HomeMy WebLinkAboutStaff Report 2303-123515.PUBLIC HEARING: Adoption of a Resolution Approving the Fiscal Year 2024 Electric
Utility Financial Plan and Proposed Reserve Transfers, Deactivating Utility Rate Schedule
E‐HRA, and Amending Utility Rate Schedules E‐1, E‐2, E‐2‐G, E‐ 4, E‐4‐G, E‐4 TOU, E‐7, E‐
7‐G, E‐7 TOU, E‐NSE, and E‐EEC; CEQA Status: Not a project under Public Resources Code
15378(b)(5) and exempt under Public Resources Code 15273(a)
City Council
Staff Report
From: City Manager
Report Type: PUBLIC HEARING
Lead Department: Utilities
Meeting Date: April 17, 2023
Staff Report:2303-1235
TITLE
PUBLIC HEARING: Adoption of a Resolution Approving the Fiscal Year 2024 Electric Utility
Financial Plan and Proposed Reserve Transfers, Deactivating Utility Rate Schedule E‐HRA, and
Amending Utility Rate Schedules E‐1, E‐2, E‐2‐G, E‐ 4, E‐4‐G, E‐4 TOU, E‐7, E‐7‐G, E‐7 TOU, E‐NSE,
and E‐EEC; CEQA Status: Not a project under Public Resources Code 15378(b)(5) and exempt
under Public Resources Code 15273(a)
RECOMMENDATION
The Finance Committee and Staff recommend the City Council adopt a Resolution (Attachment
A):
1. Approving the FY 2024 Electric Financial Plan (Attachment B); and
2. Approving the following transfers at the end of FY 2023:
a. Up to $12 million from the Supply Operations Reserve to the Distribution Operations
Reserve; and
b. Up to $4.5 million from the Supply Operations Reserve to the Cap and Trade Program
Reserve; and
3. Approving the following transfers in FY 2024:
a. Up to $10 million from the Supply Operations Reserve to the Electric Special Projects
(ESP) reserve; and
b. Up to $8 million from the Supply Operations Reserve to the Hydroelectric Stabilization
Reserve; and
c. Up to $3 million from the Supply Operations Reserve to the Cap and Trade Program
Reserve; and
4. Approving the following rate actions for FY 2024 (Attachment C):
a. Deactivation of the hydroelectric rate adjuster from customer bills effective July 1,
2023;
b. An increase to retail electric rates E-1 (Residential Electric Service), E-2 (Small Non-
Residential Electric Service), E-4 (Medium Non-Residential Electric Service), E-4 TOU
(Medium Non-Residential Time of Use Electric Service), E-7 (Large Non-Residential
Electric Service), and E-7 TOU (Large Non-Residential Time of Use Electric Service) of
21% effective July 1, 2023;
c. An increase to the Export Electricity Compensation (E-EEC-1) rate to reflect 2022
avoided cost, effective July 1, 2023;
d. An increase to the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect
current projections of FY 2023 avoided cost, effective July 1, 2023; and
e. An update to the Residential Master-Metered and Small Non-Residential Green Power
Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-
4-G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate
schedules to reflect modified distribution and commodity components, effective July
1, 2023
EXECUTIVE SUMMARY
On March 21, 2023 the Finance Committee reviewed the recommended Council actions above
and unanimously recommended them for Council approval. The attached FY 2024 Electric Utility
Financial Plan (Attachment B) and proposed rate changes (Attachment C) reflect the Finance
Committee (and staff) recommendation. The actions above and rate changes included in
Attachment C result in the deactivation of the hydroelectric rate adjuster and a 21% increase to
the base electric rates, the net effect of which is a 5% decrease to the customer bill. Approval of
this item would result in implementation of the finalized rates for FY 2024, beginning July 1, 2023.
BACKGROUND
Every year staff presents the Finance Committee with Financial Plans for its Electric, Gas, Water,
and Wastewater Collection Utilities and recommends any rate adjustments required to maintain
their financial health. These Financial Plans include a comprehensive overview of the utility’s
operations, both retrospective and prospective, and are intended to be a reference for UAC and
Council members as they review the budget and staff’s rate recommendations. Each Financial
Plan also contains a set of Reserves Management Practices describing the reserves for each utility
and the management practices for those reserves
ANALYSIS
Staff and the Finance Committee propose a set of electric utility rate changes that will decrease
bills by 5%. The proposal involves deactivating the hydroelectric rate adjuster while increasing
base electric rates 21%, for a net decrease in utility bills of 5%. This is in contrast to the original
staff proposal recommended for approval by the UAC in March of this year, which involved a 50%
reduction in the hydroelectric rate adjuster and a 14% increase in the base electric rates. The
new proposal is made possible by the pending receipt of a $24 million refund from the Bureau of
Reclamation of overcharges associated with the Central Valley Project, where the City gets most
of its hydroelectric power, due to a successful result in litigation the City participated in against
the Federal Bureau of Reclamation over overcharges associated with the Central Valley Project.
Additional detail on the staff proposal is available in the study session staff report on tonight’s
Council agenda (Staff Report 2304-1247, April 17, 2023) and in the March 21, 2023 Finance
Committee staff report (Staff Report 2303-1109).1
FISCAL/RESOURCE IMPACT
The resource impact of the recommendations summarized in this report is the continued
financial solvency of the electric utility and, as the City is a ratepayer, an increase to General Fund
expenses (due to the rate increases) and revenues (due to the General Fund transfer). The
estimated FY 2024 revenue impact of the recommendations in this report would be a $12 million
increase or 6% compared to FY 2023 levels in the Electric Fund (excluding expected monies to be
received from the CVPIA payment). General Fund utility bill costs are expected to increase by
$0.14 million as a result of these rate changes.
POLICY IMPLICATIONS
The proposed electric rate adjustments are consistent with Council-adopted Reserve
Management Practices that are part of the Financial Plan and were developed using a cost-of-
service study and methodology consistent with the California constitution and industry-accepted
cost of service principles. As noted in the Reserves Management Practices (Appendix C of
Attachment B), if reserves fall below the minimum guidelines, Council approval is required for a
rate plan that requires more than one year to return reserves to within guideline levels.
COMMITTEE AND COMMISSION REVIEW
Utilities staff presented a different proposal to the UAC on March 1, 2023 which is summarized
in the staff report presented to the UAC that evening.2
Staff presented to the Finance Committee on March 21, 20233 a recommendation that Council
approve the FY 2024 Electric Utility Financial Plan as follows, as detailed in staff report
2303-1141:
At the March 21 Finance Committee meeting, Staff recommended the following transfers at the
end of FY 2023:
1. Up to $12 million from the Supply Operations Reserve to the Distribution Operations
Reserve; and
2. Up to $4.5 million from the Supply Operations Reserve to the Cap and Trade Program
Reserve; and
1Council Staff Report 2303-1109
https://cityofpaloalto.primegov.com/meeting/document/1854.pdf?name=Item%204%20Staff%20Report
2 Utilities Advisory Commission Staff Report https://www.cityofpaloalto.org/files/assets/public/agendas-minutes-
reports/agendas-minutes/utilities-advisory-commission/archived-agenda-and-minutes/agendas-and-minutes-
2023/03-mar-2023/03-01-2023-item-4.pdf
3 Finance Committee Staff Report 2303-1141
https://cityofpaloalto.primegov.com/Portal/Meeting?meetingTemplateId=11228
In addition, Staff recommended the following transfers in FY 2024:
3. Up to $10 million to the Electric Special Projects (ESP) reserve from the Supply Operations
Reserve; and
4. Up to $8 million to the Hydroelectric Stabilization Reserve from the Supply Operations
Reserve; and
5. Up to $3 million from the Supply Operations Reserve to the Cap and Trade Program
Reserve; and
Staff also recommended the following rate actions for FY 2024:
6. Deactivation of the hydroelectric rate adjuster from customer bills effective July 1, 2023;
and
7. An increase to retail Electric Utility Rates E-1 (Residential Electric Service), E-2 (Small Non-
Residential Electric Service), E-4 (Medium Non-Residential Electric Service), E-4 TOU
(Medium Non-Residential Time of Use Electric Service), E-7 (Large Non-Residential
Electric Service), and E-7 TOU (Large Non-Residential Time of Use Electric Service) of 21%
effective July 1, 2023; and
8. An increase to the Export Electricity Compensation (E-EEC-1) rate to reflect 2022 avoided
cost, effective July 1, 2023; and
9. An increase to the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect current
projections of FY 2023 avoided cost, effective July 1, 2023; and
10. An update to the Residential Master-Metered and Small Non-Residential Green Power
Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4-
G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate schedules to
reflect modified distribution and commodity components, effective July 1, 2023
The Finance Committee unanimously recommended approval of this proposal on March 21,
2023.
STAKEHOLDER ENGAGEMENT
These recommendations were reviewed by the UAC and Finance Committee in public meetings.
The public will be notified of the final rate changes adopted by Council through various channels,
including social media, the website, utility bill inserts, and City newsletters. Published in the Palo
Alto Daily on Friday, April 7th and 14th, 2023.
ENVIRONMENTAL REVIEW
The Council’s approval of the Electric Financial Plan does not meet the California
Environmental Quality Act’s (CEQA) definition of a project under Public Resources Code Section
21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative governmental
activity which will not cause a direct or indirect physical change in the environment, and
therefore, no environmental assessment is required. The Council finds that changing electric
rates to meet operating expenses, purchase supplies and materials, meet financial reserve
needs and obtain funds for capital improvements necessary to maintain service is not subject
to CEQA, pursuant to California Public Resources Code Sec. 21080(b)(8) and CEQA Guidelines
section 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.
ATTACHMENTS
Attachment A: Electric Resolution FY24
Attachment B: Electric FY 2024 Financial Plan
Attachment C: Rate Schedule Combined
APPROVED BY:
Dean Batchelor, Director Utilities
Staff: Micah Babbitt
Attachment A
6056737CUtility Electric Rate
Schedules FY24 Electric
Financial Plan
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*Yet to be Passed*
Resolution No.
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2024 Electric Utility Financial Plan and Reserve Transfers, Deactivating
Utility Rate Schedule E-HRA (Electric Hydro Rate Adjuster), and Amending
Utility Rate Schedules E-1 (Residential Electric Service), E-2 (Residential
Master-Metered and Small Non-Residential Electric Service), E-2-G
(Residential Master- Metered and Small Non-Residential Green Power
Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium
Non-Residential 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-NSE (Net
Surplus Electricity Compensation Rate), and E-EEC (Export Electricity
Compensation)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes making
long-term projections of market conditions, the physical condition of the system, and other
factors that could affect utility costs, and setting rates adequate to recover these costs. It does
this with the goal of providing safe, reliable, and sustainable utility services at competitive rates.
The City adopts Financial 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 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 April 17, 2023, 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 FY 2024 Electric Utility Financial Plan
Attachment A
6056737CUtility Electric Rate
Schedules FY24 Electric
Financial Plan
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SECTION 2. The Council hereby approves the following transfers to be made by the
end of FY 2023, as described in the FY 2024 Electric Utility Financial Plan:
a. A transfer of up to $12 million from the Supply Operations Reserve to the
Distribution Operations Reserve; and
b. A transfer of up to $4.5 million from the Supply Operations Reserve to the Cap and
Trade Program Reserve; and
SECTION 3. The Council hereby approves the following transfers to be made by the
end of FY 2024, as described in the FY 2024 Electric Utility Financial Plan:
a. A transfer of up to $10 million from the Supply Operations Reserve to the Electric
Special Projects (ESP) reserve; and
b. A transfer of up to $8 million from the Supply Operations Reserve to the
Hydroelectric Stabilization Reserve; and
c. A transfer of up to $3 million from the Supply Operations Reserve to the Cap and Trade
Program Reserve; and
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-HRA (Electric Hydro Rate Adjuster) is hereby deactivated, effective July 1,
2023.
SECTION 5. 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, 2023.
SECTION 6. 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, 2023.
SECTION 7. 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, 2023.
SECTION 8. 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, 2023.
SECTION 9. 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
Attachment A
6056737CUtility Electric Rate
Schedules FY24 Electric
Financial Plan
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become effective July 1, 2023.
SECTION 10. 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, 2023.
SECTION 11. 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, 2023.
SECTION 12. 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, 2023.
SECTION 13. 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, 2023.
SECTION 14. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-NSE (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, 2023.
SECTION 15. 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, 2023.
SECTION 16. The Council makes the following findings:
a. 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.
b. The fees and charges adopted by this resolution are charges imposed for a specific
government service or product provided directly to the payor that are not provided
to those not charged, and do not exceed the reasonable costs to the City of providing
the service or product.
//
//
Attachment A
6056737CUtility Electric Rate
Schedules FY24 Electric
Financial Plan
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//
SECTION 17. The Council finds that approving the Financial Plan and Reserve transfers
does not meet the California Environmental Quality Act’s (CEQA) definition of a project under
Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an
administrative governmental activity which will not cause a direct or indirect physical change in
the environment, and therefore, no environmental assessment is required. The Council finds that
changing electric rates to meet operating expenses, purchase supplies and materials, meet
financial reserve needs and obtain funds for capital improvements necessary to maintain service
is not subject to the California Environmental Quality Act (CEQA), pursuant to California Public
Resources Code Sec. 21080(b)(8) and CEQA Guidelines Sec. 15273(a). After reviewing the staff
report and all attachments presented to Council, the Council incorporates these documents
herein and finds that sufficient evidence has been presented setting forth with specificity the
basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
Assistant City Attorney City Manager
Director of Utilities
Director of Administrative Services
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FY 2024 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2024 TO FY 2028
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FY 2024 ELECTRIC UTILITY
FINANCIAL PLAN
FY 2024 TO FY 2028
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations.................................................................................4
Section 2: Executive Summary and Recommendations............................................................5
Section 2A: Overview of Financial Position..................................................................................5
Section 2B: Summary of Proposed Actions..................................................................................9
Section 3: Detail of FY 2023 Rate and Reserves Proposals......................................................10
Section 3A: Rate Design.............................................................................................................10
Section 3B: Current and Proposed Rates...................................................................................11
Section 3C: Bill Impact of Proposed Rate Changes....................................................................13
Section 3D: Proposed Reserve Transfers ...................................................................................14
Section 4: Utility Overview ....................................................................................................16
Section 4A: Electric Utility History .............................................................................................16
Section 4B: Customer Base........................................................................................................19
Section 4C: Distribution System.................................................................................................19
Section 4D: Cost Structure and Revenue Sources ......................................................................20
Section 4E: Reserves Structure ..................................................................................................21
Section 4F: Competitiveness......................................................................................................22
Section 5: Utility Financial Projections...................................................................................23
Section 5A: Load Forecast .........................................................................................................23
Section 5B: FY 2018 to FY 2022 Cost and Revenue Trends ........................................................25
Section 5C: FY 2022 Results.......................................................................................................27
Section 5D: FY 2023 Projections ................................................................................................28
Section 5E: FY 2024 – FY 2028 Projections ................................................................................28
Section 5F: Risk Assessment and Reserves Adequacy................................................................30
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Section 5G: Long-Term Outlook.................................................................................................36
Section 5H: Alternative Rate Projections...................................................................................38
Section 6: Details and Assumptions .......................................................................................39
Section 6A: Electricity Purchases...............................................................................................39
Section 6B: Operations..............................................................................................................41
Section 6C: Capital Improvement Program (CIP).......................................................................42
Section 6D: Debt Service............................................................................................................43
Section 6E: Equity Transfer........................................................................................................44
Section 6F: Wholesale Revenues and Other Revenues..............................................................44
Section 6G: Sales Revenues .......................................................................................................45
Section 7: Communications Plan............................................................................................46
Appendices............................................................................................................................48
Appendix A: Electric Utility Financial Forecast Detail................................................................49
Appendix B: Electric Utility Reserves Management Practices ...................................................53
Appendix C: Description of Electric utility Operational Activities ..............................................58
Appendix D: Samples of Recent Electric Utility Outreach Communications ..............................59
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SECTION 1: DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a section
of the distribution system operates. The transmission system operates at 115-500 kV,
and this is lowered to 60 kV in the sub-transmission section of the Electric Utility’s
distribution section, then 12 kV or 4 kV in the rest of the distribution system, and
finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum electricity
demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Sub-transmission System: The section of the Electric Utility’s distribution system that operates
at 60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115 kV
or more. The voltage at the intersection of the Electric Utility’s distribution system
and PG&E’s transmission system is 115 kV. The Electric Utility does not own or operate
any transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
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SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City of Palo Alto (City) Electric Utility for the next
five-year forecast, FY 2024 - 2028. This Financial Plan describes how revenues will cover the costs
of operating the utility safely over that time while adequately investing for the future. It also
addresses the financial risks facing the utility over the short term and long term and includes
measures to mitigate and manage those risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
From July 2019 through April 2022 the City did not increase rates, to mitigate the economic
impact of the COVID-19 pandemic on residents and businesses. In that time supply and
distribution expenses increased $50 million (30%). The expense increases combined with
pandemic-related electricity sales revenue declines created a $43 million shortfall in FY 2022.
