HomeMy WebLinkAboutStaff Report 7980
City of Palo Alto (ID # 7980)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/18/2017
City of Palo Alto Page 1
Summary Title: FY 2018 Electric Utility Financial Plan and Rate Proposals
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt 1) a Resolution Approving the Fiscal Year 2018 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 and E-14 Rate Schedules
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission request that the Finance Committee recommend
that Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2018 Electric Financial
Plan (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), and E-14 (Street Lights).
Executive Summary
The FY 2018 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2027. Ongoing costs rose significantly from FY 2016 to FY 2017 and are projected to
remain at or slightly above their FY 2017 levels in the future. Staff is increasing rates over three
years to match revenues to costs, with the first increase taking place July 1, 2016.There are
several reasons for these cost increases. First, costs for electric supply purchases are increasing
as a result of new renewable energy projects coming online, which is responsible for 27% of the
cost increase. Increases in transmission access charges are also projected, another 7% of the
cost increase. Substantial additional capital investment in the electric distribution system is
planned for FY 2018 through FY 2023 (, and operations and maintenance costs are increasing.
City of Palo Alto Page 2
Lastly, sales volumes decreased 5% to 7% in 2016, which has a significant short term impact on
revenue.1
Because of these rising costs and reduced sales, an increase in rates is required to cover
expenses. A 10% to 14% rate increase (depending on customer class and usage) is proposed
effective July 1, 2017 (a nearly 14% overall increase in revenue), and a 7% increase is projected
effective July 1, 2018. However, even with these increases, residential electric rates remain 35%
to 45% below PG&E rates and comparable to or lower than Santa Clara and Roseville, other
publicly-owned utilities that maintain very low bills for customers. The Electric Utility transfer to
the General Fund is estimated at $13.2 million in FY 2018 and using the Council-adopted
methodology rises to $14.2 million in FY 2027.
While staff would normally attempt to spread these rate increases across more than two years
to reduce the single-year ratepayer impact, the electric utility reserves have reached minimum
acceptable levels over the last few years. Due to higher power supply purchase costs as a
result of the drought, operational and other reserves have decreased substantially in the past
couple years, making it infeasible to spread rate increases over multiple years. However, staff
proposes various reserves transfers for FY 2017 and FY 2018 that would limit the rate impact
for most customers as much as is possible, while maintaining the fiscal health of the utility.
While 14% is the overall increase in sales revenues, actual rate increases for each customer
class will differ. Actual rate increases are calculated using the cost of service analysis (COSA)
model created for the City by EES Consulting and first implemented on July 1, 2016.
The Utilities Advisory Commission (UAC) reviewed the Electric Utility Financial Plan and Rate
Proposals at its meeting on April 5, 2017 meeting, and approved them unanimously.
Background
Every year staff presents the Financial Plans for its Electric, Gas, Water, and Wastewater
Collection Utilities and recommends any rate adjustments required to maintain their financial
health. These Financial Plans include a comprehensive overview of the utility’s operations,
both retrospective and prospective, and are intended to be a reference for UAC and Council
members as they review the budget and staff’s rate recommendations. Each Financial Plan also
contains a set of Reserves Management Practices describing the reserves for each utility and
the management practices for those reserves.
The Finance Committee reviewed preliminary financial forecasts at its March 21, 2017 meeting.
Staff has not made any changes to the preliminary projections presented at that meeting.
Discussion
1 Over the long term, decreased consumption allows staff to incorporate new loads, such as electric vehicles,
without as much impact on existing supply and distribution assets. Over the long term this reduces bills for all
consumers, but in the short term rates can increase.
City of Palo Alto Page 3
Summary of Proposed Actions
The two resolutions recommended for Council adoption will accomplish the following:
1. Increase overall electric rates by 14% effective July 1, 2017;
2. Approve various reserves transfers for FY 2017;
3. Approve the FY 2018 Electric Financial Plan.
Proposed and Projected Sales Revenue Requirement, FY 2018 through FY 2022
Table 1 shows the sales revenue increases needed to recover costs of operation over the
forecast period in the FY 2018 Electric Financial Plan.
