HomeMy WebLinkAbout2026-03-31 Utilities Advisory Commission Agenda PacketUTILITIES ADVISORY COMMISSION
Special Meeting
Tuesday, March 31, 2026
Council Chambers & Hybrid
6:00 PM
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1 Special Meeting March 31, 2026
CALL TO ORDER 6:00PM - 6:05PM
AGENDA CHANGES, ADDITIONS AND DELETIONS 6:05PM - 6:10PM
The Chair or Board majority may modify the agenda order to improve meeting management.
PUBLIC COMMENT 6:10PM - 6:25 PM
Members of the public may speak to any item NOT on the agenda.
APPROVAL OF MINUTES 6:25PM - 6:30PM
1.Approval of the Minutes of the Utilities Advisory Commission Meeting Held on March 4,
2026 Late Packet Report added
UTILITIES DIRECTOR REPORT 6:30PM - 6:35PM
NEW BUSINESS
2.Staff Recommends the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution Approving the Fiscal Year 2027 Gas Utility Financial Forecast, Reserve
Transfer, General Fund Transfer, and Amending Rate Schedules G-1 (Residential Gas
Service), G-2 (Residential Master-Metered and Commercial Gas Service), and G-3 (Large
Commercial Gas Service) ; CEQA Status: Not a project under CEQA Guidelines Section
15378(b)(5) (ACTION: 6:35PM – 7:35PM)
3.Staff Recommends the Utilities Advisory Commission Recommend that the City Council
Adopt a Resolution Approving the FY 2027 Electric Financial Forecast, including
Approving a Reserve Transfers, and Amending Electric Rate Schedules E-1 (Residential
Electric Service), E-1 TOU (Residential Time of Use Electric Service), E-2 (Residential
Master-Metered and Small Non-Residential Electric Service), E-2-G (Residential Master-
Metered and Small Non-Residential Green Power Electric Service), E-4 (Medium Non-
Residential Electric Service), E-4-G (Medium Non-Residential Green Power Electric
Service), E-4 TOU (Medium Non-Residential Time of Use Electric Service), E-7 (Large Non-
Residential Electric Service), E-7-G (Large Non-Residential Green Power Electric Service),
E-7 TOU (Large Non-Residential Time of Use Electric Service), E-14 (Street Lights), E-16
(Unmetered Electric Service), E-EEC-1 (Export Electricity Compensation), and E-NSE-1
(Net Metering Net Surplus Electricity Compensation); CEQA Status: Not a project. under
CEQA Guidelines Section 15378(b)(5) (ACTION: 7:35PM – 8:35PM) Late Packet Report
added
2 Special Meeting March 31, 2026
Preliminary Information on the City of Palo Alto's (City) 2025 Urban Water Management
Plan (2025 UWMP) (DISCUSSION: 8:35PM – 9:00PM) Late Packet Report added
COMMISSIONER COMMENTS AND REPORTS FROM MEETINGS/EVENTS
ADJOURNMENT
OTHER INFORMATION
The materials below are provided for informational purposes, not for action or discussion during this meeting’s agenda. Written
public comments may be submitted in advance and will be provided to the Board and available for public inspection on the
City’s website three days before the meeting.
A.12 Month Rolling Calendar
B.Public Comments
C.Information Report: Utilities Quarterly Report for FY2026-Q2
3 Special Meeting March 31, 2026
4.
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4 Special Meeting March 31, 2026
Utilities Advisory Commission
Staff Report
Report Type: APPROVAL OF MINUTES 6:25PM - 6:30PM
Lead Department: Utilities
Meeting Date: March 31, 2026
Report #:2603-6160
TITLE
Approval of the Minutes of the Utilities Advisory Commission Meeting Held on March 4, 2026
This will be a late packet report published on Thursday, March 26, 2026.
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Utilities Advisory Commission
Staff Report
From: Alan Kurotori, Director of Utilities
Lead Department: Utilities
Meeting Date: March 31, 2026
Report #: 2512-5641
TITLE
Staff Recommends the Utilities Advisory Commission Recommend that the City Council Adopt a
Resolution Approving the Fiscal Year 2027 Gas Utility Financial Forecast, Reserve Transfer,
General Fund Transfer, and Amending Rate Schedules G-1 (Residential Gas Service), G-2
(Residential Master-Metered and Commercial Gas Service), and G-3 (Large Commercial Gas
Service) ; CEQA Status: Not a project under CEQA Guidelines Section 15378(b)(5)
RECOMMENDATION
Staff recommends that the Utilities Advisory Commission (UAC) recommend that the City Council
adopt a resolution (Attachment A):
1. Approving the Fiscal Year 2027 Gas Utility Financial Forecast shown in this staff report and
attachments, which includes amending the Gas Utility Reserve Management Practices;
and
2. Approving the transfer of up to $1.5 million from the Gas Utility Operations Reserve to
the Distribution Rate Stabilization Reserve at the end of FY 2026; and
3. Transferring up to 18% of gas utility gross revenues received during FY 2025 (up to $10.7
million) to the General Fund in FY 2027; and
4. Amending Rate Schedules (Attachment A, Exhibit 1) effective July 1, 2026 (FY2027):
a. G-1 (Residential Gas Service)
b. G-2 (Residential Master-Metered and Commercial Gas Service)
c. G-3 (Large Commercial Gas Service)
EXECUTIVE SUMMARY
This staff report provides the UAC with a financial forecast for the Gas Utility and provides an
overview of the utility’s operations costs, capital costs, and debt and includes recommended rate
adjustments required to maintain the utility’s financial health. The Gas Utility financial forecast
proposes a 9% overall rate increase for FY 2027, which includes a 14.5% increase to distribution
rates, assuming no change in supply costs, effective July 1, 2026. Additionally, this forecast
projects overall rate increases of 7% in FY 2028, and 6% annually from FY 2029 through FY 2031.
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Staff updated cost projections for the FY 2027 to FY 2031 five-year financial planning period using
the most recent load forecast, cost data, and escalation assumptions. Relative to the FY 2026
financial forecast1, the updated forecast projects total gas usage to be about on average 4% lower
in the FY 2027 to FY 2031 period, resulting in decreased retail sales revenue. Total expenses are
expected to be about 8% lower than projected over the same period, driven primarily by lower
supply purchase due to lower sales, and lower general fund transfers from lower revenues.
Table 1: Current Year (FY2026) and Projected Overall Rate Trajectory (FY 2027 to FY 2031)
2, and the Finance
Committee on November 18, 20253, staff presented a rate trajectory of 9% in FY 2027, 7% in FY
2028, and 6% annually from FY 2029 through FY 2031. The current forecast maintains the same
rate changes but reduces the rate increase from 8% to 6% in FY 2031.
BACKGROUND
1 FY 2026 Financial Forecast for the Gas utility (approved June 16, 2025) is described in the Finance
Committee Staff Report 2412-3868:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=64777&dbid=0&repo=PaloAlto
2 Staff Report 2503-4364:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84164&dbid=0&repo=PaloAlto
3 Staff Report 2508-5119:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83887&dbid=0&repo=PaloAlto
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The City is committed to transparency with utilities customers about the reason for rate changes,
including explaining the cost drivers, benefits to customers, what the City is doing to manage
costs for ratepayers, and the services and programs provided by the City to help customers keep
utility bill costs affordable. Staff prepare the financial forecast annually as part of the rate-setting
cycle. Attachment A, Exhibit 3 contains a set of Reserves Management Practices describing the
reserves. Attachment A, Exhibit 4 outlines CPAU’s plan for communicating rate changes to
customers. Next steps include presenting an overview of the financial forecast and rate change
proposal for each utility service to the Finance Committee in April and to the City Council in June
2026.
ANALYSIS
FY 2025 Costs and Revenues
Table 2: FY 2025 Actuals vs. Prior Year’s Forecast ($000)
Net Cost/ (Benefit) Variance Type of Change
Net Cost / (Benefit) of Variances (547)Net Cost Decrease
Projections
Overview
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mainly due to lower projected operations and maintenance costs, including the deferral of the
Crossbore project from FY 2026 to FY 2027. Additionally, CIP costs in FY 2026 are expected to be
about $3.7 million (23%) higher, primarily due to higher projected CIP costs.
Figure 1: Gas Utility Expenses, Revenues, Rate Changes Excluding Supply-Related Changes
*FY25 Commitments and Reappropriations reserves balances for Operations and Capital Investment are
anticipated to be utilized in FY 2026 and FY 2027.
Note: Excludes Cap-and-Invest auction sales revenue and Cap-and-Invest-related expenses, which directly impacts
the Cap-and-Invest reserve.
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Load Forecast
Gas usage in Palo Alto declined from FY 2020 to FY 2022, mainly due to the impacts of the COVID-
19 pandemic. However, FY 2023 saw an increase in gas usage, likely driven by a modest recovery
from COVID-19 effects and colder than average winter temperatures. However, like previous
declines in gas usage due to economic factors, it is unlikely that consumption will return to pre-
pandemic levels. Instead, a long-term decline in gas usage is expected. Further changes, such as
the voluntary replacement of gas appliances with electric appliances and building electrification
are also expected to lower long-term usage. Staff will conduct strategic planning and financial
analysis separately from this financial forecast to develop a financial and infrastructure strategy
for the Gas Utility as the community electrifies. Any insights from that analyses will be integrated
into future financial forecasts.
Staff worked with a consultant to assist in the development of an updated gas load forecast,
which included statistically adjusted end-use (SAE) modeling, weather-normalized modeling,
economic factors, and high electrification assumption. The FY 2025 actual gas supply purchases
totaled 25,436,120 therms, representing a decrease of about 8% compared to projections in the
FY 2026 financial forecast. The lower-than-anticipated gas supply purchases in FY 2025 were
primarily due to lower residential consumption, particularly during the winter season, along with
improvements in energy efficiency and electrification-driven fuel-switching away from gas. The
result, shown in Figure 2, projects gas supply load for FY 2027 at 25,239,664 therms, about 3%
lower than prior year’s forecast. This downward projection was driven by weather-normalized
lower consumption in FY 2025. Over time, declining gas consumption is expected to increase
pressure on rates, as rising and fixed costs for gas operations and distribution will need to be
allocated across fewer units sold.
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2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040
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Actual Load FY26 Load Forecast FY27 Load Forecast
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Revenues
This financial forecast bases sales revenue projections on the load forecast. Except where stated
otherwise, these load forecasts are based on normal weather. Variations in weather have a
substantial impact on revenues. Changes in customer behavior, gas appliance efficiency
improvements, and electrification also impact gas usage. Staff regularly monitor emerging trends
and make updates to forecasts as needed.
The Gas Utility’s costs fall into two main categories: gas supply costs and distribution-related
costs. Gas supply costs are the cost of the gas itself, transmission of the gas to Palo Alto, and
environmental expenses. These supply-related costs vary with the market or are set by other
entities and are passed through to customers. Distribution-related costs cover the operation and
capital improvement of the distribution system, and overall business operations, and are
collected through a distribution rate adjusted annually. Table 3 shows total Gas Utility costs. The
operations and capital costs are considered distribution costs.
Commodity 8,918 10,270 11,383 10,717 10,373 10,263 9,631
Transportation 6,610 6,800 6,915 7,019 7,174 7,347 7,635
Carbon Offset 961 1,147 1,198 1,244 1,291 1,340 1,411
Cap-and-Invest 2,669 3,867 4,032 4,613 5,241 5,920 6,361
Operations 33,375 35,361 36,635 36,834 38,786 40,316 42,178
Capital 8,176 19,499 22,829 11,914 17,776 11,411 15,266
Supply Costs
Overall, supply expenses are projected to increase by an average of about 2% annually from FY
2027 through FY 2031. Gas commodity costs, which are the most variable component, account
for the largest share of overall costs. Although market forecasts currently indicate that gas prices
will remain relatively steady over the next several years, those forecasts are highly uncertain. The
financial forecast assumes that gas prices decrease by an average of about 4% annually during
the forecast period.
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Transportation and environmental compliance costs are expected to rise gradually over the
forecast period. PG&E's local transportation rates, which have experienced steady increases in
recent years, are expected to rise by an average of 3% per year throughout the forecast period7.
8
9)
and Council’s goal of reducing GHGs 80% by 2030, Palo Alto began allocating Cap-and-Invest
reserves to support programs such as the Full-Service Heat Pump Water Heater Program. In
Calendar Year 2024, Palo Alto received about $3.35 million in revenue from freely allocated
allowances from the State. About $0.72 million was spent on the heat pump water heater direct
installation and incentive program, while the remaining $2.63 million was transferred to the Gas
Cap-and-Invest reserve at the end of FY 2025 to fund future gas GHG emissions reduction
programs. The Gas Cap-and-Invest reserve has about $15.05 million at the end of FY 2025. The
types of S/CAP related expenditures for Gas Cap-and-Invest revenues are for residential and non-
residential building electrification pilot programs.
10, which involves purchasing carbon offsets
equivalent to the emissions generated by the community's natural gas use. These high-quality
offsets fund projects that reduce GHG emissions, such as forest conservation or methane capture
from dairy farms. While purchasing carbon offsets is an important initial step in reducing carbon
emissions, the long-term goal is to decrease the community's natural gas usage by maximizing
efficiency and transitioning to high-efficiency electric appliances where feasible. Carbon offset
purchases totaled about $1.1 million in FY 2025, and carbon offset costs are projected to rise by
4% annually through the forecast period.
7 The transportation rates for calendar years 2023-2026 reflect the rates in the adopted PG&E 2023 Gas
Transmission & Storage (GT&S) Cost Allocation and Rate Design (CARD) (D.24-03-002), afterward a 3% escalation
rate is applied.
8 Based on allowance broker quotes.
9 Council Resolution 10077:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=61567&dbid=0&repo=PaloAlto
10 Staff Report 7441: https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=80132&dbid=0&repo=PaloAlto
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prices. Funds collected from the gas price mitigation adder accrue in the Gas Distribution Rate
Stabilization Reserve and can be used to offset the impact of a potential gas market price spike
above the maximum gas commodity charge to customers. Through this program, about $1 million
has been funded and allocated in the Gas Distribution Rate Stabilization Reserve at the end of FY
2025. The program is designed to fund the reserve over a three-year period through the adder,
which is expected to result in approximately $4.5 million over three years to hedge against future
short-term gas price spikes.
Figure 3: Gas Distribution Utility Operations Costs
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2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
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Resource Management
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Capital Improvement Program
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Table 4 shows the CIP cost categories and projected spending.
Table 4: Projected CIP Spending ($000)
*Includes unspent funds from previous years carried forward or reappropriated
**A portion of project salaries and benefits has been allocated to the Gas Main Replacement budget in the table
above for FY 2027-31, with a larger share assigned in FY 2027 to meet grant reimbursement requirements
Table 5: Debt Service Coverage Ratio ($000)
FY 2026
Debt Service 802
Reserves
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Figure 4: Operations Reserve Projection
Table 6 summarizes the risk assessment calculation for the Gas Utility through FY 2031. The risk
assessment is intended to be covered by the Operations Reserve and includes the revenue
shortfall that could occur due to:
1. Maximum non-commodity revenue percentage variance from the previous ten years; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
CIP Contingency for FY 2030 and after is not needed due to resuming the use of the CIP
reserve.
Total Distribution Revenue 39,847 45,114 49,670 53,641 57,877 62,454
Risk of Revenue Loss @14% 5,591 6,330 6,970 7,527 8,121 8,763
CIP Budget 19,499 22,829 11,914 17,776 - -
CIP Contingency @10%* 1,950 2,283 1,191 1,778 - -
*CIP budget is excluded from FY 2030 onward
Staff estimates that the gas price mitigation adder in the gas commodity charge will collect about
$1.36 million in FY 2026 for the gas hedging program15. Although these funds are initially
collected in the Operations Reserve, they should be transferred to the Gas Distribution Rate
Stabilization Reserve to be available to mitigate the impact of potential gas market price spikes
15 Staff Report 2401-2510:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=82970&dbid=0&repo=PaloAlto; the utility collected
about $1.05 million for this program in FY 2025, which was transferred from the Operations Reserve to the Gas
Distribution Rate Stabilization reserve at the end of FY 2025.
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exceeding the maximum gas commodity charge to customers. Staff proposes transferring up to
$1.5 million
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from the Gas Utility Operations Reserve to the Gas Distribution Rate Stabilization Reserve at the
end of FY 2026. The projected transfer is listed in row 12 in Table 7 below and the amount is
included in part of the Operations transfer out in row 11. The exact transfer amount will be
determined at year end based on calculations aligned with the gas hedging program.
Reserve Balances
Figure 5: Gas CIP Reserve Levels
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Figure 6: Gas Utility Year-End Reserves Levels
Note: Excludes Cap-and-Invest Reserve
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Table 7: Operations, CIP, Cap-and-Invest, and Debt Service Reserve Starting and Ending
Balances, Revenues, Transfers To/(From) Reserves, Capital Program Contribution To/(From)
Reserves, Total Reserve Changes, and Reserve Guideline Levels ($000)
*Operations Reserve represents the Gas Supply Fund Rate Stabilization Reserve and the Gas Distribution Fund
Operations Reserve combined.
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Proposed Rates
Table 11 shows the current and proposed monthly service charges, and Table 12 shows the
current and proposed distribution volumetric charges for all rate schedules. As previously
noted, supply-related charges are pass-through charges that are updated periodically. The
latest charges are shown in the City’s Rates website17. The proposed rates reflect the proposed
rate increases compared to the current rates, which are based on the Natural Gas Cost of
Service and Rate Study and were adopted by City Council at the December 1, 2025 meeting18.
(as of 2/1/2026)(effective 7/1/2026)($)(%)
G-1 (Residential)$ 19.58 $ 22.41 $ 2.83 14.5%
G-2 (Small Commercial)
G-2 (≤ 220 scfh)$ 29.24 $ 33.47 $ 4.23 14.5%
G-2 (> 220 and < 4,000 scfh) 94.56 108.27 13.71 14.5%
G-2 (≥ 4,000 scfh) 419.08 479.84 60.76 14.5%
G-3 (Large Commercial)$ 1,712.36 $ 1,960.65 $ 248.29 14.5%
(as of 2/1/2026)(effective 7/1/2026)($)(%)
(Residential)
Tier 1 Rates $ 1.0456 $ 1.1972 $ 0.1516 14.5%
Tier 2 Rates 2.5203 2.8857 0.3654 14.5%
(Residential Master-Metered and Small Commercial)
Uniform Rate $ 1.2204 $ 1.3973 $ 0.1769 14.5%
(Large Commercial)
Uniform Rate $ 1.1874 $ 1.3595 $ 0.1721 14.5%
Table 13 shows the impact of the proposed July 1, 2026 rate changes on the median monthly
residential bill for representative average winter and summer bills, excluding supply-related
cost changes. The annual gas bill for the median residential customer is projected to be 9%
17 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
18 Staff Report 2506-4908:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84117&dbid=0&repo=PaloAlto
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higher in FY 2027 than FY 2026. The actual impact may be different because customer gas
usage varies and commodity price changes monthly.
Table 13: Bill Impact of Proposed G-1 Gas Rate Changes ($/Month)
ChangeUsage Bill Amount
1)
Bill Amount
2)
Summer (Apr-Oct)
Winter (Nov-Mar)
Annual Median
1. Calculated based on FY25 actual supply rates with current distribution rates; assumes current
distribution rates were effective for the full year. If the current rate calculation instead applies
Council-approved rates for July 2025 – January 2026, followed by cost-based adjustments
from February 2026 – June 2026, the residential bill is projected to increase by about 14%
from FY26 to FY27.
2. Calculated based on FY25 actual supply rates with proposed distribution rates; assumes no
change to supply-related rates.
Table 14: Bill Impact of Proposed G-2 and G-3 Gas Rate Changes ($/Month)
ChangeUsageBill Amount
1)
Bill Amount
(Proposed Rates2)
G-2 (Residential Master-Metered and Small Commercial)
G-3 (Large Commercial)
1. Calculated based on FY25 actual supply rates with current distribution rates
2. Calculated assuming no change to supply-related rates
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Bill Comparisons/Competitiveness
Table 15 presents the median residential bills for Palo Alto and Pacific Gas and Electric
Company (PG&E) customers. The bill calculations for PG&E customers are based on PG&E
Climate Zone X, an area which includes Palo Alto’s surrounding communities. The calculated
monthly gas bill for the median Palo Alto residential customer is about 11% lower than that of a
PG&E customer with equivalent consumption. This difference is primarily attributable to the
City’s fixed monthly service charge; PG&E does not apply a similar charge.
(Therms)
Summer 17 $ 51 $ 39 30%
Winter 51 117 157 (26%)
Annual Average 31 78 88 (11%)
Note: Calculated based on FY25 actual supply rates with current distribution rates
Table 16 presents the median monthly commercial bills for Palo Alto and PG&E customers. Palo
Alto bills have been higher than PG&E’s bills over the years, mainly due to higher service
charges.
(Therms)
Commercial 280*$ 668 $ 583 15%
Large Commercial 20,834**43,576 29,637 47%
Note: Calculated based on FY25 actual supply rates with current distribution rates
*Based on median usage for Palo Alto G-2 rate class with meter capacity of >220 and <4,000 Scfh
**Based on annual usage of about 250,000 therms
Because the Cap and Trade program has been renamed the Cap-and-Invest program, this staff
report requests the renaming of the Cap and Trade Reserve to the Cap-and-Invest Reserve. In
accordance with Section 11 of the Gas Reserve Management Practices and Council-approved
Cap-and-Invest revenue uses (Council Resolution 1007721), staff is authorized to transfer
revenues from allocated allowance auction proceeds to the Cap-and-Invest Reserve at the end
of each fiscal year. Additionally, staff may utilize funds from the Cap-and-Invest Reserve to
21 Council Resolution 10077:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=61567&dbid=0&repo=PaloAlto
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support greenhouse gas (GHG) reduction programs by transferring funds from the Cap-and-
Invest Reserve to the Operations Reserve.
General Fund Transfer
Next Steps
FISCAL/RESOURCE IMPACT
POLICY IMPLICATIONS
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STAKEHOLDER ENGAGEMENT
On November 5, 202523, staff presented the preliminary rate proposals at the UAC meeting. Some
Commissioners raised affordability concerns and expressed interest in exploring innovative
operating cost reductions rather than relying on the traditional approach of deferring capital
investments.
On November 18, 202524, staff presented the same preliminary rate proposals to the Finance
Committee. Committee members focused on benchmarking rates against comparable utilities.
They also inquired about cost-containment strategies. Additional discussion centered on reserve
guidelines and the associated risk assessment. Members emphasized that the absence of rate
increases during the pandemic created a catch-up scenario that should be avoided in the future.
Additional feedback from the UAC and Finance Committee meetings in 2026 will be incorporated
in the financial forecast and included in the proposal presented to City Council in June 2026
concurrent with the budget adoption process.
Attachment A, Exhibit 4 contains examples of CPAU’s communication and outreach methods
including the use of the Utilities website, utility bill inserts, messaging on utility bills, and MyCPAU
online account management platform, email newsletters, print and digital ads in local
publications, social media, and community messaging platforms.
The UAC’s review and recommendation to the Finance Committee on the FY 2027 Gas Utility
financial forecast and rate adjustments does not meet the California Environmental Quality Act’s
definition of a project, pursuant to Public Resources Code Section 21065, thus no environmental
review is required.
Attachment A: FY27 Gas Resolution
Attachment A, Exhibit 1: FY27 Gas Rate Schedules
Attachment A, Exhibit 2: FY27 Gas Utility Financial Details
Attachment A, Exhibit 3: FY27 Gas Reserve Management Practices
Attachment A, Exhibit 4: FY27 Gas Communications Plan
:
Alan Kurotori, Director of Utilities
Staff: Eric Wong, Resource Planner
23 Staff Report 2503-4364:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84164&dbid=0&repo=PaloAlto
24 Staff Report 2508-5119:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83887&dbid=0&repo=PaloAlto
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Attachment A *NOT YET APPROVED*
6059739 1
Resolution No.
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2027 Gas Utility Financial Forecast and Reserve Transfers,
General Fund Transfer, and Amending Rate Schedules G-1
(Residential Gas Service), G-2 (Residential Master-Metered and
Commercial Gas Service), and G-3 (Large Commercial Gas Service)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations, including reserves.
This includes making long-term projections of market conditions, the physical condition of the
system, and other factors that could affect utility costs, and setting rates adequate to recover
these costs. It does this with the goal of providing safe, reliable, and sustainable utility services
at competitive rates. The City adopts Financial Forecasts or Plans to summarize these
projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Forecasts or Plans.
C. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
D. On June 15, 2026, 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 Amended Reserves Management Practices
(Exhibit 3 1) and FY 2027 Gas Utility Financial Forecast presented to the Finance Committee on
March 17, 2026 2 and updated by the June 15, 2026 Council report, (Exhibit 2 3), which is attached
to this resolution and made a part of the staff report presented to the City Council.
SECTION 2. The Council hereby approves the transfer of up to $1.5 million
from the Gas Utility Operations Reserve to the Distribution Rate Stabilization Reserve at
the end of FY 2026.
SECTION 3. The Council hereby approves the transfer of up to 18% of gas utility
gross revenues received during FY 2025 to the general fund in FY 2027.
1 Exhibit 3 <<link>>
2 Meeting Agenda Item #: XX <<link>>
3 Exhibit 2 <<link>>
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Attachment A *NOT YET APPROVED*
6059739 2
SECTION 4. 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 shown in Exhibit 14.
Utility Rate Schedule G-1, as amended, shall become effective July 1, 2026.
SECTION 5. 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 shown in Exhibit 1. Utility Rate Schedule G-2, as amended, shall become
effective July 1, 2026.
SECTION 6. 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 shown in
Exhibit 1. Utility Rate Schedule G-3, as amended, shall become effective July 1, 2026.
SECTION 7. The City Council finds that revenues derived from the gas rates approved
by this resolution do not exceed the funds required to provide gas service and shall not be used
for any purpose other than providing gas service, and the purposes set forth in Article VII,
Section 2, of the Charter of the City of Palo Alto.
SECTION 8. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
//
//
//
//
//
//
4 Exhibit 1 <<link>>
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Attachment A *NOT YET APPROVED*
6059739 3
SECTION 9. The Council finds that approving the FY 2027 Gas Utility Financial
Forecast does not meet the California Environmental Quality Act’s (CEQA) definition of a
project under Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(5),
because it is an administrative governmental activity which will not cause a direct or indirect
physical change in the environment, and therefore, no environmental assessment is required.
The Council finds that changing gas rates to meet operating expenses, purchase supplies and
materials, meet financial reserve needs and obtain funds for capital improvements necessary to
maintain service is not subject to the California Environmental Quality Act (CEQA), pursuant to
California Public Resources Code Sec. 21080(b)(8) and Title 14 of the California Code of
Regulations Sec. 15273(a). After reviewing the staff report and all attachments presented to
Council, the Council incorporates these documents herein and finds that sufficient evidence has
been presented setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
Assistant City Attorney City Manager
Director of Utilities
Director of Administrative Services
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RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-1 Effective 027-01-2026
dated 072-01-20265 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: .............................................................................................$ 22.42 19.58
Tier 1 Rates: Per Therm
Supply Charges:
1.Commodity (Monthly Market-Based) ......................................... $0.10-$4.00
2.Cap and Trade Compliance Charge ............................................ Pass-through
3. Transportation Charge ................................................................. Pass-through
4.Carbon Offset Charge .................................................................. $0.00-$0.10
Distribution Charge:.......................................................................................$ 1.1971
1.0456
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 ............................................. Pass-through
3. Transportation Charge ................................................................. Pass-through
4.Carbon Offset Charge .................................................................. $0.00-$0.10
Distribution Charge:.............................................................................................$ 2.8857
2.5203
Attachment A, Exhibit 1 Item #2
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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 027-01-2026
dated 072-01-20265 Sheet No G-1-2
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
purchase discount1 and $0.055 per Therm for mitigating the impact of short-term natural
gas market price spikes2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s
compliance obligations. The Cap and Trade Compliance Charge 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 Therm cap.