Some of this was related to the impacts of extreme drought and rising electricity market prices,
and in response, the City activated the hydroelectric rate adjuster (E-HRA) in April 2022. In 2023
the City began increasing base rates to begin recovering costs, starting with a 5% rate increase
on July 1, 2022. The intent was to use loans from the Electric Special Projects Reserve and what
Operations Reserves remained to phase in rate increases gradually. But in late 2022 electricity
market prices increased at unprecedented levels, leading to the need to increase the
hydroelectric rate adjuster on January 1, 2023 to match the cost of replacing hydroelectric power
with market power. Costs are projected to exceed revenues again in FY 2023, leading to further
depletion of reserves.
This forecast assumes some decrease in power prices after this year, but prices are expected to
continue to remain elevated over FY 2022 and earlier levels based on forward market price curves
developed by OTC Global Holdings, an independent commodity broker. Some recovery of
hydroelectric generation is forecasted in FY 2024 based on the Western Area Power
Administration’s current forecast, but not to normal levels given the dry ground and low reservoir
levels, which are expected to absorb a significant share of precipitation even if it is above average.
Normal levels of hydroelectric generation are not forecasted until FY 2026, assuming normal
rainfall in the winter of 2022/2023 and 2023/2024. The forecast assumes it takes multiple years
to recover because reservoirs can take multiple seasons to fill and return to normal operations
based on historical experience. To reduce hydroelectric-related volatility in the future, staff is
now making its rate projections assuming that long-term “normal” production from the City’s
hydroelectric resources is about 80% of historical average levels.
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Since presenting the rate proposal and financial plan to the UAC on March 1, 2023, new
information has arisen that materially improves the electric utility’s financial position. Staff
expects to receive a $24 million payment in the coming weeks from successful litigation against
the Bureau of Reclamation for overcharges related to power purchased from the Central Valley
Project. The litigation was filed in 2014 by the Northern California Power Agency (NCPA) and its
members (NCPA, City of Redding and City of Roseville v. United States; Case No. 14-817C)1. Based
on the information, staff revised the rate proposal provided to the UAC and proposes a net
average rate reduction of 5%. The net rate reduction results from the combination of deactivating
the hydroelectric rate adjuster (HRA) and increasing the base rates by 21%. The previous plan
presented to UAC reduced the HRA by 50% and increased the base rates by 14%, resulting in a
negligible average rate change. However, the $24M damages repayment can be used to replenish
reserves with some funds available for rate stabilization, providing adequate reserves to manage
hydroelectric risk and enabling future rate increases to be phased over a slightly longer period.
Significantly for this year’s rate proposal, the replenished reserves enable the HRA to be removed
entirely.
Over the forecast period other costs are increasing as well. Cost increases include:
•Significant increases in transmission costs
•Significant increases in capital investment to replace aging infrastructure
•Increased operations costs
•Debt service costs for grid modernization improvements and investments in fiber
infrastructure to support AMI.
Long-term costs are expected to continue to increase, so the 5% drop in customer bills forecast
for July 1, 2023 is projected to be offset with a 5% increase in FY 2025 and another increase of
5% in FY 2026 as shown in table 3, even if hydroelectric and power market conditions improve.
There are some significant uncertainties in this forecast. Load is assumed to stay fairly flat in this
forecast, with long-term declines in electric load offset by some load growth due to electrification
and potential new data centers. If load growth exceeds expectations, it could improve this
forecast and reduce the size of future rate increases. On the other hand, if costs for
electrification-related grid modernization and electrification programs exceed forecasts, which is
quite possible given the high uncertainties involved in current cost projections, it could offset the
benefits of increased load.
The Electric Utility’s costs are projected to decline by about 2% per year from FY2023 levels,
before then increasing again in FY2026, for an average of 1% increase from FY 2024 - 2028, as
shown in Table 1. As noted above most of the costs are related to electric supply purchases,
which continue to increase mainly due to rising transmission costs over the span of the financial
plan, but also higher commodity costs in the near term due to low hydro conditions and higher
1 NCPA is a Joint Powers Authority with sixteen public electric utility members, including the City of Palo
Alto.
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market prices. Overall supply costs are projected to increase at an estimated 0.5% per year on
average from FY2023 levels, which are estimated to be the highest on record. Operations and
maintenance costs are about 30% of total costs and are projected to increase by about 1.5% per
year on average due to both inflation as well as salary and benefits increases. Capital
improvement costs are projected to fall slightly in the short term as the Smart Grid technology
project and rebuilding of the Foothill distribution system spending declines from its peaks in
FY2022 and FY2023, then stabilize just over $20 million a year thereafter. Ongoing projects will
include rebuilds of existing underground districts as well as substation improvements and voltage
conversion projects.
As shown in Table 1, debt service payments for grid modernization and fiber begin in FY2025 and
increase to $9.6m in FY2028. These new bonds and investments are expected to commence in
FY2024 as shown in Table 1.1 below.
Table 1: Electric Utility Expenses for FY 2022 to FY 2028
Expenses ($000)FY 2022
(act)
FY 2023
(est)FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Power Supply Purchases 112,525 117,900 118,019 115,638 118,069 118,851 121,028
Operations 61,948 69,337 68,329 65,303 66,547 67,638 64,877
Capital Projects 34,525 28,991 25,508 24,610 22,644 22,716 22,730
Debt Service from Grid
Modernization and Fiber
Projects
2,032 3,632 6,432 9,632
TOTAL 208,998 216,228 211,856 207,583 210,892 215,637 218,268
Table 2.1: Electric Utility Investments FY 2024 to FY 2028
Expenses ($000)FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Grid Modernization
Projects 25,000 25,000 50,000 50,000 50,000
Electric Utility Fiber
Backbone 13,000 0 0 0 0
TOTAL 38,000 25,000 50,000 50,000 50,000
Table 2 below shows the proposed rate projections alongside the current rates with the
hydroelectric rate adjuster. While base rates increase by 21%, the removal of the hydroelectric
rate adjuster means that the total effective rate for FY2024 is 5% lower than the current total
effective rate.
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Table 3: Projected Electric Rates, FY 2024 to FY 2028
Current Proposed Projected
Projection Mid-Year
FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
System Average Base Rates
($/kWh)$0.171 $0.208 $0.217 $0.227 $0.237 $0.249
Proposed % Base Rate
Increase 21%5%5%5%5%
Hydroelectric Rate Adjuster
($/kWh)$0.048 Inactive Inactive Inactive Inactive Inactive
Proposed % HRA Decrease -100%0%0%0%0%
Total System Average Rate
($/kWh)
(with Hydroelectric Rate
Adjuster)
$0.219 $0.208 $0.217 $0.227 $0.237 $0.249
% Change in Total System
Average Rate -5%5%5%5%5%
The rate changes above are made possible by the $24 million refund from the successful litigation
against the Bureau of Reclamation for overcharges related to power purchases from the Central
Valley Project. Staff is proposing to use $10 million of the funds to repay a loan from the Electric
Special Projects Reserve.
•In FY 2018 Council approved (Staff Report 81862), a $10 million transfer from the Electric
Special Projects (ESP) 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. $5 million was repaid in FY 2020
•In FY 2022 Council approved (Staff Report 13361, June 13, 2022), a $5 million transfer
from the ESP Reserve to the Operations Reserve to avoid rate increases exceeding 5%.
Staff proposes using $8 million of the $24 million refund payment from the Central Valley Project
litigation to fund the balance of the Hydroelectric Stabilization Reserve, bringing the balance
above the minimum requirement and eliminating the need for the hydroelectric rate adjuster.
Table 4 shows the projected reserve transfers over the forecast period.
2 https://www.cityofpaloalto.org/files/assets/public/agendas-minutes-reports/reports/city-
manager-reports-cmrs/year-archive/2017/8186.pdf
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Table 4: Reserves Starting and Ending Balances, Revenues, Expenses, Transfers To/(From)
Reserves, Operations and Capital (CIP) Reserve Guideline Levels for FY 2023 to FY 2028 ($000)
FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Starting Reserve Balances
1 Supply Operations 27,197 14,378 14,003 19,933 27,680 33,136
2 Distribution Operation 2,945 5,077 7,208 10,124 10,673 12,304
3 CIP 880 880 880 880 5,880 10,880
4 Electric Special Projects 24,649 17,649 24,649 24,649 26,649 28,649
5 Hydro Stabilization 400 400 8,400 8,400 8,400 8,400
6 Low Carbon Fuel Standard 7,236 6,214 5,142 4,574 4,121 3,668
7 Cap and Trade Program 1,189 5,612 8,577 11,307 11,307 11,307
Revenues
8 Supply 134,629 141,976 132,031 136,751 134,384 135,204
9 Distribution 60,314 79,398 86,837 94,660 100,856 107,187
Transfers
a
-From Supply Operations to
Distribution (12,000)
b
-From Supply Operations to Cap
and Trade Program (4,423)(2,965)(2,730)
c
-Into Supply Operations from
ESP -
a+b+c = 10 Supply Operations Total (16,423)(12,965)(2,730)(2,000)(2,000)(2,000)
11 Distribution Operations 12,000 --(5,000)(5,000)(5,000)
12 CIP ---5,000 5,000 5,000
13 Electric Special Projects -10,000 -2,000 2,000 2,000
14 Hydro Stabilization -8,000 ----
15 Low Carbon Fuel Standard ------
16 Cap and Trade Program 4,423 2,965 2,730 ---
Capital Program Contribution
17 Distribution Operations
18 CIP Reserve
Expenses
19 Supply Funded Expenses (131,025)(129,386)(123,371)(127,004)(126,927)(131,698)
20 Distribution Non-CIP Expenses (48,191)(54,759)(58,311)(63,467)(67,510)(78,601)
21 Planned CIP (21,991)(22,508)(25,610)(25,644)(26,716)(25,730)
22 ESP Funded (7,000)(3,000)---(10,000)
23 Hydro Funded ------
24 LCFS Funded (1,022)(1,072)(568)(453)(453)-
Ending Reserve Balance
1+8+10+19 Supply Operations 14,378 14,003 19,933 27,680 33,136 34,643
2+9+11+17+20+21 Distribution Operation 5,077 7,208 10,124 10,673 12,304 10,160
3+12+18 CIP 880 880 880 5,880 10,880 15,880
4+13+22 Electric Special Projects 17,649 24,649 24,649 26,649 28,649 20,649
5+14+23 Hydro Stabilization 400 8,400 8,400 8,400 8,400 8,400
6+15+24 Low Carbon Fuel Standard 6,214 5,142 4,574 4,121 3,668 3,668
7+16 Cap and Trade Program 5,612 8,577 11,307 11,307 11,307 11,307
Operations Reserve Guidelines (Supply)
25 Minimum 21,749 21,765 20,739 21,164 21,326 21,706
26 Max imum 43,499 43,530 41,478 42,328 42,652 43,412
Operations Reserve Guidelines (Distribution)
27 Minimum 9,057 8,913 9,458 9,975 10,658 10,788
28 Max imum 15,785 15,419 16,437 17,396 18,687 18,867
CIP Reserve Guidelines
29 Minimum 4,938 5,174 5,685 4,215 4,392 5,873
30 Max imum 24,688 25,869 28,425 31,223 34,288 34,288
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SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff recommends the City Council adopt a Resolution:
1. Approving the Fiscal Year (FY) 2024 Electric Financial Plan;
2. Approving the following transfers at the end of FY 2023:
a. Up to $12 million from the Supply Operations Reserve to the Distribution
Operations Reserve; and
b. Up to $4.5 million from the Supply Operations Reserve to the Cap and Trade
Program Reserve; and
3. Approving the following transfers in FY 2024:
a. Up to $10 million from the Supply Operations Reserve to the Electric Special
Projects (ESP) reserve; and
b. Up to $8 million from the Supply Operations Reserve to the Hydroelectric
Stabilization Reserve; and
c. Up to $3 million from the Supply Operations Reserve to the Cap and Trade
Program Reserve; and
4. Approving the following rate actions for FY 2024:
a. Deactivation of the hydroelectric rate adjuster from customer bills effective July
1, 2023;
b. An increase to retail electric rates E-1 (Residential Electric Service), E-2 (Small Non-
Residential Electric Service), E-4 (Medium Non-Residential Electric Service), E-4
TOU (Medium Non-Residential Time of Use Electric Service), E-7 (Large Non-
Residential Electric Service), and E-7 TOU (Large Non-Residential Time of Use
Electric Service) of 21% effective July 1, 2023;
c. An increase to the Export Electricity Compensation (E-EEC-1) rate to reflect 2022
avoided cost, effective July 1, 2023;
d. An increase to the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect
current projections of FY 2023 avoided cost, effective July 1, 2023; and
e. An update to the Residential Master-Metered and Small Non-Residential Green
Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric
Service (E-4-G), and the Large Non-Residential Green Power Electric Service (E-7-
G) rate schedules to reflect modified distribution and commodity components,
effective July 1, 2023.
