideas suggested by UAC Commissioners included
daylighting the policy issue of debt financing vs revenue financing and the risks and benefits to
each approach; conducting a lean analysis of expenses including what activities do customers
value and what activities do we need to do to get that value to customers and are there
activities we do not need to do; examining cost containment beyond deferring CIP including a
close look at operating costs and whether CIP costs can be canceled not just deferred; and
charging customers who opt out of paperless billing and AMI meters. The UAC plans to make a
recommendation on forming this subcommittee at the next UAC meeting scheduled for
December 3, 2025.
3 UAC Meeting, November 5, 2025, item 5:
https://cityofpaloalto.primegov.com/Portal/Meeting?meetingTemplateId=17466 A video recording of the meeting
is available: https://www.youtube.com/watch?v=1e6NrB2KDCw
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expressed interest in having this agendized. One Commissioner discussed that demand is
declining in the water and gas utilities and we need to be proactive to avoid a death spiral of
prices going up and demand going down. One Commissioner suggested staff should make the
rate increase more clear by providing the whole utility bill in future years instead of providing
incremental changes.
ANALYSIS
1) Changes shown with commodity rates held constant; actual gas commodity rates vary monthly. Gas
increase in FY 2026 reflects Council-approved increase.
2) A rate increase of $0 is used as a placeholder for Refuse in FY 2027 in this table because the Cost of
Service study results are pending and not yet available.
3) Stormwater management fees increase by Consumer Price Index (CPI) annually per approved 2017
ballot measure (2.6% in FY 2025).
4) Based on projected average monthly residential bill over FY 2026 of $442; includes proposed cost of
service adjustments for the Gas Utility in FY 2026 which was presented to the UAC. This approach
shows the proposed FY 2027 gas rate increase impacts discussed in this preliminary rate proposal.
5) Bill dollar changes are rounded to the nearest $0.10, and bill percentage changes are rounded to the
nearest whole percent.
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Electric
The FY 2027 preliminary rate projections in the Electric Utility Financial Forecast are unchanged
from the FY 2026 Financial Forecast presented to the Council on June 16, 2025 of 6% for FY
2027.
At the end of FY 2025 the Electric Utility’s combined Operations Reserves for Distribution and
Supply totaled $46.6 million, which is close to the target level of $49.5 million.5 At the end of FY
2025 the following transfers were completed:
1) The Electric Utility repaid the remainder ($7.5 million) of the June 30, 2018 and June 30,
2022 loans totaling $15 million to the Electric Special Projects Reserve bringing the
reserve balance from $22.6 million to $30.1 million.6 These funds covered higher costs
during the pandemic, lower hydroelectric generation during the drought, and high
winter energy prices during 2022-2023.
2) The Electric Utility has a Hydroelectric Stabilization Reserve that is used to manage the
supply cost impacts associated with variations in generation from hydroelectric
resources. In FY 2025, $1.4 million was placed into the Hydro Stabilization Reserve as a
result of favorable hydro conditions in FY 2025, bringing the hydro reserve balance to
$18.7 million, which is within the target hydro reserve amount of $19.0 million.7
Replenishing this reserve reduces the risk that, in the event of unforeseen condition
declines in hydro conditions, the City will need to use the Hydro Rate Adjuster to
5 Attachment D, Exhibit 1 to Staff Report 2411-3776, June 16, 2025, Table 1, line 66:
https://www.paloalto.gov/files/assets/public/v/2/agendas-minutes-reports/agendas-minutes/city-council-
agendas-minutes/2025/june-16/rates-attachments/finalized-attachment-d-exhibit-1-fy26-electric-utility-financial-
forecast-and-cip-detail.pdf
6 In FY 2018 Council approved a $10 million transfer from the Electric Special Projects Reserve to the Operations
Reserve to mitigate higher supply costs due to the drought, the costs of new renewable energy projects coming
online and increasing transmission charges. See Staff Report 8186
https://www.cityofpaloalto.org/files/assets/public/v/1/agendas-minutes-reports/reports/city-manager-reports-
cmrs/year-archive/2017/8186.pdf. $5 million was repaid in FY 2020; See Staff Report 11341
https://www.paloalto.gov/files/assets/public/v/1/agendas-minutes-reports/reports/city-manager-reports-
cmrs/year-archive/2020/id-11341-mini-packet-062220.pdf. In FY 2022 Council approved an additional $5 million
transfer from the ESP reserve to the Operations Reserve to avoid rate increases exceeding 5%. (Staff Report 13361,
June 13, 2022) https://www.cityofpaloalto.org/files/assets/public/v/6/agendas-minutes-reports/agendas-
minutes/city-council-agendas-minutes/2022/20220613/20220613pccsm-final-amended-linked.pdf#page=102. This
left a total outstanding loan of $10 million. In FY 2024, $2.5 million was repaid (Staff Report 2411-3776, June 16,
2025, Attachment D, Exhibit 1, line 55 shows the balance in the Electric Special Project Reserve increased by $2.5
million in FY 2024 https://www.paloalto.gov/files/assets/public/v/2/agendas-minutes-reports/agendas-
minutes/city-council-agendas-minutes/2025/june-16/rates-attachments/finalized-attachment-d-exhibit-1-fy26-
electric-utility-financial-forecast-and-cip-detail.pdf).