The Transportation Charge is a pass-through charge based on the current PG&E G-WSL3
(Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
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
Attachment A, Exhibit 1 Item #2
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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 027-01-2026
dated 072-01-20265 Sheet No G-1-3
The Commodity and Carbon Offset Charges will fall within the minimum/maximum
ranges set forth in Section C. Current and historic per Therm rates for the Commodity,
Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the
City Utilities website.4
2. Seasonal Rate Changes:
The Summer period is effective April 1 to October 31 and the Winter period is effective
from November 1 to March 31. When the Billing Period includes use in both the Summer
and the Winter periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates for each period. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Calculation of Usage Tiers
Tier 1 Natural Gas usage is calculated and billed based upon a level of 23 Therms per 30
day Billing Period during the Summer period, and 60 Therms per 30 day Billing Period
during the Winter period, based on Meter reading days of Service, and rounded to the
nearest whole Therm. As an example, Tier 1 Natural Gas is calculated at 0.767 Therms per
day during the Summer period (.767 Therms per day x 30 days = 23 Therms) and 2.0
Therms per day during the Winter period (2 Therms per day x 30 days = 60 Therms). For
further discussion of bill calculation and proration, refer to Rule and Regulation 11.
{End}
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
Attachment A, Exhibit 1 Item #2
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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 072-01-2026
dated 027-01-20265 Sheet No G-2-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use less than 250,000 Therms per year at one site;
2. Master-Metered residential Customers in multi-family residential facilities.
B. TERRITORY:
This schedule applies 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) .............................................$ 33.47 29.24
2. Above 220 scfh and less than 4,000 scfh ....................................................$ 108.27 94.56
3. 4,000 scfh and above ..................................................................................$ 479.84 419.08
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) ......................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges ........................................................... Pass-through
3. Transportation Charge .................................................................................. Pass-through
4. Carbon Offset Charge ................................................................................... $0.00-$0.10
Distribution Charge: ..................................................................................................$ 1.3973
1.2204
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 meter’s maximum capacity used to determine the applicable Monthly Service Charge
for G-2 Gas Service is the installed Meter’s City of Palo Alto-approved maximum
capacity in standard cubic feet per hour (scfh), measured at 7 inches of water column or
equivalent to 0.25 pounds per square inch.
Attachment A, Exhibit 1 Item #2
Packet Pg. 33
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 072-01-2026
dated 027-01-20265 Sheet No G-2-2
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
purchase discount1 and $0.055 per Therm for mitigating the impact of short-term natural
gas market price spikes2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge 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 Therm cap.
The Transportation Charge is a pass-through charge based on the current PG&E G-WSL3
(Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity and Carbon Offset Charges will fall within the minimum/maximum
ranges set forth in Section C. Current and historic per Therm rates for the Commodity,
Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the
City Utilities website.4
{End}
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
Attachment A, Exhibit 1 Item #2
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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 072-01-2026
dated 027-01-20265 Sheet No G-3-1
A. APPLICABILITY:
This schedule applies to Customers receiving Gas Service from the City of Palo Alto Utilities, who
use at least 250,000 Therms per year at one site.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: $ 1,960.65 1,712.36
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges .................................................... Pass-through
3. Transportation Charge .......................................................................... Pass-through
4. Carbon Offset Charge ........................................................................... $0.00-$0.10
Distribution Charge: ................................................................................................$ 1.3595 1.1874
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
purchase discount1 and $0.055 per Therm for mitigating the impact of short-term natural
gas market price spikes2.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
Attachment A, Exhibit 1 Item #2
Packet Pg. 35
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 072-01-2026
dated 027-01-20265 Sheet No G-3-2
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge 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 Therm cap.
The Transportation Charge is a pass-through charge based on the current PG&E G-WSL3
(Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity and Carbon Offset Charges will fall within the minimum/maximum
ranges set forth in Section C. Current and historic per Therm rates for the Commodity,
Cap and Trade Compliance, Carbon Offset and Transportation Charges are posted on the
City Utilities website.4
2. Request for Service
A qualifying Customer may request Service under this schedule for more than one Account
or Meter if the Accounts are located on one site. A site consists of one or more contiguous
parcels of land with no intervening public right-of- ways (e.g. streets).
3. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable City of Palo
Alto full-service rate schedule.
{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/business/business-rates/monthly-gas-volumetric-and-service-charges-
commercial.pdf
Attachment A, Exhibit 1 Item #2
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Attachment A, Exhibit 2
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Attachment A, Exhibit 2
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Gas Utility Capital Improvement Program (CIP) Financial Details
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Attachment A, Exhibit 3
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GAS UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Gas Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015
to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets
as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Gas Utility’s Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
Section 3. Distribution Fund Reserves
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Gas Utility’s Capital
Improvement Program (CIP), as described in Section 6 (CIP Reserve)
d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 8 (Operations Reserve)
f) For tracking unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the gas utility under the State’s Cap-
and- Trade Invest Program, as described in Section 11 (Cap- and- Trade Invest Program
Reserve)
g) Any funds not included in the other reserves will be considered Unassigned Reserves and
shall be returned to ratepayers or assigned a specific purpose as described in Section 9
(Unassigned Reserves)
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Attachment A, Exhibit 3
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7
5
7
Section 4. Reserve for Commitments
1. These guideline levels are
calculated for each fiscal year of the Financial Planning Period and approved by Council
resolution.
1 The guideline levels were corrected to match the Council-approved language updated from the
FY 2021 Financial Plan.
2 Each month is calculated based upon 1/12 of the annual budget.
3 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual
average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use to
derive the annual average would be FY 2022 through FY 2025 etc.
Minimum Level 20% of the maximum CIP Reserve guideline level l
Maximum Level Average annual (12 month)2 CIP budget, for 48 months of
budgeted CIP expenses3
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Attachment A, Exhibit 3
6
7
5
7
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds may
be added to this reserve. If there are funds in this reserve in excess of the maximum level
staff must propose to transfer these funds to another reserve or return them to
ratepayers in the next Financial Plan. Staff may also seek Council approval to hold funds
in this reserve in excess of the maximum level, if they are held for a specific future purpose
related to the CIP.
Section 3. Rate Stabilization Reserve
The Rate Stabilization Reserve is used to manage the trajectory of future Funds may be added
to the Rate Stabilization Reserve by action of the City Council and held to manage the
trajectory of future year rate increases. Withdrawal of funds from the Rate Stabilization
Reserve requires Council action. If there are funds in the Rate Stabilization Reserve at the end
of any fiscal year, any subsequent Gas Utility Financial Plan must result in the withdrawal of
all funds from this Reserve by the end of the Financial Planning Period.
Section 4. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves
described in Section 4-Section 7 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for that
year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months of
the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
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Attachment A, Exhibit 3
6
7
5
7
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Gas Utility’s Fund Balance
shall be automatically included in the Unassigned Reserve described in Section 9, below.
Section 5. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas Utility’s
Fund Balance will be held in the Unassigned Reserve. If there are any funds in the Unassigned
Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council
must include a plan to assign them to a specific purpose or return them to the Gas Utility
ratepayers by the end of the first fiscal year of the next Financial Planning Period. For
example, if there were funds in the Unassigned Reserves at the end of FY 2015, and the next
Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a plan
to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff may
present an alternative plan that retains these funds or returns them over a longer period of
time.
Section 6. Intra-Utility Transfers Between Supply and Distribution Funds
The Gas Utility records costs in two separate funds: the Gas Supply Fund and the Gas
Distribution Fund. At the end of each fiscal year staff is authorized to transfer funds between
the Gas Supply Fund and Gas Distribution Fund if consistent with the purposes of the two
reserves involved in the transfer and in order to balance gas utility reserves to avoid negative
balances. For example, Gas Distribution revenues are needed to pay for certain supply-
related costs such as administration of the Gas Supply Fund. Such transfers shall be included
in the ordinance closing the budget for the fiscal year.
Section 7. Cap- and- Trade Invest Program Reserve
This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the gas utility, under the State’s Cap- and-
Trade Invest Program. Funds in this Reserve are managed in accordance with the City’s Policy
on the Use of Freely Allocated Allowances under the State’s Cap- and- Trade Invest Program
(the Policy), adopted by Council Resolution 9487 in January 2015, and amended by Council
Resolution 10077 in October 2022. At the end of each fiscal year, the Cap- and- Trade Invest
Program Reserve will be adjusted by the net of revenues and expenses associated with the
Cap- and- Trade Invest program.
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Attachment A, Exhibit 4
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COMMUNICATIONS PLAN AND OUTREACH EXAMPLES – GAS UTILITY
The proposed gas utility rate adjustments are part of the City of Palo Alto Utilities (CPAU) ongoing
effort to maintain the financial health and reliability of the Gas Utility while managing the impacts of
declining gas consumption and increasing operating and capital expenses.
Reasons for the Proposed Rate Increase
During the pandemic, the city kept overall Gas Utility rate increases to 2% to 3% annually and utilized
reserve funding to cover costs. In the winter of 2022-23, surging gas prices depleted the Gas Utility
reserves, which were used to cover the difference between actual gas costs and the revenue generated
by charging customers the Council-approved maximum gas commodity charge. Reserves need to be
replenished over time to ensure funds are available for safety and reliability needs, while managing
ongoing cost inflation.
The Gas Utility financial results have been affected by lower-than-expected sales revenues driven by
reduced gas usage and lower commodity prices. Although supply purchases have also been below
expectations, these savings were insufficient to offset revenue shortfalls. Additionally, capital
improvement program (CIP) expenses exceeded projections, largely due to emergency repair work and
rising labor costs.
Looking ahead, staff project a continued decline in gas consumption due to electrification trends and
long-term efficiency improvements, which will place upward pressure on rates as fixed operational and
capital costs are spread across fewer therms sold. To maintain reliable operations, meet reserve
targets, and fund essential infrastructure projects, staff are recommending a 9% overall rate increase in
FY 2027. This includes a 14.5% increase in distribution rates and assumes stable supply-related charges.
Communication Plan and Messaging Strategy
Staff will implement a comprehensive communication plan to ensure that gas customers and
community stakeholders understand the reasons for the proposed rate adjustment and CPAU’s efforts
to minimize bill impacts. Key communication objectives are to:
Increase transparency by clearly explaining how lower gas sales, infrastructure reinvestment,
and reserve requirements contribute to the need for the rate adjustment.
Emphasize stability and fairness by highlighting the stepwise approach to rate adjustments and
the alignment of rates with actual cost-of-service principles, consistent with City Council
direction and Proposition 26.
Demonstrate fiscal stewardship by sharing that staff have pursued federal and state funding
support (including Department of Transportation, FEMA, and CalOES grants) to offset
emergency costs and provide additional main replacement.
Promote understanding of long-term trends by contextualizing the rate increase within the
broader transition to community electrification and declining gas demand.
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Attachment A, Exhibit 4
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Communication methods throughout the year, and specifically for rate changes, include direct
customer outreach through utility bill inserts, targeted community newsletters and/or blogs, website
updates at www.paloalto.gov/RatesOverview, social media, print and digital advertising, and
participation in community outreach events. Public communication materials about rate changes will
feature FAQs, charts or other visuals including infographics showing the breakdown of utility costs that
correlate with the need for rate increases, and explanations of how customer classes are affected.
Messaging will emphasize rate adjustments are necessary to sustain safe, reliable, and financially
sound gas operations consistent with voter-approved guidelines and the city’s long-term energy
strategy. In addition, CPAU continues to explore cost-containment measures for each utility fund.
Stakeholder Engagement
Public meetings before the UAC, Finance Committee, and City Council to present rate proposals
and solicit community feedback.
Communication with community partners—including key accounts, business, residential
customer groups and associations, and low-income assistance advocates—to ensure rate
impacts and mitigation options are well understood.
Customer service training for Utilities staff to ensure consistent messaging in addressing
customer inquiries.
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Attachment A, Exhibit 4
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Item #2
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Utilities Advisory Commission
Staff Report
Report Type: NEW BUSINESS
Lead Department: Utilities
Meeting Date: March 31, 2026
Report #:2603-6163
TITLE
Staff Recommends the Utilities Advisory Commission Recommend that the City Council Adopt a
Resolution Approving the FY 2027 Electric Financial Forecast, including Approving a Reserve
Transfers, and Amending Electric Rate Schedules E-1 (Residential Electric Service), E-1 TOU
(Residential Time of Use Electric Service), E-2 (Residential Master-Metered and Small Non-
Residential Electric Service), E-2-G (Residential Master-Metered and Small Non-Residential
Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G (Medium
Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-Residential Time of Use
Electric Service), E-7 (Large Non-Residential Electric Service), E-7-G (Large Non-Residential
Green Power Electric Service), E-7 TOU (Large Non-Residential Time of Use Electric Service), E-
14 (Street Lights), E-16 (Unmetered Electric Service), E-EEC-1 (Export Electricity Compensation),
and E-NSE-1 (Net Metering Net Surplus Electricity Compensation); CEQA Status: Not a project.
under CEQA Guidelines Section 15378(b)(5)
This will be a late packet report published on Thursday, March 26, 2026.
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Utilities Advisory Commission
Staff Report
Report Type: NEW BUSINESS
Lead Department: Utilities
Meeting Date: March 31, 2026
Report #:2603-6164
TITLE
Preliminary Information on the City of Palo Alto's (City) 2025 Urban Water Management Plan
(2025 UWMP)
This will be a late packet report published on Thursday, March 26, 2026.
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Date: March 31, 2026
12-MONTH ROLLING CALENDAR
FORECAST
Utilities Advisory Commission City Council
CCM – City Council Meeting
(April 1, 2026
canceled)
March 31, 2026 (Special Meeting)
• FY 2026 – Q2 Informational Report
• Gas Rates and Financial Forecast
• Electric Rates and Financial Forecast
• Preliminary Information on Palo Alto’s 2025
Urban Water Management Plan
April CCM, PS & FCM Items
• Gas Rates and Financial Forecast (FCM)
• Electric Rates and Financial Forecast (FCM)
• Duke’s Root Control for Root Foaming Treatment
Services
• Larratt Brothers Plumbing for Emergency Water
Heater Replacement Contract Amendment
• Utilities Reserves Advisory Report (PS)
May 2026 May 6, 2026
• FY 2027 Utilities Operating and CIP Budget
• Urban Water Management Plan
• Water Supply and Demand Assessment
• Election of UAC Chair and Vice Chair
• FY 2027 Utilities Operating and CIP Budget (FCM)
• Updates to Utilities Rules and Regulations
• Commercial Customer Characterization Tool
• Commercial Electrification Technical Assistance
•
June 3, 2026
• FY 2026 - Q3 Report, Informational
• Status Update on the Gas Transition Study
• GoGreen Business Energy Financing Program
• UAC Work Plan
• FY 2027 Utility Rates and 5-year Forecasts
• FY 2027 Utilities Operating and CIP Budget
• Commercial Efficiency and Electrification Program
• North American Energy Standards Board (NAESB)
Agreement with JPMorgan Chase Bank, N.A
• Urban Water Management Plan
• Permanent Water Use Ordinance
•
July 1, 2026
• FTTP Pilot Report Out
• Grid Mod Project Update
August 2026 August 5, 2026 • FTTP Pilot Report Out (FCM & CCM)
• GoGreen Business Energy Financing Program
• Grid Mod Bond Financing (FCM)
• Sewer Lateral Replacement Project
• CLEAResult for Residential Energy Efficiency and
September 2, 2026 • Substations’ Electric Equipment and Structures
Painting
• Grid Mod Bond Financing
October 2026 October 7, 2026
• FY 2026 – Q4 Report, Discussion
November 2026 November 4, 2026
• FY 2028 Preliminary Rates
December 2026 December 2, 2026 • FY 2028 Preliminary Rates (FCM)
January 2027 January 6, 2027
February 2027 February 3, 2027
March 2027 March 3, 2027
Council Recap on Utilities Items – March 2026
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Approved By Council & Finance Committee:
• Wastewater Rates and Financial Forecast (FCM)
• Water Rates and Financial Forecast (FCM)
• Flynn Resources Contract Amendment
• Edison Electric Institute Master Power Purchase and Sales Agreement
• Smart Energy Water/MyCPAU Customer Portal Contract Amendment
Recurring Items Items to Be Scheduled
• Educational Update on any Type of New Technology or Terminology
• Projects with a Resiliency Component
• Quarterly Reports (Q1-3 Info Rpts)(Q4 Discussion Summary of the year)
o Financial Report
o Utilities Programs Update
Informational EV Charger Installation Updates
Informational Bucket 1 REC Sales Updates
Informational Fiber Updates
• Rates and Financial Forecast
• Utilities Budget
• Utilities Quarterly Informational Report – Council
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DOCUMENTS IN THIS PACKET INCLUDE:
LETTERS FROM CITIZENS TO THE
UTILITIES ADVISORY COMMISSION
No public letters received from
March 4, 2026 - March 19, 2026
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Utilities Advisory Commission
Staff Report
From: Alan Kurotori, Director Utilities
Lead Department: Utilities
Meeting Date: March 31, 2026
Report #: 2512-5644
TITLE
Information Report: Utilities Quarterly Report for FY2026-Q2
RECOMMENDATION
This is an informational report, and no action is requested.
EXECUTIVE SUMMARY
This report has been prepared to keep the Utilities Advisory Commission (UAC) apprised of the major issues that are
facing the water, gas, electric, wastewater collection and fiber utilities, including legislative/regulatory issues, utility-
related capital improvement programs, operations, reliability impact measures and a utility financial summary. Items of
special interest in this report are summarized below:
Vacancies and Staffing – Appendix B
The Utilities Department has 46 vacant positions out of 269 authorized positions or a 17% vacancy rate at the
end of December 2025 compared to 44 vacancies or 16% in September 2025.
Electric Operations continues to have the highest number of vacancies at 19 full-time employees (FTEs) or a 23%
vacancy rate, however, there are 3 new hires since the previous quarter. Some of the hard to fill positions are
lineperson cable splicer (4 FTEs), overhead underground troubleperson (2 FTEs), and utility compliance
technician (2 FTEs).
Electric Utility:
Electric net supply cost for FY 2026 is currently projected to be $88.7M, which represents a 3.3% decrease from
the adopted budget level of $91.7M. FY 2026 through Q2 has seen higher-than-anticipated load, which led to an
increase in market purchases relative to budget projections. (Section 1.1.1)
Utilities staff is working with the Northern California Power Agency to identify new renewable energy and
storage projects. (Section 1.1.3)
An update regarding the electric grid modernization work is provided, (Section 1.2) and an update on electric
power outages and reliability is provided (Section 1.3)
Electric sales volumes in Q2 were 7.8% higher than forecasted, driven by new data center load. (Section 1.4.1)
Gas Utility:
Gas prices have been relatively low and stable. (Section 2.1)
One gas main replacement project is in progress, and one is in the design stage; repairs from the winter of 2023
storms are anticipated to begin mid-2026. (Section 2.2)
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An update on gas service interruptions and work to proactively meet new compliance goals before they go into
effect is provided (Section 2.3)
Gas sales are highly weather-dependent and were down slightly in the first half of FY 2026. (Section 2.4.1)
Water Utility:
As of February 1, precipitation at the Hetch Hetchy weather station was about 110% of median for Water Year
2026. (Section 3.1)
Water sales through Q2 of FY 2026 were about 6.1% lower than forecasted, which is attributed to relatively mild
summer months. (Section 3.4.1)
Wastewater Utility:
Actual wastewater sales revenues through Q2 are tracking 3.1% above the budget. (Section 4.3.1)
Fiber Utility:
For Fiber-to-the-Premises (FTTP), the City received delivery of the fiber hut which holds the electronic equipment
to provide fiber internet service. The fiber hut is scheduled to be provisioned with power and fiber by end of
March 2026. (Section 5.1)
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OVERVIEW
Utilities Quarterly Report
Fiscal Year 2023
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1 ELECTRIC UTILITY.....................................................................................................................................................................6
1.1 ELECTRICITY SUPPLY AND TRANSMISSION ...........................................................................................................................................6
1.1.1 Forecasted Supply Costs...................................................................................................................................................6
1.1.2 Hydroelectric Conditions ..................................................................................................................................................7
1.1.3 Renewable Energy Procurement ......................................................................................................................................7
1.2 CAPITAL IMPROVEMENT PLAN STATUS ...............................................................................................................................................7
1.3 RELIABILITY ..................................................................................................................................................................................8
1.4 FINANCIAL HEALTH ........................................................................................................................................................................9
1.4.1 Sales Forecasts vs. Actuals ...............................................................................................................................................9
1.4.2 Financial Position ...........................................................................................................................................................10
2.1 GAS SUPPLY AND TRANSMISSION ....................................................................................................................................................11
2.1.1 Actual and Forecasted Supply Costs ..............................................................................................................................12
2.2 CAPITAL IMPROVEMENT PLAN STATUS .............................................................................................................................................12
2.3 RELIABILITY ................................................................................................................................................................................13
2.4 FINANCIAL HEALTH ......................................................................................................................................................................13
2.4.1 Sales Forecasts vs. Actuals .............................................................................................................................................13
2.4.2 Financial Position ...........................................................................................................................................................14
3.1 WATER SUPPLY AND TRANSMISSION ...............................................................................................................................................16
3.2 CAPITAL IMPROVEMENT PLAN STATUS .............................................................................................................................................18
3.3 RELIABILITY ................................................................................................................................................................................20
3.4 FINANCIAL HEALTH ......................................................................................................................................................................21
3.4.1 Sales Forecasts vs. Actuals .............................................................................................................................................21
4 WASTEWATER UTILITY ..........................................................................................................................................................22
4.1 WASTEWATER TREATMENT UPDATES AND CAPITAL PLANNING STATUS ..................................................................................................22
4.1.1 Treatment Cost Trends...................................................................................................................................................22
4.1.2 Regional Water Quality Control Plant Capital Planning Status .....................................................................................23
4.2 COLLECTION SYSTEM CAPITAL IMPROVEMENT PLAN STATUS ................................................................................................................24
4.3 FINANCIAL HEALTH ......................................................................................................................................................................25
4.3.1 Sales Forecasts vs. Actuals .............................................................................................................................................25
4.3.2 Financial Position ...........................................................................................................................................................26
5.1 FIBER UTILITY STRATEGIC PLANNING ...............................................................................................................................................27
5.2 CAPITAL IMPROVEMENT PLAN STATUS .............................................................................................................................................27
5.3 RELIABILITY ................................................................................................................................................................................27
5.4 FINANCIAL HEALTH ......................................................................................................................................................................27
5.4.1 Fiber Sales ......................................................................................................................................................................28
5.4.2 Financial Position ...........................................................................................................................................................28
7.1 STATE LEGISLATIVE ACTIVITY ..........................................................................................................................................................30
7.2 STATE REGULATORY ACTIVITY ........................................................................................................................................................30
7.3 FEDERAL ACTIVITY .......................................................................................................................................................................30
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8.1 OVERVIEW OF HEDGING PROGRAMS ...............................................................................................................................................32
8.2 OVERVIEW OF ENERGY RISK MANAGEMENT PROGRAM.......................................................................................................................32
8.3 FORWARD DEALS.........................................................................................................................................................................32
8.4 ELECTRIC MARKET EXPOSURE ........................................................................................................................................................33
9 APPENDIX B: STAFFING AND VACANCIES ...............................................................................................................................34
APPENDIX C: WASTEWATER UTILITY ANNUAL INFRASTRUCTURE MAINTENANCE AND REPLACEMENT REPORT .............................35
11. APPENDIX D: PALOALTOGREEN GAS PROGRAM ................................................................................................................................40
10 APPENDIX E: FISCAL YEAR 2025 DEMAND SIDE MANAGEMENT REPORT ............................................................................42
10.1 EXECUTIVE SUMMARY ..................................................................................................................................................................42
10.1.1 Summary Goals and Achievements................................................................................................................................42
10.2 ELECTRIC EFFICIENCY ....................................................................................................................................................................43
10.3 GAS EFFICIENCY AND ELECTRIFICATION ............................................................................................................................................45
10.4 WATER EFFICIENCY ......................................................................................................................................................................48
10.5 ELECTRIC VEHICLES ......................................................................................................................................................................49
10.6 SOLAR AND STORAGE ...................................................................................................................................................................51
Figures
FIGURE 1: FY 2026 Q2 NET SUPPLY COST FORECAST VS. ACTUALS..........................................................................................................................6
FIGURE 2: HYDRO GENERATION: FY 2026-2028 ACTUALS & PROJECTIONS (GWH)...................................................................................................7
FIGURE 3: ELECTRIC OUTAGE RELIABILITY, CY 2019 THROUGH 2025.......................................................................................................................9
FIGURE 4: ELECTRIC SALES VOLUME (KWH), FY 2026-Q2...................................................................................................................................10
FIGURE 5: ELECTRIC SALES REVENUE ($), FY 2026-Q2.......................................................................................................................................10
FIGURE 6: PALO ALTO GAS COMMODITY RATES .................................................................................................................................................11
FIGURE 7: GAS SUPPLY COSTS ($), ACTUAL VS BUDGET, FY2026-Q2....................................................................................................................12
FIGURE 8: GAS SERVICE INTERRUPTIONS, FY 2025 TO FY 2026............................................................................................................................13
FIGURE 9: GAS SALES VOLUME (THERMS), FY 2026 Q2......................................................................................................................................14
FIGURE 10: GAS SALES REVENUE ($), FY 2026 Q2............................................................................................................................................14
FIGURE 11: REGIONAL WATER SYSTEM STORAGE ...............................................................................................................................................16
FIGURE 12: SFPUC WATER DELIVERIES ............................................................................................................................................................17
FIGURE 13: WATER SERVICE INTERRUPTIONS, FY 2025 TO FY 2026.....................................................................................................................20
FIGURE 14: WATER SALES VOLUME (CCF), FY 2026 Q2 ....................................................................................................................................21
FIGURE 15: WATER SALES REVENUE ($), FY 2026 Q2........................................................................................................................................21
FIGURE 16: PALO ALTO’S SHARE OF ESTIMATED WASTEWATER TREATMENT EXPENSES ..............................................................................................23
FIGURE 17: CURRENT RWQCP CAPITAL WORK IN-PROGRESS (BASED NOVEMBER 4, 2025 REPORT TO FINANCE COMMITTEE).........................................24
FIGURE 18: WASTEWATER SALES REVENUE ($), FY 2026 Q2...............................................................................................................................26
FIGURE 19: ELECTRIC RESOURCE ADEQUACY DEALS.............................................................................................................................................32
FIGURE 20: ELECTRIC LOAD RESOURCE BALANCE, FY 2026 – 2028.......................................................................................................................33
FIGURE 21: UTILITIES VACANCIES AND RECRUITMENTS BY DIVISION........................................................................................................................34
FIGURE 22: OFFSET PORTFOLIO COMPOSITION ...................................................................................................................................................40
FIGURE 23: OFFSET PROJECT DESCRIPTIONS ......................................................................................................................................................41
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1 Electric Utility
The City’s electric utility serves all residential and non-residential electric demands in Palo Alto at a lower cost than PG&E
in surrounding communities. Its electric supply portfolio is 100% carbon neutral. The City maintains and operates an
electric distribution system but does not operate any transmission lines or any generating capacity on its own. Instead,
the City belongs to Northern California Power Agency (NCPA) which operates its Calaveras hydroelectric generating plant
and provides power scheduling services for its other generating resources. This carbon free power is supplied through
power purchase agreements with various generation operators.