SECTION 3: DETAIL OF FY 2024 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The Electric Utility’s rates are evaluated and implemented in compliance with cost of service
requirements set forth in the California Constitution and applicable statutory law. This Financial
Plan is based on staff’s assessment of the financial position of the Electric Utility and updated
using the methodology from the “City of Palo Alto Electric Cost of Service and Rate Study”3
3 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
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drafted by EES Consulting, Inc. in 2015/16. The COSA is also based on design guidelines adopted
by Council on September 15, 2015 (Staff Report 6061).
SECTION 3B: CURRENT AND PROPOSED RATES
The City adopted the current rates effective July 1, 2022, when CPAU increased electric rates by
5%. Staff held back further rate increases during the COVID-19 pandemic and instead drew down
reserves. While using reserves mitigated larger increases during the pandemic, costs have
continued to rise and higher rates are needed to recover costs. In order to move towards full cost
recovery, staff recommends a rate increase to all customer classes of 21%. Staff is also engaging
the services of consultants to review and revise the Electric Utility’s Cost of Service study and
rates. This study will examine how costs are allocated among the residential and commercial
classes and realign them if needed, and will develop cost-based rates for several emerging
groups, such as: all-electric customers, DC-fast charging facilities, and micro-grid customers. The
current rates and proposed FY 2024 rates are reflected in Table 4 below:
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Table 5: Current and Proposed Electric Rates
Net Energy Metering Compensation Rates
The City operates two Net Energy Metering (NEM) programs. Solar customers served by the City
of Palo Alto's (CPAU) original NEM program, also called NEM 1, are compensated at retail rates
for electricity they export to the grid, and solar customers served by the NEM successor program,
or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are compensated at
the Export Electricity Compensation (EEC-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) rate. The Net Surplus Electricity
Propo sed
Rates
(7/1/2023)$%
Electric Hydro Rate Adjus ter
E-HRA ($/kWh)0.04800 0.00000 -0.04800 -100%
E-1 (Res idential )
Tier 1 Energ y ($/kWh)0.14445 0.17522 0.03077 21%
Tier 2 Energ y ($/kWh)0.20335 0.24666 0.04331 21%
Minimum Bill ($/day)0.34470 0.41812 0.07342 21%
Summer Energ y ($/kWh)0.21896 0.26560 0.04664 21%
Winter Energy ($/kWh)0.15355 0.18626 0.03271 21%
Minimum Bill ($/day)0.87770 1.06465 0.18695 21%
Summer Energ y ($/kWh)0.13490 0.16363 0.02873 21%
Winter Energy ($/kWh)0.10443 0.12667 0.02224 21%
Summer Demand ($/kW)30.36000 36.82668 6.46668 21%
Winter Demand ($/kW)19.92000 24.16296 4.24296 21%
Minimum Bill ($/day)18.13790 22.00127 3.86337 21%
Summer Energ y ($/kWh)0.12004 0.14561 0.02557 21%
Winter Energy ($/kWh)0.08125 0.09856 0.01731 21%
Summer Demand ($/kW)32.22000 39.08286 6.86286 21%
Winter Demand ($/kW)17.90000 21.71270 3.81270 21%
Minimum Bill ($/day)51.56960 62.55392 10.98432 21%
Cu rrent Rates Change
E-2 & E-2-G (Smal l Non-Res idential)
E-4 & E-4-G (Medium Non-Res idential)
E-7 & E-7-G (Large Non-Res idential)
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Compensation rate represents the value of the City’s avoided cost or value of customer-
generated electricity in Palo Alto, including compensation for the energy, avoided capacity
charges, avoided transmission and ancillary service charges, avoided transmission and
distribution (T&D) losses, and renewable energy credits (RECs), or environmental attributes. Staff
proposes increasing the E-NSE-1 rate to $0.1535/kWh based on updated avoided cost
calculations for 2022 reflecting the greatly increased electricity market prices expected to
continue into the future.
Under the City’s NEM successor program, participating solar customers in Palo Alto are billed at
the current retail rate for electricity drawn from the grid, and receive a credit for electricity they
export to the grid at the Export Electricity Compensation (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 for solar generation in Palo Alto is 10.45 cents/kWh, which is significantly lower than
the avoided cost on the proposed NEM compensation rate (16.85 cents/kWh). This increase in
the overall avoided cost is driven by greatly increased electricity market prices.
Table 5: NEM Buyback Rates – Current vs. Proposed
Rate
Current
$/kWh
Proposed
$/kWh
Export Electricity (E-EEC)$0.1045 $0.1685
Net Surplus Electricity (E-NSE)$0.1026 $0.1535
Palo Alto Green (PAG) Program
The Palo Alto Green (PAG) program provides CPAU’s commercial customers an opportunity to
voluntarily pay a premium to receive renewable electricity credits to match their energy usage.
Under this program, CPAU staff purchase and retire Green-e certified renewable energy
certificates (RECs) in the wholesale market on behalf of PAG customers. This enables participating
commercial customers to claim credit for the REC purchases in order to satisfy their corporate
sustainability goals and meet federal “green certification” requirements.
The PAG charge is a pass-through charge; the revenue collected through the PAG rate premium
is intended to fully recover the costs of administering the program. The PAG program has very
low overhead costs (e.g., the cost of hiring an auditor to carry out an annual Green-e verification
process for the program), so the vast majority of the program cost is the purchase cost of the
RECs. In the past year the wholesale cost of Green-e certified RECs in the Western US market has
remained relatively flat at around $6.5/REC. As such, the PAG rate premium should remain at
$7.5 per 1,000 kWh block (.75 cents/kWh), enough to cover the cost of the RECs and overhead.
The PAG rate premium is reflected on the Residential Master-Metered and Small Non-Residential
Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service
(E-4-G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate schedules.
14 | P a g e
SECTION 3C: BILL IMPACT OF PROPOSED RATE CHANGES
Table 6 shows the impact of the proposed July 1, 2023 rate changes on the residential and non-
residential bills for various consumption levels. For more on comparisons of rates with
surrounding agencies, see Section 4F: Competitiveness below.
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Table 6: Impact of Proposed Electric Rate Changes on Customer Bills
Bill under Change
Rate
Schedule
Usage
(kWh/mo)
Peak
Demand
(kW-mo)
Current
Rates
($/mo)
Bill Under
Rates Proposed
7/1/23 ($/mo)$/mo %
300 N/A $58 $53 ($5)-9%
(Summer
Median)
365
N/A $72 $66 ($6)-8%
(Winter
Median)
453
N/A $94 $88 ($6)-7%
650 N/A $144 $137 ($7) -5%
E-1
(Residential)
1200 N/A $282 $272 ($10) -3%
E-2 (Small
Non-
Residential)
1,000 N/A $234 $226 ($8) -4%
160,000 274 $33,715 $31,580 ($2,135)-6%E-4 (Medium
Non-
Residential)500,000 856 $105,352 $98,680 ($6,672)-6%
E-7 (Large
Non-
Residential
2,000,000 3,424 $383,095 $348,247 ($34,849)-9%
SECTION 3D: PROPOSED RESERVE TRANSFERS
In FY 2018, Council approved a $10 million loan from the ESP Reserve. Prior financial plans
assumed full repayment by FY 2025, but with the $24 million refund payment from the successful
litigatoin against the Bureau of Reclamation, staff is proposing to repay the loan early. Staff
proposes using $8 million of the $24 million payment to increase the balance of the hydro
stabilization reserve from the current level of $400,000 above the minimum guideline level, but
still below the target level of $19 million.
Given the drought over the prior 3 years and FY 2023 hydroelectric projections currently
remaining fairly low, there is an estimated supply cost increase of $8-$10 million in FY 2023
compared to FY 2022. Because of this, Council approved an increase to the hydroelectric rate
adjuster effective January 1, 2023 to bring in additional revenue to cover increased supply costs.
Staff proposes to eliminate the HRA mechanism in FY 2024 given the $8 million that can be
transferred into the hydro stabilization reserve.
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The remaining $6 million would be added to the Supply and Distribution Operations Reserve and
used to phase in the rate increases needed to stabilize those reserves slightly more gradually over
the forecast period.
There are repayments of $2 million per year from FY 2026 through FY 2030 to the ESP Reserve
for loans to the electric, gas, and fiber utilities for AMI investments.
The City maintains a Cap and Trade Program Reserve within the Electric fund to hold revenues
from the sale of carbon allowances freely allocated by the California Air Resources Board to the
City’s electric utility. Cap and Trade Program revenues are provided to the electric utility to
support a wide variety of carbon reducing activities, including local decarbonization. Until the
establishment of the REC Exchange program, adopted by Council in August 2020 (Staff Report
#11556),4 all of this revenue was spent on purchasing renewable energy. In accordance with
Council’s August 2020 direction, the City has began exchanging certain types of renewable energy
to take advantage of market conditions to reduce supply costs, fund electric utility programs and
capital investment, and raise funds for local decarbonization. For FY 2021 and FY 2022 Council
directed that 1/3 of the revenue be used for local decarbonization and 2/3 for rate reduction. On
December 12, 20225 Council approved continuation of the program with 100% of revenue going
to local decarbonization. In accordance with Council policy, staff will fund the Cap and Trade
Program Reserve with unspent revenues from the sale of carbon allowances freely allocated to
the electric utility in an amount equal to 100% of the FY 2022 Renewable Energy Credit (REC)
Exchange program revenues, currently estimated to be between $2.7 million and $4.5 million
going forward, for future local decarbonization projects.
Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E:
FY 2022 – FY 2026 Projections show the impact of these transfers on reserves levels. Table 7
shows the projected balance of each of the Electric Utility reserves for the period covered by this
Financial Plan. See also: Appendix A: Electric Utility Financial Forecast Detail
4 https://www.cityofpaloalto.org/civicax/filebank/documents/78046
5 https://cityofpaloalto.primegov.com/Portal/Meeting?meetingTemplateId=8713
Agenda Item 3, Utilities Advisory Commission Recommend the City Council Affirm the
Continuation of the REC Exchange Program, Staff Report #14375
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Table 7: End of Fiscal Year Electric Utility Reserve Balances for FY 2022 to FY 2028
SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4A: ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel engine
in 1914 due to rising fuel oil costs. As the population and the demand for electricity continued to
grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E proved more
economical than the diesel engines, and by the late 1920s CPAU was using its own diesel engines
only during peak demand periods. At that time CPAU owned 45 miles of distribution lines and
the City used 9.7 GWh annually, less than 1% of today’s annual consumption. The diesel engines
remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did throughout
the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the sales in 1950
(30 GWh). Some of that growth was related to a development boom in Palo Alto, which doubled
the number of customers. Some was related to the proliferation of electric appliances, as
evidenced by the fact that residential customers were using three times more electricity in 1970
than they had been in 1950. But the most notable factor was the growth of industry in Palo Alto
during that time. By 1970, commercial customers were using 20 times more electricity per
Ending Re serve Balance
($000)FY 2022 (Act)FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Re-a ppropr i a ti ons 120 120 120 120 120 120 120
Commi tments 6,679 6,679 6,679 6,679 6,679 6,679 6,679
Low Ca rbon Fuel Sta nda r d (LCFS) 7,236 6,214 5,142 4,574 4,121 3,668 3,668
Ca p a nd Tr a de 1,189 5,612 8,577 11,307 11,307 11,307 11,307
Under ground Loa n 727 727 727 727 727 727 727
Publ i c Benefi ts 3,891 4,608 5,380 6,175 6,910 7,585 8,200
Spec i a l Proj ects 24,649 17,649 24,649 24,649 26,649 28,649 30,649
Hydr o Sta bi l i za ti on 400 400 8,400 8,400 8,400 8,400 8,400
Ca pi ta l 880 880 880 880 5,880 10,880 15,880
Ra te Sta bi l i za ti on - - - - - - -
Di s tr i buti on a nd Suppl y
Oper a ti ons 30,142 19,455 21,211 30,057 38,354 45,440 44,802
Una s s i gned 845 - - - - - -
TOTAL 76,757 62,344 81,765 93,569 109,147 123,455 130,432
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customer than they had been in 1950. These decades also saw several other notable events,
including:
•1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of
Reclamation to purchase power from the Central Valley Project (CVP), a contract which
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
•1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
•1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement program
for its underground system in the early 1990s.
In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and
in 1996 the State legislature passed Assembly Bill 1890, which, among other things, created the
California Independent System Operator (CAISO) to operate the transmission system and the
Power Exchange to facilitate wholesale energy transactions. This restructuring was anticipated
to bring lower costs to consumers, and while CPAU was not required to participate in the industry
restructuring, in 1997 the Council approved a Direct Access Program for the Electric Utility6 that
enabled CPAU to sell electricity outside its service territory and allowed customers within CPAU’s
service territory to choose other providers. The utility unbundled its electric rates, creating
separate supply and distribution components, which would enable customers to receive only
distribution service while purchasing the electricity itself from another provider. The energy crisis
in 2000 to 2001 led to the suspension of direct access by the CPUC in September 2001 as
wholesale energy prices skyrocketed. The Electric Utility was less impacted than other utilities by
the 2000 to 2001 energy crisis thanks to the Calaveras project and its contract with WAPA for
CVP hydropower.
In 2001 CPAU began planning for the impacts associated with the new terms of its contract with
WAPA, set to take effect in 2005. The previous contract had provided 90% of Palo Alto’s power
supply at favorable rates, and PG&E, as a party to the contract, had provided supplemental power
6 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
19 | P a g e
to balance the monthly and annual variability of CVP generation. The new contract would provide
only a third of Palo Alto’s requirement, and the monthly and annual variability in CVP generation
would be passed directly to Palo Alto. As a result, electric supply costs would increase and CPAU
needed to more actively manage its supply portfolio. CPAU began purchasing power from
marketers and also investigated building a power plant in Palo Alto or partnering in the
development of a gas-fired power plant elsewhere. Climate change was also becoming more of
a concern to the community, and gradually CPAU shifted its focus to the procurement of
renewable energy. In 2002 the Council adopted a goal of achieving 20% of its energy supply from
renewables by 2015. Subsequently the City signed its first contract for renewable power, a
contract for energy from a wind generator commencing deliveries in 2005. In 2011 the renewable
energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a plan to make
its electric supply 100% carbon neutral, which it achieves through the combination of its carbon-
free hydroelectric supplies, purchases of long-term renewable energy supplies, and short-term
RECs to meet the balance of its needs.
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SECTION 4B: CUSTOMER BASE
The City of Palo Alto’s Electric Utility
provides electric service to the
residents, businesses, and other
electric customers in Palo Alto. There
are roughly 29,700 customers
connected to the electric system,
25,600 (86%) of which are residential
and 4,100 (14%) of which are non-
residential. Residential customers
consumed 154 gigawatt-hours (GWh)
in FY 2022, approximately 20% of the
electricity sold, while non-residential
customers consumed 80% or 659 GWh.