7 Electric Utility Reserves Management Practices, Section 7 d; Attachment D, Exhibit 3 to Staff Report 2411-3776,
June 16, 2025: https://www.paloalto.gov/files/assets/public/v/1/agendas-minutes-reports/agendas-minutes/city-
council-agendas-minutes/2025/june-16/rates-attachments/attachment-d-exhibit-3-fy26-electric-reserves-
management-practices.pdf
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recover higher supply costs.
Staff expects that debt will be issued later in FY 2026 to cover the grid modernization costs
already spent and planned in FY 2026. The Electric Distribution Operations Reserve is currently
low because it reflects grid modernization costs, commitments, and reappropriations planned
to be reimbursed through the debt issuance (an estimated total of $3.5 million in FY 2025 and
$6 million in FY 2026). As mentioned above, on a combined basis, the Electric Distribution and
Supply Operations Reserves are within the guideline range.
Staff updated the preliminary forecast for the electric supply purchase costs in FY 2027. Net
electric supply purchase costs are anticipated to be 3% higher than the FY 2026 Financial
Forecast. Revenues from selling surplus system Resource Adequacy and Renewable Energy
Certificates provide additional supply revenues.11 The demand forecast for FY 2027 is 8% higher
than that in the FY 2026 Financial Forecast. Transmission costs continue to rise, and capital
spending and distribution system maintenance spending is rising due to grid modernization and
other substation upgrades to increase capacity and enhance reliability, which will benefit all
electric ratepayers.
The current year (FY 2026) Financial Forecast for the Electric Utility (approved June 16, 2025) is
described in the Finance Committee Staff Report 2412-3870 from April 15, 2025:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment
/?historyId=cdf2cce3-a2be-45f3-9acf-9b073bb01196
Changes made after the Finance Committee Staff Report are described in the City Council
Report 2411-3776:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment
/?historyId=35104f06-6925-4fe3-89c7-b0e53e6eec42
Attachment D, Exhibit 1 to City Council Report 2411-3776 includes financial and Capital
Improvement Program (CIP) details: https://www.paloalto.gov/files/assets/public/v/2/agendas-
minutes-reports/agendas-minutes/city-council-agendas-minutes/2025/june-16/rates-
attachments/finalized-attachment-d-exhibit-1-fy26-electric-utility-financial-forecast-and-cip-
detail.pdf
11 Resolution 9913 https://www.paloalto.gov/files/assets/public/v/1/city-clerk/resolutions/reso-
9913.pdf?t=40151.26, Staff Report 11556 https://www.paloalto.gov/files/assets/public/v/1/agendas-minutes-
reports/reports/city-manager-reports-cmrs/year-archive/2020-2/id-11566.pdf,
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Gas
Last year’s Financial Forecast (FY 2026) projected a 6% increase for the Gas Utility in FY 202713.