1.1 Electricity Supply and Transmission
Below is an update on electricity supply and transmission services.
1.1.1 Forecasted Supply Costs
The electric net supply cost for FY 2026 is currently projected to be $88.7M, which represents a 3.3% decrease from the
Adopted Budget level of $91.7 M. For FY 2027, electric net supply cost is projected to be $95.2 M. During Q2 of FY 2026,
net supply cost was about $0.9M lower than the adopted budget. Although the actual net supply cost was consistent with
projections for Q2, the actual supply costs for FY2026 are below the budgeted supply cost by ~$2.1 M. FY2026 has seen
higher-than-expected load demand, which eliminated any sales from surplus energy. The other most notable variances
from the adopted budget were the lower congestion and loss costs (down $2.8M) and the lower costs in renewable
projects (down $1.2M). Revenue from RA sales as well was higher than expected (up $1.75M)Overall, actual supply costs
in the first half of FY 2026 were 4.9% below the budgeted level. Based on these actuals and the forecasted supply costs
for the remainder of the year, FY 2026 net supply cost is projected to end the fiscal year 3.3% below the adopted budget..
Figure 1: FY 2026 Q2 Net Supply Cost Forecast vs. Actuals
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1.1.2 Hydroelectric Conditions
The City receives power from two hydroelectric projects, the Calaveras project and the Western Base Resource contract
for federal hydropower from the Central Valley Project.1 The watershed for Western hydropower is primarily in the
northern end of California, while the watershed for the Calaveras project is in the Central Sierras.
Following the average water year of 2024-2025, reservoir levels across the state began this water year at slightly above
average levels. As of February 9th, precipitation in northern California is about 10% above average for this time of year,
while central California is 3% below average. Hydro generation levels are currently projected to be roughly average for FY
2026 and FY 2027, with total output of about 97% of the long-term average level for FY 2026 through FY 2028.
Figure 2: Hydro Generation: FY 2026-2028 Actuals & Projections (GWh)
1.1.3 Renewable Energy Procurement
Utilities staff is currently working with NCPA to issue a new request for proposals (RFP) for new renewable energy and
storage projects, with proposals expected to be received by the end of the calendar year. Staff will update the UAC in the
coming months as this effort proceeds.
1.2 Capital Improvement Plan Status
The following capital projects are currently in progress or have been recently completed:
EL-17001 (East Meadow Circles 4/12kV Conversion)
This project is scheduled to be completed in several phases. Phase 1 is completed. Phase 2 engineering design is
completed. Phase 2 construction is expected to be completed December 2026.
EL-10006 (Rebuild Underground 24)
This project is in the design phase, which is scheduled to be completed in June 2026. Construction will be
completed by Summer 2027.
EL-16000 (Rebuild Underground 26)
The engineering design for this project is currently in progress. The project will be completed in multiple phases
and will take additional years to complete. All engineering design phases are expected to be completed by
December 2026. Construction is expected to be completed by Summer 2027.
EL-19004 (Wood Pole Replacement)
1 The Calaveras project is a hydropower project located in Calaveras County that is maintained and operated by the Northern California Power Agency
on behalf of the City and other project participants. The City is also one of several public entities with contracts with the Western Area Power
Administration for “Base Resource” electricity, which is the hydroelectric power available from the federal government’s Central Valley Project
(operated by the Bureau of Reclamation) after accounting for power used for Central Valley Project operations and power delivered to certain
“preference” customers.
FY 2026 FY 2027 FY 2028
Calaveras Generation (GWh)81 116 95
Western Generation (GWh)261 298 249
Total Hydro Generation (GWh)342 414 343
% of Long-term Average Total 91%110%91%
Long-term Average Total Hydro (GWh)376 376 376
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CPAU staff and contract consultants are continuously working on pole replacement designs for construction.
25 poles were replaced to date in FY 2026. The replacement of poles will continue to be prioritized in the Grid
Modernization areas.
EL-16003 (Substation Physical Security).
This project is scheduled to be completed in two phases. Substation Security lighting and camera contract was
awarded in June 2022. The installation for the first phase was completed for 7 of the 9 substations in
December 2024. The next phase of the Substation Physical Security Project is pending the Colorado Master
Plan. The Colorado Master Plan incorporates and coordinates all planned construction work at Colorado
Substation, and the Physical Security work is expected to start in FY27.
EL-17002 (Substation 60kV Breaker Replacement)
This project funds the purchase and replacement of both 60kV and 12kV substation circuit breakers that are
reaching the end of their useful life expectancy. Council approved the purchase request for the sixteen 12kV
circuit breakers and eight 60kV breakers. The installation of the 12kV breakers is complete. The project to
purchase the eight 60KV breakers was approved by City Council on May 20, 2024. The engineering design and
installation of the 60kV breakers has been postponed pending the results and recommendations of a Master Plan
for Colorado Substation, a Plan that coordinates all planned work in the Substation and is expected to result in a
re-design of the 60KV Buss to either a Breaker-and-a-Half or Ring Buss scheme. The final Master Plan from the
City's consultant Ampirical is expected to be delivered by the end of FY26, and the tentative schedule for the
Colorado Substation re-design is expected to commence in FY27.
EL-21001 (Foothills Rebuild)
This project will rebuild approximately 9 miles of overhead line in Foothills Park, as necessary to lower the risk of
wildfires due to overhead electric lines. Staff has completed 39,200 feet of substructure work and de-energized
an equivalent amount of overhead electric lines. Substructure for Phase 1 was completed in Spring 2022 and the
substructure for Phase 2 was completed in June 2023. Phase 3 construction is 100% complete with substructures
and cable installed and energized. Phase 4 construction has completed 13,500 feet of the planned 22,000 feet.
Phase 4 undergrounding and has slowed due to winter weather. Phase 5 substructure installation along
Arastradero road is 100% completed with all substructure and cable installed and energized. Phase 4
undergrounding is planned for completion this summer and overhead lines (currently de-energized) will be
removed on all phases as weather permits. All work is expected to be complete before the end of fiscal year 2026.
EL-02011 (Electric Utility Geographic Information System (GIS))
The project scope includes on-going maintenance/technical support of the existing GIS system and
implementation of the new GIS platform, ESRI. Staff is exploring options with IT to accelerate migration to the
new ESRI platform.
EL-24000 (Grid Modernization)
The Pilot project was completed April 2025. Sixty-six poles have been replaced in the Grid Modernization Pilot
area. Additionally, 908 homes in the Pilot area are ready for electrification. The overhead design and material
procurement is in progress for the remainder of Phase 1. This includes an additional ~3,500 homes within
boundaries of Embarcadero Road, West Bayshore Road, Loma Verde Ave, Middlefield Road, Oregon Expressway,
and El Camino Real. The scope remains the same as the Pilot area, which is to upgrade and install new
transformers, overhead wires, poles and attachment equipment. The target date for Engineering design is
February 2026 and construction to follow (12-18 months). Additionally, as Engineering staff review customer
service upgrade requests and maintenance projects throughout the City, opportunities for infrastructure upgrades
are being executed.
1.3 Reliability
CPAU tracks electric power outages through industry recognized indices; System Average Interruption Duration Index
(SAIDI), System Average Interruption Frequency Index (SAIFI), and Customer Average Interruption Duration Index
(CAIDI). The chart below summarizes outage indices for Palo Alto. With this quarterly update, staff is presenting both
outage indices with and without the impacts of “major event days” (MED). For Palo Alto a MED is defined as a 24-hour
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period that impacts more than 10% of Palo Alto’s electric customers. By including and excluding MED, staff can review
both the impact of major events versus outages associated with more typical day-to-day operations.
Figure 3: Electric Outage Reliability, CY 2019 through 2025
Major Event Days Included Major Event Days Excluded
CY SAIDI SAIFI CAIDI SAIDI SAIFI CAIDI
2019 132.8 1.065 124.7 25.3 0.225 112.0
2020 46.2 0.830 55.7 20.9 0.165 126.7
2021 39.7 0.277 143.1 9.4 0.029 329.3
2022 71.7 0.622 115.3 13.4 0.070 190.5
2023 154.1 1.182 130.4 43.5 0.176 247.0
2024 134.7 0.844 159.7 67.4 0.474 142.1
2025 68.1 0.614 110.9 27.2 0.111 245.2
1.4 Financial Health
1.4.1 Sales Forecasts vs. Actuals
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Figure 4: Electric Sales Volume (kWh), FY 2026-Q2
Figure 5: Electric Sales Revenue ($), FY 2026-Q2
1.4.2 Financial Position
The FY 2027 preliminary electric rate trajectory presented at the November 5, 2025 UAC meeting3 remains unchanged
from the FY 2026 Financial Forecast4 presented to Council on June 16, 2025, which projected a 6% rate increase in FY 2027.
Staff projects the Electric Utility’s Operations Reserve will total $49.7 million at end of FY 2026, which is close to the target
level of $49.3 million. Staff expects that debt will be issued in FY 2027 to offset a portion of the grid modernization costs
already spent and planned in FY 2026 – FY 2029. Staff will provide an updated financial forecast projection to the UAC in
April 2026.
3 Staff Report 2503-4364: https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84164&dbid=0&repo=PaloAlto
4 Attachment D, Exhibit 1 to Staff Report 2411-3776, June 16, 2025:
7.8%
4.0%
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2 Gas Utility
The City’s gas utility serves all residential and non-residential gas demand in Palo Alto. The City maintains and operates a
system of medium-pressure gas lines for delivering gas but does not operate any transmission lines. Costs for the gas
utility are split approximately two thirds for the operation, maintenance, and capital improvement and one third for the
cost of the gas commodity, PG&E gas transmission, compliance with the State’s Cap and Trade Program and the City’s
Carbon Neutral Gas Program.
2.1 Gas Supply and Transmission
After experiencing a notable price spike during winter 2022-2023, natural gas prices in California have seen a significant
decline, returning to more typical ranges. This shift can be attributed to several factors, including milder temperatures
and above average gas storage levels in the West. The combination of these factors has kept natural gas prices low, and
we do not expect a significant price spike to occur in the near future. The chart below shows Palo Alto’s gas commodity
rates from September 2021 through December 2025.
Figure 6: Palo Alto Gas Commodity Rates
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2.1.1 Actual and Forecasted Supply Costs
Actual supply costs through FY 2026-Q2 were approximately 27% lower than budgeted in the FY 2026 Financial Forecast.
This variance was primarily driven by historically low natural gas prices, which remained well below initial forecasts. PG&E
benchmark prices at Citygate and Malin were projected at $4.49 and $3.77 per MMBtu for the first half of the fiscal year,
while actual average costs came in lower at $3.42 per MMBtu.
Through FY 2026-Q2, the budget total was $8,936,348, the actual total was $6,984,166, and the variance was ($1,952,182),
which was 22% lower than budgeted in the FY 2026 Financial Forecast.
Figure 7: Gas Supply Costs ($), Actual vs Budget, FY2026-Q2
2.2 Capital Improvement Plan Status
The following capital projects are currently in progress:
GS-15000 – GMR 25 (Gas Main Replacement 25)
The GMR 25 project will replace approximately 26,000 linear feet of gas mains on Ross Road from Colorado Avenue
to East Meadow Drive and surrounding streets, as well as North and Southampton Drive and surrounding streets,
and Walter Hays Drive and surrounding streets. Construction on the project is anticipated to begin in early 2026
and finish in mid-2027. A $16.5 million reimbursable grant from the Pipeline and Hazardous Material Safety
Administration was awarded for this project.
GS-25001 – Gas Line Repair at Arastradero Creek
During the 2023 winter storms, portions of Arastradero Creek eroded away and exposed a gas pipeline crossing
Arastradero Creek. This project completed the data gathering phase and will begin the design and permitting phase
of the work. A permanent solution was presented to the permitting agencies (Water Board, CDFW, USACE) in
August 2025 for input and permitting could take 9 months to complete. Construction on this project is anticipated
to begin in 2027. All work will take place in the Pearson Arastradero Preserve.
GS-16000 – GMR 26 (Gas Main Replacement 26)
The GMR 26 project will replace approximately 26,000 linear feet of gas mains in the Midtown, Palo Verde,
Fairmeadow, and Evergreen Park neighborhoods. The project is currently in design with construction anticipated
in mid-2027.
Operational Fund – Historic Crossbore Inspection Project
The Cross Bore Phase IV Project includes a total of 963 sewer laterals located throughout the City. The project
inspections are on-going and are being performed by the City’s Operational crew. The laterals that cannot be
completed by city crews, will be inspected by a contractor at a later date. A total of 271 laterals have been inspected
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by city crews, with 153 being cleared of a cross bore and 118 more complex situations requiring reinspection with
more specialty equipment, which may be completed by a contractor or staff with additional training. A lateral
launch camera may be required for the reinspection, which Operations staff recently acquired. Training was
completed in December 2025. 692 sewer laterals remain to be inspected by city crews and will continue in 2026
when new hourly employees are anticipated to be hired.
2.3 Reliability
The City of Palo Alto tracks all gas service interruptions. A summary chart of these interruptions can be found below. Gas
service interruptions are usually due to repairs of broken or damaged gas services and mains. This kind of damage is often
caused by excavation by outside parties digging in the City. In Q1 FY25, staff recorded higher numbers in gas service
interruption tracking due to the division allocating more resources to resolve existing gas leaks. These leaks are small and
are monitored; however, expected changes in gas legislation will require them to be resolved more quickly. The gas
division has been proactively working to meet upcoming compliance goals before the new rules go into effect. In Q2 FY
2026 there was an increased number of gas dig-ins by outside contractors. These were responsible for 7 of the 11 outages
and 189 of the customers affected.
Figure 8: Gas Service Interruptions, FY 2025 to FY 2026
FY 2025 FY 2026
Gas Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Number of Breaks 13 7 6 6 4 11
Total Minutes 1860 1205 1050 930 300 1063
Customers
Affected 135 48 23 40 17 200
2.4 Financial Health
Below is a summary of the financial position for the gas utility.
2.4.1 Sales Forecasts vs. Actuals
Actual gas sales volumes through Q2 2026 were approximately 3.1% below forecast, resulting in revenues 8.6% below
budget, as gas market prices continued to be lower than anticipated.
153
118
692
Total Sewer Laterals Completed
Total Sewer Laterals Incomplete
Total Addresses remaining to be
Inspected
963 sewer laterals for Inspection
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Figure 9: Gas Sales Volume (Therms), FY 2026 Q2
2.4.2 Financial Position
At the end of FY 2025, the Gas Utility’s Operations Reserve was $9.7 million, slightly above the minimum guideline level
of $8.6 million (this balance includes $8.57 million held in the CIP Reappropriations Reserve to be reimbursed through a
grant, and $5.4 million temporarily recorded in the Operations Commitments Reserve, due to an administrative oversight
which should have been placed in Operations Reserve).
Gas sales revenue in FY 2025 was about $4.7 million below forecast due to lower usage. Although supply purchases were
$3.2 million below forecast and distribution expenses were $0.6 million lower, these savings did not fully offset the
revenue shortfall. CIP expenses exceeded projections by $6.8 million, funded largely through the CIP Reappropriation and
Commitments Reserve for Gas Main Replacement Project 24. An additional $700,000 will be needed in FY 2027 for gas
line repairs at Arastradero Creek, partially offset by approximately $395,000 in grant funding shared across Water,
Wastewater, and Gas Utilities. In FY 2026 and FY 2027, staff projects the Operations Reserve will be impacted by lower
-3.1%
-8.6%
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sales revenues from lower consumption and higher CIP expenses. Staff projects the Gas Utility’s Operations Reserve will
total $12.3 million at end of FY 2026.
7 is a 14.5% distribution
rate increase, or a 9% overall increase for FY 2027, assuming supply charges remain unchanged, which is higher than the
6% overall increase projected in the FY 2026 Financial Forecast8 presented to Council on June 16, 2025. Staff will provide
an updated financial forecast projection to the UAC in April 2026.
7 Staff Report 2503-4364: https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84164&dbid=0&repo=PaloAlto
8 Attachment D, Exhibit 1 to Staff Report 2411-3776, June 16, 2025:
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3 Water Utility
The Water Utility serves water to virtually all Palo Alto residential and non-residential customers. All potable water in the
City is from the San Francisco Public Utilities Commission (SFPUC) Hetch Hetchy Water System. This system delivers high
quality water from the Sierra Nevada and uses no pumping to deliver water to the City. Palo Alto uses a small amount of
recycled water for irrigation of the Municipal Golf Course and a few other sites near the Regional Water Quality Control
Plant. The City also maintains a system of reservoirs, wells, and emergency interties that enable Palo Alto to serve water
during an interruption of the Hetch Hetchy system. Costs for the Water Utility are split approximately half for the
operation, maintenance and periodic replacement of Palo Alto’s water system and half for the costs of the water
purchased.
3.1 Water Supply and Transmission
As of February 1, 2026, cumulative Hetch Hetchy Weather Station precipitation for Water Year (WY) 2026 was 110% of
median, and the Regional Water System total storage operated by the San Francisco Public Utilities Commission (SFPUC)
was at 93% of maximum storage and the Water Bank was 99% full. In the figure below, the solid black line shows storage
in the Regional Water System for the past 12 months (color bands show contributions to total system storage) and the
dashed black line shows total system storage for the previous 12 months. Regional Water System Storage is 1,334
Thousand Acre Feet (TAF) as of February 1, 2026.
Figure 11: Regional Water System Storage
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The figure below shows water usage for the South Bay/East Bay (including Palo Alto) compared to several benchmarks,
including 2015, 2025 and a five-year average. For the South Bay/East Bay region as well as systemwide, demand for 2026
has been higher than the average of the last five years.
Figure 12: SFPUC Water Deliveries
CY2022
o Apparent Losses: 16.1 gal/connection/day
o Real Losses: 6.7 gal/connection/day
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CY2023
o Apparent Losses: 16.7 gal/connection/day
o Real Losses: 4.0 gal/connection/day
CY2024
o Apparent Losses: 11.6 gal/connection/day
o Real Losses: 6.8 gal/connection/day
3.2 Capital Improvement Plan Status
The following capital projects are currently in progress:
WS-09000 – Water Tank Seismic Upgrade and Rehabilitation
The seismic water system improvement project will involve an engineering assessment and seismic analysis of
two 60-year-old, one-million-gallon, welded steel tanks located near the San Andreas Fault. These are the last two
water storage tanks in the distribution network yet to be seismically retrofitted. The tanks also require
rehabilitation and new coatings. The engineering assessment will be completed by June 2026. Staff will solicit
services for engineering design, and the anticipated project construction start date for rehabilitation is January
2030.
WS-16001 – WMR 30 (Water Main Replacement 30)
The WMR 30 project is currently in the design phase and will replace approximately 2,000 linear feet of water main
on Stanford Avenue and Channing Avenue. The anticipated project construction start date is in January 2027.
WS-19001 – WMR 31 (Water Main Replacement 31)
The WMR 31 project is currently in a preliminary scoping phase. The project will replace approximately 4,000
linear feet of water main. This pipe replacement project is being coordinated with the Wastewater Replacement
Program. A combined water and wastewater replacement project is anticipated to start in January 2028.
WS-11003 – Water Distribution System Improvements
Arastradero Creek Relocation: During the 2023 winter storms, a section of Arastradero Creek eroded away and
exposed a gas pipeline crossing. The gas line is in close proximity to a large diameter water pumping line. This
project will relocate the water pumping line to a location out of the creek bed and eliminate the undermined creek
crossing. The project is currently in design and permitting phase of the work. A preliminary design for the relocated
water line has been completed. Work to relocate the pipeline is anticipated for July 2028.
Water System Leak Detection: Leaks are repaired when they reach the surface, but small leaks can remain hidden.
This project will use acoustical leak detection to identify and map small, unreported leaks in the distribution
system. The data will guide future repairs and pipe replacement priorities. Leak detection will begin in March 2026
and finish by year end, with additional leak detection repeated in 2027 and 2028 under a 3-year contract, as
needed. This approach follows state guidance.
Water HDPE and Water Standard Updates: The Plastic Pipe Institute released a new technical paper for
engineering and design of in-line anchor blocks for new HDPE pipe. This project will prepare new engineering
calculations and standard details. HDPE is the primary pipe material for all water pipes in Palo Alto. These
engineered details will be used in all water main replacement projects within the City.
WS-11004 – Water System Supply Improvements
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Risk and Resilience Assessment & Emergency Response Plan: In compliance with the Safe Drinking Water Act
Section 1433 and the America’s Water Infrastructure Act Section 2013 an update to the Risk and Resilience
Assessment was completed in December of 2025 and certified with the U.S. EPA before the deadline. An update
to the Emergency Response Plan (“ERP”) for the water utility began in January of 2026, and the new ERP will be
completed by June of 2026.
Water System Master Plan: The previous full system water system master plan was completed in 1999, and a
Master Plan of the water distribution piping network was completed in 2015. A new Water System Master Plan
will evaluate the City’s existing water distribution system, demands, and maintenance needs. The plan will develop
a recommended and prioritized list of capital improvement projects. Professional engineering services to prepare
the plan will be solicited by Spring of 2026.
Well Improvements: Palo Alto owns eight wells. The pump at the El Camino Park Well failed and was removed,
rebuilt, and returned to service. About one hundred eighty feet of column pipe was replaced with new 10-inch
steel pipe, and the pump received a new power cable, new coatings, and a new intake strainer. The well casing
was inspected and cleaned before reinstallation. Engineering and operations staff are planning a well site
assessment for potential emergency backup power needs, with an informal review completed in Winter 2025 to
identify generator locations, new power cables, and other well site improvements.
Wildfire Hardening Improvements: Wildfires can contaminate potable water and damage water system
infrastructure. The Office of Emergency Services, with input from water engineering staff, updated vegetation
removal plans and wildfire hardening buffers around water facilities in Fire Hazard Severity Zones. Professional
services will be solicited in 2026 to evaluate vulnerable facilities in these zones and recommend improvements.
Appurtenances and Large Meter Replacements: Small water meters are routinely replaced and monitored for
low and no flow errors. Meters three inches and larger serve critical customers and require more complex testing
and replacement. Several large meters have been identified for replacement through the AMI program, which will
improve accuracy and data quality for annual water audits and loss reduction efforts. A solicitation for
construction services is planned for Spring 2026 and will include on call work to replace aging sampling stations
and air release valves.
Water Storage Improvements: The City of Palo Alto owns and maintains seven water storage reservoirs, two of
which need improvement or replacement. A new PAX water tank mixer has been purchased to replace the mixer
for the Montebello Tank site after the water tank mixer failed. The Boronda Tank roof has multiple indentations
where water collects and ponds on the roof. Construction services will be solicited in 2026 to mitigate the roof
ponding in accordance with State Water Resources Control Board requirements.
Water Supply Connections: Palo Alto receives water through five connections to the San Francisco Public Utility
Commission Regional Water System. Three of the connections tie into the 36-inch Palo Alto Pipeline along El
Camino Real. The supply connection at California Avenue and El Camino Real was reconstructed in 2024, providing
improved control of water supply pressure. Engineering and operations plan to adjust valving from the new station
to serve a second pressure zone and strengthen system resiliency. This project will also add communication and
control devices and pipe supports. Operations have improved water quality monitoring with new on demand
chlorine analyzers installed at the supply connections.
Automatic Flushing Systems: Most storage in the distribution network is reserved for emergency supply. About
six and a half million gallons are stored west of El Camino Real in tanks built in the 1950s and 1960s, including a
series of five tanks and pump stations from Arastradero Road to Montebello Road. Water in these tanks and in
the main City reservoirs is routinely cycled into the system to maintain freshness, and staff flush low-demand
areas to manage water age. Operations and engineering have identified potential sites for automatic flushing
systems that can be coordinated with tank down flush cycles and seasonal water quality needs. A pilot is planned
for 2026.
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WS-13002 – Water General Equipment/Tools
This project will purchase multiple new tools and equipment to support operation and engineering needs. The
following equipment and tools will be purchased this fiscal year.
o A new tapping machine to replace an old tapping machine with a failed motor
o New clamp-on flow monitoring device
o New line stopping equipment and replacement components
WS-80013 – Water System Customer Connections
This project is a permanent, ongoing project. The project includes improvements required to provide service to
new customers and customers requesting expanded service. Work includes new main extensions, valves, domestic
services, meters on upgraded services, backflow devices, fire services, and fire hydrants.
WS-80014 – Water Service and Hydrant Replacement
This project is a permanent, ongoing project. The project replaces system control valves, deteriorated services,
and replacing fire hydrants.
WS-80015 – Water Meters
New meters have been purchased for the AMI program, which is currently 90% complete. In 2026, staff will
purchase all of the new large meters of 3” and larger, for the Appurtenance and Large Meter Replacement project
work described above in the WS-11004 section.
3.3 Reliability
The City of Palo Alto tracks all water service interruptions. A summary chart of these interruptions can be found below.
Water service interruptions are usually due to repairs of broken or damaged water services and mains.
Figure 13: Water Service Interruptions, FY 2025 to FY 2026
FY 2025 FY 2026WaterQ1Q2Q3Q4Q1Q2Q3 Q4
Number of Breaks 8 7 7 8 6 7
Combined Minutes 510 1250 795 960 1200 1295
Customers Affected 127 99 61 146 95 114
Water distribution network hydraulic capacity design includes sizing pipelines, pump stations, pressure-regulating valves,
tanks and reservoirs to meet water demand and system flow needs. Fire-flow demand plus maximum day demand is an
important limiting demand condition for pipe sizing and system operation. In 2025, the Fire Department and Water
Transmission Operational team completed multiple large, multi-hydrant fire flow tests throughout the two largest
pressure zones. The results indicated stronger than expected water system performance, and it improved coordination
between the Fire Department and Water utility.
The City of Palo Alto’s water system has seven emergency interties with neighboring water agencies. There are two
interties with Stanford University, one intertie with the City of East Palo Alto, two interties with the City of Mountain View,
and two interties with Purissima Hills Water District. The City of Palo Alto and the City of East Palo Alto maintain an
emergency intertie on the University Avenue bridge over the San Francisquito Creek. The City of East Palo Alto completed
the first phase of the reconstruction of the emergency intertie. The project improved reliability and flows of the emergency
intertie. The General Manager of Purissima Hills Water District requested an additional emergency intertie located near
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the intersection of Page Mill and Old Page Mill Road. City of Palo Alto and Purissima Hills Water District engineering teams
are analyzing benefits.
3.4 Financial Health
3.4.1 Sales Forecasts vs. Actuals
Figure 14: Water Sales Volume (CCF), FY 2026 Q2
Figure 15: Water Sales Revenue ($), FY 2026 Q2
-6.1%
-6.1%
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4 Wastewater Utility
The Wastewater Utility includes the system of sewer pipes that collect and transport wastewater to the Regional Water
Quality Control Plant (RWQCP) operated by the City of Palo Alto under a partnership agreement with several surrounding
communities, as well as Palo Alto’s share of the cost of operating the RWQCP. The RWQCP provides treatment and disposal
of wastewater for Palo Alto. Costs for the Wastewater Utility are split approximately half for the operation, maintenance
and periodic replacement of Palo Alto’s sewer collection system and half for the costs of wastewater treatment at the
RWQCP.