Residential customers use electricity
primarily for lighting, refrigeration,
electronics, and air conditioning.7 Non-residential customers use the majority of their electricity
for cooling, ventilation, lighting, office equipment (offices), cooking (restaurants), and
refrigeration (grocery stores).8
As shown in Figure 1, large customer loads represent the biggest proportion of sales for the
Electric Utility. The proportion of sales to large vs. small customers is greater than for the City’s
other utilities. For example, the largest customers (the 70 customers on the E-7 rate schedule)
account for around 44% of CPAU’s sales. The next largest customer group (the 890 non-
residential customers on the E-4 rate schedule) represents another 30% of sales. In total, that
means that about 3% of customers account for nearly three quarters of the electric load.
SECTION 4C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 472 miles of
distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are
underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line
transformers, around 1,100 underground and substation transformers, and the associated
electric services (which connect the distribution lines to the customers’ homes and businesses).
These lines, substations, transformers, and services, along with their associated poles, meters,
and other associated electric equipment, represent the vast majority of the infrastructure used
to deliver electricity in Palo Alto.
7 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
8 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
Figure 1: Customer Consumption By Class (FY 2022)
18%
6%
32%
44%Residential
Small Comm.
Med. Comm.
Large Comm.
20%
5%
30%
45%Residential
Small Comm.
Med. Comm.
Large Comm.
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SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 54% of the Electric Utility’s
costs in FY 2022. Operational costs
represented roughly 30%, and
capital investment was responsible
for the remaining 16%. CPAU’s non-
hydro long-term commodity supply
is heavily dependent on long-term
contracts which have little variability
in price. On average, costs for these
long-term contracts are not
predicted to increase as quickly as operations and CIP costs, and will steadily become a smaller
proportion of the Electric Utility’s costs. Staff projects commodity supply costs to be
approximately 55% of total costs in FY 2028.
While average year purchase
costs for the electric utility
are predictable due to its
long-term contracts,
variability in hydroelectric
generation can result in
increased or decreased costs.
This is by far the largest
source of variability the
utility faces. Figure 3 shows
the difference in the annual
load resource balance under
high, projected, and low hydroelectric
generation scenarios for FY 2022.
Additional costs associated with a very
low generation scenario can range from
$8-20 million per year, depending on
market prices. For the current
hydroelectric risk assessment see Section
5F: Risk Assessment and Reserves
Adequacy.
As shown in Figure 4 the Electric Utility
receives 79% of its revenue from sales of electricity and the remainder from connection fees,
interest on reserves, cost recovery transfers from other funds for shared services provided by the
electric utility, accounting entries that reflect things such as CPAU’s participation in a pre-funding
Figure 2: Cost Structure (FY 2022)
54%
30%
16%
Commodity
Supply
Operations
Capital
54%
30%
16%
Commodity
Supply
Operations
Capital
56%
32%
12%
Commodity Supply
Oper ations
Capital
Figure 3: Hydroelectric Variability as a % of Load (FY 2022)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro (sales)
Market Power/RECs
Hydro
Renewables
Load
Figure 4: Revenue Structure (FY 2022)
79%
21%
Sales of Electricity
Other Revenue
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program associated with its contract with WAPA, revenues from sales of surplus hydroelectric
energy during wet years, as well as LCFS and Cap and Trade revenues. Appendix A: Electric Utility
Financial Forecast Detail shows more detail on the utility’s cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 960 largest customers, which provide a similar share of the utility’s revenue stream.
About 25% of the utility’s revenue comes from peak demand charges on large non-residential
customers. Due to moderate weather and the prevalence of natural gas heating, however, loads
(and therefore revenues) are very stable for this utility, without the large seasonal air
conditioning or winter heating loads seen at some other utilities.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of contingencies
and for ease of reporting. It also maintains two funds, the Supply Fund and the Distribution Fund,
to manage costs associated with electricity supply and electricity distribution, respectively. The
City established this separation of supply and distribution costs as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) in the late 1990s and
early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues to maintain
separate funds to facilitate separation of supply and distribution costs in the rates. This could be
important if California ever decides to broadly reintroduce Direct Access, and is useful for rate
design as the nature of utility service evolves in response to higher penetrations of distributed
generation. Thus, individual reserves may reside within a particular fund (for instance, Electric
Special Projects is under Electric Supply) or be included within both funds (there are both Supply
and Distribution Reserves for Commitments).
The summary below describes the various reserves, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
•Reserves for Commitments: Reserves equal to the utility’s outstanding contract liabilities
for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
•Reserves for Reappropriations: Reserves for funds dedicated to projects re-appropriated
by the City Council, nearly all of which are capital projects. Most City funds, including the
General Fund, have a Re-appropriations Reserve. This is currently an important reserve
for all utility funds, but changes in budgeting practices will change that in future years, as
described in Section 3C (Reserves Management Practices).
•Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which was accumulated during deregulation of California’s electric system to
fund the stranded costs associated primarily with the Calaveras hydroelectric resource
and the California-Oregon Transmission Project. When that reserve was no longer needed
for that purpose, the reserve was renamed and the purpose was changed to fund projects
with significant impact that provide demonstrable value to electric ratepayers.
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•Hydroelectric Stabilization Reserve: This contingency reserve is used for managing
additional costs due to below average hydroelectric generation, or to hold surpluses
resulting from above average hydroelectric generation.
•Underground Loan Reserve: This reserve is an accounting tool used to offset receivables
associated with loans made through the underground loan program. It is adjusted
according to principal payments made on those loans.
•Cap and Trade Program Reserve: This reserve tracks unspent or unallocated revenues
from the sale of carbon allowances freely allocated by the California Air Resources Board
to the electric utility, under the State’s Cap and Trade Program. Funds in this Reserve are
managed in accordance with the City’s Policy on the Use of Freely Allocated Allowances
under the State’s Cap and Trade Program.
•Low Carbon Fuel Standard (LCFS) Reserve: This reserve tracks revenues earned via the
sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City,
in accordance with California’s Low Carbon Fuel Standard program.
•Public Benefits Reserve: CPAU’s electric rates include a separate charge called the “Public
Benefits Charge” which generates revenue to be used for energy efficiency, demand-side
renewable energy, research and development, and low-income energy efficiency
services. Any funds not expended in the current year are added to the Public Benefits
Reserve for use in future years.
•Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to accumulate
funds for future expenditure on CIP projects, as well as to manage cash flow for ongoing
capital projects. This reserve can also act as a contingency reserve for unforeseen capital
expenses. This type of reserve is used in other utility funds (Water, Gas, and Wastewater
Collection) as well.
•Supply and Distribution Rate Stabilization Reserves: These reserves are intended to be
empty unless one or more large rate increases are anticipated in the forecast period. In
that case, funds can be accumulated to spread the impact of those future rate increases
across multiple years. This type of reserve is used in other utility funds (Gas, Wastewater
Collection, and Water) as well.
•Supply and Distribution Operations Reserves: These are the primary contingency
reserves for the Electric Utility and are used to manage yearly variances from budget for
operational costs and electric supply costs (aside from variances related to hydroelectric
generation). This type of reserve is used in other utility funds (Gas, Wastewater Collection,
and Water) as well.
•Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves
are for any financial resources not assigned to the other reserves and are normally empty.
SECTION 4F: COMPETITIVENESS
For the median consumption level, the annual CPAU residential electric bill for calendar year 2022
was $792, which was $683 (46%) lower than the annual bill for a PG&E customer with the same
consumption ($1,475) and approximately $142 (22%) higher than the annual bill for a City of
Santa Clara customer ($649). The bill calculations for PG&E customers are based on PG&E
Climate Zone X, which includes most surrounding comparison communities.
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Table 8 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara
(Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown
below were in effect as of January 1, 2023.
Over the next several years low usage customers in PG&E territory are expected to continue to
see higher percentage rate increases than high usage customers as PG&E compresses its tiers
from the highly exaggerated levels that have been in place since the energy crisis. This is likely to
make the bill for the median Palo Alto consumer look even more favorable compared to most
PG&E customers. Even with the compressed tiers, bills for high usage Palo Alto consumers are
likely to remain substantially lower than the bills for high usage PG&E customers.
Table 8: Residential Monthly Electric Bill Comparison (Effective 1/1/2023, $/mo.)
Season Usage (kwh)Palo Alto PG&E Santa Clara
300 57.74 94.11 39.31
453 (Median)94.42 143.32 60.09
650 143.94 221.07 86.85Winter
1200 282.18 438.13 161.54
300 57.74 97.76 39.31
(Median) 365 72.31 123.41 48.14
650 143.94 235.88 86.85Summer
1200 282.18 452.94 161.54
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 5 shows a 38-year history of Palo Alto electricity consumption. Average electricity
consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then
electricity consumption has declined slowly as a result of a continuing focus on energy efficiency,
as well as the adoption of more stringent appliance efficiency standards and energy standards in
building codes. Electrification will likely reverse some of this trend, although the pace of that
impact is uncertain at this time. In recent years, some larger commercial customers have
relocated operations or shifted to more light-commercial type usage. It is unknown how long this
trend may continue, or what the longer-term impacts of COVID and work-from home policies
might mean for commercial utilization in Palo Alto.
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Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2028. The solid black straight
line is the long-term average trend of usage.
The small-dash red line represents the projected retail sales used in the financial forecast. Sales
are assumed to recover to a level slightly above the long-term trend line due to conservative
expected load growth from data centers. These projections will be revised if continuing sales
change.
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Figure 6: Forecasted Electricity Consumption
SECTION 5B: FY 2018 TO FY 2022 COST AND REVENUE TRENDS
As shown in Appendix A: Electric Utility Financial Forecast Detail, annual expenses for the Electric
Utility increased markedly in FY 2018 but came back down in FYs 2019 and 2020 before increasing
again in FY 2021 and FY 2022. On the capital side, the large Upgrade Downtown CIP project began
in FY 2018. Electric supply costs increased as new renewable projects came online, and
transmission costs rose and have continued to rise as improvements are made to the California
grid.
Section 6A: Electricity Purchases discusses the factors influencing Electric Utility expenses. During
the last drought in FYs 2014 and 2015 commodity costs were higher due to lower than average
output from hydroelectric resources, and similar circumstances are occurring in FY 2021, FY 2022
and are projected to continue through FY 2024. Transmission costs have increased as projected
in prior financial plans. Better than average hydro conditions in FY 2019 led to lower than
expected generation expenses as well as better than expected surplus energy revenues, but
extreme drought followed.
Commodity costs have increased, on average, by about 4.8% per year over this timeframe.
Operations costs have increased by about 2.9% annually on average. Revenues have increased
Projection
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on average by about 0.5% per year over this period and have been negatively impacted due to
declining sales and COVID.
Figure 7 shows the electric utility revenues, expenses, and proposed rate changes for the
previous five years, the current year, and the projections for the next five years. The percentages
listed do not include the hydroelectric rate adjuster. The total rate, including the adjuster, is
shown in Figure 8.
Embedded in the revenue line in Figure 7 is the assumption that the hydroelectric rate adjuster
will be cut in half in FY 2024 and the proposed rates changes are just the changes to base rates.
Figure 7: Electric Utility Revenues, Expenses, and Rate Changes:
Actual Costs through FY 2022 and Projections through FY 2028
Figure 8, similar to Figure 7, shows the historical and projected revenues and expenses, but instead
of showing the proposed base rate changes, it shows the change to the overall system rate, including
both the base rate and the hydroelectric rate adjuster. This shows how significantly rates increased
in FY 2022 and FY 2023 due to poor hydroelectric conditions and steeply increasing electricity market
prices. In FY 2024, the system average rate decreases 5% from the current system average rate
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established on January 1, 2023. These forecasts could change depending on changes in hydroelectric
generation and electricity market prices.
Figure 8: Electric Utility Revenues, Expenses, and Rate Changes:
Actual Costs through FY 2022 and Projections through FY 2028
SECTION 5C: FY 2022 RESULTS
FY 2022 revenues were $4 million lower than projections, as retail sales and surplus energy sales
combined were $2 million less than projected. Revenues from the HRA were also $2 million less
than projected as the rate went into effect later than anticipated. Net supply purchase costs came
in $12 million higher than projected, but these costs were partially offset by approximately $6
million savings from surplus energy sales as well as lower administration and demand side
management (DSM) costs. Capital projects costs exceed projections by $4 million.
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Table 9 FY 2022, Actual Results vs. FY 2022 Financial Plan Forecast ($000)
Net Cost/(Benefit)Type of change
Lower revenues from retail sales, surplus
energy sales, and Hydroelectric Rate Adjuster
$4,000 Revenue decrease
High Capital Projects cost $4,000 Cost increase
Higher net purchase cost $12,446 Cost increase
Lower Admin, DSM, and Surplus Energy Costs (5,962)Cost decrease
Net Cost / (Benefit) of Variances $14,482
SECTION 5D: FY 2023 PROJECTIONS
Net purchase costs are currently projected to increase by about $19.6 million, due to significantly
higher market prices and poor hydro conditions. Some of this increased cost is being recovered
by the increase to the hydroelectric rate adjuster on January 1, 2023. About $8 million more in
revenue is expected for FY 2023 than the FY 2022 as a result. Surplus energy costs and
administration costs are roughly $3 million lower than projected, partially offsetting higher
supply costs. However, the increased revenues and lower costs are not sufficient to offset the
higher purchase costs completely, leading to a $8.5 million decrease in the Operations Reserve
in FY 2023.
Table 10 FY 2022, Change in Projected Results, 2023 Forecast vs. 2022 Forecast ($000)
Net Cost/(Benefit)Type of change
Sales revenues higher than forecasted ($8,000)Revenue increase
Purchased electricity costs higher than forecasted $19,609 Cost increase
Reduced Surplus Energy Cost and Admin ($3,064)Cost decrease
Net Cost / (Benefit) of Variances to Ops Reserve $8,545
SECTION 5E: FY 2024 – FY 2028 PROJECTIONS
As shown in Figure 7 above, the Electric Utility’s costs rose significantly in FY 2023 due to
extremely high power market prices combined with deep, extended drought that decreased the
amount of power coming from the City’s hydroelectric resources. Some recovery of hydroelectric
generation and reduction in prices is forecasted in FY 2024, but not to normal levels given the
dry ground and low reservoir levels, which are expected to absorb a significant share of
precipitation even if it is above average. Normal levels of hydroelectric generation are not
forecasted until FY 2026, assuming normal rainfall in the winter of 2022/2023 and 2023/2024. To
reduce hydroelectric-related volatility in the future, staff is now making its rate projections
assuming that long-term “normal” production from the City’s hydroelectric resources is about
80% of historical average levels.
Staff projects other costs for the Electric Utility to increase through FY 2028 and as a result
projects rate increases in FY 2025 through FY 2028 to keep revenues in line with expenses over
the next five years. Beyond hydro conditions, electricity purchase costs are increasing
substantially as transmission costs rise to make improvements to the California grid. Operations
costs are expected to increase at or near the average inflation rate (2-3%/year) through the
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forecast period. Projected capital expenses are higher due to the rebuilding of existing
underground districts, substation and line voltage upgrades. The City is also evaluating the cost
and scope of other system resiliency projects, such as pole replacements, which may increase
costs as well as rates in the future.
