HomeMy WebLinkAboutStaff Report 10217
City of Palo Alto (ID # 10217)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/15/2019
City of Palo Alto Page 1
Council Priority: Fiscal Sustainability
Summary Title: FY 2020 Electric Financial Plan and Rates
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt: 1) a Resolution Approving the Fiscal Year 2020 Electric Financial Plan,
and 2) a Resolution Increasing Electric Rates by Amending the E -1, E-2, E-2-G,
E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU, E-14, E-EEC and E-NSE Rate Schedules
From: City Manager
Lead Department: Utilities
Recommendation
Staff requests that the Finance Committee recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2020 Electric Financial
Plan and proposed transfers (Attachment B); and
2. Adopt a resolution (Attachment C) amending Rate Schedules E -1 (Residential Electric
Service), E-2 (Small Non-Residential Electric Service), E-2-G (Small Non-Residential
Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-
Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-
7-G (Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-
Residential Time of Use Electric Service), E-14 (Street Lights), E-NSE (Net Metering Net
Surplus Electricity Compensation), and E-EEC (Export Electricity Compensation).
Executive Summary
The FY 2020 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2024. Costs are projected to rise substantially for the next several years for several
reasons. Costs for electric supply purchases are increasing as a result of increases in
transmission costs. Substantial additional capital investment s in the electric distribution system
are planned for FY 2019 through FY 2023, and operational costs are increasing. There has also
been some decrease in the City’s electric load over the past few years. Lastly, revenues are
below costs as of FY 2019.
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Because of these rising costs and other factors, an increase in sales revenues is req uired to
adequately maintain the Electric Fund. An 8 percent rate increase is proposed for July 1, 2019,
with 4 percent increases in the following years. While 8 percent would be the overall increase
in average rates, different customer classes will see slightly different increases ranging from 6
percent to 8 percent, as shown in Tables 3 and 4. Actual rate increases are calculated using the
2016 cost of service analysis (COSA) model created for the City by EES Consulting, which was
implemented on July 1, 2016.
Background
Every year staff presents the Utility Advisory Commission (UAC) with Financial Plans for its
Electric, Gas, Water, and Wastewater Collection Utilities and recommends any rate adjustments
required to maintain the financial health of these utilities. 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.
City of Palo Alto Page 3
Discussion
Summary of Proposed Actions
The two resolutions recommended for Council adop tion will accomplish the following:
1) Increase overall electric rates by 8 percent effective July 1, 2019;
2) Approve the FY 2020 Electric Financial Plan, including the following transfers for FY 2019:
a) Approve a transfer of up to $4 million from the Hydro Stabilization Reserve to the
Supply Operations Reserve to maintain reserve adequacy.
b) Transfer all remaining funds ($9.011 million) from the Rate Stabilization reserve to
the Supply Operations Reserve;
c) Transfer up to $2 million from the Supply Operations to the Distribution Operations
reserve to maintain reserve adequacy.
Reserve balance projections for FY 2019 have taken these transfers into account. To effect
these transfers, staff is re-ratifying the following transfer proposals, which were previously
approved in resolution 9692 to take place in FY 2017, but which were not performed: 1)
transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to the Supply
Operations Reserve, 2) transfer up to $9.011 million from the Supply Rat e Stabilization Reserve
to the Supply Operations Reserve, and 3) transfer up to $4.5 million from the Supply Operations
Reserve to the Distribution Operations Reserve.
Proposed and Projected Sales Revenue Requirement, FY 2020 through FY 2024
The proposed July 1, 2019 rate increase would be the fourth and last projected increase in a
series of substantial rate increases starting in FY 2017 and continuing into the foreseeable
future. Prior to the first increase on July 1, 2016, rates had not been increased for six
consecutive years since July 1, 2009 because costs had been low over that period. Table 1
shows the sales revenue increases needed to recover costs of operation over the forecast
period in the FY 2020 Electric Financial Plan.
Table 1: Electric Rate Adjustments, FY 2017 to FY 2024
FY 2017
Approved
FY 2018
Approved
FY 2019
Approved
FY 2020
Projected
FY 2021
Projected
FY 2022
Projected
FY 2023
Projected
FY 2024
Projected
11% 14% 6% 8% 4% 4% 4% 3%
These retail rate increases are for the utility as a whole, but the rate changes will differ for
individual customer classes. Proposed rate increases for each customer class are discussed
below.
City of Palo Alto Page 4
Changes from Prior Financial Forecasts
This projection has changed since the FY 2019 Electric Utility Financial Plan presented last year.
Table 2 compares current rate projections to those projected in the last two year’s Financial
Plans.
Table 2: Projected Electric Rate Trajectory for FY 2019 to FY 2025
Projection FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Current
(FY 2020 Financial Plan) 8% 4% 4% 4% 3%
Last year
(FY 2019 Financial Plan) 3% 2% 0% 1% 1%
Two years ago
(FY 2018 Financial Plan) 0% 0% 1% 2% 1%
The rate increases are related to several factors: increasing transmission costs and the cost of
renewable projects coming online, substantial additional capital investment in the electric
distribution system is planned through FY 2023, and operations costs are increasing due to
larger contracting needs. Revenues have also declined as customer usage has decreased,
requiring larger than projected rate increases.
Historically, total electric utility costs (excluding short-term drought impacts) were roughly
$120 million per year, allowing the electric utility to go without a rate increase from July 1, 2009
to July 1, 2016. Over the period from FY 2016 to FY 2018, though, annual costs (net of energy
supply related revenue, like surplus energy sales) increased to roughly $146 million per year
(costs are unusually low in FY 2019 due to some one time savings). Costs are projected to
increase to over $160 million by FY 2024. Figure 1 shows the overall utility’s costs (net of
surplus sales revenues) in FY 2014, FY 2019, and FY 2024. Costs for the supply portfolio
increased by about 3.5 percent per year on average in the past, but are projected to increase at
a slower pace (about 1 percent) in the future. Costs for managing the distribution system (e.g.
maintenance, capital investment, customer service, billing, etc.) have increased as well, growing
by 3.2 percent per year on average in the past, but projected to grow by nearly 4 percent per
year going forward. Overall, costs are projected to increase by 2.2 percent per year over the
forecast horizon
City of Palo Alto Page 5
Figure 1: Electric Utility Costs, FY 2014 Actual vs. FY 2019 and FY 2024 Projections
Figure 2 shows electric distribution costs more specifically. Capital costs increased significantly,
increasing by about 7.5 percent per year on average over the last five years. Increased costs are
related to increased capital investment in the distribution system (e.g. underground district
rebuilds, as well as substation and upgrades). Distribution system operational spending is
projected to increase by about 3 to 4 percent annually. Some of this is due to projected
increases in costs of labor and materials, but also due to the fact that in FY 2014 operational
costs were unusually low due to higher than anticipated staff vacancies and other factors.
Figure 2: Electric Distribution Costs, FY 2014 vs. FY 2019 and FY 2024
City of Palo Alto Page 6
The electric supply portfolio cost increases from FY 2014 to FY 2019 are related primarily to
transmission cost increases and, to a lesser extent, to renewable energy projects coming online,
as shown in Figure 3. In the future, staff forecasts that increased costs will largely be due to
transmission cost increases. These are due to rehabilitation and replacement of the existing
statewide electric transmission system as well as expansion of that system to accommodate
new generation, mostly renewable. Staff works to contain transmission costs through partner
agencies, including the Transmission Agency of Northern California (TANC) and Northern
California Power Agency (NCPA), and through direct partners hips with other local utilities (the
Bay Area Municipal Transmission group, BAMx). All of these groups intervene in transmission
proceedings at the Federal Energy Regulatory Commission (FERC) and the California
Independent System Operator (CAISO) and have achieved some reductions in long-term
transmission costs. Staff is beginning to look at strategies to achieve cost savings in electric
supply, and will discuss these strategies in greater detail through the ongoing Integrated
Resource Planning (IRP) process.
Figure 3: Electric Supply Costs, FY 2014 Actual vs. FY 2019 and FY 2024 Projections
With an 8 percent rate increase, this Financial Plan will prevent any further reductions in
reserves, which are relatively low. The Supply and Distribution Operations Reserves are at their
minimums, the Hydroelectric Stabilization Reserve is at $7.4 million, below the target of $17
million that enables the City to implement its strategy for managing the financial impacts of a
multi-year drought, and the electric utility has already taken a loan of $10 million from its
Electric Special Projects reserve, which is intended to fund projects like smart grid and a second
transmission line. More information on reserve transfers can be found in the FY 2020 Electric
Financial Plan (Attachment B).
City of Palo Alto Page 7
Staff also recognizes the importance of managing operating costs and maximizing efficiency in
order to minimize rate increases. As discussed above, staff is working on cost containment
measures related to transmission and renewable en ergy costs. Utility consumers also see some
long-term cost savings from City-wide efforts to manage personnel costs. As reflected in the
Utilities Strategic Plan, staff is exploring additional ways to effectively use available resources,
particularly across Divisions.
Rate Changes by Customer Class
Table 3 shows the rates that will be used to recover sale revenues for each customer class. The
Street Lighting (E-14) class and the E-4 and E-7 Time of Use (TOU) rates are not shown in the
table, but can be seen in the attached rate schedules (Attachment E). These schedules are
omitted from Table 3 due to the complexity of these rate schedules and/or these rate
schedules are used by one or none of CPAU’s customers.