In FY 2025, gas utility sales revenues were about $4.7 million (8%) lower than forecasted due to
lower-than-expected gas usage. Although supply purchases were $3.2 million (14%) below
forecast, the cost savings were insufficient to offset the revenue shortfall. Distribution expenses
were approximately $0.6 million (-4%) lower than projected, while CIP expenses exceeded
projections by about $6.8 million, most of which were funded through the CIP reappropriation
and commitments reserve. Also, approximately $700,000 in additional funds will be needed in
FY 2027 for gas line repairs at Arastradero Creek. To offset these costs, the City received grant
funding of approximately $300,000 of Federal Energy Management Agency (FEMA) funding and
$95,000 in California Governor’s Office of Emergency Services (CalOES) funding that will be
shared among the Water, Wastewater Collection, and Gas Utilities in GS-25001 (the capital
project completing the emergency repairs at Arastradero Creek).
On April 15, 2025, staff presented a 2025 COSA and Gas Utility proposal to the Finance
Committee and members expressed concern about the bill impact to median and low usage
residential gas customers resulting from the 2025 COSA study. The item was continued to May
7, 2025 when staff presented additional information to the Finance Committee, including an
interim alternative recommendation to continue the FY 2025 rate structure based on the 2020
cost study, with rate increases to meet FY 2026 revenue requirements.14 The Finance
Committee voted unanimously to recommend the City Council revise the proposed FY 2026
rates to retain the FY 2025 rate structure, with a rate increase to meet the revenue
requirement for FY 2026 in the gas utility, and to refer staff to return to the UAC to further
review the cost-of-service study assumptions and principles. On June 16, 2025 the City Council
agreed that the UAC should review the updated COSA.15
13 Staff Report 2412-3868
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844-77c1-448d-b9f3-77514c21a64b
14 May 7, 2025 Finance Committee Meeting
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=530a4f
25-5455-4cec-a95c-5190d95d9a4f; Video: https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Item
2.a., 3.b. Supplemental Report https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Video
15 During the UAC, Finance Committee and Council meetings, various proposals were also discussed regarding one-
time credits using Cap and Trade auction revenues and ultimately the Council returned the issue of a one-time
credit to the UAC at the time they review the updated COSA. However, currently no credits are being proposed.
For a full history of those proposals, see UAC Staff Report 2411-3751 from April 2, 2025:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=29fcc1
53-3f31-44d8-9b96-ec5349e043c2; and Finance Committee Staff Report 2412-3868, April 15, 2025
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=8bb9e
844-77c1-448d-b9f3-77514c21a64b; and May 7, 2025 Finance Committee Meeting:
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On July 9, 2025 the UAC voted to form a subcommittee to work with staff and the cost-of-
service consultant to develop a new 2026 gas COSA and provide regular report-outs to the full
UAC. 19 On September 15, 2025 the Council directed staff to follow the reasonable-cost analysis
required by Proposition 26 and to collaborate with the UAC to develop revised gas rates
effective January 2026 based on five design principles.20
21
Staff met with the UAC subcommittee four times from August through October, followed the
reasonable-cost analysis required by Proposition 26 and developed revised gas rates based on
the five design principles approved by the City Council. The implementation of the Gas Utility
rates resulting from the cost-of-service study on February 1, 2026 enables the utility to take a
stepwise approach to rate adjustments. This approach distinguishes the cost-of-service-based
rate changes, effective in early 2026, from the general gas utility rate increases proposed in this
report to take effect in July 1, 2026 for FY 2027.
During the pandemic, the City kept overall Gas Utility rate increases at 2% to 3% annually and
utilized reserve funding to cover costs. In the winter of 2022-23, surging gas commodity prices
depleted the Gas Utility reserves, which covered the gap between actual gas commodity costs
and the Council-approved maximum gas commodity charge. Reserves need to be replenished
to provide a target of 90 days of operations and maintenance and commodity expenses.22
The Gas Utility's transfer to the City’s General Fund is a component of the City’s gas rates. This
transfer was first authorized by voters in 1950 and reaffirmed in November 2022 with the
passage of Measure L which authorizes a transfer amount up to 18% of the gross revenues of
the Gas Utility. The preliminary forecast assumes a transfer based on 18% of estimated gross
revenues from FY 2025, to be $10.7 million in FY 2027, an increase of $1.0 million from FY 2026.