Reserves trends based on these revenue projections are shown in Figure 9 (for Supply Fund
Reserves) and Figure 10 (for Distribution Fund Reserves), below. The Supply and Distribution
Operations Reserves are not projected to recover until FY 2026. However, the benefits of
repaying the loan from the Electric Special Projects Reserve early and transferring $8 million to
the Hydro Stabilization Reserve allow staff to comfortably recommend keeping the supply and
distribution operation reserves below guidelines in FY 2024 and FY 2025. This forecast includes
transfers from the Electric Special Projects Reserve to the Operations Reserve for Advanced
Metering Infrastructure expenses, as approved by Council in 2018, but not for other potential
projects that might be approved by Council for Electric Special Projects Reserve funding, such as
a second transmission line.
Figure 9: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2022 and Projections through FY 2028
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Figure 10: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2022 and Projections through FY 2028
SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY
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 ESP Reserve, and a Capital Reserve, which can be utilized with Council
approval.
This Financial Plan does not maintain reserves above the reserve minimum for both the Supply
and Distribution Operations Reserves in FY 2024 and FY 2025, but does between FY 2026 and FY
2028. Reserve levels also exceed the short-term risk assessment level for the Distribution Fund.
There are a variety of risks associated with the Supply Fund related to resource generation
variability, market price volatility, transmission cost increases, regulatory changes to market
rules. Because of the high range of uncertainty in energy price predictions more than three years
in the future, this risk assessment is only performed for the first two fiscal years of the forecast
period. It is important to note that the likelihood of all of these adverse scenarios occurring
simultaneously and to the degree described in Table 12 is very low.
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Table 12: Electric Supply Fund Risk Assessment
Estimates of Adverse
Outcomes (M$)
Estimates of Adverse
Outcomes (M$)
Categories of Electric Supply Cost
Uncertainties
FY 2024 FY 2025
1. Load Net Revenue 4.9 5.0
2. Hydro Production:
Western & Calaveras 8.1 9.1
3. Renewable Production: Landfill
& Wind & Solar 1.8 1.8
4. REC Purchases 0.52 0.56
5. REC Sales -0.52 -0.56
6. Market Price 0.7 0.2
7. Resource Adequacy 1 1
8. Transmission/CAISO 3.9 4.3
9. Plant Outage 1 1
10. Western Cost 1.1 1.6
11. Legislative & Regulatory 0 0
12. Supplier Default+0.2 0.2
Electric Supply Fund Risks 22.73 24.22
Of the risks faced by the Electric Utility’s Supply Fund, the risk of a dry year with very low
hydroelectric output is normally the largest, accounting for more than one-third ($8.1 million) of
all the adverse cost uncertainty. Since the utility’s costs for its hydroelectric resources are almost
entirely fixed, costs do not decline when the output of those resources are low, but the utility
needs to buy power to replace the lost output. The converse happens when hydroelectric output
is higher than average.
Of the remaining risks for FY 2024, $3.9 million is related to potential transmission cost increases
(above staff’s current forecast). $4.9 million is related to the potential that total load (and the
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associated retail sales revenue) may be lower than projected, $1.8 million is associated with
uncertainty around renewables production, and $1.0 million is associated with possible
decreases in Resource Adequacy capacity sales revenues (and/or increases in Resource Adequacy
capacity purchase costs).
As shown in Figure 11, staff projects the Supply Operations Reserve to drop below the minimum
guideline levels in FY 2023 but return to minimum levels and slowly increase towards the end of
the forecast period. Figure 12 shows that the combined Hydro Stabilization and Supply
Operations Reserves are projected to be above what is needed for the risk assessment level in FY
2023, but that FY 2024 are approximately at the Risk Assessment level.
Figure 11: Electric Supply Operations Reserve Adequacy
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Figure 12: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 13 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2027. As shown in Figure 13, the Distribution Operations Reserve is also projected to
drop near to the minimum reserve guidelines in FY 2024, but is projected to recover to near
target levels over the course of the forecast period. The risk assessment includes the revenue
shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 13: Electric Distribution Fund Risk Assessment ($000)
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FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Total non-commodity revenue $76,791 $82,662 $88,987 $99,524 $109,529
Max. revenue variance, previous ten years 8%8%8%8%8%
Risk of revenue loss $6,061 $6,524 $7,023 $7,855 $8,645
CIP Budget $25,508 $24,610 $22,644 $22,716 $22,730
CIP Contingency @10%$2,551 $2,461 $2,264 $2,272 $2,273
Total Risk Assessment value $8,612 $8,985 $9,288 $10,126 $10,918
Figure 13: Electric Distribution Operations Reserve Adequacy
The Electric Utility also has a CIP Reserve that acts as a reserve for short term capital
contingencies or as a place to set aside funds for large, one-time projects that the Utilities would
otherwise need to debt-fund. In the future, staff would also like to use this reserve to manage
cash flow for capital projects on an ongoing basis.
Figure 14 below reflects the maximum and minimum CIP Reserve guideline levels, starting in FY
2022. Because of the fluctuating annual dollar amounts and timing of CIP projects budgeted to
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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.
Because of constrained operating conditions resulting from COVID, increasing power supply costs
and a desire not to raise rates more than needed, the 2024 Financial Plan doesn’t anticipate
funding the CIP Reserve from the Distribution Operations Reserve. In future years, the CIP
Reserve will reflect actual fluctuations in CIP expenditures (money spent on actual projects in a
given year). CIP expenditures are currently reflected in the Operations Reserve. Staff is
anticipating, once the CIP Reserve has an adequate ending balance, to annually fund the CIP
reserve with an amount based on average anticipated CIP spending for that year (currently
estimated at $20 to $25 million in FY 2024 through FY 2026 and increasing to $30 to $35 million
once grid modernization expenses ramp up in FY 2027 and FY 2028. Moving forward, the reserve
will allow any cost savings or over-runs be reflected in the CIP Reserve instead of the Operations
Reserve, as described above. This will allow for better transparency and accounting of CIP related
funds, will address uneven annual funding associated with ongoing CIP projects, and offer a
funding source for one-time or immediately needed projects. Having the reserve guidelines in
place will ensure the reserve has sufficient funding for budgeted CIP as fluctuating annual
amounts of capital investment occur going forward.
Figure 14 shows the projected CIP Reserve balances and guideline levels for FY 2022 through FY
2028, as well as the prior reserve and guidelines in FY 2022. Because of constrained financial
conditions, the CIP reserve is projected to be below the minimum guideline for two years, until
reserve funding can take place. Per the Reserves Management Practices (Appendix B), Section
10, any rate plan that does not return CIP reserves to minimum levels within one year requires
Council approval. Council approved the FY 2023 Electric Utility Financial Plan, which included
keeping the CIP Reserve below minimum until FY 2027, and this FY 2024 Financial Plan modifies
that plan to keep CIP Reserves below minimum until FY 2026.
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Figure 14: Electric CIP Reserve Adequacy
SECTION 5G: LONG-TERM OUTLOOK
This forecast covers the period from FY 2024 through FY 2028, but various long-term
developments may create new costs for the utility over the next 10 to 35 years. While it is
challenging to accurately forecast the impact these events will have on the utility’s costs, it is
worth noting them as future milestones and keeping them in mind for long-term planning
purposes.
For the supply portfolio, the 2020s will see a number of notable events. The contract with the
Western Area Power Administration (Western) for power from the Central Valley Project (CVP)
will expire in 2024. Determining the future relationship with Western after 2024 will be
important in the years leading up to the contract expiration, especially because this resource
represents nearly 40% of the electric portfolio and is the utility’s largest source of carbon-free
electricity. The utility’s three earliest and lowest cost renewable contracts will also begin expiring
around that time, with the first contract expired in 2021 and the last in 2028. These three
$0
$5
$10
$15
$20
$25
$30
$35
$40
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
CIP Reappropriations
(Year-End)
CIP Reserve (Year-End)
CIP Commitments (Year-
End)
Reserve Minimum
Reserve Target
Reserve Maximum
Mi
l
l
i
o
n
s
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contracts, plus one more expiring in 2030, currently provide 17% to 18% of the energy for the
utility’s supply portfolio at prices under $65 per megawatt-hour (MWh). It is difficult to know
what renewable energy prices will be when those contracts expire. Although recent prices have
been in that range (or even lower), and costs may decrease in the future, current renewable
projects also benefit from a wide range of tax and other incentives that may or may not be
available in the 2020s and beyond. However, staff procured a replacement for the contract
expiring in 2021 at a lower price than any of the City’s current renewable contracts. In addition,
staff is in the process of procurement for a renewable geothermal project expected to start in
2025.
The costs of the Calaveras hydroelectric project will also change in the 2020s, with debt service
costs dropping by half or approximately $4 million in 2025 as some of the debt is paid off, and all
debt retired by the end of 2032. Some additional debt may be issued to fund the costs of
relicensing the project, but this is not anticipated to be as high as the current debt service. The
project will only be 40 years old at that time, and hydroelectric projects can last for 70-100 years
before major rebuilding is needed. Calaveras debt service represents roughly 70% of the annual
costs of that project (and nearly 7% of the utility’s total costs), so when the debt is retired, the
project could be a low-cost asset for the utility, providing carbon-free energy equal to around
13% of the Electric Utility’s supply needs in an average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to $5 million per year in revenue from allocated
carbon allowances under the State’s cap-and-trade program. It uses that revenue to pay for
energy efficiency programs and to purchase renewable energy to support the utility’s Carbon
Neutral Plan. Staff expects that revenue source to continue in some fashion through 2030,
although the number of allowances allocated to Palo Alto have been reduced. Discussions at the
state level are ongoing to determine any further restrictions CARB may wish to enact on both the
number of future allowances received as well as usage of allocation sales revenues. If the Electric
Utility no longer received these allowances or was limited in how it could spend revenues, it
would have to fund these programs from sales revenues.
Transmission costs are also continuing to rise. If the State continues to increase mandates or
incentives for renewable energy development, integrating these new projects into the
transmission grid will be an ever-increasing challenge, some costs of which will be borne by Palo
Alto. The planned expansion of the CAISO to a larger regional grid control area may result in
additional transmission costs that could further increase CPAU’s transmission costs. In addition
to the costs of new transmission lines that will need to be built, flexible resources will be required
to balance rapid changes in wind or solar output throughout the day. Palo Alto will likely bear
some of the costs of these new lines and resources. CPAU is also currently investigating installing
a second transmission interconnection for Palo Alto, which could be funded by the Electric Special
Projects Reserve.
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Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility is actively promoting electric vehicle ownership and
gas-to-electric fuel switching in Palo Alto. In the coming years these factors are expected to
create notable increases in electric consumption and have a variety of impacts on the distribution
system. Other technologies such as battery storage and rooftop solar installations are also
becoming even more common. The utility has already started to take some of these factors into
account in its long-term planning processes but will need to continue to incorporate them into
its planning methodologies.
Over the long term, electricity may replace natural gas and petroleum almost entirely as part of
the City’s efforts to combat climate change. Many, if not most, vehicles would use electricity,
though hydrogen is another potential fuel source under development and other technologies
might be developed. Staff is undertaking initial analysis of these types of scenarios in the context
of the Sustainability and Climate Action Plan (S/CAP) development process. These types of
scenarios require careful planning for the associated load growth to make sure the distribution
system does not end up overloaded, or conversely, to avoid over-investment, and the evaluation
of changes to utility distribution system management to accommodate integration of the various
technologies involved in electrification. Utility analyses in progress that take into account
potential load growth include a grid modernization study, the Electric Integrated Resource Plan,
and a potential upcoming S/CAP funding needs and sources study that may help assess the
impact of these trends on rates. Staff will integrate results from these studies in Financial Plans
as they become available.
SECTION 5H: ALTERNATIVE RATE PROJECTIONS
As an alternative to the proposed rate increases shown above in figures 7 and 8 of -5% (21%
increase to base rates) in FY 2024, 5% in FY 2025-FY 2028, staff could instead set rates to increase
the supply and operations reserves to minimum guidelines in FY 2024 as opposed to FY 2026.
This alternative still assumes that the HRA is removed starting in FY 2024 and that revenues must
be derived from general rates. This leads to a 1% system average rate reduction (or a 27%
increase to base rates) in FY 2024, followed by increases of 2%, 0%, 3%, and 9% in the following
years. Supply and Distribution Operations Reserves would reach the minimum guideline levels in
FY24 and target levels thereafter.
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Figure 15: Alternative Rate Proposal
SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: ELECTRICITY PURCHASES
As shown in Figure 16 the utility is projected to get roughly 40% of its energy from hydroelectric
projects in a normal year, but only 30% is expected or projected during FY 2023 and FY 2024 due
41 | P a g e
to the drought. Contracts with renewable sources make up approximately 50% of the portfolio
in FY 2024 before increasing to 60% by FY 2025. Staff expects contracts with renewable sources
to continue at approximately 50% of the portfolio for the forecast period. The remainder comes
from unspecified market sources. Under the City’s Carbon Neutral Plan, CPAU purchases RECs
corresponding to the amount of market energy it purchases.
Figure 16: Electricity Supply by Source
Figure 16 shows the historical and projected costs for the electric supply portfolio,9 as well as
average and actual hydroelectric generation.10 FY 2021, FY 2022, FY 2023, and FY2024 had lower
hydroelectric generation than or are projected to be lower. In addition, staff has reduced average
hydro generation output expectations to more closely align with the past 10 year of historical
averages. Renewable energy costs have stayed relatively flat as one renewable energy contract
ended while another renewable project came online to fulfill the City’s carbon neutral and RPS
goals. The current market outlook is uncertain for newer renewables projects because of
headwinds from supply chain issues and tailwinds from federal subsidies. Transmission charges
are projected to increase as new transmission lines are built throughout California to
9 Costs are shown net of wholesale revenues and cannot be directly compared with the electric supply purchase
figures shown in Appendix A: Electric Utility Financial Forecast Detail.
10 Average hydroelectric generation based on the current E-HRA rate schedule.
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accommodate new renewable projects. In total, net electric supply costs are projected to
increase from about average of $80 million from FY 2018 through FY 2022 to about $100 million
between FY 2023 through FY 2028.
Figure 17: Electric Supply Portfolio Costs, Historical and Projected
SECTION 6B: OPERATIONS
CPAU’s Electric Utility operations include the following activities:
•Administration, including financial management of charges allocated to the Electric Utility
for administrative services provided by the General Fund and for Utilities Department
administration, as well as debt service and other transfers. Additional detail on Electric
Utility debt service is provided in Section 6D (Debt Service)
•Customer Service
•Engineering work for maintenance activities (as opposed to capital activities)
•Operations and Maintenance of the distribution system; and
•Resource Management
Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
43 | P a g e
From FY 2018 to FY 2022, overall operations costs have risen annually by about 3% on average.
Operations and maintenance costs are increasing mainly due to higher inflation, especially in
salaries and benefits, as well as the use of contract line crew to help while the Utility is
understaffed. These costs may be reduced depending on how much work is needed and may be
phased out as longer-term employees are gained. Debt service is also forecasted to increase due
to grid modernization and fiber investments.