City of Palo Alto Page 8
Table 3: Electric Rates (Current and Proposed)
Current
Rates
Proposed
Rates
(7/1/19)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.12871 0.13757 0.00886 6.9%
Tier 2 Energy ($/kWh) 0.19279 0.19367 0.00088 0.5%
Minimum Bill ($/day) 0.3040 0.3283 0.0243 8.0%
E-2 & E-2-G (Small Non-Residential)
Summer Energy
($/kWh)
0.20090 0.20853 0.00763 3.8%
Winter Energy ($/kWh) 0.13861 0.14624 0.00763 5.5%
Minimum Bill ($/day) 0.7740 0.8359 0.0619 8.0%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy
($/kWh)
0.12081 0.12848 0.00767 6.3%
Winter Energy ($/kWh) 0.09297 0.09946 0.00649 7.0%
Summer Demand
($/kW)
24.11 28.91 4.80 19.9%
Winter Demand ($/kW) 18.52 18.97 0.45 2.4%
Minimum Bill ($/day) 15.9946 17.2742 1.2796 8.0%
E-7 & E-7-G (Large Non-Residential)
Summer Energy
($/kWh)
0.10507 0.11432 0.00925 8.8%
Winter Energy ($/kWh) 0.07449 0.07738 0.00289 3.9%
Summer Demand
($/kW)
26.77 30.69 3.92 14.6%
Winter Demand ($/kW) 17.01 17.05 0.04 0.2%
Minimum Bill ($/day) 45.4758 49.1139 3.6381 8.0%
Table 4 shows the impact of the proposed July 1, 2019 rate changes on the residential and non -
residential bills for various consumption levels. The overall rate change for the residential class
is roughly 4 percent.
City of Palo Alto Page 9
Table 4: Impact of Proposed Electric Rate Changes on Customer Bills
Rate
Schedule
Usage (kwh/mo)
Bill under
Current Rates
($/mo)
Bill Under Rates
Proposed 7/1/19
($/mo)
Change
$/mo %
E-1 300 38.61 41.27 2.66 6.9
(Summer Median) 365 49.22 45.40 2.92 6.9
(Winter Median) 453 66.19 69.22 3.03 4.6
650 104.17 107.37 3.21 3.1
1200 210.20 213.89 3.69 1.8
E-2 1,000 170 178 8 4.5
E-4 160,000 26,347 28,661 2,313 8.8
E-7 500,000 75,758 81,337 5,579 7.4
E-7 2,000,000 289,010 325,346 22,316 7.4
Cost of Service Analysis and Rate Study
The rates discussed in the previous section are based on the cost of service methodology
established in the “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2016. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates.
Electric Bill Comparison with Surrounding Cities
Table 5 compares electric bills under current rates as of March 1, 2019 for residential customers
to those in surrounding communities. Under current rates, CPAU’s customer bills are far below
PG&E’s and are lower than others for non-residential customers, but slightly higher than Santa
Clara’s for higher using residential customers. It is unclear at this time what electric rate
changes may be implemented in these communities for FY 2020.
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
City of Palo Alto Page 10
Table 5: Average Electric Bill Comparison ($/month)
As of March 1, 2019
Customers
Usage
(KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E Santa Clara
Residential
Customers
300 $ 38.61 $ 41.27 $ 65.33 $ 35.89
365 (Summer
Median) 49.22 45.40 85.16 43.95
453 (Winter
Median) 66.19 69.22 98.64 54.86
650 104.17 107.37 150.77 79.29
1200 210.20 213.89 301.48 147.48
Non-
Residential
Customers
1,000 170 178 253 184
160,000 25,628 28,661 30,936 21,243
500,000 66,780 81,337 86,341 64,155
2,000,000 289,010 325,346 372,799 261,360
Commission Review
The UAC reviewed this proposal at its April 9, 2019 meeting. The excerpted draft minutes from
the UAC’s April 9, 2019 meeting can be found on the City’s website, located here.
Timeline
If the Finance Committee supports the proposed rate adjustments, the City Council will
consider the proposed Financial Plans and amended rate schedules with the FY 2020 budget.
Resource Impact
The proposed July 1, 2019 rate changes are projected to increase sales revenues by $9 million
per year over the forecast period. The FY 2020 Budget is being developed concurrent with these
rates and depending on final rates, adjustments to the budget may be necessary at a later time.
Policy Implications
The proposed electric rate adjustments were developed using the 2016 cost of service study
and methodology, and are consistent with the Council adopted Reserve Management Practices
that are part of the Financial Plan.
Environmental Review
The Finance Committee’s review and recommendation to Council on the FY 2020 Electric
Financial Plans and rate adjustments does not meet the California Environmental Quality Act’s
definition of a project, pursuant to Public Resources Code Section 21065, thus no
environmental review is required.
Attachments:
City of Palo Alto Page 11
• Attachment A: Resolution Approving FY 2020 Electric Utility Financial Plan Draft
• Attachment B: FY 2020 Electric Utility Financial Plan
• Attachment C: Resolution Adopting FY 2021 Electric Rate Schedules
• Attachment D: Proposed Electric Rate Schedules effective July 1, 2019
Attachment A
* NOT YET APPROVED *
6055193
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2020 Electric Utility Financial Plan
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.
This is done 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.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2020 Electric Utility Financial Plan.
SECTION 2. The following transfers that were previously approved by resolution 9692
to take place in FY 2017, but which were not performed due to staff error, are hereby
reauthorized in FY 2019: 1) transfer up to $9.0 million from the Hydroelectric Stabilization
Reserve to the Supply Operations Reserve, 2) transfer up to $9.011 million from the Supply Rate
Stabilization Reserve to the Supply Operations Reserve, and 3) transfer up to $4.5 million from
the Supply Operations Reserve to the Distribution Operations Reserve.
//
//
//
//
//
//
//
Attachment A
* NOT YET APPROVED *
6055193
//
//
SECTION 3. The Council finds that the adoption of this resolution 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 review is required.
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
FY 20 20 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 20 20 TO FY 202 4
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F Y 20 20 ELECTRIC UTILITY
F INANCIAL PLAN
FY 20 20 TO FY 20 2 4
TABLE OF C ONTENTS
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 .................................................................................. 6
Section 3: Detail of FY 2020 Rate and Reserves Proposals ....................................................... 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 7
Section 3C: Reserves Management Practices .............................................................................. 8
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................. 10
Section 4A: Electric Utility History ............................................................................................. 10
Section 4B: Customer Base ........................................................................................................ 12
Section 4C: Distribution System ................................................................................................. 12
Section 4D: Cost Structure and Revenue Sources ...................................................................... 13
Section 4E: Reserves Structure ................................................................................................... 14
Section 4F: Competitiveness ...................................................................................................... 15
Section 5: Utility Financial Projections ................................................................................. 16
Section 5A: Load Forecast .......................................................................................................... 16
Section 5B: FY 2014 to FY 2018 Cost and Revenue Trends ........................................................ 18
Section 5C: FY 2018 Results ....................................................................................................... 19
Section 5D: FY 2019 Projections ................................................................................................ 20
Section 5E: FY 2020 – FY 2024 Projections ................................................................................ 20
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 22
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Section 5G: Long-Term Outlook ................................................................................................. 27
Section 6: Details and Assumptions ..................................................................................... 30
Section 6A: Electricity Purchases ............................................................................................... 30
Section 6B: Operations .............................................................................................................. 32
Section 6C: Capital Improvement Program (CIP) ....................................................................... 33
Section 6D: Debt Service ............................................................................................................ 34
Section 6E: Equity Transfer ........................................................................................................ 35
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 35
Section 6G: Sales Revenues ....................................................................................................... 36
Section 7: Communications Plan .......................................................................................... 37
Appendices ......................................................................................................................... 39
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 40
Appendix B: Electric Utility Reserves Management Practices ................................................... 44
Appendix C: Description of Electric utility Operational Ac tivities .............................................. 49
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 50
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SECTION 1 : DEFINITIONS AND ABBR EVIATIONS
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’s Electric Utility for the next five fiscal
years. 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 2 A : OVERVIEW OF FINANC IAL POSITION
The Electric Utility’s costs are projected to increase by about 3% per year on average over the
forecast horizon, as shown in Table 1. The majority of cost is related to electric supply
purchases, which are increasing mainly due increased transmission costs and are projected to
grow at an estimated 2% per year on average. Operations and maintenance costs are about one
third of total costs, and are projected to increase by about 3 to 4% per year on average due to
both inflationary as well as salary and benefits increases. Capital improvement costs are
currently projected to grow by about 6% on average, mainly precipitated by rebuilds of existing
underground districts as well as substation improvements and volta ge conversion projects.
Table 1: Electric Utility Expenses for FY 2018 to FY 2024
Expenses
($000)
FY 2018
(act.)
FY 2019
(est.) FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Power Supply
Purchases
94,630 90,625 95,615 95,488 98,895 98,309 98,673
Operations 54,770 52,547 55,087 57,302 60,284 62,265 63,256
Capital Projects 18,803 14,156 15,409 20,148 17,915 19,172 19,268
TOTAL 168,203 157,328 166,112 172,938 177,094 179,746 181,197
To cover these increases in costs, revenues (and therefore rates) need to increase over the next
several years to balance costs and maintain adequate reserves, as shown in Table 2. The table
also compares current rate projections to those projected in last year’s Financial Plan. The rate
projections are slightly higher over the forecast period than last year primarily due to lower
actual and projected sales, increases to transmission cost projections and increases to capital
investment spending.