4.1 Wastewater Treatment Updates and Capital Planning Status
The RWQCP, operated by Palo Alto's Public Works Department, provides wastewater treatment to Palo Alto, Mountain
View, Stanford, Los Altos, East Palo Alto, and Los Altos Hills. The Palo Alto Wastewater Collection Utility contributes
approximately 36% of the costs in FY 2025). Capital costs, driven by necessary upgrades to aging equipment and changing
environmental regulations, are a major factor in cost increases. With plant equipment over 50 years old, significant
rehabilitation and replacement are required to maintain safe, compliant wastewater treatment operations.
4.1.1 Treatment Cost Trends
RWQCP staff project an 8% average annual increase in net treatment costs paid by Palo Alto’s Wastewater Utility from FY
2027 to FY 2031. The main drivers are capital projects, materials, and debt service (including loan repayments). Treatment
capital expenses, including debt service, are expected to rise by about 18% per year on average to fund equipment
replacement and major upgrades. Larger increases in capital expenses are anticipated starting in FY 2030 due to new debt
for major projects. The figure below outlines Palo Alto’s share of estimated net treatment costs, including treatment
operations costs, pay-as-you-go CIP expenses, existing debt service, and planned debt service payments shown in the
"Planned Debt Service" bar.
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Figure 16: Palo Alto’s Share of Estimated Wastewater Treatment Expenses
While operations costs make up the bulk of treatment expenses, they are growing slower than planned debt service. The
largest increase in planned debt service in FY 2030 is primarily due to the debt service repayments beginning on the
Secondary Treatment Upgrades, which is an estimated $193 million capital project to remove nutrients from the
wastewater (denitrification) in order to meet upcoming regulatory requirements. Nutrient removal is important to reduce
algae blooms that kill fish and other aquatic life. The Secondary Treatment Upgrades project will also replace critical, aging
mechanical and electrical equipment.
In June 2024, the Council approved a Cost-Sharing Agreement with the Santa Clara Valley Water District for the Guiding
Principle 5 grant program, which funds future RWQCP11 projects. The program supports communities like Palo Alto, where
taxpayers pay State Water Project property taxes but rely on non-Valley Water supplies for most of their water. Staff
estimates a total of $11.2 million in grant funding for Palo Alto’s share of approved RWQCP projects, directly benefiting
local customers. Four upcoming projects are eligible for this funding:
Outfall Line Construction
Headworks Facility Replacement
12kV Electrical Power Distribution Loop Improvements
Joint Intercepting Sewer Rehabilitation
In FY 2025, approximately $2.8 million in CIP expenses were reimbursed through this funding, and about $3.9 million in
reimbursements are anticipated in FY 2026.
4.1.2 Regional Water Quality Control Plant Capital Planning Status
The RWQCP continues to undergo significant capital improvements to address aging infrastructure, respond to evolving
regulations, and meet future capacity needs. These efforts are guided by the Long-Range Facilities Plan (LRFP), which was
originally adopted in 2012 and is now undergoing a comprehensive update, anticipated for completion in 2027. The
RWQCP’s current capital work in-progress includes an estimated $464.2 million in projects. The following table
11 Staff Report 2404-2877, June 3, 2024 https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=82864&dbid=0&repo=PaloAlto
12,734 -6%
11,962
48%
17,648
-1%
17,449
2%
17,803
33%
23,691
2%
24,275
(5,000)
-
5,000
10,000
15,000
20,000
25,000
30,000
2025 2026 2027 2028 2029 2030 2031
Actuals Projected
Ne
t
E
x
p
e
n
s
e
s
(
$
0
0
0
)
Fiscal Year
Treatment O&M Pay-as-you-go CIP Expenses Existing Debt Services
Planned Debt Services Total/YOY%
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summarizes these ongoing projects and provides their status and costs. Palo Alto’s share of these costs is captured in
Figure 17 in the “Planned Debt Service” category.
Figure 17: Current RWQCP Capital Work In-Progress (based November 4, 2025 report to Finance Committee13)
Project Status Planned Expense
(million $)
New and Rehabilitated Outfall
Pipeline
Secondary Treatment Upgrades
Local Advanced Water
Purification System
Headworks Facility Replacement
Horizontal Levee Pilot Project
New Laboratory and
Environmental Services Building
Projects in Progress
4.2 Collection System Capital Improvement Plan Status
WC-15002 – Wastewater System Improvements - Sewer Master Plan Study
The Master Plan Study will evaluate the City’s existing wastewater collection system, flows, and flow patterns to
determine the adequacy of the system’s hydraulic capacity to meet current and anticipated future wastewater flow
demands and develop a recommended prioritized Sewer Main rehabilitation plan. The project kicked off in
December 2023. The project was completed in December 2025.
WC-15002– Wastewater System Improvements and WC-13002 – Lodge/Foothills Lift Station Pump #1 and Pump #2
Repair
13 Staff Report 2508-5132 https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83790&dbid=0&repo=PaloAlto
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The Lodge/Foothills Lift Station (LFHLS) experienced pump failure of Pump #1 and partial failure of Pump #2. Pump
#1 was removed, repaired, and reinstalled. Pump #2 was removed and transported to vendor to repair. Pump #2
was repaired and installed in December 2025.
WC-15002– Wastewater System Improvements – Arastradero Creek Wastewater Relocation
During the 2023 winter storms, a section of Arastradero Creek eroded away and exposed a gas pipeline crossing.
The gas line is in close proximity to a sanitary sewer main. This project will relocate the sanitary sewer main to a
location out of the creek bed and eliminate the undermined creek crossing. The project is currently in design and
permitting phase of the work. A preliminary design for the relocated sanitary sewer main has been completed.
Work to relocate the pipeline is anticipated for July 2028.
WC-20000 - SSR 32 (Sanitary Sewer Replacement 32)
The SSR 32 project is currently in the design phase and will replace approximately 26,000 lineal feet of sewer mains,
laterals, and manholes. Currently, the project is in the process of being rescoped based on the recently received
Sewer Master Plan which identifies prioritized improvements based on rehabilitation and capacity issues. Design
will restart in FY27 for construction in FY28.
WC-26001 – 3-Year CCTV Sanitary Sewer Mainline Inspection
The City is in the process of developing a Request for Proposal (RFP) for a three-year program to CCTV Sanitary
Sewer Mains. The project will CCTV approximately 225,000 lineal feet of Sanitary Sewer Main over a three-year
duration at an annual rate of approximately 75,000 lineal feet per year. Results of the project will be used to identify
defective Sanitary Sewer Mains which will be incorporated into future SSRs to rehabilitate and replace Sanitary
Sewer Mains. The project has an anticipated RFP bid date early 2026 for an anticipated start date in Summer 2026.
WC-99013 – Sanitary Sewer Lateral Rehabilitation and Replacement
The City is in the process of developing an IFB for a three-year program to rehabilitate or replace Sanitary Sewer
Lower Laterals (Lower Laterals). City staff has identified approximately 210 Lower Laterals that will be rehabilitated
or replaced over a three-year period at an annual rate of approximately 70 per year. In addition to addressing
defective Lower Laterals, the project will reduce inflow and infiltration into the sanitary sewer system. Due to
financial issues, the project was put on hold until October 2025, and now has an anticipated and target date for
Solicitation process in February 2026.
4.3 Financial Health
Below is a summary of the financial position for the wastewater utility.
4.3.1 Sales Forecasts vs. Actuals
Wastewater sales revenues through Q2 FY 2026 were 3.1% above budget.
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Figure 18: Wastewater Sales Revenue ($), FY 2026 Q2
4.3.2 Financial Position
At the end of FY 2025, the Wastewater Collection Utility’s Operations Reserve was $1.7 million, which is below the risk
assessment level of $2.8 million.
In FY 2025, the Utility received $2.7 million in Valley Water grant revenue to offset Wastewater Treatment costs, directly
benefiting Palo Alto customers. The cash balance at the end of FY 2025 was approximately $0.9 million, which is lower
than Staff’s projections. The Utility plans to fully repay the Fiber Utility loan15 due in FY 2026.
New CIP needs have emerged, including $2.4 million from FY 2027 through FY 2029 for Arastradero Creek exposed pipe
repairs and pipe relocation. These costs will be partially offset by shared grant funding across the water and gas utilities.
Staff projects the Wastewater Collect Utility’s Operations Reserve will total $6.7 million at end of FY 2026.
The FY 2027 preliminary wastewater rate trajectory presented at the November 5, 2025 UAC meeting16 remains
unchanged from the FY 2026 Financial Forecast17 presented to Council on June 16, 2025, which assumed a 16% rate
increase in FY 2027. On March 4, 202618, staff presented the Wastewater Collection Utility rate proposal to the UAC. The
UAC voted 6-1 to recommend that the City Council adopt a resolution approving the 16% rate increase. Staff will present
the proposed the rate changes to the Finance Committee on March 17, 2026.
15 Resolution 10173: https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=62043&dbid=0&repo=PaloAlto
16 Staff Report 2503-4364: https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84164&dbid=0&repo=PaloAlto&searchid=ffbb0624-e25e-
413d-8cc1-ffb7fcd6db8a&cr=1
17 Attachment D, Exhibit 1 to Staff Report 2411-3776, June 16, 2025:
18 Staff Report 2512-5640: https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=86546&dbid=0&repo=PaloAlto&searchid=95f2dfdc-8b45-
4b0f-b793-dc0806d033ad
3.1%
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4 Fiber Utility
The City offers a "Dark" fiber service, providing a fiber connection from Palo Alto businesses to the downtown Internet
Exchange. At the exchange, businesses select an internet service provider (ISP) for bandwidth and connection speed. The
City is piloting Palo Alto Fiber ISP service under the fiber-to-the-premises project (FTTP) to provide residents with a fast,
reliable, affordable, and local internet service.
4.1 Fiber Utility Strategic Planning
Below are highlights and status updates of the Fiber-to-the-Premises (FTTP) Project:
The fiber hut and emergency generator have been delivered and installed at the Colorado substation.
Aerial fiber construction and installation of five fiber distribution cabinets are complete in the pilot area.
City is working on vendor contracts to perform fiber drop and in-home installations
4.2 Capital Improvement Plan Status
The following capital projects are currently in progress:
FO-16000 – Fiber Optic System Rebuild
o The new fiber backbone will be built in segments in alignment with the phased FTTP. CPAU is installing
new aerial ducts or substructure (conduit and boxes) and fiber backbone cables to increase capacity in
areas that are at or near capacity to meet new customer dark fiber connection requests. The initial areas
of rebuild are in Stanford Research Park for capacity and along Colorado Ave to provide resiliency and
redundancy for electric and fiber.
FO-24000 – Fiber-to-the-Premises
o The pilot area consists of approximately 800 homes which are bounded by Embarcadero Road, Louis
Road, Colorado Avenue, Greer Road and West Bayshore Road. Staff anticipate launch of service in
March of 2026. During the aerial construction phase, over 15 residents voluntarily expressed interest in
subscribing to Palo Alto Fiber internet.
4.3 Reliability
There were no unplanned fiber outages or events to report in Q2 of FY 2026.
4.4 Financial Health
Below is a summary of the financial position for the fiber utility.
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5.4.1 Fiber Sales
Through FY 2026 Q2, dark fiber licensing sales were $1.5M and ($0.3M) or (8%) below the revenue forecast of $1.8M.
Fiber expenses were $2.7M and $0.3M or 12% above forecast of $2.4M due to construction costs and network equipment
for FTTP. Three of the four positions added in FY 2024 to support FTTP are on hold, pending results of the FTTP Palo Alto
Fiber pilot. Existing staff and contractors are collectively performing the work that staff in those roles would perform at
this time.
5.4.2 Financial Position
At the end of FY 2025, the Fiber Fund had a total reserve of $34 million which consists of $17.4 million of rate stabilization,
$13.1 million of commitments and reappropriations, and $3 million loan to Wastewater Collection utility.
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5 Communications
This section summarizes communications highlights, updates on major campaigns and noteworthy events. Copies of ads
bill inserts, and brochures are available online at www.paloalto.gov/UTLbillinsert
Customer Satisfaction Surveys: CPAU participated as a member of the California Municipal Utilities Association (CMUA)
in customer satisfaction surveys for residential electric and water customers. A statewide survey of municipal and investor-
owned utilities customers was completed in July 2025 and responses from Palo Alto residents in what is called an
“oversample” survey were completed in November. These surveys inform us of customer perspectives on reliability, rates,
customer programs, customer service, and communications.
Wildfire Mitigation: The California Wildfire Safety Advisory Board (WSAB) completed its review of utilities wildfire
mitigation plans and applauded Palo Alto in its public report for substantially reducing wildfire risk by undergrounding
overhead utility lines in the high fire threat district, the Foothills. You may have seen the recent article in Palo Alto Online
about the city’s wildfire prevention activities. The WSAB also commended the city for its contributions to an innovative
gas monitoring network for early detection of wildfire. The WSAB members and staff acknowledged that this technology
is not widely used by publicly owned utilities or investor-owned utilities. It was recommended that CPAU report on the
status of its undergrounding project (scheduled for completion in June 2026) in the next wildfire mitigation plan, and its
efforts to reduce risk from remaining infrastructure. WSAB also advised that the city report the results, benefits, and
challenges of deploying gas monitoring technology to inform broader adoption decisions in the utility community.
Electric Integrated Resource Plan: Every five years, CPAU submits an Electric Integrated Resource Plan (IRP) to the
California Energy Commission (CEC) to demonstrate that the City is on track to meet the state’s requirements for long-
term energy policy goals, greenhouse gas emissions reduction targets, and renewables portfolio standard. The CEC
recently sent us a detailed report and letter from the Executive Director to verify that the 2023 IRP, which staff provided
in April 2024, satisfies all requirements, including meeting the state’s mandated 60% by 2030 renewables standard.
Charging Smart Gold Designation: The city received Gold level designation from Charging Smart, a program funded by the
US Department of Energy and implemented by the International Renewable Energy Council, for its leadership in advancing
efficient EV charging. After reviewing the city’s efforts, the program awarded Palo Alto its highest-level award for robust
planning, streamlined permitting, community programs, and fleet and infrastructure investments. This recognition
showcases our progress and helps us exchange best practices with other communities advancing clean mobility.
NCPA Annual Conference: UAC Chair Scharff, Vice Mayor Veenker, and several CPAU staff attended NCPA’s annual
conference in September, which is the largest of its kind hosted in the state, bringing together 270 attendees from the
public power sector, broader electricity industry, key policy stakeholders, and vendors. Conference sessions focused on
issues impacting public power utilities, such as legislation, electricity demands including the rise of AI data centers, and
energy markets. The NCPA Legal Committee meeting, of which Assistant City Attorney Amy Bartell chairs, discussed the
interactions between federal and state policy, specifically possibilities for federal preemption, that have become
increasingly important to energy and environmental projects. In the Legislative and Regulatory Affairs Committee, we
heard from two panels of experts about wildfire and power supply management. Utilities Director Alan Kurotori
moderated a panel of speakers from the Western Area Power Administration (WAPA), Bureau of Reclamation, and
Bonneville Power Administration, discussing federal and customer collaboration for investment in power infrastructure,
energy market opportunities, and ways to ensure reliability, resiliency, and affordable power rates.
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6 Legislative, Regulatory and Industry Activity
6.1 State Legislative Activity
State legislative activity was quiet in the second quarter of FY26 as the legislature was adjourned for the year. With 2026
being an election year, less major activity is expected on energy or water issues as lawmakers seek to avoid contentious
issues. Despite this, energy affordability, wildfire mitigation, permitting streamlining for clean energy and transmission
projects, and the potential extension of Diablo Canyon nuclear plant operations beyond 2030 are expected to be important
topics. CPAU has also been working to extend the Renewable Portfolio Standard (RPS) treatment of publicly owned utility
(POU) large hydropower, which was carried by AB 1273 last year but ultimately vetoed. With the help of NCPA, CPAU staff
secured a commitment from the author of AB 1273, Assemblymember Joe Patterson, to carry similar legislation in 2026.
CPAU staff are working toward securing co-authorship with local representatives Assemblymember Marc Berman and
Senator Josh Becker and developing advocacy in support of the legislation.
6.2 State Regulatory Activity
Regulatory activity at the end of 2025 included updates to water efficiency regulations, wildfire mitigation analysis, and
pending updates to the Cap and Invest program. In conjunction with CMUA, CPAU staff advocated for clarifying language
in the Model Water Efficient Landscaping Ordinance (MWELO) regarding non-potable water and non-functional turf. If
adopted, this will prevent situations where certain customers are allowed to install non-functional turf with the
understanding they can irrigate with non-potable water, only for CPAU to have to inform customers that non-potable
water is not supplied at non-City properties. The California Air Resources Board (CARB) was delayed in releasing the draft
regulatory language for the Cap and Invest program update, which was expected by the end of 2025. Regardless, CPAU
staff are working closely with NCPA and CMUA to collect data and prepare talking points to preserve the revenue and local
flexibility used for many of CPAU’s decarbonization programs. As directed by SB 254, the California Earthquake Authority
(CEA) is preparing a natural catastrophe resiliency study that is analyzing options for long-term reforms that protect access
to insurance, reduce litigation costs, provide fair compensation to claimants, support wildfire mitigation, and ensure large
IOUs are accountable for wildfire safety while maintaining financial health to help keep electric rates low. CPAU, like all
electric utilities in California, faces cost pressures and liability risks from wildfires and is interested in reforms that enhance
wildfire safety, alleviate rising costs, and ensure wildfire victims are made whole.
6.3 Federal Activity
CPAU continues its work with NCPA to support federal workers and investments related to the Central Valley Project (CVP).
Seeking to downsize the federal workforce, the federal administration eliminated critical employees at the Bureau of
Reclamation (BOR) and the Western Area Power Administration (WAPA). Especially concerning are significant reductions
in dam and powerplant mechanics and other technologists instrumental for the safe and effective operations of the dams
and powerplants. Through NCPA, CPAU staff and elected officials have been able to secure protections for the remaining
BOR and WAPA employees and start hiring for open WAPA positions. However, the BOR has not received permission to
resume hiring, leaving critical operational positions unfilled. NCPA and other utilities are exploring stop-gap measures for
providing mutual aid to federal facilities, as conditions permit, to complete important projects safely and efficiently while
also advocating to fill vacant BOR positions.
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Appendices
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7 Appendix A: Energy Risk Management Program
This appendix provides a quarterly update on the City’s Energy Risk Management Program.
7.1 Overview of Hedging Programs
The City’s Utilities Department maintains a hedging program for its Electric and Gas Utilities. In the Gas Utility, the program
protects against short-term (intra-month) price spikes caused by weather or major incidents on the Western gas system.
However, the City does not hedge its gas supply more than one month in advance, choosing instead to protect the Gas
Utility’s financial position by passing gas supply costs through to customers via a charge that varies monthly based on gas
market prices. As a result, the Gas Utility’s only market exposure is the amount by which gas demand deviates from
forecasts within the month. This exposure is relatively small and can be managed using Gas Utility Operating Reserves. A
risk assessment is performed each year as part of the Gas Utility financial planning process to ensure adequate reserves
to cover all risks. The most recent Gas Utility Financial Forecast was adopted June 16, 2025 (Staff Report #2411-377623).
The City has entered into long-term contracts for its Electric Utility to ensure that the City has carbon free electricity
supplies equal to 100% of Palo Alto’s annual electric demand. However, the output from these generating sources does
not match Palo Alto’s electric load in every season. In the summer, the City has a surplus of carbon free energy and it has
a deficit in the winter. This exposes the City to market risk, and staff maintains a hedging program to protect against this
risk. In addition, hydroelectric generators make up approximately half the City’s energy supply. During dry years, these
resources do not generate as much energy, creating an additional market exposure that must be hedged. Unlike the gas
hedging program, which is operated by City staff, the electric hedging program is operated by the Northern California
Power Agency (NCPA), a joint powers agency the City formed in partnership with several other California publicly owned
electric utilities, with oversight by City staff.
7.2 Overview of Energy Risk Management Program
The hedging programs described above are conducted in accordance with the City’s Energy Risk Management Program,
which includes a set of Program Policies adopted by the City Council, Guidelines adopted by the City’s Utilities Risk
Oversight Coordinating Committee (UROCC), and Procedures approved by the Utilities Director. In addition, for the electric
hedging program, NCPA maintains its own Risk Management Program. The City is able to provide policy level oversight of
this program through its seat on the NCPA Risk Oversight Committee, which is held by the City’s Risk Manager.
Per the Energy Risk Management Policies, the City Council must receive quarterly reports on the City’s forward contract
purchases, market exposure, credit exposure, counterparty credit ratings, transaction compliance, and other relevant
data.
7.3 Forward Deals
Palo Alto executed the following Electric and Gas transaction in Q2 of FY 2026.
Figure 19: Electric Resource Adequacy Deals
Delivery Month Deal Type Avg RA
(MW-mo)
Price ($/kW-mo)
Jan’27-Dec’27 Purchase 0.83 $8.25
Jan’28-Dec’28 Purchase 0.83 $8.50
Jan’27-Dec’28 Purchase 36.25 $1.87
23 Staff Report #2411-3776 https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83992&dbid=0&repo=PaloAlto&searchid=72f573b6-
b169-4a0e-8991-969fbd3253be
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8.4 Electric Market Exposure
The chart below shows the City’s electric supply market exposure and committed purchases and sales to cover exposed
positions. Additional purchases and sales will be executed for FY 2026 and FY 2027 in the coming months.
Figure 20: Electric Load Resource Balance, FY 2026 – 2028
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8 Appendix B: Staffing and Vacancies
The Utilities Department has 46 vacant positions out of 269 authorized positions, or a 17% vacancy rate. CPAU attracts
qualified candidates for many recruitments. However, there are often challenges related to salary, benefits, or commute
at the offer stage. CPAU maintains a competitive stance by negotiating counteroffers depending on qualifications and
experience. For 2026, “Government Efficiency” is identified as one of City Council’s priorities. As a result, CPAU is
leveraging available and qualified internal resources between departments when opportunities or vacancies arise. The
City has also instituted a citywide Hiring Review Committee to evaluate all recruitments in relation to Council priorities
and community impacts which could delay future recruitments of non-safety or non-compliance positions.
Figure 21: Utilities Vacancies and Recruitments by Division
As of December 31, 2025
Division
Authorized
FTEs
Vacant
FTEs
Active
Recruitments Vacancy %
Administration 15 3 2 20%
Customer Service 24 2 2 8%
FTTP & S/CAP 6 4 0 67%
Resource Management 26 3 2 12%
Electric Engineering 25 4 4 16%
Electric Operations 81 19 17 23%
WGW Engineering 23 4 4 17%
WGW Operations 69 7 7 10%
Total 269 46 38 17%
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Appendix C: Wastewater Utility Annual Infrastructure Maintenance and
Replacement Report
Executive Summary
The City continues to keep up with daily routine maintenance
Sewer Main Replacement program continues as planned
Emergency Standby team continually responded to fewer calls
Infrastructure Overview
See attached for an overview of all assets. Key infrastructure replacement
efforts in the next five years include:
●Regular main replacement
●Regular manhole rehabilitation/replacement
●Regular lateral replacement
●Routine maintenance program for main, laterals, siphons and lift
station
●Routine testing/maintenance of SCADA overflow monitoring devices
System Operations and Maintenance
Total FTE’s working on Wastewater O&M.
Main
Maintenance
[2.66]
44%
Construction
[0.34]
6%
Emergency
Standby [0.75]
Main/Lateral
Inspection
[0.75]
13%
Lateral
Maintenance
[1.50]
25%
Main Maintenance Construction
Emergency Standby Main/Lateral Inspection
Lateral Maintenance
Wastewater Operations and
Maintenance
(Full-Time Equivelent [FTE] and % of total)
Asset Management Goals
What are our goals?
- Repair, rehabilitate, replace, and upgrade
system components as needed
-Maintain our ability to reliably deliver service
to our community
- Properly manage, operate and maintain the
wastewater collection system
-Keep costs down by maximizing asset life
and controlling unplanned maintenance costs
- Cost effectively minimize Inflow and
Infiltration (I/I) and provide sufficient
system capacity
- Eliminate all preventable overflows in dry
and wet weather
- Maintain an effective sanitary sewer spills
response that reduces overflow impact to
public health & the environment
- Analysis and evaluation of historical spills to
provide recommendations to reduce future
risk
- Identify system blockages due to fats, oil and
grease (FOG) and develop strategies to
decrease backups
- Provide regular training for City of Palo Alto
Utility Staff and Contractors in wastewater
collection system maintenance, operations
and emergency response
How do we achieve those goals?
-Inspect our collection system to make sure it
is flowing properly
-Make necessary repairs in a timely manner
-Replace assets as they reach end of life or as
their condition deteriorates
-Identify capacity constraints and risks to our
collection system and mitigate these issues
promptly through appropriate capital
improvement projects
-Seek ways to increase our productivity and
control costs by completing our work more
safely and efficiently
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●Main Maintenance (2.66 FTE):
o *Hydro-flushing: High Velocity hydroflushing/vacuum truck
o *Root/Grease Treatment: Heribicides, along with grease emulsifying agents are used to control root and Fat,
Oils and Grease (FOG) issues.
●Lateral Maintenance (1.50 FTE):
o *SOAP / AJAC: Preventive maintenance program includes: Sewer Overflow Alternative Program (SOAP) using an
electric power rodder and Advanced Jetting and Cleaning (AJAC) which uses a hydrojetting tool to clear systemic
sewer blockages.
●Main / Lateral Inspections (0.75 FTE): Routine field inspections of mains, laterals, siphons, manholes and other
sewer components (lift station). Process involves remote Closed-Circuit Television (CCTV) cameras and visual
inspections.
●Emergency Standby Team (0.75 FTE): consist of a standby team of 3 which includes 2 installers and a heavy
equipment operator. ERT receives calls 24/7 daily from Dispatch center and responds promptly to investigate and
mitigate sewer issues. When team is not responding to calls, the team works on Lateral Maintenance.
●Construction (0.34 FTE): Installation of new services laterals, pipe repairs, and manhole replacements.
*First priority programs critical to daily operation
●Essential maintenance programs continue as Operation’s primary routine daily task.
●Main/Lateral inspection program continues to provide Engineering Dept. with valuable pipe assessment for CIP
project inclusion.
●Aging remote overflow monitoring devices have been replaced with new reliable units for accuracy and
performance.
Wastewater Maintenance and Construction Charts
In the last 10 years, the sanitary sewer spills have noticeably decreased due to annual maintenance and biennial sewer
main and lateral replacement projects.
81
121
70 64 67
3
43
55
36
25
53
23 23 23
22 11 9 15 25
123
33
21
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Spills Median Spill Volume, gallons
Spills (By Year)
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28,495
44,968 37,952
50,783 49,006
57,083
27,610 33,155 30,681
44,222 45,064
21,645
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Flushing (Linear Feet)Goal (32,120)
Main Maintenance (2025)
292
203
152
225
270
236
175 198
45
140
89
170
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Lateral Tags
Goal (200)
Lateral Maintenance Completed (2025)
3
0
2
0
5
3
2
4 4
3
6
3
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Construction Tasks Completed (2025)
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Table 1: Status of Collection System Operation and Maintenance Programs
System
Operation or
Maintenance
Program
Status
Green = good
Orange = room
for improvement
Comments
Lateral
Maintenance
Daily SOAP/AJAC tags are completed year-long with help from standby ERT
crew members. Annual YTD goal was not met with the crew averaging 183 tags
per month. Goal is set at 200 tags/month.