Figure 18: Historical and Projected Electric Utility Operational Costs
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
Staff projects CIP spending for FY 2024 through FY 2028 to be consistent with last year’s forecast,
though there is a slight shift in the funding by project category. There will be a reduction in
funding for undergrounding conversion from overhead to underground as current projects are
completed and others are delayed. There will be an increase in funding for underground
rebuilding and 4/12kV conversion as improvements are made to the system in portions of the
Crescent Park/Duveneck/St. Francis/Community Center/Leland Manor/Garland neighborhoods
to facilitate rebuild of the Hopkins Substation. An increase in funding is also needed for
replacement of distribution system and substation facilities that are at the end of their useful life.
Other significant projects are deteriorated wood pole replacements, substation physical security
upgrades, smart grid implementation, and ongoing capital investment in the electric distribution
44 | P a g e
system to maintain/improve reliability. This forecast assumes that the utility finances smart grid
projects (along with funding from the water and gas funds), the Foothill fire mitigation rebuilds,
and the 115kV electric interconnection from the ESP Reserve. Bond financing may also be
considered for some of these capital projects.
Excluding the one-time projects listed above, the CIP plan for FY 2024 to FY 2028 is primarily
funded by utility rates, but other sources of funds include connection fees (for Customer
Connections), phone and cable companies (primarily for undergrounding), and other funds (for
smart grid, foothill rebuilds, electric interconnection). The details of the CIP budget will be
available in the Proposed FY 2024 Utilities Capital Budget. Table 14 shows the FY 2022 projected
budget and the five year CIP spending plan, although these figures are preliminary pending
budget discussions starting in May. The ‘committed’ column represents funds committed to
contracts for which work has not yet been completed or invoices paid.
Table 14: Electric Utility CIP Spending ($000)
Expenses outlined in table 14 include grid modernization and fiber investments, which are not
shown in table 4.
SECTION 6D: DEBT SERVICE
The Electric Utility made its last payment on the 2007 Electric Utility Clean Renewable Energy Tax
Credit Bonds, Series A in FY 2021. This $1.5 million bond issuance was to fund a portion of the
construction costs of solar demonstration projects at the Municipal Services Center, Baylands
Interpretive Center, and Cubberley Community Center.
The Electric Utility also pledges reserves and net revenue as security for the bond issuances listed
in Table 15, even though the Electric Utility is not responsible for the debt service payments. The
Electric Utility’s reserves or net revenues would only be called upon if the responsible utilities are
Project Cate gory Current Budget *FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
One Ti me Projects 6,987 6,647 7,350 1,000 1,000 -
Re l i abi l i ty 6,802 3,915 4,765 4,765 3,400 529
Undergroundi ng 190 --100 3,000 -
4/12 kV Conversi on 3,500 1,500 1,500 ---
Underground Rebuil d 2,395 -400 1,850 1,600 -
Ongoing 9,211 5,339 5,415 5,375 5,586 6,093
Custome r Conne cti ons 5,490 2,700 2,700 2,700 2,700 2,700
Grid Moderni zation and Fiber**12,984 28,000 25,000 50,000 50,000 50,000
El e ctri f i cati on ---4,300 7,800 19,700
Total 47,560 48,101 47,130 70,090 75,086 79,022
* Incl ude s unspe nt funds from previous years carried forward or re appropriated into the current fi scal year
**Wi l l be funde d by seque nti al bonds, de bt servi ce for bonds i ncluded in Appendix A
45 | P a g e
unable to make their debt service payments. Staff does not currently foresee this occurring. In
FY 2022, the Electric Utility’s net revenues dropped to -12% of debt service. However, the other
utilities listed in Table 15 below were able to make their debt service payments in FY 2022 and
Electric Utility’s net revenues were not needed. Staff projects that the Electric Utility’s net
revenues in each future year will exceed 125% of debt service (see Appendix B, line 70).
Table 15: 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
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
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
Embedded in this year’s financial plan is the assumption that grid modernization and fiber
investments will begin in FY 2024. While the financing details are still being assessed and may
differ a bit from these assumptions, the current financial plan assumes the city will issue
sequential $50 million bonds every 18 months beginning in FY 2024 until $300 million or 6 bonds
have been issued. In addition, the fiber investment costs are estimated to be $13 million and
included in the first bond, for a total of $63 million in FY 2024 and $313 million cumulatively. As
shown in Appendix A, the financial plan assumes debt service costs beginning in FY 2025 of $2
million and increasing to $9.6 million in FY 2028. Depending on the scope of work, schedule and
bond issuance costs, the timing, number of bonds, and amount of the bonds maybe be adjusted.
Table 16 illustrates the estimated bond proceeds and debt service costs over the next ten years.
Table 16: Projected Bond Proceeds and Debt Service Costs
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.11 Each year it is calculated
according to the 2009 Council-adopted methodology and does not require additional Council
action.
11 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 equity transfer methodology.
Expenses ($000)FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030 FY 2031 FY 2032 FY 2033
Bond Proce eds 63,000 50,000 0 50,000 50,000 0 50,000 50,000 0 0
Debt Service Costs 0 -2,032 -3,632 -6,432 -9,632 -12,832 -16,032 -19,232 -20,032 -20,032
46 | P a g e
SECTION 6F: WHOLESALE REVENUES AND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 20 to 25%
comes from other sources. Of these other sources, about 50% to 75% represents wholesale
revenues of surplus energy sales. These revenues may offset electric supply purchase costs,
smooth rate increases, or fund reserves or other costs. Of the remaining revenues, the largest
revenue sources are interest on reserves, connection fees for new or replacement electric
services, and carbon allowance revenues associated with the State’s cap-and-trade program
Revenues from connection fees have increased since FY 2009 but vary from year to year.
Connection fee revenues are collected to offset costs incurred in setting up new connections and
are pass-through in nature. Staff forecasts $1.8 million in in FY 2024.
Staff projects carbon allowance and interest income revenues to stay relatively stable through
the forecast period. However, both of these revenue sources are subject to some uncertainty.
This forecast assumes the program State’s cap-and-trade program will remain in place but with
declining returns through 2030. It is possible this funding source may be removed entirely in the
future, as the current CARB plan in the gas fund is for free allowances to stop entirely by 2030.
The forecast for interest income assumes current interest rates continue and there are no major
reserve reductions aside from what is anticipated in this Financial Plan. If interest rates rise,
interest income could increase, and if reserves decrease (due to drought or a withdrawal from
the ESP reserve for a major project), interest income would decrease.
SECTION 6G: SALES REVENUES
The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7
provide the basis for sales revenue projections. As discussed in Section 5A, sales revenues for this
utility have been decreasing due to load reduction but are helped by the mild climate in Palo Alto.
Palo Alto is a built-out City, so the opportunities for increased load growth are limited to the
existing footprint of commercial structures and incremental growth in population. As utilization
of existing spaces changes, and energy efficiency measures continue, Palo Alto could see greater
load loss. Increased loads from electric vehicles and the electrification of households may
increase loads somewhat.
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SECTION 7: COMMUNICATIONS PLAN
The fiscal year (FY) 2024 electric utility communications strategy covers these primary areas:
market price increases, cost containment measures, efficiency services and utility bill savings,
capital improvement, operations and maintenance for infrastructure safety and reliability,
renewables, carbon neutral portfolio, and beneficial electrification. City of Palo Alto Utilities
(CPAU) communication methods include use of the utilities website, utility bill inserts, messaging
on utility bills, email newsletters, print and digital ads in local publications, social media, and
community message boards.
In advance of the rate-setting process, staff working on rates and communications are focusing
on informing customers of higher than anticipated electric rates this year due to lower revenues
from rates and interest income, impacts to hydroelectric supplies as a result of drought
conditions, higher purchase costs, and contract line crew costs. The goal is to help customers
navigate a challenging economic situation through efficiency services, rate assistance and bill
payment relief programs.
CPAU customers also benefit from local control and policy setting, and community values-driven
programs and services, including the decision to go carbon neutral in 2013. Palo Alto’s renewable
energy purchase agreements contribute to our utility’s long-term energy security and
commitment to sustainability. Power purchase agreements have allowed CPAU to procure long-
term renewable electric supplies at low costs. CPAU will highlight these environmental attributes
and value in our communications.
Programs such as the Home Efficiency Genie and commercial energy efficiency audits help
residents and businesses better understand energy usage, activities and/or upgrades they can
implement to improve efficiency and keep utility costs low. For several years, CPAU has offered
a Genie in-home assessment, including a virtual option during the pandemic, and webinars about
home energy and water efficiency to help customers keep utility costs low. Now the Genie
program provides a home electrification readiness assessment so customers who may want to
switch out gas for electric appliances or install an electric vehicle (EV) charger, can understand
what may be necessary for electric panel upgrades.
Recently CPAU also launched new programs to help businesses improve energy efficiency and
investigate the potential to switch from natural gas/fossil-fuel energy supplies to electricity. The
Business Energy Advisor provides a “concierge” service for businesses to evaluate areas of their
facility for efficiency improvements such as in the areas of building envelope, lighting, and
heating. The Business Energy Advisor acts as the flagship program for businesses to then learn
about available rebates for appliance or facility upgrades and opportunities for building
electrification. CPAU also offers programs to help businesses, multi-family properties, non-profits
and schools install EV charging infrastructure to assist employees and tenants with goals to switch
from fossil fueled transportation to clean, electric driving.
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APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
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APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
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1 FISCAL Y EAR FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
2
3 ELECTRIC LOAD 160 159
4 Purchases (MW h)925,329 905,071 879,913 827,106 836,828 849,043 869,163 869,404 860,135 851,407 843,088
5 Sale s (MWh)899,997 884,322 854,761 813,881 812,841 809,059 830,051 843,322 834,331 825,865 817,795
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kW h)0.1413$ 0.1487$ 0.1624$ 0.1590$ 0.1606$ 0.2010$ 0.2078$ 0.2172$ 0.2270$ 0.2374$ 0.2491$
9 Cha nge in System Average Rate 13%5%9%-2%1%25%3%5%5%5%5%
10 Cha nge in Ave rage Residential Bill 11%6%8%-1%-1%5%21%4%5%4%5%
11
12 STARTING RESERVES
13 Reappropriatio ns (Non-CIP)----56,811 120,000 120,000 120,000 120,000 120,000 120,000
14 Commitments (Non-CIP)2,970,955 3,725,000 3,910,695 3,518,525 3,512,355 6,679,000 6,679,000 6,679,000 6,679,000 6,679,000 6,679,000
15 Low Carbon Fuel Sta ndard (LCFS) Re serve ---6,340,000 6,943,525 7,235,894 6,213,691 5,141,701 4,574,052 4,121,071 3,668,090
16 Cap and Trade Program 1,189,000 1,189,000 5,612,019 8,576,896 11,307,292 11,307,292 11,307,292
17 Underground Loa n Reserve 730,147 730,147 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659
18 Public Benefits Reserve s 681,330 681,330 809,700 1,904,547 3,027,599 3,890,774 4,608,011 5,380,396 6,175,499 6,910,325 7,584,849
19 Electric Special Proje cts Re se rve 51,837,855 41,837,855 41,664,855 46,664,855 46,664,855 24,649,000 17,649,000 24,649,000 24,649,000 26,649,000 28,649,000
20 Hydro Stabilizatio n Reserve 11,400,000 11,400,000 11,400,000 15,400,000 15,400,000 400,000 400,000 8,400,000 8,400,000 8,400,000 8,400,000
21 Capital Reserve s 879,964 879,964 879,964 5,879,964 879,964 879,964 879,964 879,964 879,964 5,879,964 10,879,964
22 Rate Stabilization Reserve s 9,010,840 9,010,840 ---------
23 Operatio ns Reserves (Supply & Dist)29,912,981 18,600,000 45,244,167 38,538,459 29,902,850 30,142,000 19,455,158 21,211,224 30,057,451 38,353,661 45,440,073
24 Una ssigned -244,354 -0 (0)844,513 -----
25 TOTAL STARTING RESERVES 107,424,072 87,109,490 104,636,040 118,973,010 108,303,618 76,756,805 62,343,503 81,764,839 93,568,917 109,146,972 123,454,927
26
27 REVENUES
28 Net Sa les 127,172,308 131,471,245 137,026,504 129,389,001 130,557,545 162,595,679 172,499,236 183,169,260 189,432,176 196,079,973 203,727,979
29 Whole sa le Revenues 18,106,327 21,060,071 20,686,925 25,959,207 25,529,188 24,751,851 25,801,694 27,834,224 28,388,544 26,324,976 26,540,307
30 Other Revenue s a nd Transfers In 13,373,312 19,914,635 15,260,937 9,324,996 9,348,837 9,235,543 34,092,443 10,654,877 13,334,635 13,638,723 10,469,612
31 TOTAL REVENUES 158,651,947 172,445,951 172,974,366 164,673,204 165,435,570 196,583,072 232,393,373 221,658,360 231,155,355 236,043,672 240,737,898
32
33 EXPENSES
34 Electric Supply Purchas e s 94,629,654 89,625,027 90,645,768 98,460,911 112,524,986 117,899,840 118,019,453 115,637,790 118,068,830 118,850,995 121,028,178
35 Operating Expenses
36 Administra tion 110.0%
37 Allocated Charges 6,374,241 4,568,027 6,146,498 6,674,515 5,732,098 6,018,937 6,217,658 6,404,293 6,596,079 6,793,665 6,997,186
38 Rent 5,284,977 5,454,097 5,666,805 5,949,976 6,069,000 6,182,562 6,329,377 6,479,932 6,635,163 6,794,135 6,956,847
39 Debt Service 8,867,395 8,464,883 7,170,631 7,841,922 8,068,219 8,502,737 8,275,943 6,253,175 7,855,970 10,694,458 13,851,850
40 Transfers and Other Adjustments 13,632,059 13,342,321 10,133,943 9,610,379 13,811,097 14,572,449 15,482,046 15,629,938 16,040,156 16,449,711 16,838,612
41 Subtotal, Administration 34,158,672 31,829,328 29,117,878 30,076,792 33,680,414 35,276,685 36,305,024 34,767,338 37,127,368 40,731,968 44,644,494
42 Resource Mana gement 1,873,954 2,082,405 2,870,524 2,781,010 2,824,303 2,991,189 3,100,525 3,205,176 3,263,228 3,328,493 3,407,229
43 De mand Side Management 3,889,846 3,655,547 2,733,047 3,819,646 4,086,083 6,179,462 6,693,931 6,543,793 6,809,407 6,831,864 3,040,455
44 Ope rations and Mtc 11,528,747 11,606,585 13,450,568 15,988,315 16,576,083 20,981,726 18,712,141 19,309,318 19,771,526 20,263,837 20,773,883
45 Engine e ring (Operating)1,790,942 1,838,799 2,051,303 2,408,524 1,806,550 1,898,848 1,962,319 2,022,073 2,079,850 2,139,750 2,201,511
46 Customer Se rvice 2,291,246 2,180,400 2,228,469 2,320,338 2,974,968 3,145,349 3,258,085 3,365,609 3,434,569 3,510,129 3,588,840
47 Allow ance fo r Unspent Budge t -----(568,039)(587,742)(606,422)(621,182)(636,877)(654,081)