Table 2: Projected Electric Rates, FY 2020 to FY 2024
Projection FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Current 8% 4% 4% 4% 3%
Last Year 3% 2% 0% 1% 1%
Table 3 shows the projected reserve transfers over the forecast period. The Supply Rate
Stabilization Reserve is projected to be drawn down entirely by the end of FY 201 9. Per Council
approval, $10 million was transferred from the Electric Special Projects (ESP) Reserve in FY 2018
to the Operations Reserve. Any transfers from the ESP Reserve require Council approval.
Council also approved using all remaining funds ($11.2 million) from the Hydro Stabilization
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Reserve, but ending reserves show that only $4 million is warranted at this point. It is staff’s
intention to repay the $10 million loan from ESP reserve and fund the Hydro Stabilization
reserve as is prudent.
Table 3: Reserves Transfers for FY 2019 to FY 2024 ($000)
Reserve FY 2019 FY 2020 FY 2021 to FY 2024
Supply Reserves
Electric Special Projects - - 10,000
Hydro Stabilization (4,000) - 4,000
Supply Rate Stabilization (9,011) - -
Supply Operations 11,011
Distribution Reserves
Capital Improvement Program - - -
Distribution Operations 2,000 - -
*
SECTION 2 B : SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2019:
1. Approve a transfer of up to $4 million from the Hydro Stabilization Reserve to the
Supply Operations Reserve to maintain reserve adequacy.
2. Transfer all remaining funds ($9.011 million) from the Rate Stabilization reserve to the
Supply Operations Reserve.
3. Transfer up to $2 million from the Supply Operations to the Distribution Operations
reserve to maintain reserve adequacy.
Staff proposes the following actions for the Electric Utility in FY 2020:
1. Increase rates effective July 1, 2019 for an 8% increase in system average rates.
SECTION 3 : DETAIL OF FY 20 20 RATE AND RESERVES P ROPOSALS
SECTION 3 A : RATE DESIGN
The rate increase discussed in the previous section is based on the cost of service methodology
established in “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2015/16. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
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proposed rates. The COSA is based on design guidelines adopted by Council on September 15,
2015 (Staff Report 6061).
SECTION 3 B : CURRENT AND PROPOSED RATES
The City adopted the current rates effective July 1, 2018, when CPAU increased electric rates by
6%. Table 4, below, summarizes the current and proposed rates for the four largest customer
classes. The Electric Utility also has specialty rates for smaller groups of customers. These
include variations on its primary rates, such as time of use rates and solar net metering. Staff
proposes an 8% overall increase in average rates. Different customer classes may see different
percentage changes to their rates, based upon their usage of the system and cost to serve each
group.
Table 4: Current and Proposed FY 2020 Electric Rates
Current Rates
Proposed Rates
(7/1/19)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.12871 0.13757 0.00886 6.9%
Tier 2 Energy ($/kWh) 0.19279 0.19367 0.00088 0.5%
Minimum Bill ($/day) 0.3040 0.3283 0.0243 8.0%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.20090 0.20853 0.00763 3.8%
Winter Energy ($/kWh) 0.13861 0.14624 0.00763 5.5%
Minimum Bill ($/day) 0.7740 0.8359 0.0619 8.0%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.12081 0.12848 0.00767 6.3%
Winter Energy ($/kWh) 0.09297 0.09946 0.00649 7.0%
Summer Demand ($/kW) 24.11 28.91 4.80 19.9%
Winter Demand ($/kW) 18.52 18.97 0.45 2.4%
Minimum Bill ($/day) 15.9946 17.2742 1.2796 8.0%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.10507 0.11432 0.00925 8.8%
Winter Energy ($/kWh) 0.07449 0.07738 0.00289 3.9%
Summer Demand ($/kW) 26.77 30.69 3.92 14.6%
Winter Demand ($/kW) 17.01 17.05 0.04 0.2%
Minimum Bill ($/day) 45.4758 49.1139 3.6381 8.0%
These proposed rates were prepared in conformance with the “FY 2017 City of Palo Alto Electric
Cost of Service and Rate Study,” performed by EES Consulting (2016).
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SECTION 3 C : RESERVES MANAGEM ENT PRACTICES
This financial plan proposes no changes to the Reserves Management Practices (See Appendix
B: Electric Utility Reserves Management Practices), although staff will continue to review these
policies as required.
SECTION 3 D : PROPOSED RESERVE TRA NSFERS
As part of the FY 2019 Financial Plan, Staff did not propose and FY 2019 transfers but was
intending on including them as part of the year end BAO process. However, the timing of
reserve reconciliations did not allow for these recommendations to take place. Therefore, staff
will be proposing multiple transfers for FY 2019, requesting that Council approve amounts ‘up
to’ the levels suggested, based upon anticipated ending reserve levels:
• Transfer up to $9.011 million from the Rate Stabilization Reserve to the Supply
Operations Reserve.
• Transfer up to $4.0 million from the Hydroelectric Stabilization Reserve to the Supply
Operations Reserve.
Transfer up to $2 million from the Supply Operations Reserve to the Distribution
Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve.
Reserve balances for FY 2019 have taken these transfers into account. To affect these transfers,
staff is re-ratifying the following transfer proposals, which were previously approved in
resolution 9692 to take place in FY 2017, but were not performed: 1) transfer up to $9 million
from the Hydroelectric Stabilization Reserve to the Supply Operations Reserve, 2) Transfer up to
$9.011 million from the Rate Stabilization Reserve to the Supply Operations Reserve, and 3)
Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution Operations
Reserve.
In FY 2018, Council approved a $10 million loan from the Electric Special Projects (ESP) reserve,
and it is staff’s intention as part of this financial plan to repay the full amount back within the
timeframe of this financial planning horizon. The pace of payback may be moderated based
upon the general financial health of the electric fund.
Figure (for Supply Fund Reserves) and Figure 5 (for Distribution Fund Reserves) in Section 5E: FY
2020 – FY 2024 Projections show the impact of these transfers on reserves levels. Table 5 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
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Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2017 to FY 2024
Ending Reserve
Balance ($000)
FY 2018
(Act.) FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Re-appropriations 9,063 - - - - - -
Commitments 8,637 3,533 3,533 3,533 3,533 3,533 3,533
Underground Loan 730 730 730 730 730 730 730
Public Benefits 681 - - - - - -
Special Projects 41,838 41,838 41,838 41,838 41,838 46,838 51,838
Hydro Stabilization 11,400 7,400 7,400 7,400 11,400 11,400 11,400
Capital 880 880 880 880 880 880 880
Rate Stabilization 9,011 - - - - - -
Operations 19,900 30,933 30,074 31,260 32,472 36,630 40,603
Unassigned - - - - - - -
TOTAL 102,140 85,314 84,455 85,641 90,853 100,011 108,984
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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 4 A : 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 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
11 | P a g e
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 Californ ia, 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
Utility2 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 pr oject 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 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 CPAU adopted a goal of achieving 20% of its energy
supply from renewables by 2015. Subsequently CPAU 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 renewable energy purchases (RECs) to meet the balance of its needs.
2 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
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Figure 1: Customer Consumption By Class (FY 2018)
16%
6%
36%
42%
Residential
Small Comm.
Med. Comm.
Large Comm.
SECTION 4 B : 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 29,600 customers
connected to the electric system,
25,550 (86%) of which are residential
and 4,050 (14%) of which are non-
residential. Residential customers
consumed 148 gigawatt-hours (GWh)
in FY 2018, approximately 16% of the
electricity sold, while non-residential
customers consumed 84% or 752
GWh. Residential customers use
electricity primarily for lighting,
refrigeration, electronics, and air conditioning.3 Non-residential customers use the majority of
their electricity for cooling, ventilation, lighting, office equipment (offices), cooking
(restaurants), and refrigeration (grocery stores).4
As shown in Figure 1 large customer loads represent a large 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 71 customers on the E-7 rate schedule)
account for around 42% of CPAU’s sales. The next largest customer group (the 830 non-
residential customers on the E-4 rate schedule) represents another 36% of sales. In total, that
means that about 3% of customers account for nearly three quarters of the electr ic load.
SECTION 4 C : 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.
3 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
4 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
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Figure 2: Cost Structure (FY 2018)
56%
33%
11%
Commodity
Supply
Operations
Capital
Figure 3: Hydroelectric Variability (FY 2019)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 4: Revenue Structure (FY 2018)
80%
20%
Sales of Electricity
Other Revenue
SECTION 4 D : COST STRUCTURE AND R EVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 56% of the Electric Utility’s
costs in FY 2018. Operational costs
represented roughly 33%, and
capital investment was responsible
for the remaining 11%. 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 54% of total costs in FY 2024.
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
shows the relative difference
in costs under high,
projected, and low hydroelectric
generation scenarios for FY 2019.
Additional costs associated with a very
low generation scenario can range from
$9-11 million per year. For the current
hydroelectric risk assessment see Section
5F: Risk Assessment and Reserves
Adequacy.
As shown in Figure the Electric Utility
receives 80% 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, and other sources. Some revenue sources are primarily
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accounting entries that reflect things such as CPAU’s participation in a pre-funding program
associated with its contract with WAPA, as well as accounting entries associated with
occasional sales of surplus hydroelectric energy during wet years. 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 900 largest customers, which provide a similar share of the utility’s revenue stream.
The utility’s retail rate schedules have no fixed charges, although about 24% 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 4 E : RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of
contingencies. 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 may
also be useful for rate design as the nature of utility services evolves in response to higher
penetrations of distributed generation.
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 reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations 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 began 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.