Main
Maintenance
Flushing is performed on a regular schedule throughout the year. City is
keeping up with its flushing schedule. The crew fell below their goal on only
four months this year. However, the City’s YTD goal of 385,440 L.F. of mains
has been surpassed this year with City completing 470,664 L.F. of main flushing.
Main/Lateral
Inspections
(CCTV)
Operations typically work off a scheduled inspection; however, there are times
when the crew work on a list of special request CCTV inspections that tend to
postpone the current month inspections.
Emergency
Standby
Wastewater operations maintain a 24-hour system monitoring for any
emergency events. A wastewater crew has assigned to be ready for any on-
call emergencies and respond promptly to mitigate any wastewater issues at
any hour of the day or night.
Construction
(Repair
main/laterals,
new laterals)
An Operations crew is assigned the task to perform construction work for new
Development Services installations and emergency repair work for our sewer
mains and lower laterals, when work is needed and not included in our Capital
Improvement Projects (CIP).
Asset Class Quantity Maintenance Asset Condition
Manholes
(active, non-
private)
3702 Hydro-Vacuum manhole bases
for excessive debris and visually
inspecting manhole walls for I &
I, report to Engineering with
recommendations for future
replacement.
Old brick manholes are typically replaced with more
reliable pre-cast concrete structures. Over time
brick manholes introduce groundwater via cracks in
bases or wall structures.
Mains and Lateral
service
~ 207
miles of
mains,
~17,815
services
Most mains/laterals are flushed
annually, whereas some less
severe areas are flushed every
36 months. For high frequency
lines, flushing happens every 6
months.
With routine maintenance, our mains and lateral
services can be easily assessed by our Operations
crew for remaining useful life of our aging sewer
assets.
Lift Station / Force
main
1 station
/ ~900
Wastewater Operations perform
routine operational checks of the
Our lift station currently requires only minor and
routine maintenance and is in good condition
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linear
feet of
10-inch
force
main
station once a month and the wet
well is cleaned quarterly.
Preventive maintenance for
mechanical and electrical
equipment is done annually by
WGW Operations. The station has
an audible alarm and is connected
through a SCADA system to the
Utilities Dispatch Center. The
station serves approximately 25
homes and a portable generator is
available in the event of power
outages.
overall. This year, the two lift station pumps have
been rebuilt with all new parts, along with the
purchase of a new properly sized emergency
standby generator with an automatic transfer
switch (ATS). New generator and ATS shall be ready
for active deployment January/February 2026.
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11. Appendix D: PaloAltoGreen Gas Program
In December 2020, Council adopted Resolution #993025 maintaining the Carbon Neutral Natural Gas Plan to achieve
carbon neutrality for the gas supply portfolio using high-quality carbon offsets with a cost cap of $19 per ton CO2e.
Offsets are purchased to neutralize emissions equal to those caused by natural gas usage in Palo Alto. Staff procured
115,000 tons of offsets during Spring 2025 to cover FY25 usage. The figure below shows the composition of offset
purchases.
Figure 22: Offset Portfolio Composition
The following table provides a description of the projects.
25 Resolution #9930 https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=61672&dbid=0&repo=PaloAlto
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Figure 23: Offset Project Descriptions
Project Name Project Type Description
Grotegut Dairy Livestock Grotegut Dairy is a 3,900 milk-cow operation in Newton, Wisconsin with a methane capture system.
Green Trees U.S. Forest
GreenTrees Advanced Carbon Restored Ecosystem is reforestation of agricultural lands into native
hardwood forest in Mississippi, Louisiana, Arkansas, and Illinois
San Juan Lachao Mexico Forest
Protection of forests located in High Biological Value Zones which contain flora and fauna listed in the
Mexican Endangered Species List and the International Union for Conservation of Nature’s Red List of
Threatened Species. Project in San juan Lachao near Palo Alto's Sister City of Oaxaca.
Blandin Forest U.S. Forest Blandin Native American Hardwoods Conservation and Carbon Sequestration project in Minnesota.
Pocosin+ U.S. Forest
These projects are all forested land that will not be disturbed by human development. Without this
protection, the forests would be converted to grow wheat or corn. Forest conservation plays a vital role in
protecting freshwater systems like lakes. The forests around the lakes act as natural water filters and purify
the water for all who use it. The projects also support healthy populations of red wolf, bald eagle, black
bear, and various bird species.
Refex ODS Ozone Depleting Substance
The RemTec facility in Bowling Green, Ohio uses an argon arc plasma destruction device to achieve 99.99
percent removal. The majority of refrigerants originated in California, and all were sourced within the
United States.
The RemTec facility uses an argon arc plasma destruction device to achieve the required destruction and
removal efficiency of 99.99 percent. The majority of ODS refrigerants originated in California, and all were
sourced within the United States.
Methane Capture Mine Methane Capture
This project is the first of its kind. Peabody Natural Gas, LLC removed methane from the North Antelope
Rochelle Coal Mine before mining. The methane was compressed and transported to a natural gas pipeline
and distributed to a national gas grid for use as fuel. Before implementation of the project, all the methane
was vented to the atmosphere.
Virginia
Conservation
Forestry Program U.S. Forest
The Virginia Conservation Forestry Program - Clifton Farm and Rich Mountain is a 9000+ acre
improved forest management project in which the timber and carbon ownership and
management rights have been transferred to The Nature Conservancy's Conservation Forestry
Program. The program manages for multiple goals to include: Water quality protection,
habitat diversity, high value forest products, and carbon sequestration.
Co-benefits: Biodiversity, Watershed Protection, Climate Resilience, and Connectivity
Riverview Farm
Anaerobic Digester Livestock
Riverview is a carbon offset project generating emission reductions thought the capture and destruction of
methane at a dairy farm in Minnesota. Under the baseline, manure managed in open lagoons led to the
fugitive emission of methane to the atmosphere. In the project scenario, this methane is captured by an
anaerobic digester and destroyed on site in the production of electricity. Co-benefits include job creation
and the improvement of local air and water quality.
Big River / Salmon
Creek Forests IFM U.S. Forest
The Big River and Salmon Creek Forests are located in Mendocino County, CA and cover 16,000 acres of
redwood and Douglas-fir forest. This project is a conservation-based forest management project.
Co-benefits include the creation of 140 jobs, protection of 37 miles of streams, and improved water quality
for local fish and bird species.
Hiawatha
Sportsmans Club U.S. Forest
Located in Michigan’s Upper Peninsula, Hiawatha Sportsmans Club (HSC) is a member-owned 35,000-acre
forest and Michigan’s oldest certified Tree Farm. The property contains a variety of habitats: Lake Michigan
shoreline, inland lakes, spring-fed rivers, marsh, mature conifer and hardwood forest and open fields.
Supported by HSC’s sustainable forest management, these diverse habitats attract and sustain a wide
variety of birds, mammals and other wildlife.
Appalachian
Mountain Club
Maine Woods
Initiative U.S. Forest
Founded in 1876, the Appalachian Mountain Club (AMC) is the oldest outdoor conservation and recreation
organization in the U.S. By implementing sustainable management practices like deferred harvesting,
extended rotations, and the retention of standing dead wood, AMC enhances forest carbon stocks and
promotes long-term ecological health. The project sequesters carbon effectively while supporting diverse
wildlife habitats and protecting soil and water quality, all in alignment with Maine's best management
practices. Through the Maine Woods Initiative, AMC demonstrates that conservation and economic
opportunity can coexist, integrating sustainable forestry with outdoor recreation to create lasting, positive
impacts for Maine's forests and communities.
Alliance Dairy Livestock
Founded in 1876, the Appalachian Mountain Club (AMC) is the oldest outdoor conservation and recreation
organization in the U.S. By implementing sustainable management practices like deferred harvesting,
extended rotations, and the retention of standing dead wood, AMC enhances forest carbon stocks and
promotes long-term ecological health. The project sequesters carbon effectively while supporting diverse
wildlife habitats and protecting soil and water quality, all in alignment with Maine's best management
practices. Through the Maine Woods Initiative, AMC demonstrates that conservation and economic
opportunity can coexist, integrating sustainable forestry with outdoor recreation to create lasting, positive
impacts for Maine's forests and communities.
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9 Appendix E: Fiscal Year 2025 Demand Side Management Report
9.1 Executive Summary
This Demand Side Management (DSM) Report for Fiscal Year (FY) 2025 is a public document summarizing the
achievements of the City of Palo Alto Utilities’ (CPAU) customer efficiency and sustainability programs. CPAU is committed
to supporting environmental sustainability through conservation of electric, gas and water resources. Additionally, CPAU
promotes distributed renewable generation, building electrification, and electric vehicles using incentives and educational
programs. CPAU accomplishes these goals by delivering a wide range of customer programs and services as described in
this report and strives to do so while remaining in touch with customer needs.
The Fiscal Year 2025 DSM Report format is designed to highlight key performance indicators in the major areas of focus
for the City of Palo Alto’s sustainability efforts. FY 2025 marks the third year the DSM reports are included as an attachment
to the Q2 Utilities Quarterly Update provided to the Utilities Advisory Commission in April each year.
9.1.1 Summary Goals and Achievements
CPAU offers incentives and education programs for customers to encourage energy and water efficiency – Table ES.1
summarizes FY 2025 efficiency goals and achievements. The energy and water efficiency savings achieved through the
City’s energy reach code and green building ordinance are included in the table.
Palo Alto set its 10-year electric efficiency (EE) goals for 2022-2031 in 202127, and City Council updated EE goals for 2026-
2035 in 202528. For FY 2025, CPAU fell short of meeting its EE goal. There are multiple factors contributing to this
shortfall, including a reduction in large commercial projects, increasingly stringent state energy efficiency baseline
requirements, and increasing community interest in electrification projects. These factors are all indicators of a shrinking
EE market, as was identified in the EE potential study used to develop CPAU’s new 10-year EE goals. Overall, annual
electric efficiency savings continued trending up since the post-COVID lows, with around 500 MWh more savings in FY
2025 compared to FY 2024. FY 2026 will be an important year to see if this trend continues its upward trajectory,
especially given the potential impacts of the state’s 2025 changes to lighting efficiency requirements for commercial
buildings, which have historically been one of Palo Alto’s leading sources of electric efficiency savings.
CPAU has previously adopted gas efficiency goals to reduce gas use; these goals ranged from 0.5% to 1.1% gas use
reduction per year. These goals are no longer relevant and are superseded by the S/CAP goal for the building sector.
Water efficiency goals are in transition as CPAU is evaluating future demands to determine a water use target goal based
on State efficiency standards.
Table ES.1: Efficiency Goals vs. Achievements
Resource FY 2025 Savings
Goals (% of Load)
FY 2025 Savings
Achieved (% of Load)
FY 2025 Savings
Achieved
Electricity 0.60%0.20%1,847 MWh
Gas N/A 0.45%106,136 Therms
Water N/A 1.70%72,591 CCF
27 2022-2031 Electric Efficiency Goals:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=86755&dbid=0&repo=PaloAlto&searchid=5e037f24-6bd1-4aac-af50-
b496e0de7036&cr=1
28 2026-2035 Electric Efficiency Goals:
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83450&dbid=0&repo=PaloAlto&searchid=d6299e51-ee74-4a2a-8ae2-6130cfe44f86
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CPAU is committed by its own policies and State law to implementing all cost-effective energy and water efficiency
measures (i.e. those that are less expensive than supply-side resources). Table ES.2 summarizes the cost of efficiency over
the last three years compared to the projected cost of supply resources. The rolling 3-year average is a suitable metric to
track the cost effectiveness of efficiency portfolios, as it accounts for yearly variations in program engagement and
funding.
The current 3-year average cost for the electric and water efficiency portfolios are below the cost of supply resources,
demonstrating the cost effectiveness of the portfolios. The cost gap leaves room for increasing customer incentives while
maintaining overall portfolio cost effectiveness. The gas efficiency portfolio’s 3-year average cost has been pushed up due
to the high startup costs of the water heater electrification program in FY 2023, while the gas future supply cost estimate
decreased compared to last year’s projection. As a result, the average gas savings cost per therm remains above the cost
of future supply. The gas efficiency portfolio should become more cost effective on a per therm basis as electrification
programs continue to expand offerings and enrollments, particularly in the nonresidential sector. Also, as electrified
technology markets mature, the level of monetary support needed to incentivize adoption should decrease.
Table ES.2: Actual Levelized Efficiency Costs vs. Projected Supply Costs
FY 2023
Efficiency
FY 2024
Efficiency
FY 2025
Efficiency
3-yr Average
Efficiency
Future
Supply
Electricity $/kWh $0.13 $0.04 $0.02 $0.06 $0.13
Gas $/Therm $4.02 $1.25 $1.75 $2.34 $1.07
Water $/CCF $1.53 $2.12 $0.97 $1.54 $7.36
10.2 Electric Efficiency
CPAU offers both residential and non-residential programs that target EE improvements for customers. Every year CPAU’s
energy efficiency program details are published by the California Municipal Utilities Association (CMUA)31 as required by
California Senate Bill 1037. Table 1 contains a high-level summary of FY 2025 electric program savings and expenditures,
as well as the EE savings target.
Table 1: FY 2025 Electric Efficiency Metrics
Electric Efficiency
MWh Reduced 1,847
$ Spent $285,950
Cost of Efficiency ($/kWh)$0.02
Total MWh Load 911,001
Savings (% of Load)0.20%
Savings Goal (% of Load)0.60%
31 SB 1037 Status Reports: https://www.cmua.org/sb1037-reports
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CPAU fell short of its FY 2025 EE savings goal for a variety of reasons, the most impactful of which being the shortage of
large commercial EE projects. Large commercial EE projects have historically been the backbone of CPAU’s EE savings, and
many of the quick win opportunities like efficient lighting have already been completed by engaged businesses or have
been made redundant by stricter state baseline requirements. Electrification has also been an increasing focus to push
Palo Alto towards its sustainability goals. The FY 2025 electric efficiency savings indicate that CPAU is likely on track to
achieve its FY 2026 goal of 0.24% of annual load, which was adopted based on an updated 2025 EE potential study that
accounted for current energy efficiency program and market conditions.
Figure 1: Cumulative Net Electric Efficiency Savings
33. Some savings will still be claimable for early replacement projects
or high efficiency LED installation, but likely much less than current and historical savings levels.
33 CA AB 2208: Bill Text - AB-2208 Fluorescent lamps: sale and distribution: prohibition.
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Figure 2: Composition of Net Electric Efficiency Savings in FY 2025
10.3 Gas Efficiency and Electrification
CPAU has previously adopted gas efficiency goals to reduce gas use; these goals ranged from 0.5% to 1.1% gas use
reduction per year. These goals are no longer relevant as they are superseded by the S/CAP (Sustainability and Climate
Action Plan) goal to reduce GHG emissions from the direct use of natural gas in Palo Alto’s building sector by at least 60%
below 1990 levels by 2030. Rather than continuing gas efficiency rebates and services to support the installation of new
gas equipment that would remain in place for the next decade or longer, CPAU replaced traditional gas efficiency rebates
with technical assistance and rebates to help customers with the transition away from gas equipment. Building envelope
improvements will remain a program priority to ensure comfort for building occupants and to avoid oversizing of all-
electric heating, ventilation and air conditioning (HVAC) equipment.
Table 2 contains a summary of FY 2025 program gas savings through electrification or efficiency projects. CPAU focused
initial residential electrification efforts on water heating, but in FY 2025 expanded its rebate offerings to include residential
heat pump HVAC electrification projects. CPAU is also expanding outreach and programs to facilitate nonresidential heat
pump HVAC installation. The majority of other gas savings in FY 2025 came from a large industrial kitchen electrification
project.
In FY 2025, the cost per metric ton (MT) of GHG avoided was $330, compared to CPAU’s long term goal of spending less
than $200/MT GHG avoided. The cost was high in FY 2025 due to a combination of factors including low gas reduction
relative to the fixed costs of program operation for early electrification programs. CPAU anticipates that the cost per MT
GHG avoided could stay above the target in the near future due to the expansion of pilot programs that are designed to
Non Res Lighting
87%
Non Res HVAC
10%
Non Res Codes &
Standards
2%
Res Lighting
1%
Total Electric Savings by Sector and End Use
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kickstart the electrification market in Palo Alto. Key focal points for reducing avoided GHG costs will be further tapping
the commercial electrification market with potential for greater gas savings per unit, increasing electrification program
participation to spread out fixed costs, and reducing incentive levels as technology markets mature. For reference, the
current cost of direct air carbon capture ranges from $500-1000/MT CO235, so even these electrification programs
continue to be more cost effective than the carbon sequestration alternative.
Table 2: FY 2025 Gas Efficiency and Electrification Metrics
Gas Efficiency and Electrification
35 Energy Solutions Intelligence, “Direct Air Capture in 2026: Cost, Scale, and Path to $200/tCO2”: https://energy-solutions.co/articles/sub/carbon-
capture-direct-air-dac-cost-analysis
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Figure 3: Historical Gas Usage and Savings
As illustrated in Figure 4, 40% of CPAU’s gas reductions in FY 2025 can be attributed to the electrification of residential
water heaters through CPAU’s heat pump water heater programs. In FY 2025, CPAU offered boosted incentives for
nonresidential HVAC electrification projects, which contributed another 40% of CPAU’s gas savings portfolio. The
remaining 20% of gas reductions come mainly from a large industrial kitchen electrification project, alongside a small
chunk of savings from nonresidential water heating electrification and other end uses like residential HVAC electrification.
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Figure 4: Composition of Natural Gas Use Reduction in FY 2025
10.4 Water Efficiency
The City partners with the Santa Clara Valley Water District (Valley Water) to provide water conservation rebate programs
and resources. Valley Water administers the programs for Palo Alto customers, and CPAU provides additional funds to
increase rebate amounts. CPAU markets and promotes the programs through all media channels. The State Water
Resources Control Board (SWRCB) adopted regulations to implement the Water Conservation as a Way of Life legislation
(AB 1668 & SB 606). CPAU is evaluating future demands to determine a water use target goal based on State efficiency
standards. The standard takes into account residential indoor and outdoor use, commercial irrigation use, and water loss.
Palo Alto’s S/CAP includes a goal of completing a One Water Plan to evaluate alternative water supplies and additional
conservation measures to make the City’s water supply more resilient. The One Water Plan was completed and shared
with Council in October 2025.
CCF Water Reduced 72,591
$ Spent $70,270
Cost of Efficiency ($/CCF)$0.97
Total CCF Load 4,274,539
Savings (% of Load)1.70%
Savings Goal (% of Load)N/A
Non Res HVAC
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Res Water Heating
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Non Res Cooking
16%
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Heating
3%
Other
1%
Total Gas Reduction by Sector and End Use
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Figure 5 illustrates the City’s historical total water usage and savings. In FY 2025 CPAU programs yielded above average
water savings and total usage was around 125,000 CCF higher than FY 2024. In FY 2025, Palo Alto’s water savings were led
by the Water Efficient Technology (WET) Rebate Program, followed closely by savings from weather-based irrigation
controllers. Palo Alto’s water usage is expected to continue its downward trend over the long term as the city navigates
water efficiency and water waste restrictions.
Figure 5: Historical Water Usage and Savings
10.5 Electric Vehicles
Table 4: Electric Vehicle and Charger Metrics
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The average utilization rates, total utilization, and number of installed city owned EV chargers all continued to grow in FY
2025. CPAU programs also supported installation of the largest yearly number of EV chargers to date throughout the city,
providing charging access to over 500 additional multifamily units, bringing the cumulative total to 982 units.
Figure 6 highlights the evolution of EV adoption in Palo Alto compared to our S/CAP transportation electrification target.
2025 annual data has been requested from the DMV and will be updated in the next DSM report.
Figure 6: EV Adoption and Forecast vs. 2030 Target
S/CAP 2030 Target
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10.6 Solar and Storage
Solar-plus-storage systems generally consist of a solar array connected to a battery storage system. These systems allow
solar energy to be deployed both day and night, making the electricity grid more resilient to changes in demand. Rooftop
solar-plus-storage systems also provide resiliency by providing backup power during power outages or public safety power
shutoff events. The City participates in Bay Area SunShares – a group-buy program that offers discounts and vetted
contractors for installing rooftop solar and battery storage systems. In FY 2025, there were 3 residential solar installations
and 1 storage installation completed through the SunShares program.
At the end of FY 2025, PV installations in Palo Alto totaled 1,768, with 1,649 residential, 113 non-residential, and 6 Clean
Local Energy Accessible Now (CLEAN) projects installed since CPAU began supporting local solar PV installations in FY 2000.
These customer-side generation systems represent 20.2 megawatts (MW) of generating capacity and are not included in
CPAU’s Renewable Portfolio Standard (RPS) supply requirements. In FY 2025, CPAU customers installed 198 new solar
systems (193 residential and 5 non-residential) with a total 1.6 MW of additional capacity. It is important to note that
CPAU is currently undergoing a transition in tracking, recording, and verifying solar and storage data. As a result, some of
the data in this FY 2025 report may not align exactly with previous years.
Figure 7: Photovoltaic (PV) Cumulative Installations
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Res 859 941 1,029 1,092 1,149 1,160 1,167 1,271 1,456 1,649
Non Res 58 71 84 96 97 98 99 102 108 113
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Total 917 1,012 1,118 1,193 1,252 1,264 1,272 1,379 1,570 1,768
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Figure 8: PV Cumulative System Capacity (kW)
As of the end of FY 2025, there were 194 battery storage installations with a total estimated capacity of 1.8 MW, all of
which were in the residential sector. In FY 2025, CPAU customers installed 57 new storage systems with an estimated 431
kW of additional capacity.
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Non Res 4,313 4,976 6,701 7,815 7,834 7,870 7,876 7,956 8,254 8,457
CLEAN 0 0 1,588 1,588 2,841 2,841 2,841 2,841 2,841 2,841
Total 7,936 9,005 12,799 14,284 15,883 16,012 16,072 16,871 18,651 20,212
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Approved By:
Alan Kurotori, Director of Utilities
Staff: Tim Denterlein, Resource Planner
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Utilities Advisory Commission
Staff Report
From: Alan Kurotori, Director Utilities
Lead Department: Utilities
Meeting Date: March 31, 2026
Report #:2603-6142
TITLE
Approval of the Minutes of the Utilities Advisory Commission Meeting Held on March 4, 2026
RECOMMENDATION
Staff recommends that the Utility Advisory Commission review and approve the March 4, 2026
minutes.
Commissioner ______ moved to approve the draft minutes of the March 4, 2026 meeting as
submitted/amended.
Commissioner ____ seconded the motion
ATTACHMENTS
Attachment A: March 4, 2026 Draft Minutes
AUTHOR/TITLE:
Alan Kurotori, Director of Utilities
Staff: Rachael Romero, Program Assistant I
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UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF MARCH 4, 2026 REGULAR MEETING
CALL TO ORDER
Chair Scharff called the meeting of the Utilities Advisory Commission (UAC) to order at 6:00 p.m.
Present: Chair Scharff, Vice Chair Mauter, Commissioners Croft, Gupta, Metz, Phillips, and
Tucher
Absent: None
AGENDA REVIEW AND REVISIONS
None.
ORAL COMMUNICATIONS
1. Kanami T. expressed that she was pleased with the work that UAC is doing and
expressed excitement for the Induction Water Program and Rebate Program.
2. Sven T. asked the Commission to recommend that the Utility Department focus
on the health effects of natural gas stoves.
3. Dave W. suggested that when the UAC selects the new Chair, they ask
candidates about their plans to improve the commission’s effectiveness.
4. Prisha agreed with the other public commenters.
APPROVAL OF THE MINUTES
ITEM 1: ACTION: Re-Approval of the Minutes of the Utilities Advisory Commission Meeting Held
on December 3, 2025
ITEM 2: ACTION: Approval of the Minutes of the Utilities Advisory Commission Meeting Held on
February 4, 2026
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MOTION: Commissioner Croft moved, seconded by Commissioner Phillips, to approve the
minutes of the December 3, 2025 meeting and February 4, 2026 meeting.
MOTION PASSED: 7-0
UNFINISHED BUSINESS
UTILITIES DIRECTOR REPORT
Alan Kurotori, Utilities Director, reported City Council approved the Fiscal Year 2026 UAC Work
Plan. Council approved contracts for procuring equipment for upgrades of the Maybell electric
substation and professional services for a new three-year water leak detection survey in
February. City Council approved the Sustainability and Climate Action Work Plan on Monday,
heard from Terry Crowley, Chief Operating Officer, on the Reliability and Resiliency Plan, and
received feedback from City Council. Director Kurotori acknowledged Councilmember Lauing for
suggesting having a UAC commissioner present at the Council meeting and Commissioner Croft
for attending the meeting. The City has rolled out a full-service single-family residential home
heat pump/water heater program and expansion for a turnkey home electrification program. On
February 26, the City began offering a fixed price appliance and expert assistance for electrifying
homes including space heating, water heating, cooking, clothes drying, and energy efficiency
improvements. Residents will be able to take advantage of existing rebates, technical assistance,
and can sign up for the Go Green financing program. There is interest in looking at data centers.
Staff will share some of the scenario analysis that was performed by the consultants and bring it
back to the full UAC for discussion. The department participated in the city’s Discover Your Career
Path fair for youth that was held February 28.
NEW BUSINESS
ITEM 3: ACTION: The Utilities Advisory Commission Recommend that the City Council Adopt a
Resolution Approving the Fiscal Year 2027 Water Utility Financial Forecast and Reserve Transfers,
and Amending Rate Schedules W-1 (General Residential Water Service), W-2 (Water Service From
Fire Hydrants), W-3 (Fire Service Connections), W-4 (Residential Master-Metered and General
Non-Residential Water Service), and W-7 (Non-Residential Irrigation Water Service). CEQA
Status: Not a project.
Adriana Artola, Senior Resources Planner, provided a slide presentation including water rate
projection FY 2027, FY 2027 proposed budget reductions, water bill comparisons, FY 2027 rate
increase drivers, water cost and revenue projections, water operations reserve projections,
water CIP reserve projections, water reserve projections, cash on hand and credit ratings, water
conservation programs and ways to save, communication and outreach, and Staff
recommendations.
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Public Comment
1. Peter D. showed slides depicting the historic and projected wholesale rates,
comparison of water demand scenarios, baseline demand projections,
residential per capita, and expected population increase.
2. Dave W. discussed advancing Palo Alto's water priorities by playing a
leadership role within BAWSCA; supporting Councilmember Stone; exploring
alignment between Staff, UAC, and City Council; the importance of having the
Urban Water Management Plan project a declining balance; and following up
on the questions Councilmember Stone asked of the San Francisco Public
Utilities Commission (SFPUC).
Commissioner Tucher asked about the 6.9 percent mentioned by Mr. Warner. Senior Resources
Planner Artola replied there was a drought the same time rate increases were implemented
that affected revenues. The 6.9 percent number is accurate.
Commissioner Gupta wanted to vote no or continue the item until May because of the
commodity rate trajectory underlying the forecast. The plan does not account for the structural
changes happening across the regional water system. Concern was expressed about the SFPUC
not answering the questions posed in Councilmember Stone's letter. It was suggested that
Council not act on rates until June. A study session should be held in April or May where SFPUC
and BAWSCA come before the Committee and give an honest picture of where wholesale rates
are heading.