Table 1: Projected Electric Rate Adjustments, FY 2017 to FY 2023
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
14% 7% 0% 0% 1% 2%
These sales revenue 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.
Changes from Prior Financial Forecasts
This projection has changed since the FY 2017 Electric Utility Financial Plan presented last year.
Table 2 compares current rate projections to those projected in the last two year’s Financial
Plans. As shown, the FY 2018 revenue projections are higher than projected the last two years.
Table 2: Projected Electric Rate Trajectory for FY 2018 to FY 2027
Projection FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Current
(FY 2018 Financial Plan) 14% 7% 0% 0% 1% 2% 1%
Last year
(FY 2017 Financial Plan) 10% 2% 0% 1% 0% 0% 0%
Two years ago
(FY 2016 Financial Plan) 6% 1% 1% 0% 0% 2% 2%
The rate increases are related to several factors: increasing transmission access charges and the
cost of renewable projects coming online, substantial additional capital investment in the
electric distribution system is planned through FY 2023, and operations cost increases.
Transmission Access (TAC) charges are levied by the California Independent System Operator
(CAISO) for use of the statewide transmission grid, under rates approved by the Federal Energy
Regulatory Commission (FERC). These charges pay for the costs PG&E and other transmission
owners incur in operating transmission lines. Annually, staff and partner agencies monitor
PG&E’s rate change requests to FERC. This can be a contentious process, and rate increases are
on ongoing issue of concern.
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Even when large rate increases are needed, staff typically attempts to keep increases below
10% per year and increase rates over multiple years. However, due to the impact of the recent
drought on hydroelectric energy generation output, the associated increased energy portfolio
costs, and decreases in customer sales, reserves are lower than forecasted, and cannot be used
for rate stabilization. However, precipitation in early 2017 is likely to lead to higher
hydroelectric output, which may improve reserves and the future financial outlook. The Electric
Utility transfer to the General Fund is calculated at $12.8 million in FY 2018 using the 2009
Council-adopted calculation methodology.
This Financial Plan contains some measures to mitigate the impact on ratepayers. The July 1,
2017 rate increases would have to be substantially higher without proposed transfers from the
Supply Rate Stabilization Reserve, Hydro Rate Stabilization, and Electric Special Projects Reserve
(see below). In addition, this Financial Plan allows the Supply Operations Reserves to be up to
$3.9 million below the minimum Supply Operations Reserve level for FY 2017 through FY 2020.
To keep the Supply and Distribution Operations Reserves above the minimum guideline without
transfers, rate increases over 20% would be required in FY 2018. Staff recommends allowing
Supply Operations Reserves to temporarily go below minimums for two reasons: first, heavy
rains and an above average snowpack indicate both an end to the drought and higher hydro
production, which may result in higher reserves, and second, the presence of the $41 million
Electric Special Projects Reserve means that a relatively small temporary shortfall in the
Operations Reserves should not affect the Electric Utility’s bond ratings. In the event the
drought resurfaces, staff will re-evaluate its projections for FY 2018 and may recommend
additional rate increases or the adoption of a hydroelectric rate adjuster. Note that the
Financial Plan’s Reserves Management Practices allow the Operations Reserve to fall below the
minimum guideline level as long as the plan provides for replenishing the reserve over time.
Staff also recognizes the importance of managing operating costs and maximizing efficiency in
order to minimize rate increases. Staff will continue to regularly review opportunities for cost
savings and efficiency improvements, and implement recommendations where practicable.
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 D). These schedules are
omitted for various reasons: the E-14 rate schedule is not easy to summarize, the E-7 TOU rate
is not easy to summarize and is only used by one customer, and the E-4 TOU rate schedule is
both difficult to summarize and not utilized by any customers at this time.