• 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 is used to provide
working capital and contingency funds for the CIP program, as well as to accumulate
funds for major future one-time expenditures. This type of reserve is used in other
utility funds (Electric, 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 for ecast 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 4 F : COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2018 was
$676 under current CPAU rates, about 35% lower than the annual bill for a PG&E customer with
the same consumption and approximately 16% higher than the annual bill for a City of Santa
Clara customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X ,
which includes most surrounding comparison communities.
Table 6 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 March 1, 2019.
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
16 | P a g e
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.
The bill calculations show bills under the existing rates, not the proposed July 1, 201 9 rates.
However, even with the proposed rate increases, Palo Alto’s residential bills will remain
substantially below PG&E’s current rates, but slightly above Santa Clara’s.
Table 6: Residential Monthly Electric Bill Comparison (Effective 3/1/19, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(March)
300 38.61 65.33 35.89
453 (Median) 66.19 98.64 54.86
650 104.17 150.77 79.29
1200 210.20 301.48 147.48
Summer
(July)
300 38.61 67.35 35.89
(Median) 365 49.22 85.16 43.95
650 104.17 163.26 79.29
1200 210.20 313.97 147.48
Table 7 shows the average monthly electric bill for commercial customers for various usage
levels. Even with the proposed rate increases, Palo Alto’s commercial bills will remain
substantially below PG&E’s, and below Santa Clara’s for some commercial customers.
Table 7: Commercial Monthly Electric Bill Comparison (3/1/19, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 170 253 184
160,000 25,628 30,936 21,243
500,000 66,780 86,341 64,155
2,000,000 289,010 372,799 261,360
SECTION 5 : UTILITY FINANCIAL PROJECTIONS
SECTION 5 A : LOAD FORECAST
Figure 3 shows a 34-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. Recently, some larger commercial customers have relocated
operations or shifted to more office type usage. It is unknown how long this trend may
continue.
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Figure 3: Historical Electricity Consumption
Figure 4 shows the forecast of electricity consumption through FY 2028. The forecast assumes
about a 3% demand drop in FY 2019, followed by a generally flattened demand thereafter. This
projection assumes the resumption of an overall declining demand trend, but at a less
steepened pace. These projections will be revised if continuing sales patterns indicate further
declines, or changes in customer mix occur.
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Figure 4: Forecasted Electricity Consumption
SECTION 5 B : FY 20 1 4 TO FY 201 8 COST AND REVENUE TR ENDS
As shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail
, the annual expenses for the Electric Utility remained fairly stable between FY 2014 and FY
2017, but increased in FY 2018. On the capital side, the large Upgrade Downtown CIP project
got underway in FY 2018, which is a much larger project than usual . Electric supply costs
increased as new renewable projects came online, and transmission co sts have risen as
improvements are made to the overall California grid.
Section 6A: Electricity Purchases discusses the factors influencing Electric Utility expenses. Since
FY 2012, total expenses for the utility have included the costs of renewable resources coming
online. In FY 2014 through FY 2015 commodity costs were higher due to lower than average
output from hydroelectric resources. Transmission and renewables costs have increased, as
projected in prior financial plans.
Commodity costs have increased, on average, by about 8% per year over this timeframe.
Operations costs have increased by about 5% annually on average. Revenues have increased on
average by about 5% per year over this period, although FY 18 sales revenues were lower than
projected due to declining sales.
Actual Projection
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2018 and Projections through FY 2024
SECTION 5 C : FY 201 8 RESULTS
FY 2018 saw a continuing decline in sales, and with it lower sales revenues than projected by
about $2 million. In addition, interest income was negligible due to market valuations, and
other revenue sources were lower as well. Total cost of purchasing electricity was higher than
the forecast by approximately $11 million due to dry hydro conditions, but these were offset
somewhat by operations and capital improvement costs being lower than projected. Overall
reserves were impacted by about $11.4 million more than expected.
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Table 8 FY 2018, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues lower than forecast $2,086 Revenue decrease
Interest and other income lower than expected 413 Revenue decrease
Higher purchased electricity costs 11,123 Cost increase
Lower operations expense (2,211) Cost decrease
Net Cost / (Benefit) of Variances $11,411
SECTION 5 D : FY 201 9 PROJECTIONS
Last year, staff recommended (and Council approved) a 6% rate change for July 1, 2018.
Declining sales led to a revision of revenues, and staff is estimating $8.2 million lower sales.
Other revenues are projected to be about $2.6 million higher, however, and revised expense
estimates bring overall operations costs down by $1.8 million. A revised CIP outlook also
reduces projected expenses by about $8.5 million, as these projects were previously
encumbered and not new funding.
Table 9 FY 2019, Change in Projected Results, 2019 Forecast vs. 2019 Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues revision 8,278 Revenue decrease
Wholesale and other revenues higher than
forecast
(2,614) Revenue increase
Capital improvement costs (8,528) cost decrease
Purchased electricity costs (1,300) cost decrease
Operations costs (460) cost decrease
Net Cost / (Benefit) of Variances ($4,624)
SECTION 5 E : FY 20 20 – FY 202 4 PROJECTIONS
As shown in Figure above, staff projects costs for the Electric Utility to increase at a fairly
steady rate through the forecast period. Revenue increases of 8% in FY 2020 and another 4% in
FY 2021 are projected to bring revenues in line with expenses. Rising electricity purchase costs
are the primary contributor to the increases. Electricity purchase costs have increased
substantially since FY 2013 as new renewable projects have come online to fulfill the City’s
environmental goals, and as transmission costs have increased due to improvements being
made to the California grid. Operations costs are expected to increase at or near the inflation
rate (2-4 %/year) through the forecast period. Projected capital expenses for FY 2018 through
FY 2021 are higher due to work on the Upgrade Downtown project, the rebuilding of existing
underground districts, substation and line voltage upgrades . Once these larger, one-time
project cost increases are completed, annual CIPs may decline somewhat, but staff has included
additional cost assumptions in case further underground district construction is required.
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Reserves trends based on these revenue projections are shown in Figure (for Supply Fund
Reserves) and Figure 5 (for Distribution Fund Reserves), below. The Supply Rate Stabilization
Reserve will be empty by the end of FY 2019.
Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2018 and Projections through FY 2024
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Figure 5: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2018 and Projections through FY 2024
SECTION 5 F : RISK ASSESSMENT AND RESERVES ADEQUA CY
The Electric Utility currently has two primary contingency reserves, the Supply Operations
Reserve and the Distribution Operations Reserve. In the past, the Supply and Distribution funds
had Rate Stabilization Reserves (RSR), but these are being phased out over time. The Supply
RSR currently has $9 million which needs to be transferred to the Supply Operations Reserve. In
addition, the Electric Utility has a Hydro Stabilization reserve and an Electric Special Projects
reserve, both of which can be utilized with prior Council approval.
This Financial Plan maintains reserves above the reserve minimum for the Distribution
Operations Reserve throughout the forecast period. Reserve levels also exceed the short-term
risk assessment level for the Distribution Fund. The Supply Operations Reserve, however, is
currently below minimum levels pending proposed transfers from the Supply Rate Stabilization
Reserve. .
There are a variety of risks associated with the Supply Fund as are shown in Table 10. Because
of the high range of uncertainty in energy price predictions more than three years in the future,
this risk assessment is only performed for the first two fiscal years of the forecast period. It is
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important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 10 is very low.
Table 10: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2020 FY 2021
1. Production from Hydroelectric
Resources: Western & Calaveras 6.8 8.3 Lower than forecasted hydro
2. Nenewable Production: Landfill,
Wind, Solar 2.2 2.0 Lower than forecasted production
3. Market Price (Energy) 0.9 1.0 Higher than forecasted market prices for
energy
4. Load Net Revenue 3.2 3.4 Lower forecast surplus sales
5. Local Capacity 1.1 2.3 Additional local capacity cost
6. Transmission/CAISO 3.6 3.7 High-end transmission forecast scenario
7. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
8. Western Cost 2.3 2.0 Risk of rate adjustments from Western
9. Regulatory and Legal 0.0 0.0 Risks associated with legislative uncertainties
11. Supplier Default 0.2 0.2 Risk of supplier insolvency
Electric Supply Fund Risks $20.8
million
$23.7
million
Projected Supply Operations +
Hydro Stabilization Reserve
Levels
$28.3
million
$28.6
million
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 nearly one third the total cost of all
adverse outcomes. 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 need s to
buy power to replace the lost output. The converse happens when hydroelectric output is
higher than average.
Of the remaining risks for FY 2020, $3.6 million is related to the projected costs if transmission
cost increases are higher than staff’s current forecast. $3.2 million is related to the uncertainty
with surplus energy sales revenues, and uncertainties with regards to renewables production as
well as possible adjustments from Western account for about $2 million each .
As shown in Figure 6, the Supply Operations Reserve was below the minimum reserve
guidelines at the end of FY 2018. However, through reserve transfers and rate increases, staff
projects the Supply Operations Reserve to stay within the reserve guideline levels throughout
the rest pf the forecast period. Figure 11 shows that the combined Hydro Stabilization, Supply
Rate Stabilization and Supply Operations Reserves are projected to be above what is needed for
the risk assessment level.
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Figure 6: Electric Supply Operations Reserve Adequacy
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Figure 7: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 11 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2024. As shown in Figure 12, the Distribution Operations Reserve will stay within the
reserve guidelines 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 11: Electric Distribution Fund Risk Assessment ($000)
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Total non-commodity revenue $56,355 $58,968 $61,705 $65,803 $68,207
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $4,448 $4,654 $4,870 $5,193 $5,383
CIP Budget $15,409 $20,148 $17,915 $19,172 $19,268
CIP Contingency @10% $1,541 $2,015 $1,792 $1,917 $1,927
Total Risk Assessment value $5,989 $6,669 $6,662 $7,111 $7,310
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Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, staff projects the CIP Reserve to be above the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels, CIP Commitments are nearly impossible to project that far out, and
adjustments to the reserve can be made in future years.