48 Subtotal, Operating Expense s 55,533,407 53,193,063 52,451,788 57,394,624 61,948,401 69,905,219 69,444,285 68,606,884 71,864,768 76,169,165 77,002,331
49 Capital Program Contribution 18,803,467 10,770,456 15,539,840 21,487,061 34,524,744 28,991,316 25,508,299 25,609,608 25,643,701 26,715,557 35,730,230
50 TOTAL EXPENSES 168,966,528 153,588,546 158,637,396 177,342,596 208,998,131 216,796,374 212,972,036 209,854,282 215,577,300 221,735,717 233,760,738
51
52 ENDING RESERVES
53 Reappropriatio ns (Non-CIP)9,063,000 --56,811 120,000 120,000 120,000 120,000 120,000 120,000 120,000
54 Commitments (Non-CIP)8,637,000 3,910,695 3,518,525 3,512,355 6,679,000 6,679,000 6,679,000 6,679,000 6,679,000 6,679,000 6,679,000
55 Low Carbon Fuel Sta ndard (LCFS) Re serve --6,340,000 6,943,525 7,235,894 6,213,691 5,141,701 4,574,052 4,121,071 3,668,090 3,668,090
56 Cap and Trade Program 1,189,000 1,189,000 5,612,019 8,576,896 11,307,292 11,307,292 11,307,292 11,307,292
57 Underground Loa n Reserve 730,147 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659
58 Public Benefits Reserve s 681,330 809,700 1,904,547 3,027,599 3,890,774 4,608,011 5,380,396 6,175,499 6,910,325 7,584,849 8,199,937
59 Electric Special Proje cts Re se rve 41,837,855 41,664,855 46,664,855 46,664,855 24,649,000 17,649,000 24,649,000 24,649,000 26,649,000 28,649,000 30,649,000
60 Hydro Stabilizatio n Reserve 11,400,000 11,400,000 15,400,000 15,400,000 400,000 400,000 8,400,000 8,400,000 8,400,000 8,400,000 8,400,000
57 Capital Reserve 879,964 879,964 5,879,964 879,964 879,964 879,964 879,964 879,964 5,879,964 10,879,964 15,879,964
58 Rate Stabilization Reserve 9,010,840 ----------
59 Operatio ns Reserve (Supply & Dist)18,600,000 45,244,167 38,538,459 29,902,850 30,142,000 19,455,158 21,211,224 30,057,451 38,353,661 45,440,073 44,802,144
60 Una ssigned 244,354 -0 (0)844,513 ------
61 TOTAL ENDING RESERVES 101,084,490 104,636,040 118,973,010 108,303,618 76,756,805 62,343,503 81,764,839 93,568,917 109,146,972 123,454,927 130,432,086
62
63 OPERATIONS RESERVE
64 Min (60 days of non-capita l e xpe nses )25,849,452 24,700,922 25,579,071 26,397,217 28,629,395 30,806,909 30,678,262 30,197,099 31,138,925 31,984,104 32,493,679
65 Target (90 days of non-ca pital expenses)37,071,179 35,342,766 36,507,588 38,417,367 41,834,515 45,045,206 44,813,743 44,055,844 45,431,537 46,661,127 47,386,164
66 Max (120 da ys of non-capital expenses)48,292,905 45,984,610 47,436,104 50,437,517 55,039,635 59,283,502 58,949,225 57,914,590 59,724,148 61,338,150 62,278,648
67 Risk Asse ssment Value 5,622,455 4,992,321 6,001,771 6,381,125 6,668,204 7,063,828 8,756,964 9,247,811 9,902,791 10,615,661 12,442,421
68
69 DEBT SERVICE COVERAGE RATIO
70 Net Re ve nues (125% o f De bt Service )196%450%517%212%-12%203%643%698%625%484%408%
71 Ava ilable Re se rves (5x De bt Service)*9.4 11.9 16.1 13.4 8.7 6.5 9.1 13.9 13.0 10.9 8.9
6056714
1 FISCAL Y EAR FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
2
3 REVENUES
4 Ne t Sales 80%76%79%79%78%71%74%83%82%83%85%
5 Other Reve nues and Tra nsfe rs In 20%24%21%21%21%17%26%17%18%17%15%
6 TOTAL REVENUES 100%100%100%100%99%88%100%100%100%100%100%
7
8 EXPENSES
9 Co mmodity P urchas e s 50%53%53%53%56%56%55%52%51%51%49%
10 Operating Expens es
11 Administra tio n
12 Allocated Charges 4%3%4%4%3%3%3%3%3%3%3%
13 Rent 3%4%4%3%3%3%3%3%3%3%3%
14 Debt Service 5%6%5%4%4%4%4%3%4%5%6%
15 Transfers and Other Adjustments 8%9%6%5%7%7%7%7%7%7%7%
16 Subtotal, Administra tio n 20%21%18%17%17%17%17%17%17%18%19%
17 Re source Mana ge me nt 1%1%2%2%1%1%1%2%2%2%1%
18 Opera tio ns a nd Mtc 7%8%8%9%8%10%9%9%9%9%9%
19 Engine e ring (Opera ting)1%1%1%1%1%1%1%1%1%1%1%
20 Cus tomer Se rvice 1%1%1%1%2%1%2%2%2%2%2%
21 Allow ance for Uns pent Budget 0%0%0%0%0%0%0%0%0%0%0%
22 Subtotal, Operating Expens es 31%32%31%31%29%30%29%30%30%31%32%
23 Ca pital Progra m Contribution 11%7%10%11%11%10%12%12%12%12%15%
24 TOTAL EXP ENSES 91%92%95%94%97%97%96%94%94%94%96%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL Y EAR FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
28 1.Load Net Revenue
29 2.Hydro Production: Western & Calaveras
30 3. Renewable Produc tion: Landfill & Wind & Solar
31 4. Carbon Neut ral Cost
32 5. Market Pric e
33 6. Loc al Capac ity
34 7. T ransmission/CAISO
35 8. Plant Outage
36 9. West ern Cost
37 10. Regulatory & Legal
38 11. Supplier Default
39 T OT AL
40
Supply Operat ions + Hydro Stabilization
Reserves, % of Risk Assessment
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL Y EAR FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
44 Dist ribut ion Revenue Varianc e 3,742,109 3,915,276 4,447,787 4,432,418 4,417,304 4,864,696 6,206,135 6,686,850 7,338,421 7,944,105 8,869,398
45 10% CIP Program Cont ingenc y 1,880,347 1,077,046 1,553,984 1,948,706 2,250,900 2,199,132 2,550,830 2,560,961 2,564,370 2,671,556 3,573,023
46 T otal Risk Asssessment Value 5,622,455 4,992,321 6,001,771 6,381,125 6,668,204 7,063,828 8,756,964 9,247,811 9,902,791 10,615,661 12,442,421
47 Projec t ed Operat ions Reserve 18,600,000 45,244,167 38,538,459 29,902,850 30,142,000 19,455,158 21,211,224 30,057,451 38,353,661 45,440,073 44,802,144
48 Operations Reserve, % of Risk Value 331%906%642%469%452%275%242%325%387%428%360%
49
44 SUPPLY O PERATIO NS RESERVE
45 Min (60 da ys of no n-ca pital expenses )17,841,143 16,831,022 16,957,154 18,345,636 20,817,535 21,749,445 21,765,198 20,738,810 21,164,097 21,325,772 21,705,956
46 Targe t (90 da ys of non-capital expenses)26,761,715 25,246,533 25,435,732 27,518,453 31,226,303 32,624,168 32,647,797 31,108,216 31,746,145 31,988,658 32,558,934
47 Max (120 da ys of no n-ca pital expenses)35,682,287 33,662,044 33,914,309 36,691,271 41,635,071 43,498,891 43,530,397 41,477,621 42,328,193 42,651,545 43,411,912
48
49 DISTRIBUTIO N OPERATIONS RESERVE
50 Min (60 da ys of no n-ca pital expenses )8,008,309 7,869,900 8,621,917 8,051,581 7,811,860 9,057,464 8,913,063 9,458,289 9,974,828 10,658,331 10,787,723
51 Targe t (90 da ys of non-capital expenses)10,309,464 10,096,233 11,071,856 10,898,913 10,608,212 12,421,038 12,165,946 12,947,629 13,685,392 14,672,468 14,827,230
52 Max (120 da ys of no n-ca pital expenses)12,610,618 12,322,566 13,521,795 13,746,245 13,404,564 15,784,612 15,418,828 16,436,969 17,395,955 18,686,605 18,866,737
53 Risk As s e ssment Value 5,622,455 4,992,321 6,001,771 6,381,125 6,668,204 7,063,828 8,756,964 9,247,811 9,902,791 10,615,661 12,442,421
54
55 DEBT SERVICE COVERAGE RATIO
56 Ne t Revenue s (125% of Debt Se rvice)196%450%517%212%-12%203%643%698%625%484%408%
57 Available Reserves (5x Debt Se rvice)*9.4 11.9 16.1 13.4 8.7 6.5 9.1 13.9 13.0 10.9 8.9
ELECTRIC UTILITY FINANCIAL PLAN
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APPENDIX B: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c) For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f) For operating contingencies, as described in Section 12 (Operations Reserves)
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 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserves for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c) As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d) To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 11.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) 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 14 (Unassigned Reserves).
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Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves
for Commitments will be set to an amount equal to the total remaining spending authority
for all contracts in force for the Electric Supply Fund and Electric Distribution Fund,
respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves
for Reappropriations will be set to an amount equal to the amount of all remaining capital
and non-capital budgets that will be reappropriated to the following fiscal year for each Fund
in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies set forth in Resolution 9206 (Resolution of the Council of the City of Palo Alto
Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve and
Adoption of Electric Special Project Reserve Guidelines). These policies are included from
Resolution 9206 as amended to refer to the reserves structure set forth in these Reserves
Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2025;
f) Any uncommitted funds remaining at the end of FY 2030 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
Section 7. Hydroelectric Stabilization Reserve
The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts associated
with variations in generation from hydroelectric resources. Staff will manage the
Hydroelectric Stabilization Reserve as follows:
a) Projected Hydro Output: Near the end of each fiscal year, staff will determine the
actual and expected hydro output for that fiscal year, compare that to the long-term
average annual output level (495,957 MWh as of March 2018), and multiply the
difference by the average of the monthly round-the-clock forward market prices for
each month of the current fiscal year.
b) Changes in Reserves. Staff is authorized to transfer the amount described in Sec. 7(a)
from the Operations Reserve to the Hydroelectric Stabilization Reserve for hydro
output deviations above long-term average levels, or transfer this amount from the
Hydroelectric Stabilization Reserve to the Operations Reserve for hydro output
deviations below long-term average levels.
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c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after the
transfers described above shall be the basis for staff’s determination, with Council
approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-HRA) for
the following fiscal year.
d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve
according to the following guideline levels:
Minimum Level $3 million
Target Level $19 million
Maximum Level $35 million
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the principal
payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires action
by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels are
calculated for each fiscal year of the Financial Planning Period and approved by Council
resolution.
Minimum Level 20% of the maximum CIP Reserve guideline
level
Maximum Level Average annual (12 month)12 CIP budget, for
48 months of budgeted CIP expenses13
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve for
Commitments as a result of a change in contractual commitments related to CIP projects.
Any other additions to or withdrawals from the CIP reserve require Council action.
c) Minimum Level:
i) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve reaching
its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is
below its minimum level at the end of FY 2017, staff must present a plan by June 30,
2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff
12 Each month is calculated based upon 1/12 of the annual budget.
13 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.
ELECTRIC UTILITY FINANCIAL PLAN
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may present, and the Council may adopt, an alternative plan that takes longer than
one year to replenish the reserve, or that does so in a shorter period of time.
d) Maximum Level: If there are funds in this reserve in excess of the maximum level staff
must propose in the next Financial Plan to transfer these funds to another reserve or
return them to ratepayers in the funds to ratepayers, or designate a specific use of funds
for CIP investments that will be made by the end of the next Financial Planning period.
Staff may also seek City Council to approve holding funds in this reserve in excess of the
maximum level if they are held for a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period. The Council may approve exceptions
to this requirement, when proposed by staff to provide greater rate stabilization to
customers.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to 11 above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
ELECTRIC UTILITY FINANCIAL PLAN
J u n e 2 0 1 8 57 | P a g e
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were funds
in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning Period is
FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign the funds
in the Unassigned Reserve by the end of FY 2017. Staff may present an alternative plan that
retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
Section 15. Low Carbon Fuel Standard (LCFS) Reserve
This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the
California Air Resources Board to the City, as well as expenses incurred, in accordance with
California’s Low Caron Fuel Standard program. At the end of each fiscal year, the LCFS
Reserve will be adjusted by the net of revenues and expenses associated with California’s
LCFS program.
Section 16. Cap and Trade Program Reserve
This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the electric utility, under the State’s Cap
and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy
on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the
Policy), adopted by Council Resolution 9487 in January 2015.
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APPENDIX C: DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL ACTIVITIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Electric Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process. It
does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large commercial
customers who have more complex requirements for their electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution system
maintenance activities, including:
•monitoring the substations and performing routine maintenance;
•performing preventative maintenance on the system;
•monitoring the system’s status from the UCC using SCADA;
•maintaining the SCADA system;
•investigating outages and other customer complaints and performing emergency
repairs;
•clearing vegetation near overhead power lines; and
•testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX D: SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-1-1 Sheet No E-1-1
dated 7-1-20192022 Effective 7-1-20222023
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
$
0.099990.08
547
$
0.069540.05429
$
0.005680.00469
$
0.175210.1444
5
Tier 2 usage
Any usage over Tier 1
0.138730.11
858
0.102250.08008
0.005680.00469
0.203354666
Minimum Bill ($/day)
0.41810.3447
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 11 kWh per
day, prorated by Meter reading days of Service. As an example, for a 30-day bill, the
Tier 1 level would be 330 kWh. For further discussion of bill calculation and proration,
refer to Rule and Regulation 11.
{End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-1 Sheet No E-2-1
dated 7-1-20192022 Effective 7-1-20222023
A. APPLICABILITY:
This Rate Schedule applies to the following Customers receiving Electric Service from the City
of Palo Alto Utilities:
1. Small non-residential Customers receiving Non-Demand Metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period
$
0.142160.121
51
$
0.117750.09276
$
0.005680.00469
$
0.265590.2189
6
Winter Period
0.101960.087
15
0.078610.06171
0.005680.00469
0.186250.1535
5
Minimum Bill ($/day)
1.06460.8777
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 the Winter Periods, the usage will be prorated based on the number of days in each
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-2 Sheet No E-2-2
dated 7-1-20192022 Effective 7-1-20222023
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.
{End}
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
Supersedes Sheet No E-2-G-1 Sheet No E-2-G-1
dated 7-1-20221 Effective 7-1-20232
A. APPLICABILITY:
This Rate Schedule applies to the following Customers receiving Electric Service from the City
of Palo Alto Utilities under the Palo Alto Green Program:
1. Small non-residential Customers receiving Non-Demand Metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Palo Alto
Green
Charge Total
Summer Period
$
0.142160.12
151
$
0.117750.09
276
$
0.005680.0
0469 $ 0.0075
$
0.273090.