Table 3: Electric Rates (Current and Proposed)
Current Rates
Proposed Rates
(7/1/17)
Change
$ %
City of Palo Alto Page 5
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.11029 0.12159 0.01130 10%
Tier 2 Energy ($/kWh) 0.16901 0.19001 0.02100 12%
Minimum Bill ($/day) 0.3067 0.2938 (0.0129) -4%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.16845 0.18885 0.02040 12%
Winter Energy ($/kWh) 0.11445 0.13267 0.01822 16%
Minimum Bill ($/day) 0.7657 0.7328 (0.0329) -4%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.10229 0.11673 0.01444 14%
Winter Energy ($/kWh) 0.08049 0.08890 0.00841 10%
Summer Demand ($/kW) 19.68 21.05 1.37 7%
Winter Demand ($/kW) 14.04 15.36 1.32 9%
Minimum Bill ($/day) 16.3216 14.8414 (1.4802) -9%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.08749 0.09802 0.01053 12%
Winter Energy ($/kWh) 0.06242 0.07188 0.00946 15%
Summer Demand ($/kW) 18.34 23.84 5.50 30%
Winter Demand ($/kW) 15.65 15.59 (0.06) 0%
Minimum Bill ($/day) 48.5054 42.3648 (6.1406) -13%
Table 4 shows the impact of the proposed July 1, 2017 rate changes on the residential and non-
residential bills for various consumption levels. The overall rate change for the residential class
is roughly 12%.
Table 4: Impact of Proposed Electric Rate Changes on Customer Bills
Rate
Schedule
Usage (kwh/mo)
Bill under
Current Rates
($/mo)
Bill Under Rates
Proposed 7/1/17
($/mo)
Change
$/mo %
E-1 300 33.09 36.48 3.39 10%
(Summer Median) 330 36.40 40.13 3.73 10%
(Winter Median) 453 57.18 63.50 6.31 11%
650 90.48 100.93 10.45 12%
1200 183.43 205.44 22.00 12%
E-2 1,000 141 161 19 14%
E-4 160,000 21,366 23,734 2,368 11%
E-7 500,000 54,473 62,186 7,713 14%
E-7 2,000,000 200,895 229,031 28,136 14%
City of Palo Alto Page 6
Cost of Service Analysis and Rate Study
The rates discussed in the previous section are based on the cost of service methodology
established in “City of Palo Alto Electric Cost of Service and Rate Study”2 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
proposed rates. Additional details are provided in the attached memo (Attachment C).
Reserves Transfers, FY 2017 and FY 2018
The FY 2018 Electric Utility Financial Plan includes several proposed reserves transfers, shown
in Table 5. These reserves transfers have a variety of purposes, but overall they enable the
revenue trajectory projected in the Electric Utility Financial Plan. Without these transfers,
additional rate increases would be required.
Table 5: FY 2017 and FY 2018 Reserves Transfers
Fiscal
Year
Transfer
Amount
Transfer
From
Transfer
To Purpose
FY
2017
Up to $10
million
Special
Projects
Reserve
Distribution
Operations
Reserve
Ensures Distribution Operations Reserve is above
minimum guidelines at the end of FY 2017.
Up to $9
million
Hydroelectric
Stabilization
Reserve
Supply
Operations
Reserve
Funds additional market energy purchases that may be
needed if hydroelectric output associated with spring
2017 precipitation is insufficient to offset below-
average summer and fall 2016 output.
Up to $4.5
million
Supply Rate
Stabilization
Reserve
Distribution
Operations
Reserve
Ensures Distribution Operations Reserve is above
minimum guidelines at the end of FY 2017.
Up to $911
thousand
Supply Rate
Stabilization
Reserve
Supply
Operations
Reserve
Ensures Supply Operations Reserve is above Risk
Assessment level.
FY
2018
Up to
$3.1
million
Supply Rate
Stabilization
Reserve
Supply
Operations
Reserve
To bring Supply Operations Reserve to or above
minimum guidelines at the end of FY 2018.
Up to
$2.4
million
Hydroelectric
Stabilization
Reserve
Supply
Operations
Reserve
To bring Supply Operations Reserve to or above
minimum guidelines at the end of FY 2018.
$500
thousand
Supply Rate
Stabilization
Reserve
Distribution
Operations
Reserve
To bring Distribution Operations Reserve to or above
minimum guidelines at the end of FY 2018.