Figure 13: Electric CIP Reserve Adequacy
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SECTION 5 G : LONG -TERM OUTLOOK
This forecast covers the period from FY 2020 through FY 2024, but various long-term
developments may create new costs for the utility over the next 5 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
Western for power from the 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 expiring in
2021 and the last in 2028. These three 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
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and other incentives that may or may not be available in the 2020s and beyond. However, staff
is in the process of procuring a replacement for the contract expiring in 2021 at a lower price
than any of the City’s current renewable contracts.
The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs
dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032
(assuming the Utility does not issue any new debt). The project will only be 40 years old at that
time. 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 through 2020. However,
discussions at the state level are ongoing and will determine whether or not these allocations
continue past 2020, as well as any restrictions CARB may wish to enact on 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.
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 continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these
factors may begin to create notable increases in electric consumption and have a variety of
impacts on the distribution system. As housing stock is turned over, however, stricter building
codes may help to counteract load growth, as may increasing numbers of rooftop solar
installations. The utility has already started to take some of these factors into account in its
long-term planning processes, but will need to con tinue to incorporate them into its planning
methodologies.
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Over the long term, it is conceivable that electricity could replace natural gas and petroleum
almost entirely. Many, if not most, vehicles would use electricity, though hydrogen is another
potential fuel source under development and other technologies might be developed. Staff are
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 technolo gies
involved in electrification.
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SECTION 6 : DETAILS AND ASSUMPTI ONS
SECTION 6 A : ELECTRICITY PURCHAS ES
As shown in Figure 8 the utility gets roughly 50% of its energy from hydroelectric projects in a
normal year (FY 2014 and FY2015 were dry). Contracts with renewable sources made up just
over 30% of the portfolio in FY 2016, and 50% in FY 2017. 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 8: Electricity Supply by Source
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Figure 9 shows the historical and projected costs for the electric supply portfolio,5 as well as
average and actual hydroelectric generation .6 Electric supply costs increased in FY 2013, FY
2014, and FY 2015 due to the drought, which reduced the amount of generation from
hydroelectric resources. Costs decreased slightly in FY 2016 due to better than expected market
purchase costs, and FY 2017 and FY 2018 had lower hydroelectric costs. Renewable energy
costs assumed a larger portion of cost as various renewable projects came online to fulfill the
City’s carbon neutral and RPS goals, although some of the older, higher priced contracts will
start expiring as early as FY 2022. The current market outlook is that newer renewables projects
should come in at lower costs. Transmission charges are also projected to increase as new
transmission lines are built throughout California to accommodate new renewable projects. In
total, electric supply costs are projected to increase to about $86 million by FY 2022, at which
point all currently contracted renewable projects will be online. Supply costs are only projected
to change slightly in subsequent years.
5 Costs are shown net of wholesale revenues, and cannot be directly compared wit h the electric supply purchase
figures shown in Appendix A: Electric Utility Financial Forecast Detail
6 Average hydroelectric generation increased in January of 2015 due to an increase in the utility’s contractual share
of the output of the CVP Federal hydropower project.
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Figure 9: Electric Supply Portfolio Costs, Historical and Projected
SECTION 6 B : 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.
From FY 2014 to FY 2018, overall Operations costs have risen annually by about 4.3% on
average. Debt service and transfers costs increase (reflecting transfers to the ESP reserve to
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repay the $10 million loan in FY 2018). However, over the forecast horizon, staff project costs to
increase by roughly 2-3% per year. Starting in FY 2019 and continuing for several years,
Operations and Maintenance costs are increased mainly due to the introduction of a 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.
Figure 10: Historical and Projected Electric Utility Operational Costs
SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
Staff projects CIP spending for FY 2019 through FY 2024 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 as current projects are completed; 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;
and increase in funding for replacement of distribution system and substation facilities that are
at the end of their useful life. Other significant projects still slated to continue are deteriorated
wood pole replacements, pole relocations to facilitate the Caltrain Railway Electrification
project, Smart Grid upgrades, and ongoing capital investment in the electric distribution system
to maintain/improve reliability. This forecast assumes that the utility finances smart grid
projects from the Electric Special Projects Reserve and with additional funding from the water
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and gas funds, but it would also be possible to use bond financing. That project has tentatively
been moved out to start in FY 2023.
Excluding the one-time projects listed above, the CIP plan for FY 2019 to FY 2024 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). The details of the CIP budget will be available in the Proposed FY 2020 Utilities
Capital Budget. Figure 11 shows the FY 2019 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.
Figure 11: Electric Utility CIP Spending ($000)
SECTION 6 D : DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently
makes payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax
Credit Bonds, Series A. 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 capacity of these projects totaled 250 kW. In
exchange for funding part of the construction costs, the Electric Utility receives the RECs from
these projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are
interest free (the investors receive a tax credit from the federal government). This bond
issuance is secured by the net revenues of the Ele ctric Utility. Debt service for this bond
continues through 2021, and for the financial forecast period is as follows:
Table 11: Electric Utility Debt Service ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2007 Clean Renewable
Energy Bonds 100 100 100 - -
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
One-Time Projects 6,743 (408) 6,335 504 2,075 3,000 3,700 11,700 8,500
System Expansion 150 (4) 146 - - - - - -
Reliability 4,313 (721) 3,592 2,071 1,100 2,750 1,750 600 600
Undergrounding 3,553 (1,506) 2,047 620 50 1,750 50 2,000 -
4/12 Kv Conversion 198 (91) 107 - 1,830 2,000 2,850 1,825 -
Underground Rebuilding 2,259 (7) 2,251 165 2,700 2,650 350 350 350
Ongoing Projects 5,561 (3,183) 2,378 1,069 2,380 2,635 2,415 2,415 2,425
Customer Connections
(Fee Funded)2,830 (1,684) 1,146 411 2,400 2,550 2,700 2,400 2,400
TOTAL 25,607 (7,604) 18,003 4,840 12,535 17,335 13,815 21,290 14,275
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year.
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
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The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage
ratio of 125% of debt service. The current Financial Plan maintains compliance with these
covenants throughout the forecast period, as shown in Appendix C.
The Electric Utility also pledges reserves and net revenue as security for the bond issuances
listed in Table 12, 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 unable to make their debt service payments. Staff does not currently
foresee this occurring.
Table 12: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Electric Utility’s:
Net Revenues Reserves
1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No
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
SECTION 6 E : 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.7 Each year it is calculated
according to the 2009 Council-adopted methodology, and does not require additional Council
action.
SECTION 6 F : WHOLESALE REVENUES A ND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 20% comes
from other sources. Of these other sources, about 50 to 60% represents wholesale revenues of
surplus energy sales included solely for accounting purposes. These revenues have offsetting
electric supply purchase costs, and do not normally affect the utility’s net position. 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. In FY 2017 these sources represented roughly 28% of revenue
7 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.
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from sources other than electricity sales. The remaining FY 2017 revenues consisted of a variety
of one-time transfers.
Revenues from connection fees have increased since FY 2009 varying from year to year.
Revenue from connection fees decreased slightly during the recession, but has increased
substantially since then, peaking in FY 2016 and declining somewhat in FY 2017. Staff forecasts
slightly higher revenue from this source in 2018 through 2021 with revenue leveling out in
subsequent years.
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.
The State’s cap-and-trade program regulations only describe the program through 2020. This
forecast assumes the program will remain in place with similar program design following 2020 ,
but that may not be the case. CARB is in the process of establishing post -2020 rules.
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 6 G : SALES REVENUES
The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure
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 FY 2020 Electric Utility communications strategy covers these primary areas: rates,
efficiency, renewables, operations, infrastructure, safety, and cost containment measures. The
City of Palo Alto Utilities (CPAU) communication methods include use of the Utilit ies website,
utility bill inserts, messaging on bills and envelopes, email newsletters, print and digital ads in
local publications, videos and participation in community outreach events.
In FY 2020, CPAU is proposing an eight percent increase in electric utility rates. Prior to FY 2017,
electric utility rates had not increased since 2009, as the City had been drawing down reserves
from the Electric Fund. The rate increase is necessary in FY 2019 as operations reserves have
dropped below the reserve target level. Communications will focus on the reasons why a rate
increase is necessary due to cost increases in transmission fees, rising operating and capital
costs, and a reduction in electric sales that have affected the City’s reserves. Perhaps more
important to our customers and other stakeholders is that CPAU is actively working to make
cost containment an ongoing priority and part of an annual cycle, consistent with the newly
approved Utilities Strategic Plan.
Despite these costs and increasing rates, CPAU’s electric utility rates still remain lower than the
neighboring community average, including for municipal and investor-owned utilities (PG&E).
Keeping costs low is one of the benefits CPAU offers its customers as a public utility provider.
CPAU will continue to communicate about the environmental benefits of the City’s carbon
neutral electric supply portfolio. Outreach includes apprising the public of major renewable
energy purchase agreements which contribute toward Palo Alto’s long-term energy security
and commitment to sustainability. Power purchase agreements in recent years have allowed
CPAU to procure long-term renewable electric supplies at low costs. While upfront capital costs
to bring these renewable projects online may have initially contributed towards some increase
in CPAU’s electric rates, these higher costs are tapering off as the projects begin commercial
operations. CPAU will highlight these environmental attributes and value in our
communications.