22646
Winter Period
0.101960.08
715
0.078610.06
171
0.005680.0
0469 0.0075
$ 0.19375
0.16105
Minimum Bill ($/day)
1.06460.8777
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$
0.142160.12
151
$
0.117750.09
276
$
0.005680.0
0469
$
0.265590.
21896
Winter Period
0.101960.08
715
0.078610.06
171
0.005680.0
0469
0.186250.
15355
Minimum Bill ($/day)
1.06460.8777
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
Supersedes Sheet No E-2-G-2 Sheet No E-2-G-2
dated 7-1-20221 Effective 7-1-20232
Palo Alto Green Charge (per 1000 kWh block) $7.50
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. 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.
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
Supersedes Sheet No E-2-G-3 Sheet No E-2-G-3
dated 7-1-20221 Effective 7-1-20232
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.
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.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-1 Sheet No E-4-1
dated 7-1-202219 Effective 7-1-20223
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 applies to three-phase Electric
Service and 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 anywhere everywhere the City of Palo Alto provides Electric
Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $ 5.284.52 $ 31.5425.84 $ 36.8230.36
Energy Charge (per kWh)
0.131570.10960
0.026380.02061
0.005680.00469 0.163630.13490
Winter Period
Demand Charge (per kW) $ 3.292.82 $ 20.8717.10 $ 24.1619.92
Energy Charge (per kWh)
0.094610.07913
0.026380.02061
0.005680.00469 0.126670.10443
Minimum Bill ($/day) 22.001218.1379
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.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-2 Sheet No E-4-2
dated 7-1-202219 Effective 7-1-20223
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. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has been below 200 kilowatts for four consecutive
months.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-3 Sheet No E-4-3
dated 7-1-202219 Effective 7-1-20223
When such metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent (0.25%) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with
the Customer's Maximum Demand.
5. 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.
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 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-4 Sheet No E-4-4
dated 7-1-202219 Effective 7-1-20223
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
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.
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}
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-1 Sheet No E-4-G-1
dated 7-1-20221 Effective 7-1-20223
A. APPLICABILITY:
This Rate Schedule applies to Demand metered Secondary Electric Service for Customers with a
maximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green
Program. This Rate Schedule applies to three-phase Electric Service and may include Service to
Master-metered multi-family facilities or other facilities requiring Demand metered Service, as
determined by the City.
B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge (per kW) $ 5.284.52 $ 31.5425.84
$ 36.8230.36
Energy Charge (per kWh)
0.131570.10960
0.026380.02061
0.005680.00469 0.0075
0.171130.14240
Winter Period
Demand Charge (per kW) $ 3.292.82 $ 20.8717.10
$ 24.1619.92
Energy Charge (per kWh)
0.094610.07913
0.026380.02061
0.005680.00469 0.0075
0.134170.11193
Minimum Bill ($/day) 22.001218.1379
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-2 Sheet No E-4-G-2
dated 7-1-20221 Effective 7-1-20223
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $ 5.284.52 $ 31.5425.84
$ 36.8230.36
Energy Charge (per kWh) 0.131570.10960 0.026380.02061 0.005680.00469 0.163630.13490
Palo Alto Green Charge (per 1000 kWh block) $7.50
Winter Period
Demand Charge (per kW) $ 3.292.82 $ 20.8717.10
$ 24.1619.92
Energy Charge (per kWh) 0.094610.07913 0.026380.02061 0.005680.00469 0.126670.10443
Palo Alto Green Charge (per 1000 kWh block) $7.50
Minimum Bill ($/day) 22.001218.1379
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-3 Sheet No E-4-G-3
dated 7-1-20221 Effective 7-1-20223
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. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with
the Customer's Maximum Demand.
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.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-4 Sheet No E-4-G-4
dated 7-1-20221 Effective 7-1-20223
6. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. 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.
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 2.5 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.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-5 Sheet No E-4-G-5
dated 7-1-20221 Effective 7-1-20223
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
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.
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}
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-1 Sheet No E-4-TOU-1
dated 7-1-202219 Effective 7-1-20232
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 applies to three-phase Electric Service and may include Service to Master-
Metered multi-family facilities or other facilities requiring Demand-metered Service, as
determined by the City. In addition, this Rate Schedule is applicable for Customers who did
not pay power factor adjustments during the last 12 months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $ 3.222.71 $ 10.858.89 $ 14.0711.60
Mid-Peak 1.110.97 10.858.89 11.969.86
Off-Peak 1.110.97 10.858.89 11.969.86
Energy Charge (per kWh)
Peak
$ 0.120200.10022 $ 0.026360.02060 $ 0.005680.00469 $ 0.152240.12551
Mid-Peak 0.152040.12647 0.026360.02060 0.005680.00469 0.184080.15176
Off-Peak 0.092290.07721 0.026360.02060 0.005680.00469 0.124330.10250
Winter Period
Demand Charge (per kW)
Peak $ 1.831.57 $ 11.639.53 $ 13.4611.10
Off-Peak 1.831.57 11.639.53 13.4611.10
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-2 Sheet No E-4-TOU-2
dated 7-1-202219 Effective 7-1-20232
Commodity Distribution Public Benefits Total
Energy Charge (per kWh)
Peak
$ 0.147440.12268 $ 0.026360.02060 $ 0.005680.00469 $ 0.179480.14797
Off-Peak 0.126190.10516 0.026360.02060 $ 0.005680.00469 0.158230.13045
Minimum Bill ($/day) 22.001218.1379
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):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
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
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-3 Sheet No E-4-TOU-3
dated 7-1-202219 Effective 7-1-20232
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. Power Factor Adjustment
Time of Use Customers must not have had a power factor adjustment assessed on their
Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month, and must not have fallen
below 95% to avoid the power factor adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should
be subject to power factor adjustments, the Customer will be removed from the E-4-TOU
rate schedule and placed on another applicable rate schedule as is suitable to their
kilowatt Demand and kilowatt-hour usage.
5. 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.
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 1/2 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
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-4 Sheet No E-4-TOU-4
dated 7-1-202219 Effective 7-1-20232
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
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 the event of an interruption in utility Service and which are not used to
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-5 Sheet No E-4-TOU-5
dated 7-1-202219 Effective 7-1-20232
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}
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-1 Sheet No E-7-1
dated 7-1-202219 Effective 7-1-20232
A. APPLICABILITY:
This Rate Schedule applies to Demand Metered Service for large non-residential Customers
with a Maximum Demand of at least 1,000KW per month per site, who have sustained this
Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (kW) $ 6.035.16 $ 33.0527.06 $ 39.0832.22
Energy Charge (kWh) 0.139170.11476 0.000750.00059 0.005680.00469 0.145600.12004
Winter Period
Demand Charge (kW) $ 3.462.96 $ 18.2514.94 $ 21.7117.90
Energy Charge (kWh) 0.092120.07597 0.000750.00059 0.005680.00469 0.098550.08125
Minimum Bill ($/day) 62.553951.5696
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.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-2 Sheet No E-7-2
dated 7-1-202219 Effective 7-1-20232
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.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-3 Sheet No E-7-3
dated 7-1-202219 Effective 7-1-20232
5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option to install applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has been below 200 kilowatts for four consecutive
months.
When such metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The power factor adjustment is applied
by increasing the total energy and Demand charges for any month by 0.25 percent
(0.25%) for each one percent (1%) that the monthly Power Factor of the Customer’s load
was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with
the Customer's Maximum Demand.
6. 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.
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 1/2 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.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-4 Sheet No E-7-4
dated 7-1-202219 Effective 7-1-20232
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
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) 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
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-5 Sheet No E-7-5
dated 7-1-202219 Effective 7-1-20232
Section 2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-1 Sheet No E-7-G-1
dated 7-1-20221 Effective 7-1-20232
A. APPLICABILITY:
This Rate Schedule applies to Demand metered Service for large non-residential Customers who
choose Service under the Palo Alto Green Program. A Customer may qualify for this Rate
Schedule if the Customer’s Maximum Demand is 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:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge ( per kW) $ 6.035.16 $ 33.0527.06
$ 39.0832.22
Energy Charge (per kWh) 0.139170.11476 0.000750.00059 0.005680.00469 0.0075 0.153100.12754
Winter Period
Demand Charge (per kW) $ 3.462.96 $ 18.2514.94
$ 21.7117.90
Energy Charge (per kWh) 0.092120.07597 0.000750.00059 0.005680.00469 0.0075 0.106050.08875
Minimum Bill ($/day) 62.553951.5696
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-2 Sheet No E-7-G-2
dated 7-1-20221 Effective 7-1-20232
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $ 6.035.16 $ 33.0527.06
$ 39.0832.22
Energy Charge (per kWh) 0.139170.11476 0.000750.00059 0.005680.00469 0.145600.12004
Palo Alto Green Charge (per 1000 kWh block) $7.50
Winter Period
Demand Charge (per kW) $ 3.462.96 $ 18.2514.94
$ 21.7117.90
Energy Charge (per kWh) 0.092120.07597 0.000750.00059 0.005680.00469 0.098550.08125
Palo Alto Green Charge (per 1000 kWh block) $7.50
Minimum Bill ($/day) 62.553951.5696
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
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-3 Sheet No E-7-G-3
dated 7-1-20221 Effective 7-1-20232
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. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The power factor adjustment is applied
by increasing the total energy and Demand charges for any month by 0.25 percent or
(1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load
was less than 95%.
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-4 Sheet No E-7-G-4
dated 7-1-20221 Effective 7-1-20232
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with
the Customer's Maximum Demand.
6. 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
7. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. 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.
8. 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 1/2 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
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-5 Sheet No E-7-G-5
dated 7-1-20221 Effective 7-1-20232
a. Applicability: The standby charge, subject to the exemptions in subsection
D(9)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76
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.
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
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-6 Sheet No E-7-G-6
dated 7-1-20221 Effective 7-1-20232
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-1 Sheet No E-7-TOU-1
dated 7-1-202219 Effective 7-1-20232
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. In
addition, this Rate Schedule is applicable for Customers who did not pay power factor
adjustments during the last 12 months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $ 3.863.24 $ 11.089.08 $ 14.9412.32
Mid-Peak 1.130.99 11.089.08 12.2110.07
Off-Peak 1.130.99 11.089.08 12.2110.07
Energy Charge (per kWh)
Peak
$ 0.144570.11921 $ 0.000750.00059 $ 0.005680.00469 $ 0.151000.12449
Mid-Peak 0.182050.15011 0.000750.00059 0.005680.00469 0.188480.15539
Off-Peak 0.111710.09212 0.000750.00059 0.005680.00469 0.118140.09740
Winter Period
Demand Charge (per kW)
Peak $ 1.781.51 $ 9.227.56 $ 11.009.07
Off-Peak 1.781.51 9.227.56 11.009.07
Energy Charge (per kWh)
Peak $ 0.096970.07 $ 0.000750.00059 $ 0.005680.00469 $ 0.103400.08525
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-2 Sheet No E-7-TOU-2
dated 7-1-202219 Effective 7-1-20232
997
Off-Peak 0.083230.06864 0.000750.00059 0.005680.00469 0.089660.07392
Minimum Bill ($/day) 62.553951.5696
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):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday
All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
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.
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-3 Sheet No E-7-TOU-3
dated 7-1-202219 Effective 7-1-20232
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. Power Factor Adjustment
Time of Use Customers must not have had a power factor adjustment assessed on their Service
for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt-
ampere hours consumed during the month, and must not have fallen below 95% to avoid the
power factor adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be
subject to power factor adjustments, the Customer will be removed from the E-7-TOU rate
schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand
and kilowatt-hour usage.
6. 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.
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-4 Sheet No E-7-TOU-4
dated 7-1-202219 Effective 7-1-20232
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 1/2 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.
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
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.
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-5 Sheet No E-7-TOU-5
dated 7-1-202219 Effective 7-1-20232
(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}
NET METERING NET SURPLUS ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-NSE-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-NSE-1 Sheet No. E-NSE-1
dated 07-01-20221 Effective 7-1-20232
A. APPLICABILITY:
This Rate Schedule applies to eligible residential and small commercial Net Energy Metering
Customers who, at the end of an annual settlement period, as described in Rule 29, are Net Surplus
Customer-Generators of electricity who elect to receive monetary compensation as such preference
is indicated on the net surplus electricity election form. This Rate Schedule only applies to
Customers who participate in Net Energy Metering, and does not apply to Customers that take
service under the City’s Net Energy Metering Successor Rate, as each of these terms are defined in
Rule and Regulation 2.
B. TERRITORY:
This rate schedule applies everyanywhere the City of Palo Alto provides eElectric Sservice.
C. RATES:
Per kWh
Net Surplus Electricity Compensation rate $ 0.1535 0.1026
D. SPECIAL CONDITIONS
1. Net Surplus Electricity Compensation Rate eligibility shall be determined as specified in Rule
29. Net surplus electricity, as specified in Rule 29, if applicable, will be multiplied by the above
compensation rate to determine the Customer’s annual net surplus electricity compensation
stated in dollars.
2. Additional terms, conditions and definitions govern Net Energy Metering Service and
Interconnection, as described in Rule 29.
{End}
EXPORT ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-EEC-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-EEC-1 Sheet No.E-EEC-1
dated 7-1-20212 Effective 7-1-20232
A. APPLICABILITY:
This Rate Schedule applies in conjunction with the otherwise applicable Rate Schedules for each
Customer class. This Rate Schedule may not apply in conjunction with any time-of-use Rate
Schedule. This Rate Schedule applies to Customer-Generators as defined in Rule and Regulation 2
who are either not eligible for Net Energy Metering or who are eligible for Net Energy metering but
elect to take Service under this Rate Schedule.
B. TERRITORY:
This rate schedule Aapplies everywhere to locations within the service area of the City of Palo Alto
provides Electric Service.
C. RATE:
The following compensationbuyback rate shall apply to all electricity exported to the grid.
Per kWh
Export electricity compensation rate $ 0.1685 0.1045
D. SPECIAL CONDITIONS
1. Metering equipment: Electricity delivered by CPAU to the Customer-Generator or received by
CPAU from the Customer-Generator shall be measured using a Meter capable of registering the
flow of electricity in two directions (aka “bidirectional meter”). The electrical power
measurements will be used for billing the Customer-Generator. CPAU shall furnish, install and
own the appropriate Meter.
2. Billing:
a. CPAU shall measure during the billing period, in kilowatt-hours, the electricity delivered
and received after the Customer-Generator serves its own instantaneous load.
b. CPAU shall bill the Customer-Generator consumption charges for the electricity delivered
by CPAU to the Customer-Generator based on the Customer-Generator’s applicable Rate
Schedule.
c. In the event the electricity generated exceeds the electricity consumed and therefore is
received by CPAU, the Customer will receive a credit for all electricity received by
CPAU at the buyback Rate designated in section C above.
{End}