19 July 9, 2025, UAC voted 6-1 with Gupta voting no; see action minutes
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=40dc6
4ea-7e0c-4dca-9235-61e1a6516b07
20 Staff Report 2507-4958, September 15, 2025:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=043ab
d5a-f59f-4702-ad04-845541a8133f; see action minutes:
https://cityofpaloalto.primegov.com/Public/CompiledDocument?meetingTemplateId=16223&compileOutputType
=1
25-5455-4cec-a95c-5190d95d9a4f; Video: https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Item
2.a., 3.b. Supplemental Report https://youtube.com/watch?v=kW97GWkgaY0?feature=share; Video; and Council
Staff Report 2411-3776 June 16, 2025:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=35104f
06-6925-4fe3-89c7-b0e53e6eec42
22 Staff Report 2411-3776, Attachment C, Exhibit 3, Section 8, Operations Reserve, June 16, 2025:
https://www.paloalto.gov/files/assets/public/v/3/agendas-minutes-reports/agendas-minutes/city-council-
agendas-minutes/2025/june-16/rates-attachments/finalized-attachment-c-exhibit-3-fy26-gas-reserve-
management-practices.pdf
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As a result of lower sales revenues in FY 2025, as well as additional projected capital costs, and
rising operating costs, staff now propose a 9% overall rate increase in FY 2027. The FY 2027
preliminary Gas Utility Financial Forecast reflects a distribution rate increase of 14.5%, which is
equivalent to a 9% overall rate increase when combined with supply related charges, assuming
supply charges remain unchanged.
Water
26; however, these funds were not
transferred at year-end because the Operations Reserve balance was already within the reserve
policy guideline range (see Table 2). The Rate Stabilization Reserve has $4 million remaining as
of FY 2025 year-end, which may be used to cover costs in FY 2026 or beyond, as determined by
26 City Council June 16, 2025, Attachment B – Resolution for the FY 2026 Water Utility
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City Council.
28. Projected reserve guideline amounts for FY 2026 and FY 2027 reflect the FY27
Preliminary Forecast’s projected expenses.
29, the San Francisco Public Utilities
Commission (SFPUC), estimated a 1% increase to its wholesale water rate in FY 2027. Consistent
with this rate notice, the City’s preliminary forecast assumes that in FY 2027 SFPUC increases
the wholesale water rate from its current level of $5.80/CCF to $5.86/CCF. Table 2 shows rate
28 Water Utility Reserve Management Practices; Section 5 (CIP Reserve), Section 7 (Operations Reserve):
https://www.paloalto.gov/files/assets/public/v/1/agendas-minutes-reports/agendas-minutes/city-council-
agendas-minutes/2025/june-16/rates-attachments/attachment-b-exhibit-3-fy26-water-reserve-management-
practices.pdf
29 San Francisco Public Utilities Commission Fiscal Year 2025-2026 Wholesale Water Rates, May 13, 2025,
https://sfpuc.sharefile.com/share/view/se9a42370c51345bd9d2b495f8b885fc0
Actual
FY 2025 FY 2026 FY 2027
Operations Reserve Balance 16,351$ 9,946$ 10,880$
Mininum Reserve Guideline (60 days of O&M and commodity expense) 8,353$ 9,451$ 9,589$
Maximum Reserve Guideline (120 days of O&M and commodity expense) 16,706$ 18,903$ 19,178$
CIP Reserve Balance 3,500$ 4,472$ 7,272$
Mininum Reserve Guideline (20% of the maximum CIP Reserve guideline
level)2,226$ 3,083$ 3,639$
Maximum Reserve Guideline (Average annual (12 month) CIP budget,
for 48 months of budgeted CIP expenses)11,129$ 15,416$ 18,197$
Rate Stabilization Reserve Balance 4,000$ 4,000$ 4,000$
Projected
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projections through 2030 as stated in the SFPUC’s May 8, 2025 wholesale water rate notice.
SFPUC’s wholesale rate projection is subject to change and highly uncertain.