Throughout the year, communications staff promotes CPAU’s electric efficiency services,
rebates, carbon neutral electric portfolio, and local renewable energy programs. Within the
past few years, CPAU has launched new programs that allow customers to better understand
and manage their energy use. Programs such as the Home Efficiency Genie and commercial
energy efficiency programs help residents and businesses better understand energy usage,
activities and/or upgrades they can implement to improve efficiency and keep utility costs low.
CPAU is exploring opportunities to help customers electrify homes and buildings, as well as
their transportation. Rebates for residential appliances such as heat pump water heaters and
electric vehicle charging stations for multi-family and non-profit facilities are incentivizing more
and more customers to take action. Staff are piloting programs to explore electrification
technologies in other applications as well. These efforts are in line with the City’s Sustainability
and Climate Action Plan goals to reduce greenhouse gas emissions. CPAU will also be launching
an upgraded version of its online utility account services portal this year, which can provide
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customers with direct access and more information about utility account and consumption
data.
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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 D ETAIL
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1 FISCAL YEAR FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
2
3 ELECTRIC LOAD
4 Purchases (MWh)980,894 979,005 977,292 945,703 925,329 917,891 889,549 890,589 892,967 895,345 889,136
5 Sales (MWh)950,784 936,773 937,157 917,687 899,997 861,466 858,347 859,350 861,645 863,939 857,948
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1164$ 0.1158$ 0.1156$ 0.1249$ 0.1413$ 0.1504$ 0.1614$ 0.1693$ 0.1776$ 0.1865$ 0.1904$
9 Change in System Average Rate 1%0%0%10%13%6%7%5%5%5%2%
10 Change in Average Residential Bill -1%-5%3%11%11%6%7%4%4%4%2%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)305,000 - - - - - - - - - -
14 Commitments (Non-CIP)3,528,000 3,164,000 3,102,055 3,777,205 2,970,955 3,533,348 3,533,348 3,533,348 3,533,348 3,533,348 3,533,348
15 Restricted for Debt Service - - - - - - - - - - -
16 Emergency Plant Replacement 1,000,000 1,000,000 - - - - - - - - -
17 Central Valley Project Reserve 313,000 329,000 - - - - - - - - -
18 Underground Loan Reserve 738,000 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147
19 Public Benefits Reserves 2,197,000 2,064,000 2,574,000 1,839,000 681,330 93,397 - - - - -
20 Electric Special Projects Reserve 51,838,000 51,838,000 51,837,855 51,837,855 51,837,855 41,837,855 41,837,855 41,837,855 41,837,855 41,837,855 46,837,855
21 Hydro Stabilization Reserve - - 17,000,000 11,400,000 11,400,000 11,400,000 7,400,000 7,400,000 7,400,000 11,400,000 11,400,000
22 Capital Reserves - - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964
23 Rate Stabilization Reserves 69,029,000 70,049,000 14,410,840 9,010,840 9,010,840 9,010,840 - - - - -
24 Operations Reserves - - 22,497,607 21,850,187 29,912,981 19,806,460 30,932,608 30,073,923 31,259,973 32,472,062 36,629,491
25 Unassigned - - - - - - - - - - -
26 TOTAL STARTING RESERVES 128,948,000 129,178,000 112,152,357 100,444,086 107,424,072 87,292,010 85,313,921 84,455,237 85,641,287 90,853,375 100,010,805
27
28 REVENUES
29 Net Sales 110,246,264 108,873,377 108,312,917 114,624,726 127,172,308 129,557,477 138,565,429 145,512,954 153,045,336 161,152,446 163,393,133
30 Wholesale Revenues 6,010,409 6,267,000 4,301,366 16,188,920 18,106,327 14,301,333 17,154,668 17,850,725 20,175,945 19,366,208 19,323,362
31 Other Revenues and Transfers In 13,669,185 9,688,480 11,714,494 11,225,911 13,373,312 14,812,806 12,058,254 12,299,750 10,388,889 9,721,745 8,823,213
32 TOTAL REVENUES 129,925,858 124,828,858 124,328,776 142,039,557 158,651,947 158,671,617 167,778,351 175,663,430 183,610,170 190,240,400 191,539,708
33
34 EXPENSES
35 Electric Supply Purchases 68,785,977 80,022,010 75,705,000 80,467,136 94,629,654 90,625,027 95,615,373 95,487,759 98,895,303 98,309,225 98,672,857
36 Operating Expenses
37 Administration
38 Allocated Charges 4,139,837 4,511,222 4,934,195 3,990,822 6,374,241 6,534,109 6,697,993 6,865,675 7,037,365 7,213,364 7,393,764
39 Rent 4,051,044 4,147,742 4,997,101 5,121,102 5,284,977 5,443,527 5,606,832 5,775,037 5,948,288 6,126,737 6,310,539
40 Debt Service 9,020,651 9,037,000 8,885,994 8,953,893 8,867,395 8,464,871 8,473,276 8,439,378 8,447,315 9,280,490 8,914,853
41 Transfers and Other Adjustments 11,329,973 11,004,636 11,798,865 13,052,376 13,449,539 13,131,492 13,291,454 12,643,515 14,241,678 14,395,945 14,770,319
42 Subtotal, Administration 28,541,506 28,700,600 30,616,155 31,118,193 33,976,152 33,573,998 34,069,556 33,723,605 35,674,647 37,016,536 37,389,475
43 Resource Management 3,541,524 2,138,615 2,083,812 1,985,620 1,873,954 2,449,325 2,536,815 2,611,793 2,679,538 2,749,758 2,821,818
44 Demand Side Management 3,187,875 3,491,470 3,643,924 4,271,786 3,889,846 3,487,694 3,201,219 3,136,926 3,091,085 3,171,266 3,215,642
45 Operations and Mtc 9,488,627 10,716,881 11,523,881 11,811,016 11,528,747 15,174,255 15,677,433 16,123,738 16,538,344 16,966,985 17,406,735
46 Engineering (Operating)1,102,008 1,230,160 1,592,024 1,656,522 1,790,942 2,029,395 2,084,026 2,137,827 2,191,632 2,246,896 2,303,554
47 Customer Service 2,032,231 1,548,851 1,540,884 2,190,993 2,291,246 2,475,150 2,568,711 2,646,902 2,716,039 2,787,851 2,861,562
48 Allowance for Unspent Budget - - - - - (3,321,375) (2,525,213) (1,539,384) (1,303,821) (1,337,296) (1,371,632)
49 Subtotal, Operating Expenses 47,893,770 47,826,576 51,000,680 53,034,130 55,350,887 55,868,441 57,612,547 58,841,408 61,587,464 63,601,996 64,627,154
50 Capital Program Contribution 13,016,111 14,005,915 9,331,367 11,558,306 18,803,467 14,156,237 15,409,116 20,148,213 17,915,314 19,171,749 19,268,197
51 TOTAL EXPENSES 129,695,858 141,854,501 136,037,047 145,059,572 168,784,008 160,649,705 168,637,036 174,477,380 178,398,081 181,082,970 182,568,208
52
53 ENDING RESERVES
54 Reappropriations (Non-CIP)- - - - 9,063,000 - - - - - -
55 Commitments (Non-CIP)3,164,000 3,102,055 3,777,205 2,970,955 8,637,000 3,533,348 3,533,348 3,533,348 3,533,348 3,533,348 3,533,348
56 Restricted for Debt Service - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 - - - - - - - - - -
58 Central Valley Project Reserve 329,000 - - - - - - - - - -
59 Underground Loan Reserve 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147
60 Public Benefits Reserves 2,064,000 2,574,000 1,839,000 681,330 681,330 - - - - - -
61 Electric Special Projects Reserve 51,838,000 51,837,855 51,837,855 51,837,855 41,837,855 41,837,855 41,837,855 41,837,855 41,837,855 46,837,855 51,837,855
62 Hydro Stabilization Reserve - 17,000,000 11,400,000 11,400,000 11,400,000 7,400,000 7,400,000 7,400,000 11,400,000 11,400,000 11,400,000
58 Capital Reserve - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964
59 Rate Stabilization Reserve 70,049,000 14,410,840 9,010,840 9,010,840 9,010,840 - - - - - -
60 Operations Reserve - 22,497,607 21,850,187 29,912,981 19,806,460 30,932,608 30,073,923 31,259,973 32,472,062 36,629,491 40,600,991
61 Unassigned - - - - - - - - - - -
62 TOTAL ENDING RESERVES 129,178,000 112,152,357 100,444,086 107,424,072 102,046,595 85,313,921 84,455,237 85,641,287 90,853,375 100,010,805 108,982,305
6053706
1 FISCAL YEAR FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
2
3 REVENUES
4 Net Sales 85%87%87%81%80%82%83%83%83%85%85%
5 Other Revenues and Transfers In 15%13%13%19%20%18%17%17%17%15%15%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 52%55%54%42%50%52%52%48%47%47%46%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%3%4%3%4%4%4%4%4%4%4%
13 Rent 3%3%4%4%3%3%3%3%3%3%3%
14 Debt Service 7%6%7%6%5%5%5%5%5%5%5%
15 Transfers and Other Adjustments 9%8%9%9%8%8%8%7%8%8%8%
16 Subtotal, Administration 22%20%23%21%20%21%20%19%20%20%20%
17 Resource Management 3%2%2%1%1%2%2%1%2%2%2%
18 Operations and Mtc 7%8%8%8%7%9%9%9%9%9%10%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 2%1%1%2%1%2%2%2%2%2%2%
21 Allowance for Unspent Budget 0%0%0%0%0%-2%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 34%31%35%34%30%33%32%32%33%33%34%
23 Capital Program Contribution 10%10%7%8%11%9%9%12%10%11%11%
24 TOTAL EXPENSES 97%96%96%83%91%93%93%92%90%91%91%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
28 1. Load Net Revenue 77,428 652,853 1,208,477
29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 3,397,119
30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 539,073
31 4. Carbon Neutral Cost 331,630 303,022 114,983
32 5. Market Price 909,196 775,584 1,138,589
33 6. Local Capacity 475,962 408,388 446,695
34 7. Transmission/CAISO 4,555,915 3,741,647 2,806,120
35 8. Plant Outage 1,000,000 1,000,000 1,000,000
36 9. Western Cost 3,130,000 2,704,738 2,973,619
37 10. Regulatory & Legal - - -
38 11. Supplier Default - - -
39 TOTAL 20,170,708 19,380,490 13,624,674
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 196% 172% 303%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
44 Distribution Revenue Variance 3,244,706 3,260,213 3,182,718 3,742,109 3,915,276 4,447,787 4,654,039 4,870,078 5,193,448 5,383,251
45 10% CIP Program Contingency 1,400,592 933,137 1,155,831 1,880,347 1,415,624 1,540,912 2,014,821 1,791,531 1,917,175 1,926,820
46 Total Risk Asssessment Value 4,645,297 4,193,350 4,338,548 5,622,455 5,330,899 5,988,699 6,668,861 6,661,609 7,110,623 7,310,071
47 Projected Operations Reserve 22,497,607 21,850,187 29,912,981 19,806,460 30,932,608 30,073,923 31,259,973 32,472,062 36,629,491 40,600,991
48 Operations Reserve, % of Risk Value 484% 521% 689% 352% 580% 502% 469% 487% 515% 555%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- 15,208,552 14,498,215 15,472,236 17,841,143 17,140,924 17,988,389 17,986,039 18,570,934 18,652,144 18,676,588
46 Target (90 days of non-capital expenses)- 22,812,829 21,747,322 23,208,354 26,761,715 25,711,387 26,982,583 26,979,059 27,856,401 27,978,216 28,014,881
47 Max (120 days of non-capital expenses)- 30,417,105 28,996,429 30,944,472 35,682,287 34,281,849 35,976,777 35,972,078 37,141,869 37,304,288 37,353,175
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- 8,339,587 8,513,675 9,755,012 8,008,309 8,273,280 8,594,405 8,974,024 9,229,751 9,452,090 9,690,848