Lisa Bilir, Assistant Director, clarified when water rates are presented, the full impact is shown
on the customer's bill. It is 10 percent when combining the SFPUC increase with the distribution
increase. Council is being asked for a change in the distribution rate because it passes through
the SFPUC rate increase to customers. Vice Chair Mauter asked if that is equivalent to the gas
commodity charge. Assistant Director Bilir replied it is a different process but it is similar to the
gas commodity charge passed through to consumers.
Chair Scharff inquired why 15.9 is the rate being moved to but 14 is the reserve amount. Senior
Resources Planner Artola stated it is hard to get the reserve amount right at the reserve target
while maintaining a smooth rate trajectory. In fiscal year 2028, the reserve balance goes back
down. There is a fluctuation in the balance that has to do with smoothing rate increases and
changes in spending year to year. Chair Scharff observed 4.2 percent is restoring operating
reserves. A lower rate increase could be utilized if there is desire to restore less reserves.
Commissioner Phillips asked for clarification about a transfer of 5.5 million from the operating
reserves to CIP. Senior Resources Planner Artola responded for fiscal 2027, CIP and operating
expenses came down. This allowed an opportunity to add to reserves. Maintaining a 10 percent
rate increase for fiscal 2027 allows for a smoother rate trajectory in the future years. If the rate
increase is lowered in fiscal 2027, that could require a higher rate increase in later years to
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recover revenue when spending more on CIP. A rate increase is being deferred and starting off
with a lower based period in the following year. The focus is on 2027. The recommendation is
to approve the financial plan. Rates are updated yearly. If the water fund outperforms fiscal 27
resulting in higher reserves, the rate trajectory can be adjusted more. Chair Scharff asked what
information has been provided on the CIP that shows a need for that. Senior Resources Planner
Artola provided a slide detailing projects. Director Kurotori agreed there is some uncertainty
but efforts are being put into what the costs would be including capital cost. Commissioner
Phillips asked for clarification on the amounts shown on the slide. Senior Resources Planner
Artola said the first line is the design cost for the seismic improvements to the reservoirs.
Director Kurotori added it is the money intended for the engineering assessment. The water
utility's last master plan is more than 20 years old so an evaluation of the system is due in terms
of its hydraulic capacity and needs and helps better define some of the capital projects. Chair
Scharff inquired what difference it will make if that plan is not done and if it is worth the
money. Director Kurotori stated it is also updating the hydraulic model. It is a tool that will
ensure development is paying their share for the connection to the system.
Chair Scharff queried what is being done at Arastradero Creek. Director Kurotori answered after
the floods and storm events in the foothills, some pipelines were undermined. This is the
mitigation to do full replacement and restoration.
Vice Chair Mauter asked about project 30. Director Kurotori replied those are the watermain
replacement programs.
Vice Chair Mauter wanted to understand the origins of the variance on slide four. Senior
Resources Planner Artola replied it could be related to the age of the system, the infrastructure
needs, and what the capital plans look like.
Vice Chair Mauter requested a benchmark for the inflation in routine services associated with
the water utility to benchmark the efficiency of operations versus the cost of required outside
contracted services. Assistant Director Bilir provided slide 26 outlining the consumer price index
of urban consumers.
Vice Chair Mauter asked if there is a handle on what the nonrevenue water is and the degree to
which that is driving costs. Senior Resources Planner Artola provided a slide on real water loss.
Real water loss was 1.8 percent for 2024. That was about $500,000 that was not passed
through to customers.
Vice Chair Mauter stated a cost-of-service study is overdue and encouraged honing in on the
cost of service to different pressure zones across the service area. Vice Chair Mauter wanted to
make sure Palo Alto is prepared for the set of legal rulings that surround Prop 218's challenge
to tiered rates and an analysis of what would happen if tiered rates became illegal. There is a
need to be clear about what the operational and capital reserves are intended to do.
Commissioner Tucher asked what an operational reserve is and why they should be separate.
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Commissioner Phillips stated the commissioners are asking for an understanding of the reserve
policy across the utilities. Chair Scharff wanted to understand the necessity of the CIP stuff.
Director Kurotori mentioned pay-as-you-go has been looked at for capital projects. There was a
study about looking at the need for tank replacement. Part of the master plan is looking for
total storage. Vice Chair Mauter stated more information would be helpful for these kinds of
documents. Director Kurotori mentioned the UAC had a subcommittee look at water and
electric rates. The water utility reserve management practices are embedded into the packet
and talks about the reserves and the policies associated with that. The City is looking at the
reserve policies citywide. That report is coming some time this year. Some of the bonds are
finishing up and that is reflected in the rates. It is standard practice to bond on the value and
benefits and certainty of the utility receiving the bond.
Commissioner Metz wanted discussion about the increase in distribution costs on slide six.
Senior Resources Planner Artola replied the distribution rate increases are to fund the City's
water utility. The rate increases reflect the rate drivers. The budget includes ways to reduce the
operating expenses. It is an ongoing process. Assistant Director Bilir added the distribution rate
trajectory on table one pay for all of the CIP. The distribution rate in table one is not separated
into capital and operating. The reserve transfer is a one-time event. The Commission can
recommend a different or no transfer. The distribution costs will remain the same. The
distribution rate pays for distribution operation costs and distribution capital costs.
Commissioner Metz wanted to understand the rate increases indicated on table one after 2027.
Commissioner Tucher opposed the wholesale rate increase and wanted the Staff's
understanding of how SFPUC works. Assistant Director Bilir stated there is a contract with
SFPUC that requires them to provide 30 days of notice of their rate increase. The rate increase
hearing is typically done in May. In December or January, a courtesy estimated range for the
rate increase is provided. This year, the letter indicated the range was between 6 and 9
percent. In February, there is a wholesale customer meeting to provide an updated estimate.
BAWSCA does a full audit of the revenue requirement costs every year. The rate increase is
driven by the demand regionally. There is a balancing account that tracks any over or under
recovery of funds from wholesale customers. That account has been drawn down throughout
the drought. Money is owed to that account adding to the rate increase.
Commissioner Phillips suggested focusing on the issues about next year and the way the costs
are being structured and separate things that can be done to nudge SFPUC in the future. Chair
Scharff agreed. The pass-through will have to be done. Commissioner Tucher stated voting yes
to the 10 percent sends an advisory message to Council. Voting no sends a different message.
Chair Scharff wanted to understand the 10 percent increase. Assistant Director Bilir explained it
is on all the services. The distribution rate is a 12 percent increase on all the distribution rates
combined with the pass-through change to the commodity rate which is 7.4 percent. The
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combined impact on a median residential bill is 10 percent. Depending on the amount of water
used and different features, it can vary.
Commissioner Croft indicated the Finance subcommittee discussed the CIP budget, places the
utilities worked to save money on operations, and the surprise in the SFPUC rate. The
commissioner had issues with the large distribution cost increase for 2027 but would vote yes.
There are issues with SFPUC visibility.
Chair Scharff wanted opinions on having Staff come back with a study session about the rate
drivers, financial forecast, what the reserves look like, and the CIP. Vice Chair Mauter thought a
detailed discussion could be held after the master plan and cost of service study had been
finished. Director Kurotori advised the master plans look at the entire system. They provide a
CIP recommendation over a 5 to 10-year timeline. There is a plan to look at the age and size of
the system and water main replacements that are still needed. Director Kurotori suggested
completion of the engineering evaluation and recommendations for the repair, replacement,
and seismic retrofit of those two tanks would help inform those discussions. Vice Chair Mauter
stated coming back and seeing a finished master plan would be an opportunity to have a cost
savings discussion. The vice chair also wanted to see a complementary cost of service study to
provide an understanding of how to fairly allocate the costs of providing water to the City's
residents.
Commissioner Phillips expressed concern about what is driving the reserves. Director Kurotori
stated those covenants talk about multiple utilities. Staff is looking at the potential to save
money by refinancing those bonds. They might bring something back to see if there can be
additional cost savings.
Vice Chair Mauter summarized stating a detailed look at operational costs is needed going
forward. The Commission and city staff were not prepared to have that conversation due to a
lack of information around a master plan. The vice chair wanted to approve this year's cost
increases in terms of distribution rates and table the out-year projections for when a legitimate
conversation could be held. That should be agendized on the 12-month calendar.
Commissioner Croft wanted to assign someone to go to the Finance Committee meeting when
these rate proposals will be presented. Commissioner Phillips agreed to go.
Vice Chair Mauter stated it is important to make sure the emergency preparedness factor is
well addressed when having discussions about reserves and wanted policy around reserves and
discussion of the quantity of reserves.
MOTION: Chair Scharff moved, seconded by Commissioner Gupta, to recommend that the City
Council
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1. Not Approve the Fiscal Year 2027 Water Utility Five-Year Financial Forecast shown in
this staff report and attachments.
MOTION PASSED: 7-0
MOTION: Vice Chair Mauter moved, seconded by Commissioner Phillips, to recommend that
the City Council
2. Approve a reserve transfer of up to $5,500,000 from the Operations Reserve to the CIP
Reserve in FY 2026.
MOTION PASSED: 5-2 Tucher, Gupta no
MOTION: Commissioner Phillips moved, seconded by Vice Chair Mauter, to recommend that
the City Council adopt a resolution to
3. Increase Water Utility Rates for FY 2027 by 8 percent to reflect increases effective July
1, 2026 (FY 2027): by reducing the amount going to the operation reserves by
approximately 1.2 million from the proposed amount
a. W-1 (General Residential Water service)
b. W-2 (Water Service from Fire Hydrants)
c. W-3 (Fire Service Connections)
d. W-4 (Residential Master-Metered and General Non-Residential Water Service), and
e. W-7 (Non-Residential Irrigation Water Service)
MOTION PASSED: 5-2 Tucher, Gupta no
ITEM 4: ACTION: The Utilities Advisory Commission Recommend that the City Council Adopt a
Resolution Approving the Fiscal Year 2027 Wastewater Collection Utility Financial Forecast, and
Amending Rate Schedules S-1 (Residential Wastewater Collection and Disposal), S-2 (Commercial
Wastewater Collection and Disposal), S-6 (Restaurant Wastewater Collection and Disposal), and
S-7 (Commercial Wastewater Collection and Disposal – Industrial Discharger); CEQA Status: Not
a project under CEQA Guidelines Section 15378(b)(5)
Eric Wong, Resource Planner, provided a slide presentation including wastewater collection
rate projections, FY 2027 proposed budget deductions (wastewater), wastewater bill
comparisons, FY 2027 rate increase drivers, wastewater cost and revenue projections,
wastewater operations reserve projections, wastewater CIP reserve projections,
communications and outreach, and Staff recommendations.
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Commissioner Gupta asked about the independent contributions of each category to the cost
projection. Resource Planner Wong presented a slide that explained the drivers contributing to
the increase in the forecast. Aaron Gilbert, Palo Alto Regional Water Quality Control Plant
Manager, explained that the major drivers are aging infrastructure and construction for
nutrient removal that has been mandated by the state. Increasing projects and staff increases
also contribute. Commissioner Gupta inquired what percentage included aging infrastructure
and construction. Resource Planner Wong will get that information.
Commissioner Croft queried about the criticality of capacity fees. Resource Planner Wong
replied the budget has an anticipated $9.4 million capacity fee related to new developments,
mostly multifamily. Staff is conservatively projecting only 80 percent of that and splitting it over
a 5-year period starting in 2028. As those funds come in, revenue adjustments will be done.
Commissioner Croft asked what the risk is. Resource Planner Wong stated $1.5 million per year
of revenue is projected from capacity fees spread over 5 years due to uncertainty of the timing
of the project.
Commissioner Croft had questions about the timeline of the projects. Assistant Director Bilir
responded that information is included in the quarterly report. Gilbert added they are in the
middle of the secondary treatment upgrade. It is a $192 million project that is split between the
6 partner agencies for cost. It should be fully up and running in 2029. A $16 million project
called the primary treatment upgrade was completed last year. A $12 million project has just
been signed for. The first phase of the 12kV program upgrade was completed last year. The
Headworks program is in the design process. A $60 million advanced water purification station
is in the beginning stages of construction, mostly paid for by Valley Water and Mountain View.
Commissioner Croft asked if they are working on projects they are servicing the debt on. Gilbert
replied that some of the smaller projects have been able to utilize minor CIP. There was one
loan for the primary sedimentation tank. There was a State Revolving Fund (SRF) loan for the
$192 million project for the Secondary Treatment Upgrade (STU). They will not have to start
paying that back until the project is completed in 2029. Assistant Director Bilir provided a slide
with more details. Commissioner Croft asked if they already have the money they will start
paying in 2030. Assistant Director Bilir's understanding was that the loan is at a very good
interest rate. When receipts are submitted, the state reimburses the funds. Vice Chair Mauter
asked what the rate is on the SRF loans. Gilbert answered the one for the STU is 0.8 percent.
Commissioner Phillips observed the rates are charged by connection for residential but
volumetric for commercial and restaurant. Resource Planner Wong said the prior year's winter
average is used for commercial. Restaurant is monthly based on their volumes. Commissioner
Phillips inquired if a cost of services analysis has been done. Assistant Director Bilir responded
the latest cost of service study was in 2021. That can be looked at when returning to
wastewater for cost of service. Director Kurotori added there is a connection and capacity fee.
The residents are not paid a volumetric charge. It will be reassessed in terms of the loadings
and estimates of the flows when the cost of service study is done. Commissioner Phillips asked
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if flows have been increasing or decreasing over time. Gilbert replied it is down compared to 15
years ago. It is up from COVID. Commissioner Phillips asked about the processing charge.
Gilbert answered one part is the cost share which is the capital. There is also the flow and
loading based. That fluctuates each year.
Commissioner Croft wondered if there are reasons to try to manage stormwater better. Gilbert
stated flows are normally about 18 million gallons per day and can jump to 40 million gallons
per day after a storm. Most cities have influx and infiltration (I&I) that increases the total flow
volume over the year. Commissioner Croft wondered if that has ever been a City initiative.
Director Kurotori explained the inflow and infiltration during high wet weather goes into the
sanitary sewer system. There is a separate storm drain system that collects rainwater that goes
into the gutters and goes into the creeks and bay. There could be connections where a resident
may have connected into the sewer from the storm. It can come from events where there is
flooding. People could be popping manholes to get rid of the flow creating a surge into the
sanitary sewer system. It could happen as inflow into the pipeline. Sewer condition assessments
are done. The City has switched to high-density polyethylene pipe so there is less I&I. It is still
an issue for sewer and storm drain systems in general when there is high groundwater.
Nuisance groundwater levels can impact the I&I going into the sewer system. There is value in
tightening up the pipes and system. Gilbert added it is not part of their scope to track who has
I&I. Director Kurotori said part of the I&I is the nuisance groundwater levels. Some pipes close
to the bay can get saltwater intrusion affecting the salinity. Gilbert said there is a significant
difference between the wet and dry seasons. Better managing the stormwater would help the
Operations and Maintenance (O&M) treatment process during the year and lower the O&M
cost. Commissioner Croft asked if the change of material on the pipes will lower this over time.
Director Kurotori explained the pipeline rehab could be full replacement with high-density
polyethylene pipe or a slip lining in areas with cracks or breaks. That is part of the condition
assessment. Commissioner Croft asked about draining swimming pools. Director Kurotori stated
swimming pools should be drained into the sanitary sewer.
Commissioner Tucher inquired if Palo Alto is the lowest monthly residential wastewater city
district as indicated on slide four. Director Kurotori stated compared only to the agencies on
that slide. Commissioner Tucher found the analysis of FY25 confusing. Assistant Director Bilir
stated there is a misplaced comma and it should not say approximately 1.9 million. It will be
reworded. Commissioner Tucher did not see the point in discussing FY25 and urged improving
the write-up. The commissioner had questions about the master plan. Gilbert said the
treatment plant is currently going through an updated master plan. One was done in 2012 and
Headworks is the last project being finished from that. An updated long-range facility plan is
currently being done. Director Kurotori stated there was in update to the sewer master plan in
November tying into flow metering into the system and updating the sanitary sewer hydraulic
model. That information will be integrated into the system. The master plan will have
recommendations for CapEx, capital projects, and tie into areas looking at capacity. That has to
be prioritized in terms of what areas have capacity limitations, wet weather flows, and pipe
condition assessments.
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Chair Scharff asked what percentage of costs are caused by regulation increases and having to
rebuild the water treatment plant. Gilbert will get the information. The secondary treatment
project is based because of biological nutrient removal necessities. That process is the reason
for the STU upgrade. That project is $192 million divided by the capital capacity for each agency
and is driven by the regulations. Assistant Director Bilir presented slide six to break down the
rate increase drivers. Gilbert indicated aging infrastructure as one of the biggest drivers. Chair
Scharff observed a $30 increase before 2029 with 6 percent. Assistant Director Bilir confirmed
that to be right. Chair Scharff asked about the confidence of not going into double digit
increase. Assistant Director Bilir stated attempts to identify uncertainties that would go into the
forecast are being made.
Vice Chair Mauter indicated a need to establish a stronger line of communication between the
UAC and Public Works. There could be a committee to focus on what is happening at the
wastewater facility and ensuring the impact the operational changes and capital upgrades are
going to have on rates are well understood by the Committee. Director Kurotori replied the
UAC looks at all the rates for the utilities. The wastewater treatment plant is a component but
is not under the scope of the UAC. It is under the purview of the Public Works Department.
Gilbert explained there are six partner agencies each with a fixed share capacity. Mountain
View and Palo Alto are the two largest. When it was created in 1968, it was decided that Palo
Alto would be in charge of the facility. Kiely Nose, Assistant City Manager, explained this falls
under the Public Works Department which falls under the city manager's authority. There is no
specific commission, committee, or board associated with it. The work associated with it goes
through the appropriate Council committee, whether it be Policy and Services or Finance
Committee, and then to the full Council. There is a non-governance structure that happens
before those two which is coordinating with all the partners. They have partner meetings on a
routinized basis.
Vice Chair Mauter asked about efficiency for electrical usage and storage. Gilbert stated work is
being done on an energy evaluation at the plant.
Vice Chair Mauter asked for clarification that the current upgrades will fully cover the 2035 and
going forward regulations. Gilbert confirmed they will and there will be the capacity to intensify
the process if necessary. Vice Chair Mauter wanted to know if there are discussions about Palo
Alto participating in nutrient markets or engaging in bilateral trade agreements with other cities
to help offset the capital costs. Gilbert answered there are not active talks but people are
starting to talk.
MOTION: Vice Chair Mauter moved, seconded by Commissioner Croft, to recommend that the
City Council adopt a resolution (Attachment A):
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1. Approving the Fiscal Year 2027 Wastewater Collection Utility Financial Forecast shown
in this staff report and attachments; and
2. Amending Rate Schedules (Attachment A, Exhibit 1) effective July 1, 2026 (FY 2027):
a. S-1 (Residential Wastewater Collection and Disposal)
b. S-2 (Commercial Wastewater Collection and Disposal)
c. S-6 (Restaurant Wastewater Collection and Disposal); and
d. S-7 (Commercial Wastewater Collection and Disposal – Industrial Discharger)
MOTION PASSED: 6-1 Gupta no
FUTURE TOPICS FOR UPCOMING MEETINGS
Director Kurotori pointed out adjustments to the 12-month rolling calendar. The election of UAC
chair and vice chair will be pushed to May. The Urban Water Management Plan will be discussed
in May with the intent to bring to full Council in June.
Commissioner Gupta asked if there is an option to push the UAC work plan back to let the current
work plan work itself out. Director Kurotori stated it will be the new process for the annual work
plan. The earliest time frame is the month after the chair is seated. It is possible to push it further
out if the Commission wants to.
Commissioner Tucher asked for comments on how the Council discussion went on the work plan.
Director Kurotori said there were three work plans from Community Development with lengthy
discussions. Director Kurotori indicated Councilmember Burt had comments on the Reliability
and Resiliency Plan that went to Council on Monday.
Commissioner Metz thought it would be important to address data centers as part of the grid
mod project updates scheduled for July. Director Kurotori said that would be brought back to the
Affordability subcommittee to look at electric rates and that will be reported out at the next
meeting.
Commissioner Metz talked about the importance of having a strategic discussion of the gas
transition study. Director Kurotori indicated that may be something to put into the work plan.
The Sustainability and Climate Action Committee is also looking at the gas utility in terms of
potential carbon tax. Part of the gas transition plan is updating the modeling associated with that
and is a work in progress.
Commissioner Phillips wanted a report on the FTTP pilot report. Director Kurotori would reframe
it as information on the costs and a pickup of customers. A more definitive plan will be brought
back.
Commissioner Tucher stated it would be good to hit the high points about what was about
wastewater when the plan is finished in the Director's Report. Director Kurotori agreed.
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Commissioner Croft wanted a time of use update in the Director's Report and asked if the
discussion of long-term electricity outage plan would be brought back. Director Kurotori
indicated a time of use report will be brought back as an action item.
Commissioner Gupta observed it will be helpful to have a discussion on what is advertised in the
bill inserts and gas safety pamphlet in terms of stovetops when gas is discussed again. Director
Kurotori said Council took an action in terms of the Climate Action Plan and would like to include
some of that information.
COMMISSIONER COMMENTS AND REPORTS FROM MEETINGS/EVENTS
Commissioner Metz appreciated the informational report on residential electric and water
customer satisfaction surveys. The commissioner observed there has been no action since 2018
regarding the informational report on sampling of water microplastics and asked if something
should be done about that. Director Kurotori will provide that as an update to the work plan.
ADJOURNMENT
Adjournment: The meeting was adjourned at 10:05 p.m.
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Utilities Advisory Commission
Staff Report
From: Alan Kurotori, Director Utilities
Lead Department: Utilities
Meeting Date: March 31, 2026
Report #: 2511-5447
TITLE
Staff Recommends the Utilities Advisory Commission Recommend that the City Council Adopt a
Resolution Approving the FY 2027 Electric Financial Forecast, Approving a Reserve Transfer, and
Amending Electric Rate Schedules E-1 (Residential Electric Service), E-1 TOU (Residential Time
of Use Electric Service), E-2 (Residential Master-Metered and Small Non-Residential Electric
Service), E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G (Medium Non-
Residential Green Power Electric Service), E-4 TOU (Medium Non-Residential Time of Use
Electric Service), E-7 (Large Non-Residential Electric Service), E-7-G (Large Non-Residential
Green Power Electric Service), E-7 TOU (Large Non-Residential Time of Use Electric Service),
E-14 (Street Lights), E-EEC-1 (Export Electricity Compensation), and E-NSE-1 (Net Metering
Net Surplus Electricity Compensation); CEQA Status: Not a project.
RECOMMENDATION
Staff recommends the Utilities Advisory Commission recommend that the City Council adopt a
Resolution (Attachment A):
1. Approving the Fiscal Year 2027 Electric Utility Financial Forecast shown in this staff report
and attachments,; and
2. Approving the transfer at the end of FY 2026 of up to $5 million from the Electric Utility
Distribution Operations Reserve to the Electric Utility Capital Reserve; and Amending
Electric Rate Schedules (Attachment A, Exhibit 1) effective July 1, 2026 (FY 2027):
a. E-1 (Residential Electric Service)
b. E-1 TOU (Residential Time of Use Electric Service)
c. E-2 (Residential Master-Metered and Small Non-Residential Electric Service)
d. E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service
e. E-4 (Medium Non-Residential Electric Service)
f. E-4-G (Medium Non-Residential Green Power Electric Service)
g. E-4 TOU (Medium Non-Residential Time of Use Electric Service)
h. E-7 (Large Non-Residential Electric Service)
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i. E-7-G (Large Non-Residential Green Power Electric Service)
j. E-7 TOU (Large Non-Residential Time of Use Electric Service)
k. E-14 (Street Lights)
l. E-EEC-1 (Export Electricity Compensation) to reflect forecasted avoided cost for FY
2027, and
m. E-NSE-1 (Net Metering Net Surplus Electricity Compensation) to reflect avoided
cost for CY 2025.
EXECUTIVE SUMMARY
This staff report provides the Utilities Advisory Commission with a financial forecast for the
Electric Utility and provides an overview of the utility’s operations costs, capital costs, and debt
and includes recommended rate adjustments required to maintain the utility’s financial health.
This work is done annually as part of the budget and rate-setting cycle. Attachment A contains a
draft Council Resolution. Attachment A, Exhibit 1 contains a redline of the proposed changes to
the Electric Utility rate schedules. Attachment A, Exhibit 2 contains a summary of the financial
details and CIP budgets underlying the forecast. Attachment A, Exhibit 3 contains redlined
Electric Utility Reserves Management Practices describing the reserves and showing non-
substantive revisions to align with the state’s retitled “Cap and Invest” Program. Attachment B
contains a summary of the Electric Utility communications strategy and samples.
The Electric Utility rate forecast proposes a 6% rate increase for FY 2027. Beyond 2027, the
forecast shows additional increases that are slightly lower than the forecasts prepared last
year.1 Table 1 shows the proposed rate increases for FY 2027 through FY 2031.
Table 1: Current Year (FY 2026) and Forecasted Overall Rate Trajectory from FY 2027 to FY
2031
Fiscal Year 2026 2027 2028 2029 2030 2031
Current Forecast 6%6%6%7%7%5%
FY 2026 Plan (prior year)6%6%8%8%6%-
The drivers for this change relative to last year’s forecast include a new warehouse and laydown
1 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:
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yard for grid modernization, replacement of emergency generators, and a new approach to grid
modernization described to the Utilities Advisory Commission on January 7, 2026.3 The new
“when and where” approach to grid modernization provides the opportunity to delay costly
system upgrades until electric customers are ready to replace gas appliances or install EV
chargers. This approach lowers the expected rate increases. The rate increases in the outer years
of the forecast could change as the Council finalizes plans for debt financing grid modernization
costs.
3 Staff Report 2512-5638 Fiscal Year 2026 Mid-Year Electric Grid Modernization Update
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=85181&dbid=0&repo=PaloAlto and presentation on
pg. 9 https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=85181&dbid=0&repo=PaloAlto
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costs, commitments, and reappropriations planned to be reimbursed through the debt
issuance. On a combined basis, the Electric Distribution and Supply Operations Reserves are
within the guideline range and are forecasted to remain within the guideline range throughout
the five-year forecast period, FY 2027 to FY 2031.
BACKGROUND
ANALYSIS
FY 2025 Costs and Revenues
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normal in FY 2025, producing somewhat higher than average levels of hydroelectric generation
and enabling the City to sell some surplus generation to other utilities. In addition, the City is a
net seller of RA capacity, and extremely high RA prices during FY 2025 enabled the City to
realize significant RA sales revenue. Electric supply purchase costs increased 5% per year on
average from FY 2020 through FY 2025,5 and other operational costs increased 12% per year on
average over the same period.6
Table 2: FY 2025 Actuals vs. Prior Year’s Forecast ($000)
Net Cost (Benefit) Variance Type of change
Higher revenues from higher load, surplus
sales, and transfers
(12,712)Revenue increase
Lower electric supply costs (4,070)Cost decrease
Lower operational costs (8,353)Cost decrease
Lower than forecast capital investment (31,274)Cost decrease
Net Cost / (Benefit) of Variances (56,409)
Forecasts
Overview
5 Electric Supply Purchases plus Surplus Energy Costs less Surplus Energy Sales.
6 Operating costs include Administration, Customer Service, Engineering, Operations & Maintenance, Resource
Management, and Rent less Discounts/Uncollectible.
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Operations costs in FY 2026 are forecasted to be $9.3 million, or 22% higher than FY 2025
actuals. This large increase is due mainly to increases in Demand-Side Management program
expenses ($2.6 million) and increased engineering and operation and maintenance costs ($6.7
million). Operation expenses are increasing primarily due to a higher volume of contract work
being performed for system inspection and compliance maintenance (i.e. pole testing and
crossarm replacement). Vacancy savings will offset a portion of the contract work. Allocated
charges from other City departments are forecasted to increase 7% based on adopted FY 2026
budget numbers.