Wastewater Collection
Fiscal Year 2027 2028 2029 2030 2031
SFPUC Commodity Rate Projection (as of May '25)1%1%5%8%3%
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At year end FY 2025, the Wastewater Collection Utility had approximately $0.9 million in cash
available, which is lower than staff’s projection. There is a possibility that the Wastewater
Collection Utility will not be able to fully repay the loan (Reso 10173)32 from the Fiber Utility
that is due to be repaid with interest in FY 2026. The loan may need to be extended to keep a
positive cash balance. Extension of the loan will not impact activities in the Fiber Utility.
Consistent with the FY 2026 Financial Forecast, this preliminary forecast assumes the first five-
mile sewer main replacement project is deferred to FY 2028. The forecast continues to reflect
investments in the minimum number of necessary projects to allow the Wastewater Collection
fund to recover and mitigate a higher rate increase. However, certain necessary CIP projects
have arisen including additional costs for the Arastradero Creek exposed pipe repairs, and pipe
relocation ($2 million in FY 2028). As mentioned above, the City received grant funding that will
be shared with the Wastewater Collection utility to offset these costs.
In FY 2024, the Wastewater Collection Utility paid approximately $0.5 million more than the
base budget for vehicle replacements. In the FY 2026 Financial Forecast, staff included
additional vehicle replacement funds to pay for replacement of aging vehicles even though
there is uncertainty about the timing of those payments. Additionally, in the future there will be
costs associated with electrifying the vehicles, which are unknown and not yet incorporated
into the forecast. Staff proposes to retain the amounts set aside to pay for vehicle
replacements in the Operations Reserve to smooth those payments over time. This would mean
that those funds are held in the Operations Reserve and not used to cover fluctuations in
general operating and capital expenses. The dollars would be shown as a subtotal and not used
in the calculation of the Operations Reserve minimum, maximum, and target levels. This change
would require Council approval and a modification to the reserve management practices.
With this rate increase in FY 2027, Palo Alto’s residential rate will be approximately 2% above
neighboring cities, assuming that neighboring utilities rates remain at current levels. The
additional funding generated by this rate increase is required to pay for the ongoing
wastewater treatment charges, operations, and capital improvement.
The current year (FY 2026) Financial Forecast for the Wastewater Collection utility (approved
June 16, 2025) is described in the Finance Committee Staff Report 2412-3871:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment
/?historyId=bbddd35d-170c-46ae-a9dc-0842c797f852
Changes made after the Finance Committee Staff Report are described in the City Council
Report 2411-3776:
https://cityofpaloalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment
32 Resolution 10173: https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=62043
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/?historyId=35104f06-6925-4fe3-89c7-b0e53e6eec42
FISCAL/RESOURCE IMPACT
STAKEHOLDER ENGAGEMENT
ENVIRONMENTAL REVIEW
APPROVED BY:
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Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Administrative Services
Meeting Date: November 18, 2025
Report #:2507-5010
TITLE
Status Update on Calendar Year (CY) 2025 Finance Committee Referrals. CEQA Status -- Not a
Project.
RECOMMENDATION
This report provides a status update of Council referrals requested and approved, during the
City Council Retreat and annual Budget Process. Staff recommends the Committee review and
accept this report.
BACKGROUND
This report provides an update of the outstanding Council referrals to the Finance Committee
as requested during the February 2025 City Council Retreat, during the May - June 2025 Budget
Process, and throughout the year. The City Council requested information on various items that
are discussed in this report, and is provided in coordination with the assigned departments. A
summary table of the current referrals and their status follows.
Referral
Assigned
Department Status
FY 2023:
Planning and
Development Services
Fee Study
Planning and
Development
Services
Nov 2025 Status: Completed
Staff presented the Planning and Development
Services Cost of Services Study and proposed
municipal fee adjustment to the Finance
Committee on March 3, 2025, with a follow up
on April 29, 2025. The study and
corresponding adjustments to fees were
approved and adopted as part of the FY 2026
Operating Budget. On September 8, 2025 staff
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Referral
Assigned
Department Status
added an additional subsidized permit fee for
the installation of stand-alone residential gas
powered, water and space heating equipment.
The fee amount is lower than full cost recovery
to encourage installers of residential water
and space heating equipment to obtain
permits, thereby helping ensure these
appliances are installed in a safe and code-
compliant manner.