2 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
City of Palo Alto Page 7
Electric Bill Comparison with Surrounding Cities
Table 6 compares electric bills under current rates as of March 1, 2017 for residential customers
to those in surrounding communities. Under current rates, CPAU’s customer bills are far below
PG&E’s and are lower than others for non-residential customers, but slightly higher than Santa
Clara’s for higher using residential customers.
Table 6: Average Electric Bill Comparison ($/month)
As of March 1, 2017
Customers
Usage
(KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E Santa Clara Roseville
Residential
Customers
300 33.09 36.48 57.04 35.18 55.67
330 (Summer
Median) 36.40 40.13 63.85 38.83 58.64
453 (Winter
Median) 57.18 63.50 97.81 53.78 70.80
650 90.48 100.93 154.12 77.73 97.85
1200 183.43 205.44 374.41 144.59 179.96
Non-
Residential
Customers
1,000 142 161 240 181 146
160,000 21,366 23,734 29,108 20,562 21,009
500,000 54,473 62,186 87,015 62,956 55,955
2,000,000 200,895 229,031 333,041 243,390 214,705
Commission Review and Recommendation
The UAC reviewed this proposal at its April 5, 2017 meeting. Staff noted that the increase
proposal had changed from 12 to 14 percent overall, but that residential rates were projected
to increase by 12 percent.
Commissioner Schwartz noted that, with the recent billing error regarding gas, that staff may
want to do more outreach to customers, especially those with larger current bills. The goal
would be to have those residents understand that the increase was not another error. Staff
agreed with the assessment.
After the presentation, the UAC voted unanimously (5-0. Commissioners Forssell and Trumbull
absent) to approve the proposed rate increase and financial plan. The draft excerpted minutes
from the UAC’s April 5, 2017 meeting are provided as Attachment F.
Timeline
If the Finance Committee recommends approval of the FY 2018 Electric Financial Plan, Council
will consider the recommendations with the FY 2018 budget.
City of Palo Alto Page 8
Resource Impact
The proposed July 1, 2018 rate changes are projected to increase sales revenues by $16.1
million per year over the forecast period.
Policy Implications
The proposed electric rate adjustments were developed using a cost of service study and
methodology, and are consistent with the Council-adopted Reserves Management Practices
that are part of the Financial Plan.
Environmental Review
The Finance Committee’s review and recommendation to Council on the FY 2018 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:
Attachment A: Resolution of the Council of the City of Palo Alto Approving the FY 2018
Electric Utility Financial Plan
Attachment B: Proposed FY 2018 Electric Utility Financial Plan
Attachment C: EES 2017 COSA Model and Rate Design Update Memo
Attachment D: Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-
7-G, E-7 TOU, and E-14
Attachment E: Proposed Amendments to Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4
TOU, E-7, E-7-G, E-7 TOU, and E-14
Attachment F: Excerpted UAC Minutes of April 5, 2017
Attachment A
Not Yet Approved
170329 jb 6053933
Resolution No. _____
Resolution of the Council of the City of Palo Alto Approving the
FY 2018 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. It
does this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2018 Electric Utility Financial Plan.
SECTION 2. The Council hereby approves the transfer of up to $911 thousand from
the Supply Rate Stabilization Reserve to the Supply Operations Reserve in FY 2017, up to $9.0
million from the Hydroelectric Stabilization Reserve to the Supply Operations Reserve in FY
2017, and up to $4.5 million from the Supply Operations Reserve to the Distribution Operations
Reserve in FY 2017, as described in the FY 2018 Electric Utility Financial Plan approved via this
resolution.