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Figure 1: Electric Utility Revenues, Expenses, and Rate Changes:
Staff conducted an updated load forecast for FY 2027, with forecast methodologies that
incorporated weather patterns, economic factors, and historical trends. This forecasted
electricity sales of 982,355 MWh and a peak electric load of 180 MW in FY 2027. Electricity sales
grew 4.6% in FY 2024 and 5% in FY 2025. Electric sales in FY 2026 are currently forecasted to
grow by 4.5% while the FY 2027 forecast is expected to remain relatively flat, only growing
0.2%. The main contributors to the recent electricity sales increases include growth in the E-7
and E-4 rate classes, driven primarily by small and medium data center expansions. From
around 1999 to 2019 the electric sales showed a gradual 1% annual decline due to loss of
manufacturing, energy efficiency, and rooftop solar adoption. The roughly 20-year decline prior
to 2019 was slightly mitigated by small increases in sales from building electrification and EV
charging.
Figure 2 shows the forecasted electricity sales through FY 2045. Electricity sales are expected to
only rise slightly as the rebound from COVID-19 is largely complete and further data center
projects are uncertain at this point. Building and vehicle electrification at a business-as-usual
level is included in the FY 2027 forecast. The “High Forecast” is shown for reference to illustrate
how increases in data center loads as well as a very large increase in the pace of building and
vehicle electrification could increase sales. Staff update the forecast annually based on the
most updated information for financial forecast purposes. While Palo Alto saw rapid electricity
growth in the prior 18-24 months, that growth has slowed substantially and is currently
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trending approximately 1% below the forecast shown below in the orange line for FY 27
Expected Forecast (on a weather normalized basis). As more certainty emerges around the
residential and commercial growth staff will update this forecast in the preliminary rates
forecast towards the end of 2026.
Figure 2: Forecasted Electricity Sales
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Figure 3: Forecasted Electricity Peak Demand
The Electric Utility receives most of its revenues from sales of electricity to Palo Alto customers,
but about 20 to 25% comes from other non-rate revenue sources. Of these non-rate revenue
sources, about 80% represents wholesale revenues – from surplus energy sales, surplus RA
sales, and sales of renewable energy credits (RECs) that are in excess of the City’s renewable
portfolio standard (RPS) requirements. These revenues may offset electric supply purchase
costs, smooth rate increases, or fund reserves or other costs including the Electric General Fund
Transfer and local decarbonization programs. Of the remaining revenues, the largest sources
are interest income, customer connection fees for new or replacement electric services, and
carbon allowance sales revenues associated with the State’s Cap-and-Invest (formerly Cap-and-
Trade) program.
Staff expects Cap-and-Invest allowance revenues to decline starting in calendar year 2027 and
then increase throughout the remainder of the forecast period under the new draft calculations
from California Air Resources Board (CARB). Although CARB is still in the process of updating
the regulations, a revised regulation is expected to be adopted in 2026, with implementation
anticipated in 2027. The current proposal from CARB staff would reduce the City’s current
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allowance revenue by approximately 40%, or about $2 million per year, from the current Cap-
and-Invest revenues to the electric fund. Staff will continue to update Cap-and-Invest related
revenues forecasts as more information becomes available.
Expenses
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litigating Transmission Owner Rate Cases where transmission costs have been improperly
assigned by California Investor Owned Utilities. Utilities staff is also working alongside the
Northern California Power Agency (NCPA) and federal hydropower staff to mitigate the
forecasted loss of revenues from RA sales in 2028 due to currently proposed CAISO procedure
changes.
Figure 4: Electricity Supply by Source
9 and
Figure 5 also shows average and actual hydroelectric generation.10 FY 2021 and FY 2022 had
lower than average hydroelectric generation, while FY2024 had higher than forecasted
generation. Starting in FY 2023 (in the FY 2024 Electric Utility Financial Plan) staff lowered its
forecast of an average hydroelectric year to more closely align with the past 10 years of
historical averages.
9 Costs are shown net of wholesale revenues and cannot be directly compared with the electric supply purchase
figures shown in Attachment C: Electric Utility Financial Forecast Table.
10 Average hydroelectric generation based on the currently inactive E-HRA rate schedule.
-40%
-20%
0%
20%
40%
60%
80%
100%
120%
140%
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Actuals Projection
%
S
h
a
r
e
Fiscal Year
Net Market
Purchases/Sales
Hydroelectric
Renewable
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anticipates that net electric supply costs will increase from an average of about $80 million
from FY 2022 through FY 2025 to about $126 million by FY 2031.
Figure 5: Electric Supply Portfolio Cost/Revenues
Table 3: Electric Supply Portfolio Costs/Revenues ($000)
Actual ForecastFiscal Year 2025 2026 2027 2028 2029 2030 2031
Net Supply Costs
0
100
200
300
400
500
600
-40
-20
0
20
40
60
80
100
120
140
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Actuals Projection
Hy
d
r
o
e
l
e
c
t
r
i
c
G
e
n
e
r
a
t
i
o
n
(
G
W
h
)
Su
p
p
l
y
C
o
s
t
s
(
$
M
i
l
l
i
o
n
)
Fiscal Year
Net Resource Adequacy
Purchases/Sales
Net Market
Purchases/Sales
Other Costs
Hydroelectric Cost
Transmission
Renewables
Average Hydro
Generation
Actual/Projected Hydro
Generation
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Operations
Administration includes direct costs for the Electric Utility for administrative and general
functions as well as shared utility administrative costs (costs allocated across all City
Departments). Specifically, administration includes financial management, insurance,
information technology expenses, work yard and inventories, tools, and other overhead
type activities;
Debt service is used to fund long-term capital projects. Additional detail on Electric
Utility debt service is provided in the Debt Service section below;
Customer Service including billing, printing and mailing, and customer support;
Engineering work for maintenance activities (separate from long-term capital activities);
Operations and Maintenance of the distribution system;
Resource Management and Demand Side Management; and
General Fund Transfers fund communications dispatch, fire training, graffiti removal
from poles and boxes, and Office of Emergency Services emergency response.
Other Transfers including transfers to the City’s capital project fund, reserves, and
technology fund.
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Figure 6: Electric Utility Operational Costs
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Capital Improvement Program
Table 4: Electric Utility CIP Spending, Budgeted ($M)
*Actual values from FY 2025.
13
13 $166.7 million less $85 million for the FY2027 bond is $89 million.
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Note that the debt issuance in FY 2027 will be used to reimburse FY 2025 and FY 2026 grid
modernization expenses, resulting in the use of rate/reserve funding in those years and a
refund to the reserves in FY 2027 as the bond proceeds are applied to the actual capital costs
for grid modernization and related projects (see Council staff report 2411-3805,15 December 16,
2024 for a detailed discussion and accompanying Resolution 1020916).
Table 5: Electric Utility CIP Funding Sources Based on Cash Expenditures ($M)
2025 2026 2027 2028 2029 2030 2031 Total
Rate-Funded CIP (Non-Grid Modernization)$21.4 $39.0 $15.2 $15.9 $16.4 $17.7 $18.1 $143.7
Rate Funded Grid Modernization $11.0 $11.0 $11.0 $11.0 $11.0 $11.0 $11.0 $77.0
Total Pay-Go $32.4 $50.0 $26.2 $26.9 $27.4 $28.7 $29.1 $220.7
Debt-Funded $2.7 $19.5 $15.8 $31.6 $15.0 $43.7 $45.3 $173.6
Total $35.1 $69.5 $41.9 $58.5 $42.4 $72.5 $74.4 $394.3
Table 6: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Secured by Electric Utility’s:Bond Issuance Responsible
Utilities
Annual Debt
Service ($000)Net Revenues Reserves
2009 Water Revenue Bonds (Build
America Bonds)Water $1,977*No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water
$1,457 No Yes
*Net of Federal interest subsidy
15 Staff report 2411-3805 “Adoption of a Resolution of Intention to Reimburse Expenditures for the Grid
Modernization and Related Projects of the Electric Utility System Infrastructure from the Proceeds of the Tax-
Exempt Utility Revenue Bonds.”
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=83165&dbid=0&repo=PaloAlto
16 Council Resolution 10209 (Dec. 16, 2024)
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=62094&dbid=0&repo=PaloAlto
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Reserves
The Electric Utility currently has two primary contingency reserves: the Supply Operations
Reserve and the Distribution Operations Reserve. In addition, the Electric Utility has a Hydro
Stabilization Reserve, an Electric Special Projects (ESP) Reserve, and a Capital Reserve. Reserve
funds may be utilized with Council approval.
There are a variety of risks associated with the Supply Fund related to resource generation
variability, market price volatility, transmission cost increases, and regulatory changes to
market rules. Because of the high range of uncertainty in energy price predictions more than
two years into the future, this risk assessment is only performed for the first two fiscal years of
the forecast period. It is important to note that there is a very low likelihood of all adverse
scenarios occurring simultaneously (as the severity is defined in Table 7).
Of the risks faced by the Electric Utility’s Supply Fund for FY 2027, the largest two factors are
related to potential transmission cost increases above staff’s current forecast ($5.4 million) and
the reduction of total load (and the associated retail sales revenue) may be lower than
forecasted ($5.3 million). Together, these two risks account for almost half of the overall
Electric Supply Fund risk. Other risks are related to production from the City’s renewable
Estimates of Adverse
Outcomes (M$)
Estimates of Adverse
Outcomes (M$)
FY 2027 FY 2028
1. Load Net Revenue 5.3 5.1
2. Renewable Production: Landfill,
Wind, Solar, Geothermal 1.2 2.1
3. REC Purchases 0.5 0.5
4. REC Sales 1.0 0.8
5. Market Price 1.9 1.5
6. Resource Adequacy 4.5 2.1
7. Transmission/CAISO 5.4 5.8
8. Plant Outage 1.0 1.0
9. Western Cost 1.6 1.4
10. Legislative & Regulatory 0.0 0.0
11. Supplier Default 0.2 0.2
Electric Supply Fund Risks 22.6 20.5
Categories of Electric Supply Cost
Uncertainties
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contracts and market prices for purchases and sales of energy and resource adequacy (Items 2
through 6 in Table 7 above), totaling $9.0 million or 40% of the total risk.
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Table 8: Electric Distribution Fund Risk Assessment ($000)
Total non-commodity revenue
89,007
92,567
98,121
104,990
111,289
116,853
Max. revenue variance, previous 10 yrs 8%8%8%8%8%8%
Risk of revenue loss
7,025
7,306
7,744
8,286
8,783
9,223
CIP Budget
35,591
10,122
33,301
34,109
35,698
36,370
CIP Contingency (10%)
3,559
1,012
3,330
3,411
3,570
3,637
10,584
8,318
11,074
11,697
12,353
12,860
Figure 7 illustrates the combined Supply and Distribution Operating Reserve balances. The
combined balances have met the reserve minimum, and future rate adjustments balance rate
stability and achievement of the reserve target.
Reserve transfers are made at the end of each fiscal year so that the Electric Utility meets its
financial goals and policies. At the end of FY 2025, the Electric Utility’s combined Operations
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Reserves for Distribution and Supply totaled $46.6 million, which is close to the target level of
$49.5 million.19
20 These funds covered higher
costs during the pandemic, lower hydroelectric generation during the drought, and high winter
energy prices during 2022-2023.This forecast also reflects repayments of $1 million per year
from FY 2027 through FY 2030 to the Electric Special Projects Reserve for loans to the water
and gas utilities for AMI investments.
21 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 recover higher supply costs.
19 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
20 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://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=77755&dbid=0&repo=PaloAlto. $5 million was
repaid in FY 2020; See Staff Report 11341
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=86876&dbid=0&repo=PaloAlto, 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 13661, June 13, 2022)
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=2238&dbid=0&repo=PaloAlto. 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).
21 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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the actual and projected reserve balances for each of these reserves. The Operations Reserve
will be used temporarily to fund the grid modernization project until debt is issued in FY 2027.
25 all of the Cap and Invest
Program revenue was spent on purchasing renewable energy and none was held in reserve.
26 Council approved continuation of the program with 100% of revenue
going to local emissions reduction. In accordance with Council policy, staff will fund the Cap and
Invest Program Reserve with unspent revenues from the sale of carbon allowances freely
allocated to the Electric Utility in an amount equal to 100% of each FY’s Renewable Energy
Credit (REC) Exchange program revenues, currently estimated to be about $0.5M per year
through FY 2029, for future local decarbonization projects.
CIP Reserve Balance
25Staff Report 11556
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=86875&dbid=0&repo=PaloAlto
26December 12, 2022 Staff Report #14375
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=82045&dbid=0&repo=PaloAlto
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below reflects the maximum and minimum CIP Reserve guideline levels, starting in FY 2020
through FY 2031. The maximum reserve level is equal to the running 4-year average of
forecasted CIP expenses. Because of the fluctuating annual dollar amounts and timing of CIP
projects budgeted to occur during the forecast period, as well as the potential for new ongoing
projects to be included in the CIP plan in later years, four years of budgeted CIP are used to
calculate the reserve maximum levels. The minimum CIP Reserve level is 20% of the maximum
CIP Reserve guideline level.
Figure 8: Electric CIP Reserve Adequacy
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The reserves charts below show significant increases in the Distribution Operations Reserve as
these funds will be replenished following grid modernization investments prior to the bond
funding in FY 2027.
Figure 9: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2026 and Forecasts through FY 2031
Figure 10: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2026 and Forecasts through FY 2031
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Table 9 shows the forecasted balance of each of the Electric Utility reserves for the period
covered by this Financial Forecast. See also: Attachment A, Exhibit 2: Electric Utility Financial
Table.
Table 9: Electric Utility Reserves Starting and Ending Balances, Revenues, Transfers To/(From)
Reserves, and Reserve Guideline Levels for FY 2026 to FY 2031 ($000)
Fiscal Year 2026 2027 2028 2029 2030 2031
Starting Reserve Balances
1 Supply Operations 43,632 44,257 38,164 40,180 39,100 37,722
2 Distribution Operations 2,949 (2,623) 18,559 19,768 23,971 22,068
3 Capital Reserves 880 5,880 8,880 12,380 15,880 19,380
4 Electric Special Projects 30,149 31,169 32,189 33,209 34,229 35,249
5 Hydro Stabilization 18,767 18,767 24,767 24,767 24,767 24,767
6 Cap and Trade 6,675 5,625 4,175 3,121 1,245 871
7 Public Benefits 8,163 11,047 7,451 6,054 4,400 2,472
8 Low Carbon Fuel Standard (LCFS) 6,372 2,127 166 341 666 -
9 Electrification Reserve 2,037 2,037 2,037 2,037 2,037 2,037
Revenues
10 Supply 161,733 159,079 158,313 166,468 175,955 183,962
11 Distribution 84,566 90,013 95,841 101,787 108,354 114,187
12 Cap and Trade 3,225 2,249 2,327 2,724 3,313 3,313
13 Public Benefits 5,677 6,067 6,460 6,932 7,399 7,777
14 Low Carbon Fuel Standard 1,301 1,431 1,574 1,731 1,904 1,400
15 Electrification Reserve Repayments - - - - - -
Transfers from Supply Operations Reserve to Other Reserves or to Distribution Fund
16 Distribution Operations (1,020) (1,020) (1,020) (1,020) (1,020) (1,020)
17 Electric Special Projects (1,020) (1,020) (1,020) (1,020) (1,020) -
18 Hydro Stabilization - (6,000) - - - -
19 Cap and Trade 1,862 1,299 1,227 1,944 3,193 3,193
16+17+18+19=20 Supply Operations Total (178) (6,741) (813) (96) 1,153 2,173
Transfers from Distribution Operations Reserve to Other Reserves or to Supply Fund
21 Supply Operations 1,020 1,020 1,020 1,020 1,020 1,020
22 Capital Reserves (5,000) (3,000) (3,500) (3,500) (3,500) (3,500)
23 Low Carbon Fuel Standard - - - - - -
21+22+23=24 Distribution Operations Total (3,980) (1,980) (2,480) (2,480) (2,480) (2,480)
Expenses
25 Electric Supply Purchases (160,929) (158,431) (155,485) (167,453) (178,485) (182,252)
26 Distribution Non-CIP (50,568) (56,728) (58,851) (60,996) (72,078) (73,851)
27 Distribution Planned CIP (35,591) (10,122) (33,301) (34,109) (35,698) (36,370)
28 Cap and Trade (2,413) (2,400) (2,154) (2,656) (495) (385)
29 Public Benefits (2,793) (9,662) (7,858) (8,586) (9,327) (10,145)
30 Low Carbon Fuel Standard (5,545) (3,392) (1,399) (1,406) (2,024) (1,400)
31 Electrification Reserve - - - - - -
Ending Reserve Balance
1+10+20+25=32 Supply Operations 44,257 38,164 40,180 39,100 37,722 41,604
2+11+24+26+27=33 Distribution Operations (2,623) 18,559 19,768 23,971 22,068 23,554
3+22=34 Capital Reserves 5,880 8,880 12,380 15,880 19,380 22,880
4-17=35 Electric Special Projects 31,169 32,189 33,209 34,229 35,249 35,249
5+18=36 Hydro Stabilization 18,767 24,767 24,767 24,767 24,767 24,767
6-19+28=37 Cap and Trade 5,625 4,175 3,121 1,245 871 605
7+13+29=38 Public Benefits 11,047 7,451 6,054 4,400 2,472 104
8+14+23+30=39 Low Carbon Fuel Standard (LCFS) 2,127 166 341 666 547 -
9+15+31=40 Electrification Reserve 2,037 2,037 2,037 2,037 2,037 2,037
Operations Reserve Guidelines (Supply)
Minimum 23,964 23,487 22,780 24,615 25,856 26,191
Maximum 47,927 46,974 45,560 49,229 51,712 52,382
Operations Reserve Guidelines (Distribution)
Minimum 9,343 11,351 11,070 11,539 13,579 13,897
Maximum 18,686 22,701 22,141 23,077 27,158 27,794
Capital Reserve Guidelines
Minimum 5,656 5,661 5,661 5,661 5,661 5,979
Maximum 28,281 28,307 28,307 28,307 28,307 28,307
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Proposed Rates
The City adopted its current electric rates effective July 1, 2025. The current FY 2026 and
proposed FY 2027 rates are reflected in Table 10 below. All FY2027 commodity rates are
increased by 7% and FY2027 distribution rates are increased by 4.5%. Rate components that are
weighted more toward supply costs (summer energy rates) increase at a higher percentage
compared with rate components comprised more heavily of distribution costs (demand rates).
The results in a 6% overall adjustment for each rate schedule.
E-1 (Residential)
Tier 1 Energy ($/kWh)0.20570 0.21761 0.01191 6%
Tier 2 Energy ($/kWh)0.22944 0.24317 0.01373 6%
Customer Charge ($/month)5.15 5.44 0.29 6%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh)0.26485 0.28059 0.01574 6%
Winter Energy ($/kWh)0.17290 0.18307 0.01017 6%
Customer Charge ($/month)6.22 6.57 0.35 6%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh)0.16171 0.16872 0.01030 7%
Winter Energy ($/kWh)0.11579 0.12125 0.00696 6%
Summer Demand ($/kW)47.59 51.66 2.49 5%
Winter Demand ($/kW)24.94 27.33 1.24 5%
Customer Charge ($/month)119.53 133.44 7.20 6%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh)0.14262 0.14738 0.00946 7%
Winter Energy ($/kWh)0.09245 0.09579 0.00609 7%
Summer Demand ($/kW)42.41 45.87 2.26 5%
Winter Demand ($/kW)29.20 32.02 1.45 5%
Customer Charge ($/month)547.36 611.03 32.95 6%
Table 11 shows the impact of the proposed July 1, 2027 rate changes on the residential and non-
residential bills for various consumption levels. The increase for all rate classes is 6%.
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Table 11: Impact of Proposed Electric Rate Changes on Customer Bills in FY 2027
Monthly Bill
Rate
Schedule
Usage
(kWh/mo)
Peak
Demand
kW-mo Current Rates Proposed Rates Change
Change
(%)
300 NA $66.86 $70.72 $3.86 6%
(Summer
Median)
365
NA $80.23 $84.87 $4.64 6%
(Winter
Median)
450
NA $97.72 $103.36 $5.65 6%
650 NA $143.60 $152.00 $8.40 6%
E-1
(Residential)
1,200 NA $269.80 $285.74 $15.95 6%
E-2
(Small Non-
Residential)
1,000 NA $225.10 $238.40 $13.31 6%
160,000 274 $32,253.66 $34,152.67 $1,899.01 6%E-4
(Medium
Non-
Residential)
500,000 856 $100,515.02 $106,433.66 $5,918.64 6%
E-7
(Large Non-
Residential)
2,000,000 3,424 $355,194.24 $377,128.71 $21,934.47 6%
Net Energy Metering Compensation Rates
The City operates two Net Energy Metering (NEM) programs. Solar customers served by the
City of Palo Alto's (CPAU) original NEM program, also called NEM 1, are compensated at retail
rates for electricity they export to the grid, and solar customers served by the NEM successor
program, or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are
compensated at the Export Electricity Compensation (E-EEC-1) rate for exported electricity.
Customers on the NEM 1 program who have chosen to have the value of any annual net
generation they produced over the past 12 months credited back to their account do so under
the Net Metering Net Surplus Electricity Compensation (E-NSE-1) rate. The Net Surplus
Electricity Compensation rate represents the City’s avoided cost or value of customer-
generated electricity in Palo Alto over the preceding year, which is calculated based on the
value of the energy and RECs, avoided capacity charges, avoided transmission and ancillary
service charges, and avoided transmission and distribution (T&D) losses. Staff proposes a slight
increase to the E-NSE-1 rate to $0.1064/kWh based on updated avoided cost calculations that
reflect higher historical transmission charges and historical RA market prices in 2025 relative to
their levels in 2024.
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Under the City’s NEM successor program, participating solar customers in Palo Alto are billed at
the current retail rate for electricity drawn from the grid, and receive a credit for electricity they
export to the grid at the E-EEC-1 rate. This compensation rate also reflects the avoided cost or
value of customer-generated electricity in Palo Alto, calculated on a forward-looking basis for
the upcoming fiscal year. As shown in the table below, the current avoided cost rate for solar
generation in Palo Alto is $0.1206/kWh, which is higher than the City’s forecasted avoided cost
(due to decreases in forecasted resource adequacy and REC prices compared to a year ago),
and thus requires the proposed NEM compensation rate (E-EEC-1) to decrease to $0.0990/kWh.
This decrease in the overall avoided cost is driven by a significant drop in forward electricity
market prices and forward RA prices. Table 12 shows the current and proposed NEM buyback
rates that would be effective on July 1, 2026.
Table 12: NEM Buyback Rates – Current vs. Proposed
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Bill Comparisons/Competitiveness
For the median consumption level, the CPAU residential electric monthly bill is about $94.04.
This is about 50% lower than the monthly bill for a PG&E customer and about 24% higher than
the bill for a City of Santa Clara (Silicon Valley Power) customer with the same consumption
level, based on rates as of January 1, 2026. PG&E bill calculations are based on the “average”
bundled total rates, including the annual climate credit, and Climate Zone X, which includes
most nearby comparison communities.
Santa Clara’s electrical system benefits from a higher load factor with a significantly larger
commercial load compared to Palo Alto’s, resulting in a more efficient distribution system and
lower rates. However, unlike Palo Alto, Santa Clara’s system is not 100% carbon neutral, as part
of its electricity is generated from natural gas.
Table 13 provides sample residential bills for Palo Alto (effective 7/1/2026), PG&E (effective
1/1/2026), and the City of Santa Clara (effective 7/1/2026) at various usage levels.
Usage (kWh)
Palo Alto
7/1/2026
PG&E
1/1/2026
Santa Clara
1/1/2026
300 $70.72 $117.20 $53.28
(Median) 408 $94.12 $168.40 $71.88
650 $152.00 $283.12 $116.55
1200 $285.74 $543.85 $218.06
For commercial customers, the CPAU electric monthly bill is about 43% to 53% lower than the
bill for a PG&E customer, depending on usage levels. Compared to the City of Santa Clara, CPAU
commercial bills are approximately 15% lower to 12% higher, depending on usage levels, based
on rates as of January 1, 2026.
Table 14 presents sample commercial bills for Palo Alto (effective 7/1/2026), PG&E (effective
1/1/2026), and the City of Santa Clara (effective 7/1/2026) at various usage levels.
Usage (kWh)
Palo Alto
7/1/2026
PG&E
1/1/2026
Santa Clara
1/1/2026
1000 $238.40 $432.56 $263.86
160,000 $34,152.67 $69,209.60 $28,924.47
500,000 $106,433.66 $191,670.00 $90,174.88
2,000,000 $377,128.71 $618,760.00 $360,401.49
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Item No. 3 Page 29 of 30
General Fund Transfer
The City calculates the General Fund Transfer from its Electric Utility based on a methodology
adopted by Council in 2009, which has remained unchanged since then.29 Each year it is
calculated according to the 2009 Council-adopted methodology and does not require additional
Council action.
Staff will incorporate the UAC’s recommendations into the draft financial forecast and
attachments and bring those to the Finance Committee in April and to the City Council in June.
The City Council will consider the proposed financial forecast and rate schedules with the FY
2027 budget review and adoption process in June 2026. If Council approves the proposed rate
changes, the rates will become effective July 1, 2026.
FY 2027 revenues from retail rates are forecasted to increase 6.7% or $13.3 million from FY
2026 forecasted levels if Council adopts this financial forecast’s recommendations. The City is a
non-residential utility customer and can expect an increase to General Fund expenses (due to
the rate increases) and revenues (due to the General Fund Transfer). Street light expenses
(which are paid from the General Fund) are forecasted to increase by 6% or $0.122 million. The
General Fund revenues from the General Fund Transfer would increase from an estimate of
$17.56 million in FY 2026 to an estimated $17.95 million in FY 2027, an increase of $0.39 million
The proposed electric rate adjustments are consistent with Council-adopted Reserve
Management Practices that are part of the Financial Forecast and were developed using a cost-
of-service study30 and methodology consistent with the California Constitution and industry-
accepted cost of service principles.
At the UAC on November 5, 2025, staff discussed the preliminary rate proposals .31 The UAC did
not take any action on this item. The video of the meeting is available on the City’s website at
the following link: https://youtube.com/watch?v=1e6NrB2KDCw?feature=share. UAC members
29 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to the General Fund Transfer methodology.
30 See Staff Report 2404-2842, June 17, 2024, beginning on packet page 709
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=6490&dbid=0&repo=PaloAlto&searchid=e295a977-
520e-4aed-b382-b7e802821bcd
31 See Staff Report 2503-4364, November 5, 2025 “Discussion and Update on the Fiscal Year 2027 Preliminary
Utilities Financial Forecast and Rate Projections”
https://recordsportal.paloalto.gov/WebLink/DocView.aspx?id=84164&dbid=0&repo=PaloAlto&searchid=ffbb0624-
e25e-413d-8cc1-ffb7fcd6db8a&cr=1
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Item No. 3 Page 30 of 30
expressed concern about utility affordability and subsequently formed a UAC Subcommittee to
examine affordability of water and electric rates.