FY 2023:
Parking Permits Pricing
and Parking Permit
Funds Financial Status
Office of
Transportation
Nov 2025 Status: In Progress
On October 15, 2024, staff presented the
Finance Committee (#2409-35371) the parking
funds’ financial status (University Avenue,
California Avenue, and Residential Preferential
Parking Program (RPP)) and overview of
potential parking improvements and
adjustments under development. Since then,
Staff have recommended continuing the
practice of designating General Fund financial
support as a subsidy with obligation for
repayment. Options for program changes will
be developed in consultation with a new
permit management vendor (onboarding is in
process) and to align preferred stakeholder
alternatives with vendor capabilities and
prioritized program goals. Options will be
brought for Council consideration in Spring
2026 including paths to improve financial
sustainability for the programs involved.
FY 2025 Adopted
Budget:
Ability Path (Request
$250,000)
CMO Nov 2025 Status: Completed
On February 24, 2025 for the FY 2025 Mid-
Year Budget Review2, Council did not
appropriate funding at that time.
1 Finance Committee, October 15, 2024; Agenda Item #: AA1, Staff Report #: 2409-3537,
https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=64678
2 City Council, February 24, 2025; Agenda Item #: 9, Staff Report #: 2412-3865,
https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=83263
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Referral
Assigned
Department Status
FY 2025 Adopted
Budget:
Analyze Fire Emergency
Medical Response Fee
Adjustments (Ongoing
Revenue TBD)
Fire Nov 2025 Status: Completed
On June 16, 2025 City Council approved the
increases the Fire Emergency Medical
Response Fees that were proposed in the
Municipal Fee Study, and became effective in
FY 2026, including the new First Responder
Fee. The Base Ambulance Transport Fee was
increased to $3,897 and the new First
Responder Fee of $497 was added to the fee
schedule. An estimated
FY 2025 Adopted
Budget:
Fire Emergency Medical
Response; Supplemental
Resources (Estimated
costs: $1,000,000-
$4,000,000 Ongoing)
Fire Nov 2025 Status: In Progress
In November 2024 and April 2025, the Fire
Department presented multiple options to
Finance Committee on the expansion of
Emergency Medical Services (EMS). On April 1,
2025 Finance Committee directed staff to
propose options towards implementing Option
F, which would add 2.5 Single Role
Ambulances to the City’s Emergency Medical
Response Services.
On May 6, 2025 the Department presented
options considering an initial step by creating
the new Single Role Division and starting by
adding the 12-HR Peak ambulance with Single
Role staff. This plan was added to the FY 2026
Budget and approved on June 16, 2025 by City
Council.
This initial phase adds a 12-Hour Peak
Ambulance with Single Role staff and support
staff to begin building the Single Role Division.
The ongoing annual cost of these changes is
$1.2M.
The Department is on track to meet the
timeline outlined to Finance Committee at the
May 6th Meeting. A Job Description has been
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Referral
Assigned
Department Status
drafted and the City is working with IAFF and
CalPERS for final determination of sworn
status. The Department has begun the internal
process to post the support position, which
will assist in developing the onboarding
process and policies for the new Single Role
Division allowing the Department to hire Single
Role Ambulance staff in the Spring or early
Summer.
The shorter onboarding time for Single Role
staff will allow for deployment of the 12-HR
Peak ambulance before the end of the Fiscal
Year as planned.
FY 2025 Adopted
Budget:
Review Parks Restroom
Prioritization;
Specifically, Pardee Park
(Ongoing capital project
costs TBD)
Community
Services
Department
Nov 2025
Staff incorporated the Eleanor Paradee Park
restroom into the FY 2026 CIP that was
approved by City Council on June 16, 2025.
Staff is currently working on the Mitchell Park
restroom project, prioritized for its high use
related to the Magical Bridge Playground and
pickleball courts. Eleanor Pardee Park
Restroom is the next planned project under
CIP PG-19000. This project is anticipated to
begin mid-2026.
FY 2025 Adopted
Budget:
Active Recruitment
Digital Marketing
Services (Contract
Services)
Human
Resources
Nov 2025 Status: Completed
The Human Resources Department has
completed it analysis of available digital
marketing resources as well as analysis of the
existing labor market and determined no
additional digital marketing resources should
be purchased at this time due to the current
fiscal situation, layoffs occurring both at the
federal level and local tech, and the limited
reach of digital marketing into the hard to
recruit industries within which Palo Alto
Competes for talent.