51 Target (90 days of non-capital expenses)- 10,338,923 10,708,963 11,918,803 10,309,464 10,664,077 11,101,838 11,626,400 11,964,099 12,250,561 12,560,474
52 Max (120 days of non-capital expenses)- 12,338,259 12,904,252 14,082,593 12,610,618 13,054,873 13,609,271 14,278,777 14,698,448 15,049,033 15,430,101
53 Risk Assessment Value 4,645,297 4,193,350 4,338,548 5,622,455 5,330,899 5,988,699 6,668,861 6,661,609 7,110,623 7,310,071
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1193% 1315% 1326% 1391% 1591% 1631% 1708% 1729% 1800% 1645% 1732%
57 Available Reserves (5x Debt Service)*14.0 12.1 10.9 11.7 9.5 9.7 9.6 9.7 10.3 10.4 11.8
58 *For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants.
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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 i n
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 1.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
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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).
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 and timelines 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 and timelines
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, requirin g funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2017;
f) Any uncommitted funds remaining at the end of FY 202 2 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.
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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.
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 Publi c 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 based on the levels of
CIP expense budgeted for that year.
Minimum Level 60 days of budgeted CIP expense
Maximum Level 120 days of budgeted CIP expense
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) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
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ii) 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 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, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek 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 withd rawal of all funds from
this Reserve by the end of the Financial Planning Period.
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 d) 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 Sup ply 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
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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
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 201 7. 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.
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APPENDIX C : DESCRIPTION OF ELE CTRIC UTILITY OPERAT IONAL 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 EL ECTRIC UTILITY OUTRE ACH COMMUNICATIONS
Attachment C
* NOT YET APPROVED *
6055196 1
Resolution No. _________
Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending 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-14 (Street
Lights), E-NSE (Net Metering Net Surplus Electricity Compensation),
and E-EEC (Export Electricity Compensation).
R E C I T A L S
A. 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.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. 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, 2019.
SECTION 2. 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, 2019.
SECTION 3. 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, 2019.
SECTION 4. 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, 2019.
SECTION 5. 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
Attachment C
* NOT YET APPROVED *
6055196 2
amended to read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall
become effective July 1, 2019.
SECTION 6. 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, 2019.
SECTION 7. 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, 2019.
SECTION 8. 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, 2019.
SECTION 9. 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, 2019.
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated.
Utility Rate Schedule E-14, as amended, shall become effective July 1, 2019.
SECTION 11. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-NSE (Net Metering Net Surplus Electricity Compensation) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-NSE, as amended, shall become
effective July 1, 2019.
SECTION 12. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-EEC (Export Electricity Compensation) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-EEC, as amended, shall become effective July 1, 2019.
SECTION 13. 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
Attachment C
* NOT YET APPROVED *
6055196 3
to those not charged, and do not exceed the reasonable costs to the City of
providing the service or product.
c. The adoption of this resolution 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 Title 14 of the California Code of Regulations Sec. 15273(a). After
reviewing the staff report and all attachments presented to Council, the Council
incorporates these documents herein and finds that sufficient evidence has been
presented setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
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 7-1-2018 Effective 7-1-2019
A. APPLICABILITY:
This 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
$0.0833907
214
$0.0497105240
$0.0044700417
$0.1375712871
Tier 2 usage
Any usage over Tier 1
0.11569113
47
0.0735107515
0.0044700417
0.1936719279
Minimum Bill ($/day)
0.32833040
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 7-1-2018 Effective 7-1-2019
A. APPLICABILITY:
This 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
$0.118551120
5
$0.0855108468
$0.0044700417
$0.2085320090
Winter Period
0.0850207678
0.0567505766
0.0044700417
0.1462413861
Minimum Bill ($/day)
0.83597740
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 7-1-2018 Effective 7-1-2019
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 7-1-2018 Effective 7-1-2019
A. APPLICABILITY:
This 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
$0.11855112
05
$0.08551084
68
$0.004470
0417 $0.0020
$0.210532
0290
Winter Period
0.085020767
8
0.056750576
6
0.0044700
417 0.0020
$0.148241
4061
Minimum Bill ($/day)
0.83597740
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$0.11855112
05
$0.08551084
68
$0.004470
0417
$0.208532
0090
Winter Period
0.085020767
8
0.056750576
6
0.0044700
417
0.1462413
861
Minimum Bill ($/day)
0.83597740
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 7-1-2018 Effective 7-1-2019
Palo Alto Green Charge (per 1000 kWh block) $2.00
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 7-1-2018 Effective 7-1-2019
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 7-1-2018 Effective 7-1-2019
A. APPLICABILITY:
This schedule applies to Demand metered Secondary Electric Service for Customers with a
maximum Demand below 1,000 kilowatts. This 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 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) $4.412.98 $24.5021.13 $28.9124.11
Energy Charge (per kWh)
0.1053609893 0.0186501771 0.0044700417 0.1284812081
Winter Period
Demand Charge (per kW) $2.751.87 $16.2216.65 $18.9718.52
Energy Charge (per kWh)
0.0763407109 0.0177101865 0.0044700417 0.0994609297
Minimum Bill ($/day) 17.274215.9946
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 7-1-2018 Effective 7-1-2019
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 7-1-2018 Effective 7-1-2019
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 7-1-2018 Effective 7-1-2019
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 7-1-2018 Effective 7-1-2019
A. APPLICABILITY:
This 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 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) $4.412.98 $24.5021.13
$28.9124.11
Energy Charge (per kWh)
0.1053609893
0..0186501771
0.0044700417 0.0020
0.1304812281
Winter Period
Demand Charge (per kW) $2.751.87 $16.2216.65
$18.9718.52
Energy Charge (per kWh)
0.0763407109
0.0186501771
0.0044700417 0.0020
0.1014609497
Minimum Bill ($/day) 17.274215.9946
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 7-1-2018 Effective 7-1-2019
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $4.412.98 $24.5021.13 $28.9124.11
Energy Charge (per kWh) 0.1053609893 0.0186501771 0.0044700417
0. .1284812081
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $2.751.87 $16.2216.65 $18.9718.52
Energy Charge (per kWh) 0.0763407109 0.0186501771 0.0044700417 0..0994609497
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 17.274215.9946
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 7-1-2018 Effective 7-1-2019
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 7-1-2018 Effective 7-1-2019
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 7-1-2018 Effective 7-1-2019
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 7-1-2018 Effective 7-1-2019
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 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 $2.611.76 $8.447.28 $11.059.04
Mid-Peak 0.9564 8.447.28 9.397.92
Off-Peak 0.9564 8.447.28 9.397.92
Energy Charge (per kWh)
Peak $0.0964209248 $0.0186401771 $0.0044700417 $0.1195411436
Mid-Peak 0..1214211645 0.0186401771 0.0044700417 0.1445313833
Off-Peak 0.0745107146 0.0186401771 0.0044700417 0.0976309334
Winter Period
Demand Charge (per kW)
Peak $1.531.04 $9.049.28 $10.5710.32
Off-Peak 1.531.04 9.049.28 10.5710.32
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 7-1-2018 Effective 7-1-2019
Commodity Distribution Public Benefits Total
Energy Charge (per kWh)
Peak $0.1178108187 $0.0186401771 $0.0044700417 $0.1409210375
Off-Peak 0.1011307028 0.0186401771 $0.0044700417 0.1242509216
Minimum Bill ($/day) 17.274215.9946
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
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
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 7-1-2018 Effective 7-1-2019
SEASONAL RATE CHANGES: When the billing period includes use in both the
Summer and the Winter periods, the usage will be prorated based on the number of days
in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Demand Meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000
kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it
may be removed.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the
designated time periods as defined under Section D.2.