ENVIRONMENTAL REVIEW
ATTACHMENTS
AUTHOR/TITLE:
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Attachment A
1
02703252026
Resolution No. _
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2027 Electric Utility Financial Forecast and Reserve Transfer, and Amending Utility
Rate Schedules E-1 (Residential Electric Service), E-1 TOU (Residential Time of Use
Electric Service), E-2 (Residential Master-Metered and Small Non-Residential Electric
Service), E-2-G (Residential Master- Metered and Small Non-Residential Green Power
Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G (Medium Non-
Residential Green Power Electric Service), E-4 TOU (Medium Non-Residential Electric
Time of Use Service), E-7 (Large Non Residential Electric Service), E-7-G (Large Non-
Residential Green Power Electric Service), E-7 TOU (Large Non-Residential Electric Time
of Use Service), E-14 (Street Lights), E-EEC-1 (Export Electricity Compensation), and E-
NSE-1 (Net Metering Surplus Electricity Compensation)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) assesses the financial position of its utilities
with the goal of ensuring adequate revenue to fund operations. This includes making long-term
projections of market conditions, the physical condition of the system, and other factors that
could affect utility costs, and setting rates adequate to recover these costs. It does this with the
goal of providing safe, reliable, and sustainable utility services at competitive rates. The City
adopts Financial Forecasts or Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices (Exhibit 3) and Electric
Utility and CIP Financial Details (Exhibit 2) in addition to the Electric Financial Forecast staff
report presented to the City Council.
C. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of the
City of Palo Alto may by resolution adopt rules and regulations governing utility services, fees
and charges.
D. On June 15, 2026, the City Council heard and approved the proposed rate increase
at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the fiscal year (“FY”) 2027 Amended Electric
Utility Reserve Management Practices (Exhibit 3) and Electric Utility and CIP Financial Details
(Exhibit 2) presented to the Finance Committee on April 21, 2026 as updated by the June 15,
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Attachment A
2
02703252026
2026 Council report including the Electric Financial Forecast, which are attached to and made
a part of the staff report presented to the City Council;
SECTION 2. The Council hereby approves the transfer of up to $5 million from the
Electric Utility Distribution Operations Reserve to the Electric Utility Capital Reserve by the end
of FY 2026, as described in the FY 2027 Electric Utility Financial Forecast (Exhibit 2)
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2026;
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 TOU (Residential Time of Use Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-1, as amended, shall become effective July
1, 2026;
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2 (Residential Master-Metered and Small Non-Residential Electric Service) is
hereby amended to read as attached and incorporated. Utility Rate Schedule E-2, as amended,
shall become effective July 1, 2026;
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service) is hereby amended to read as attached and incorporated. Utility Rate
Schedule E-2-G, as amended, shall become effective July 1, 2026;
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2026;
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Non-Residential Green Power Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall
become effective July 1, 2026;
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Non-Residential Time of Use Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended,
shall become effective July 1, 2026;
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Attachment A
3
02703252026
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective
July 1, 2026;
SECTION 11. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become
effective July 1, 2026;
SECTION 12. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Non-Residential Time of Use Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall
become effective July 1, 2026;
SECTION 13. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated.
Utility Rate Schedule E-14, as amended, shall become effective July 1, 2026;
SECTION 14. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-EEC-1 (Export Electricity Compensation) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-EEC-1, as amended, shall become effective July 1, 2026;
SECTION 15. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-NSE-1 (Net Surplus Electricity Compensation Rate) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-NSE-1, as amended, shall become effective
July 1, 2026;
SECTION 16. The Council finds that the revenue derived from the adoption of this
resolution shall be used only for the purpose set forth in Article VII, Section 2, of the Charter of
the City of Palo Alto.
SECTION 17. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
//
//
//
//
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* NOT YET APPROVED *
Attachment A
4
02703252026
SECTION 18. The Council finds that approving the Electric Reserves Management
Practices, Electric Financial Forecast, and Electric Reserve transfer 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 each is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental assessment is required. The Council finds that
changing electric rates to meet operating expenses, purchase supplies and materials, meet
financial reserve needs and obtain funds for capital improvements necessary to maintain service
is not subject to the California Environmental Quality Act (CEQA), pursuant to California Public
Resources Code Sec. 21080(b)(8) and CEQA Guidelines Sec. 15273(a). After reviewing the staff
report and all attachments presented to Council, the Council incorporates these documents
herein and finds that sufficient evidence has been presented setting forth with specificity the
basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
City Clerk
Mayor
APPROVED AS TO FORM:
APPROVED:
Assistant City Attorney
City Manager
Director of Utilities
Director of Administrative Services
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RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-1-1 Supersedes Sheet No E-1-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to separately metered single-family residential dwellings receiving
Electric Service from the City of Palo Alto Utilities.
B.TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C.UNBUNDLED RATES:
Per kilowatt-hour (kWh)Commodity Distribution Public Benefits Total
Tier 1 usage $
0.110990373
$
0.1002509593
$ 0.0063704 $
0.217610570
Tier 2 usage
Any usage over Tier 1
0.143083372 0.093728968 0.0063704 0.243172944
Customer Charge
($/month)
5.4415
D.SPECIAL NOTES:
1.Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
2.Calculation of Usage Tiers
Tier 1 Electricity usage shall be calculated and billed based upon a level of 15 kWh per
day, prorated by Meter reading days of Service. As an example, for a 30-day bill, the Tier
1 level would be 450 kWh. For further discussion of bill calculation and proration, refer
to Rule and Regulation 11.
{End}
Attachment A Item #3
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RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-1-TOU-11 Sheet No E-1-TOU-1
Ddated 1-1-2026 Effective 7-1-2026
A. APPLICABILITY:
This voluntary Rate Schedule applies to separately metered single-family residential dwellings
receiving Electric Service from the City of Palo Alto Utilities (CPAU) who have an Advanced
Metering Infrastructure meter installed. This Rate Schedule is not available to Net Energy
Metered (NEM) customers and is provided at the sole discretion of CPAU.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Per kilowatt-hour e kWh Commodit Distribution Public Benefits Total
Summer Perio
Ener Char e
Peak $ 0.249893354
$
0.09772351 $ 0.0063704
$
0.3539833
09
Off-Peak 0.08826249 0.09772351 0.0063704
0.1923582
04
Su er Off-Peak 0.071586690 0.09772351 0.0063704
0.1756766
45
Winter Perio
Ener Char e
Peak $ 0.178746705
$
0.09772351 $ 0.0063704
$
0.2828366
60
Off-Peak 0.11805033 0.09772351 0.0063704
0.2221409
88
Su er Off-Peak 0.083837835 0.09772351 0.0063704
0.1879277
90
Customer Char e $/month 5.4415
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RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-1-TOU-12 Sheet No E-1-TOU-2
Ddated 1-1-2026 Effective 7-1-2026
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Seasonal Periods
Summer Period: Service from June 1 to September 30
Winter Period: Service from October 1 to May 31
SEASONAL RATE CHANGES: When the Billing Period includes use in both Summer and
Winter periods, usage will be prorated based on the number of days in each seasonal period, and
the Charges based on the applicable rates therein. For further discussion of bill calculation and
proration, refer to Rule and Regulation 11.
3. Definition of Time Periods
Peak: 4:00 p.m. to 9:00 p.m. Every day
Off-Peak: 9:00 p.m. to 9:00 a.m. Every day
3:00 p.m. to 4:00 p.m.
Super Off-Peak: 9:00 a.m. to 3:00 p.m. Every day
4. Changing Rate Schedules
Customers electing to be served under E-1 TOU must remain on said Rate Schedule for a
minimum of 6 months. Should the Customer so wish, at the end of 6 months, the Customer may
request a Rate Schedule change to any applicable City of Palo Alto full-service Rate Schedule as
is suitable to their kilowatt-hour usage. However, once a customer elects a rate other than E-1
TOU, they cannot re-elect E-TOU for the next 12 billing cycles.
{End}
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RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-1 Supersedes Sheet No E-2-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities:
1. Non-residential Customers receiving Non-Demand metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities receiving Non-
Demand metered Electric Service.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Per kilowatt-hour kWh Commodit Distribution Public Benefits Total
Summer Perio
$
0.161305075
$
0.112920806
$ 0.0063704
$
0.28059648
5
Winter Perio
0.09987334
0.07683352
0.0063704
0.18307729
0
Customer Charge ($/month)
6.5722
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
Item #3
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RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-2 Supersedes Sheet No E-2-2
Effective 7-1-20265 dated 7-1-20254
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh
for twelve consecutive months, whereupon, at the option of the City, it may be removed.
{End}
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RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-G-1 Supersedes Sheet No E-2-G-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities who qualify for E-2 Service and choose to participate in the Palo Alto Green
Program:
1. Non-residential Customers receiving Non-Demand metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities receiving Non-Demand
metered Electric Service.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodit Distribution
Public
Benefits
Palo Alto
Green
Char e Total
Summer Perio
$
0.161305075
$
0.112920806
$
0.0063704 $ 0.0075
$
0.2880972
35
Winter Perio
0.09987334
0.07683352
0.0063704 0.0075
0.1905780
40
Customer Charge
($/month)
6.5722
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodit Distribution
Public
Benefits
Total
Summer Perio
$
0.161305075
$
0.112920806
$
0.0063704
$
0.2680594
85
Winter Perio
0.09987334
0.07683352
0.0063704
0.1830772
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RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-G-2 Supersedes Sheet No E-2-G-2
Effective 7-1-20265 dated 7-1-20254
90
Customer Charge
($/month)
6.5722
Palo Alto Green Char e (per 1000 kWh block) $ 7.50
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation
Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities
Department of enough renewable energy credits (RECs) to match 100% of the metered
energy usage at the Customer’s facility each month. Any Customer may alternately request
that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs.
CPAU will charge the Customer the Palo Alto Green Charge for each such requested block.
These REC purchases support the production of renewable energy, increase the financial
value of power from renewable sources, and create a transparent and sustainable market
that encourages new development of wind and solar power.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any time,
in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program.
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RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-2-G-3 Supersedes Sheet No E-2-G-3
Effective 7-1-20265 dated 7-1-20254
4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh
for twelve consecutive months, whereupon, at the option of the City, it may be removed.
{End}
Item #3
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MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-1 Supersedes Sheet No E-4-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to Demand metered Secondary Electric Service for Customers with
a maximum Demand below 1,000 kilowatts. This Rate Schedule may include Service to master-
metered multi-family facilities or other facilities requiring Demand metered Service, as
determined by the City.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodit Distribution
Public
Benefits Total
Summer Perio
Demand Char e er kW
$ 11.8709
$ 39.798.08
$ 51.6649.17
Ener Char e er kWh
0.133122441
0.02923797
0.0063704
0.168725842
Winter Perio
Demand Char e er kW
$ 2.7860
$ 24.553.49
$ 27.336.09
Ener Char e er kWh
0.08590028
0.02923797
0.0063704
0.121501429
Customer Char e $/month 133.4426.24
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.
Item #3
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MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-2 Supersedes Sheet No E-4-2
Effective 7-1-20265 dated 7-1-20254
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a Maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh
for twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type
Demand Meter which does not reset after a definite time interval may be used at the City's
option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 pm on weekdays.
4. Changing Rate Schedules
Customers may request a rate schedule change at any time to any City of Palo Alto full-
service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage
profile.
5. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
Item #3
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MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-3 Supersedes Sheet No E-4-3
Effective 7-1-20265 dated 7-1-20254
to the Customer's electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change his system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
6. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio
$
9.098.50 $ 39.798.08 $ 48.886.58
Winter Perio 0.00 24.553.49 24.553.49
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3)
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
Item #3
Packet Pg. 162
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-4 Supersedes Sheet No E-4-4
Effective 7-1-20265 dated 7-1-20254
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
Item #3
Packet Pg. 163
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-1 Supersedes Sheet No E-4-G-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to Customers who qualify for E-4 Service and who choose to
participate in the Palo Alto Green Program.
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodit Distribution
Public
Benefits
Palo Alto
Green
Char e Total
Summer Perio
Demand Char e er kW $ 11.8709 $ 39.798.08
$
51.6649.1
7
Ener Char e er kWh 0.133122441 0.02923797 0.0063704 0.0075
0.1762265
92
Winter Perio
Demand Char e er kW $ 2.7860 $ 24.553.49
$
27.336.09
Ener Char e er kWh 0.08590028 0.02923797 0.0063704 0.0075
0.1290017
68
Customer Char e $/month 133.4426.24
Item #3
Packet Pg. 164
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-2 Supersedes Sheet No E-4-G-2
Effective 7-1-20265 dated 7-1-20254
2. 1000 kWh Block Purchase Option:
Commodit Distribution
Public
Benefits Total
Summer Perio
Demand Char e er kW $ 11.8709 $ 39.798.08
$
51.6649.1
7
Ener Char e er kWh 0.133122441 0.02923797 0.0063704
0.1687258
42
Palo Alto Green Char e er 1000 kWh block $7.50
Winter Perio
Demand Char e er kW $ 2.7860 $ 24.553.49 $27.33
Ener Char e er kWh 0.08590028 0.02923797 0.0063704
0.1215014
29
Palo Alto Green Char e er 1000 kWh block $7.50
Customer Char e $/month 133.4426.24
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted
for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill
amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
Item #3
Packet Pg. 165
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-3 Supersedes Sheet No E-4-G-3
Effective 7-1-20265 dated 7-1-20254
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has dropped
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the
City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type
Demand Meter, which does not reset after a definite time interval, may be used at the City's
option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays.
4. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full-service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
5. Palo Alto Green Program Description and Participation
Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities
Department of enough renewable energy credits (RECs) to match 100% of the metered
energy usage at the customer’s facility each month. Any Customer may alternately request
that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs.
CPAU will charge the Customer the Palo Alto Green Charge for each such requested block.
These REC purchases support the production of renewable energy, increase the financial
value of power from renewal sources, and creates a transparent and sustainable market that
encourages new development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any time,
in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
Item #3
Packet Pg. 166
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-4 Supersedes Sheet No E-4-G-4
Effective 7-1-20265 dated 7-1-20254
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change the system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue Meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio
$
9.098.50 $ 39.798.08 $ 48.886.58
Winter Perio 0.00 24.553.49 24.553.49
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3)
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue Meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
Item #3
Packet Pg. 167
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-G-5 Supersedes Sheet No E-4-G-5
Effective 7-1-20265 dated 7-1-20254
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
Item #3
Packet Pg. 168
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-1 Supersedes Sheet No E-4-TOU-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This voluntary Rate Schedule applies to Demand metered Secondary Electric Service for
Customers with Demand between 500 and 1,000 kilowatts per month and who have sustained
this level of usage for at least three consecutive months during the most recent 12 month period.
This Rate Schedule may include Service to Master-Metered multi-family facilities or other
facilities requiring Demand metered Service, as determined by the City.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodit Distribution Public Benefits Total
Summer Perio
Demand Char e er kW
Peak $ 10.519.82 $ 19.9307 $ 30.4428.89
Max Deman 1.390 19.9307 21.320.37
Ener Char e er kWh
Peak
$
0.184127208 $ 0.02944817 $ 0.0063704
$
0.219940629
Mi -Peak 0.151744181 0.02944817 0.0063704 0.187557602
Off-Peak 0.114080662 0.02944817 0.0063704 0.14989083
Winter Perio
Demand Char e er kW
Peak $ 1.4031 $ 12.451.91 $ 13.8522
Max Deman 1.4031 12.451.91 13.8522
Ener Char e er kWh
Peak
$
0.12943096
$
0.02900775 $ 0.0063704
$
0.164805475
Mi -Peak 0.1021509547 0.02900775 0.0063704 0.137522926
Off-Peak 0.070516590 0.02900775 0.0063704
0.105880996
9
Customer Charge
$/month 133.4426.24
Item #3
Packet Pg. 169
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-2 Supersedes Sheet No E-4-TOU-2
Effective 7-1-20265 dated 7-1-20254
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted
for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill
amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Energy
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 2:00 p.m. to 4:00 p.m. Monday through Friday (except holidays)
9:00 p.m. to 11:00 p.m.
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
WINTER PERIOD (Service from November 1 to April 30):
Energy
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 9:00 a.m. to 2:00 p.m. Monday through Friday (except holidays)
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Item #3
Packet Pg. 170
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-3 Supersedes Sheet No E-4-TOU-3
Effective 7-1-20265 dated 7-1-20254
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
TYPES OF DEMAND CHARGES: The Peak Demand Charge per Kilowatt applies to the
maximum peak-period Demand during the time periods noted above. The Maximum (Max)
Demand charge per Kilowatt applies to the maximum Demand at any time during the month. Both
Demand charges apply in each Billing Period, and the maximum peak-period Demand and
maximum Demand may occur at different times in the Billing Period depending on Customer
usage patterns.
SEASONAL RATE CHANGES: When the Billing Period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal period,
and the Charges based on the applicable rates therein. For further discussion of bill calculation
and proration, refer to Rule and Regulation 11.
3. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive
months, a Demand Meter will be installed as promptly as is practicable and thereafter continued
in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve
consecutive months, whereupon, at the option of the City, it may be removed.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time
periods as defined under Section D.2.
4. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said Rate Schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer
may request a Rate Schedule change to any applicable City of Palo Alto full-service Rate
Schedule as is suitable to their kilowatt Demand and kilowatt-hour usage.
5. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be offered,
but the City is not required to supply Service at a particular line voltage where it has, or will
install, ample facilities for supplying at another voltage equally or better suited to the Customer's
Item #3
Packet Pg. 171
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-4 Supersedes Sheet No E-4-TOU-4
Effective 7-1-20265 dated 7-1-20254
electrical requirements, as determined in the City’s sole discretion. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any Customer
receiving the discount in this section. The Customer then has the option to change his system so
as to receive Service at the new line voltage or to accept Service (without voltage discount)
through transformers to be supplied by the City subject to a maximum kilovolt-ampere size
limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio
$
9.098.50 $ 39.798.08 $ 48.886.58
Winter Perio 0.00 24.553.49 24.553.49
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue Meter are not operating,
the Maximum Demand will be reduced by the sum of the Maximum Generation of those
non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced
below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the
standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
Item #3
Packet Pg. 172
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-4-TOU-5 Supersedes Sheet No E-4-TOU-5
Effective 7-1-20265 dated 7-1-20254
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible
Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as
amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
Item #3
Packet Pg. 173
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-1 Supersedes Sheet No E-7-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to Demand metered Service for large non-residential Customers with
a Maximum Demand of at least 1,000KW per month per site, who have sustained this Demand
level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodit Distribution
Public
Benefits Total
Summer Perio
Demand Char e kW $ 12.9107 $ 32.961.54 $ 45.873.61
Ener Char e kWh 0.136812786 0.0042002 0.0063704 0.147383792
Winter Perio
Demand Char e kW $ 3.022.82 $ 29.007.75 $ 32.020.57
Ener Char e kWh 0.085317973 0.00411393 0.0063704 0.095798970
Customer Charge
$/month 611.03578.08
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
Item #3
Packet Pg. 174
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-2 Supersedes Sheet No E-7-2
Effective 7-1-20265 dated 7-1-20254
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account
or one Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule,
consists of one or more Accounts which cover contiguous parcels of land with no
intervening public right-of-ways (e.g. streets) and which have a common billing address.
4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the
City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-
type Demand Meter which does not reset after a definite time interval may be used at the
City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 pm on weekdays.
Item #3
Packet Pg. 175
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-3 Supersedes Sheet No E-7-3
Effective 7-1-20265 dated 7-1-20254
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.8 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change his system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kVA size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue Meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio $ 9.8925 $ 32.961.54 $ 42.850.79
Winter Perio $0.00 29.007.75 29.007.75
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section D.4)
Item #3
Packet Pg. 176
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-4 Supersedes Sheet No E-7-4
Effective 7-1-20265 dated 7-1-20254
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue Meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
Item #3
Packet Pg. 177
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-1 Supersedes Sheet No E-7-G-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This Rate Schedule applies to Customers who qualify for E-7 Service and who choose to
participate in the Palo Alto Green Program.
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodit Distribution
Public
Benefits
Palo Alto
Green
Char e Total
Summer Perio
Demand Char e er kW $ 12.9107 $ 32.961.54
$
45.873.6
1
Ener Char e er kWh
0.13681278
6 0.0042002 0.0063704 0.0075
0.15488
4542
Winter Perio
Demand Char e er kW $ 3.022.82 $ 29.007.75
$
32.020.5
7
Ener Char e er kWh
0.08531797
3 0.00411393 0.0063704 0.0075
0.10329
09720
Customer Char e $/month 611.03578.08
Item #3
Packet Pg. 178
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-2 Supersedes Sheet No E-7-G-2
Effective 7-1-20265 dated 7-1-20254
2. 1000 kWh Block Purchase Option:
Commodit Distribution Public Benefits Total
Summer Perio
Demand Char e er kW $ 12.9107 $ 32.961.54
$
45.873.6
1
Ener Char e er kWh
0.13681278
6 0.0042002 0.0063704
0.14738
3792
Palo Alto Green Char e er 1000 kWh block $ 7.50
Winter Perio
Demand Char e er kW $ 3.022.82 $ 29.007.75
$
32.020.5
7
Ener Char e er kWh
0.08531797
3 0.00411393 0.0063704
0.09579
8970
Palo Alto Green Char e er 1000 kWh block $7.50
Customer Char e $/month 611.03578.08
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
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LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-3 Supersedes Sheet No E-7-G-3
Effective 7-1-20265 dated 7-1-20254
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has dropped
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the
City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type
Demand Meter which does not reset after a definite time interval may be used at the City's
option.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts for the current month. An exception is that the Billing
Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual
Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays.
4. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account
or one Meter if the Accounts are at one site. A site, for the purposes of this Rate Schedule,
consists of one or more Accounts which cover contiguous parcels of land with no
intervening public right-of-ways (e.g. streets) and which have a common billing address.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile
6. Palo Alto Green Program Description and Participation
Palo Alto Green Service includes the purchase by the City of Palo Alto Utilities
Department of enough renewable energy credits (RECs) to match 100% of the metered
energy usage at the Customer’s facility each month. Any Customer may alternately request
that CPAU purchase a specific number of 1000 kilowatt-hour (kWh) blocks of RECs.
CPAU will charge the Customer the Palo Alto Green Charge for each such requested block.
These REC purchases support the production of renewable energy, increase the financial
value of power from renewal sources, and creates a transparent and sustainable market that
encourages new development of wind and solar.
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LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-4 Supersedes Sheet No E-7-G-4
Effective 7-1-20265 dated 7-1-20254
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any time,
in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.8 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a qualified line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited
to the Customer's Electrical requirements, as determined in the City’s sole discretion. The
City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then
has the option to change the system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
9. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e),
applies to Customers that have a non-utility generation source interconnected on
the Customer’s side of the City’s revenue Meter and that occasionally require
backup power from the City due to non-operation of the non-utility generation
source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Capacity)
Summer Period $ 9.8925 $ 32.961.54 $ 42.850.79
Winter Period 0.00 29.007.75 29.007.75
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3)
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LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-G-5 Supersedes Sheet No E-7-G-5
Effective 7-1-20265 dated 7-1-20254
occurs when one or more of the non-utility generators on the Customer’s side of
the City’s revenue Meter are not operating, the Maximum Demand will be reduced
by the sum of the Maximum Generation of those non-utility generators, but in no
event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle,
the standby charge does not apply and the Customer shall not receive the Maximum
Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
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LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-1 Supersedes Sheet No E-7-TOU-1
Effective 7-1-20265 dated 7-1-20254
A. APPLICABILITY:
This voluntary Rate Schedule applies to Demand metered Service for non-residential Customers
with a Maximum Demand of at least 1,000KW per month per site, who have sustained this
Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodit Distribution Public Benefits Total
Summer Perio
Demand Char e er kW
Peak $ 12.191.39 $ 17.066.33 $ 29.257.72
Max Deman 1.5646 17.066.33 18.627.79
Ener Char e er kWh
Peak
$
0.194738199 $ 0.0042002 $ 0.0063704 $ 0.2053019205
Mi -Peak 0.160494999 0.0042002 0.0063704 0.171066005
Off-Peak 0.120651276 0.0042002 0.0063704 0.131222282
Winter Perio
Demand Char e er kW
Peak $ 1.5646 $ 15.074.42 $ 16.635.88
Max Deman 1.5646 15.074.42 16.635.88
Ener Char e er kWh
Peak
$
0.130812225 $ 0.00411393 $ 0.0063704 $ 0.141293222
Mi -Peak
0.103230964
8 0.00411393 0.0063704 0.113710645
Off-Peak 0.071266660 0.00411393 0.0063704 0.081747657
Customer Char e $/month 611.03578.08
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LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-2 Supersedes Sheet No E-7-TOU-2
Effective 7-1-20265 dated 7-1-20254
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted
for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill
amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Energy
Peak: 4:00 pm to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 2:00 p.m. to 4:00 p.m. Monday through Friday (except holidays)
9:00 p.m. to 11:00 p.m.
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
WINTER PERIOD (Service from November 1 to April 30):
Energy
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Mid Peak: 9:00 a.m. to 2:00 p.m. Monday through Friday (except holidays)
Off-Peak: All other hours Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
Demand
Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays)
Max Demand: All hours Every day
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LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-3 Supersedes Sheet No E-7-TOU-3
Effective 7-1-20265 dated 7-1-20254
TYPES OF DEMAND CHARGES: The Peak Demand Charge per Kilowatt applies to the
maximum peak-period Demand during the time periods noted above. The Maximum (Max)
Demand charge per Kilowatt applies to the maximum Demand at any time during the month. Both
Demand Charges apply in each Billing Period, and the maximum peak-period Demand and
maximum Demand may occur at different times in the Billing Period depending on Customer
usage patterns.
SEASONAL RATE CHANGES: When the Billing Period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal period,
and the Charges based on the applicable rates therein. For further discussion of bill calculation
and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account or one
Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule, consists of
one or more Accounts which cover contiguous parcels of land with no intervening public right-of-
ways (e.g. streets) and which have a common billing address.
4. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive
months, a Demand Meter will be installed as promptly as is practicable and thereafter continued
in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve
consecutive months, whereupon, at the option of the City, it may be removed.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time
periods as defined under Section D.2.
5. Changing Rate Schedules
Customers electing to be served under E-7 TOU must remain on said Rate Schedule for a minimum
of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request
a Rate Schedule change to any applicable City of Palo Alto full-service Rate Schedule as is suitable
to their kilowatt Demand and kilowatt-hour usage.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is supplied,
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LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-4 Supersedes Sheet No E-7-TOU-4
Effective 7-1-20265 dated 7-1-20254
a discount of 2.8 percent for available line voltages above 2 kilovolts will be offered, but the City
is not required to supply Service at a particular line voltage where it has, or will install, ample
facilities for supplying at another voltage equally or better suited to the Customer's electrical
requirements, as determined in the City’s sole discretion. The City retains the right to change its
line voltage at any time after providing reasonable advance notice to any Customer receiving the
discount in this section. The Customer then has the option to change his system so as to receive
Service at the new line voltage or to accept Service (without voltage discount) through
transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodit Distribution Total
Standby Charge (per kW of
Reserved Ca acit
Summer Perio $ 9.8925 $ 32.961.54 $ 42.850.79
Winter Perio 0.00 29.007.75 29.007.75
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue Meter are not operating,
the Maximum Demand will be reduced by the sum of the Maximum Generation of those
non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced
below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the
standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
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LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-7-TOU-5 Supersedes Sheet No E-7-TOU-5
Effective 7-1-20265 dated 7-1-20254
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible
Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4) , as
amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
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