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Referral
Assigned
Department Status
FY 2025 Adopted
Budget:
Establish Organizational
Development & Safety
Division ($135,000
Ongoing; 50% GF/50%
ISF)
Human
Resources
Nov 2025 Status: Completed
The City’s Safety and Risk Management
programs have transitioned from Human
Resources to Administrative Services,
supported by 1.0 FTE Senior Management to
oversee day to day operations. This position
has been filled and appropriate responsibilities
transitioned.
In order to accommodate the heightened need
for Organizational Development work without
adding headcount, the Human Resources
department created a merged division of
Organizational Development and HRIS tasked
with overseeing the revamp and expansion of
professional development and enhancement
of existing personnel processing. This is
currently overseen by a Senior Management
Analyst however HR will review to determine
the appropriate classification to oversee this
work.
FY 2025 Adopted
Budget:
Explore financial,
outreach, and policy
processes for adding
East Palo Alto to
resident rates for the
golf course (Ongoing
revenue reduction TBD)
Community
Services
Department
Nov 2025 Status: Completed
Staff added East Palo Alto to resident rates for
the golf course for FY 2026 as part of the
Municipal Fee updates. This change went into
effect July 1st, 2025. Staff estimates that
extending Palo Alto resident rates to East Palo
Alto residents may result in an annual green
fee revenue loss of approximately $8,000 to
$16,000, or about 0.3% of budgeted annual
green fee revenue.
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Referral
Assigned
Department Status
FY 2025 Adopted
Budget:
Increasing Revenue-
Generating CSD
Programming to Meet
Demand (Ongoing cost &
revenue TBD)
Community
Services
Department
Nov 2025 In Progress
CSD programming has increased as a result
of increased resources in FY25 and a
staffing reorganization in the Art Center.
From FY24 to FY25, programming-related
revenues increased by about 9%, or
$421,000. The Bryant Street Community
Center will open in January 2026 with
additional revenue-generating programming
for youth and adults.
FY 2026 Adopted
Budget:
Cost Recovery Policy -
Update the City Cost
Recovery Policy to
include a new 100% cost
recovery category
Administrative
Services
Nov 2025 Status: In progress
Staff intends to bring forward a new 100% cost
recovery category in Spring 2026. This will
align with the annual fee update.
FY 2026 Adopted
Budget:
Update Fee Cost
Recovery Category -
Summarize the current
fee cost recovery
category by fee type and
update to reflect current
policy direction on cost
recovery and revenue
enhancement
objectives.
Administrative
Services
Nov 2025 Status: Not Started
Review of all individual fees and associated
cost recovery category is beyond available
resources to undertake the project. Narrowing
the referral scope and/or prioritizing fee
categories would enable incremental review
given resource constraints.
FY 2026:
Risk Management,
General Liability, and
Insurance – Update
Council on risk
management and safety
policies, including risk
Administrative
Services
Nov 2025 Status: In Progress
Staff will forward to the City council the
summary of risk management and relevant
updates on oversight, management, and
mitigation strategies.
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Referral
Assigned
Department Status
transfer, claims analysis
and mitigation strategies
Staff will continue evaluation of expanded
insurance policies with ACCEL pool broker
aligned with annual budget development.
City Manager’s Office will explore adding tort
reform to the proposed 2026 legislative
guidelines, which may limit public agency
maximum liability/ general damages.
Staff will continue to review existing claims
data and litigation, departmental reporting
procedures, and citywide recovery strategies.
Staff are coordinating meetings with
departments to:
-evaluate risk management and safety
within the current SOPs,
-increase risk management engagement
citywide, and
-assess safety roles shared across
departmental staff
STAKEHOLDER ENGAGEMENT
This is an informational report to follow up on Council referral items and has been coordinated
internally among departmental parties.
ENVIRONMENTAL REVIEW
This item is presented for the Finance Committee’s information and discussion purposes only
and therefore it is not a project within the definition of the California Environmental Quality Act
(CEQA) because no action is being recommended for the City Council.
APPROVED BY:
Lauren Lai, Administrative Services Director
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