4. 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 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
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 7-1-2018 Effective 7-1-2019
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.
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
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 7-1-2018 Effective 7-1-2019
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}
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 7-1-2018 Effective 7-1-2019
A. APPLICABILITY:
This 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) $5.033.14 $25.6623.63 $30.6926.77
Energy Charge (kWh) 0.1093210037 0.00053 0.0044700417 0.1143210507
Winter Period
Demand Charge (kW) $2.891.84 $14.1615.17 $17.0517.01
Energy Charge (kWh) 0.072386979 0.00053 0.0044700417 0.0773807449
Minimum Bill ($/day) 49.113945.4758
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 7-1-2018 Effective 7-1-2019
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 shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and 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 7-1-2018 Effective 7-1-2019
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 7-1-2018 Effective 7-1-2019
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
Section 2827(b)(4) , as amended.
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 7-1-2018 Effective 7-1-2019
(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 7-1-2018 Effective 7-1-2019
A. APPLICABILITY:
This 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) $5.033.14 $25.6623.63 $30.6926.77
Energy Charge (per kWh) 0.1093210037 0.00053 0.0044700417 0.0020 0.1163210707
Winter Period
Demand Charge (per kW) $2.891.84 $14.1615.17 $17.0517.01
Energy Charge (per kWh) 0..0723806979 0.00053 0.0044700417 0.0020 0.0793807649
Minimum Bill ($/day) 49.113945.4758
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 7-1-2018 Effective 7-1-2019
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $5.033.14 $25.6623.63 $30.6926.77
Energy Charge (per kWh) 0.1093210037 0.00053 0.0044700417 0.1143210507
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $2.891.84 $14.1515.167 $17.0517.01
Energy Charge (per kWh) 0.0723806979 0.00053 0.0044700417 0.0773807449
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 49.113945.4758
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
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
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 7-1-2018 Effective 7-1-2019
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 shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and 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%.
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
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 7-1-2018 Effective 7-1-2019
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
a. Applicability: The standby charge, subject to the exemptions in subsection
D(9)(e), applies to Customers that have a non-utility generation source
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 7-1-2018 Effective 7-1-2019
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
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 7-1-2018 Effective 7-1-2019
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 $3.111.92 $8.627.94 $11.739.86
Mid-Peak 0.9762 8.627.94 8.569.60
Off-Peak 0.9762 8.627.94 8.569.60
Energy Charge (per kWh)
Peak $0.1135610149 $0.00053 $0.0044700417 $0.1185610619
Mid-Peak 0.1429912779 0.00053 0.0044700417 0.1479913249
Off-Peak 0.0877607842 0.00053 0.0044700417 0.0927608312
Winter Period
Demand Charge (per kW)
Peak $0.931.47 $7.687.17 $8.618.63
Off-Peak 0.931.47 7.687.17 8.618.63
Energy Charge (per kWh)
Peak $0.0761907150 $0.00053 $0.0044700417 $0.0811907620
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-2 Sheet No E-7-TOU-2
dated 7-1-2018 Effective 7-1-2019
Off-Peak 0.0654006138 0.00053 0.0044700417 0.0704006608
Minimum Bill ($/day) 49.113945.4758
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
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving
Day, and Christmas Day. The dates will be those on which the holidays are legally observed.
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
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 7-1-2018 Effective 7-1-2019
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 shall be defined as one or more utility Accounts
serving contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and
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 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 7-1-2018 Effective 7-1-2019
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
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 7-1-2018 Effective 7-1-2019
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.
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CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-14-1 Sheet No. E-14-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY:
This schedule applies to all street and highway lighting installations.
B. TERRITORY:
Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City.
C. RATES:
Per Lamp Per Month
Class A: Utility supplies energy
and switching service only.
Lamp Rating:
High Pressure Sodium Vapor Lamps
100 watts 8.285.91
200 watts 15.2910.91
250 watts 18.7913.41
310 watts 23.2516.59
400 watts 29.9421.36
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-14-2 Sheet No. E-14-2
dated 7-1-2018 Effective 7-1-2019
Per Lamp Per Month –
Class C: Utility supplies energy
and switching service and
maintains entire system,
including lamps and glassware.
Lamp Rating:
Mercury-Vapor Lamps
400 watts 32.5834.12
High Pressure Sodium Vapor Lamps
70 watts 25.7231.40
100 watts 27.8232.90
150 watts 33.3235.40
250 watts 38.3340.40
Light Emitting Diode (LED) Lamps
70 watts-equivalent 21.0728.08
100 watts-equivalent 22.6629.22
150 watts-equivalent 24.1330.26
250 watts 28.1433.12
D. SPECIAL CONDITIONS:
1. Type of Service: This schedule is applicable to series circuit and multiple street lighting
systems to which the Utility will deliver current at secondary voltage. Unless otherwise
agreed, multiple current will be delivered at 120/240 volts, three-wire, single-phase. In
certain localities the Utility may supply service from 120/208 volt star-connected poly-phase
lines in place of 240-volt service. Single phase service from 480-volt sources will be
available in certain areas at the option of the Utility when this type of service is practical
from the Utility's engineering standpoint. All currents and voltages stated herein are
nominal, reasonable variations being permitted. New lights will normally be supplied as
multiple systems.
2. Point of Delivery: Delivery will be made to the customer's system at a point or at points
mutually agreed upon. The Utility will furnish the service connection to one point for each
group of lamps, provided the customer has arranged his system for the least practicable
number of points of delivery. All underground connections will be made by the customer or
at the customer's expense.
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-14-3 Sheet No. E-14-3
dated 7-1-2018 Effective 7-1-2019
3. Switching: Switching will be performed by the Utility (on the Utility's side of points of
delivery) and no charge will be made for switching provided there are at least 10 kilowatts of
lamp load on each circuit separately switched, including all lamps on the circuit whether
served under this schedule or not; otherwise, an extra charge of $2.50 per month will be
made for each circuit separately switched unless such switching installation is made for the
Utility's convenience or the customer furnishes the switching facilities and, if installed on the
Utility's equipment, reimburses the Utility for installing and maintaining them.
4. Annual Burning Schedule: The above rates apply to lamps which will be turned on and off
once each night in accordance with a regular burning schedule agreeable to the customer but
not exceeding 4,100 hours per year.
5. Maintenance: The rates under Class C include all labor necessary for replacement of
glassware and for inspection and cleaning of the same. Maintenance of glassware by the
Utility is limited to standard glassware such as is commonly used and manufactured in
reasonably large quantities. A suitable charge will be made for maintenance of glassware of a
type entailing unusual expense. Under Class C, the rates include maintenance of circuits
between lamp posts and of circuits and equipment in and on the posts, provided these are all
of good standard construction; otherwise, the Utility may decline to grant Class C rates.
Class C rates applied to any agency other than the City of Palo Alto also include painting of
posts with one coat of good ordinary paint as required to maintain good appearance but do
not include replacement of posts broken by traffic accidents or otherwise.
10. . System Owned In-Part by Utility : Where, at customer's request, the Utility installs, owns,
and maintains any portion of the lighting fixtures, supports, and/or interconnecting circuits,
an extra monthly charge of one and one-fourth percent of the Utility's estimate of additional
investment shall be made.
11. Rates For Lamps Not on Schedule: In the event a customer installs a lamp which is not
presently represented on this schedule, the Utility will prepare an interim rate reflecting the
Utility's estimated costs associated with the specific lamp size. This interim rate will serve as
the effective rate for billing purposes until the new lamp rating is added to Schedule E-14.
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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 7-1-2016 Effective 7-1-2019
A. APPLICABILITY:
This schedule applies in conjunction with the otherwise applicable rate schedules for each customer
class. This schedule may not apply in conjunction with any time-of-use rate schedule. This 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:
Applies to locations within the service area of the City of Palo Alto.
C. RATE:
The following buyback rate shall apply to all energy exported to the grid.
Per kWh
Export electricity compensation rate $0.100907485
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 energy delivered and
received after the Customer-Generator serves its own instantaneous load.
b. CPAU shall bill the Customer-Generator consumption charges for the energy delivered by
CPAU to the Customer-Generator based on the Customer-Generator’s applicable rate
schedule.
c. In the event the energy generated exceeds the energy consumed and therefore is received
by CPAU, the Customer will receive a credit for all energy received by CPAU at the
buyback rate designated in section C above.
3. Generation facilities shall adhere to Rule and Regulation 27: Generating Facility
Interconnections.
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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 1-1-2011707-01-2016 Effective 7-1-2019
A. APPLICABILITY:
This 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 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 anywhere the City of Palo Alto provides electric service.
C. RATES:
Per kWh
Net Surplus Electricity Compensation rate $0.08771721
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.
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