/ /
/ /
/ /
/ /
/ /
/ /
Attachment A
Not Yet Approved
170329 jb 6053933
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 therefore, no environmental assessment is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Senior Deputy City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2018 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2018 TO FY 2027
ATTACHMENT B
2 | Page
FY 2017 ELECTRIC UTILITY
FINANCIAL PLAN
FY 2018 TO FY 2027
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2018 Rate and Reserves Proposals ....................................................... 7
Section 3A: Rate Design ............................................................................................................... 7
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 ............................................................................................. 11
Section 4B: Customer Base ........................................................................................................ 13
Section 4C: Distribution System ................................................................................................. 13
Section 4D: Cost Structure and Revenue Sources ...................................................................... 14
Section 4E: Reserves Structure ................................................................................................... 15
Section 4F: Competitiveness ...................................................................................................... 16
Section 5: Utility Financial Projections ................................................................................. 17
Section 5A: Load Forecast .......................................................................................................... 17
Section 5B: FY 2012 to FY 2016 Cost and Revenue Trends ........................................................ 19
Section 5C: FY 2016 Results ....................................................................................................... 20
Section 5D: FY 2017 Projections ................................................................................................ 20
Section 5E: FY 2018 – FY 2027 Projections ................................................................................ 21
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Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 23
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 ............................................................................................................ 33
Section 6E: Equity Transfer ........................................................................................................ 34
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 34
Section 6G: Sales Revenues ....................................................................................................... 35
Section 7: Communications Plan .......................................................................................... 36
Appendices ......................................................................................................................... 38
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 39
Appendix B: Electric Utility Reserves Management Practices ................................................... 43
Appendix C: Description of Electric utility Operational Activities .............................................. 48
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 49
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SECTION 1: DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a
section of the distribution system operates. The transmission system operates at
115-500 kV, and this is lowered to 60 kV in the subtransmission 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.
5 | Page
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Electric Utility for the next ten 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 2A: OVERVIEW OF FINANCIAL POSITION
The Electric Utility’s costs will increase substantially over the next few years, as shown in Table
1. Most of the increases are related to electric supply costs, which are increasing due to
increased transmission costs and the cost of new renewable energy projects coming online.
There are also inflationary increases in Operations costs, and some additional capital
investment costs.
Table 1: Electric Utility Expenses for FY 2016 to FY 2027
Expenses
($000)
FY 2016
(act.)
FY 2017
(est.)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Power Supply
Purchases 79,115 84,371 87,987 89,066 90,841 90,728 92,221 91,758 92,925 93,904 95,224 96,465
Operations 35,443 54,152 56,307 56,795 58,409 59,238 60,089 61,931 62,507 59,519 60,550 61,610
Capital Projects 21,128 21,490 15,574 15,869 25,150 19,048 17,449 18,354 18,878 19,417 19,972 20,543
TOTAL 135,685 160,013 159,868 161,730 174,400 169,014 169,759 172,042 174,309 172,840 175,746 178,617
To cover these increases in costs, revenues (and therefore rates) need to increase over the next
several years to balance costs and revenues, 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
higher this year than last year primarily due lower actual and projected sales and increases to
transmission cost projections. In addition, the continued drought has had a greater impact than
expected on hydroelectric supplies. This has affected reserves, making it difficult to phase in
rate increases over multiple years.
Table 2: Projected Electric Rates, FY 2017 to FY 2023
Projection FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
Current 14% 7% 0% 0% 1% 2% 1% 1% 1% 1%
Last Year 10% 3% 0% 1% 0% 2% N/A N/A N/A N/A
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 2018. Funds are
projected to be transferred from the Electric Special Projects (ESP) Reserve to the Operations
Reserve to fund smart grid projects included in the long term CIP budget, but it should be noted
that the smart grid costs included in the forecast are placeholders, as are the transfers from the
ESP Reserve. Any transfers from the ESP Reserve require Council approval.
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Staff will request a temporary loan from the ESP reserve of $10 million for the Distribution
Operations reserve, as it is otherwise projected to be critically low. As the intent of the ESP
reserve is to fund projects, not to stabilize rates, this will be a temporary transfer, to be
reversed once distribution rates have increased and stabilized (FY 2020 and 2021) and funds
can be returned to the ESP reserve. Staff is also requesting authority to withdraw funds from
the Hydro Stabilization Reserve in FY 2017 and FY 2018 due to lower than average hydroelectric
generation, though this projection is subject to change with weather conditions. Based on
precipitation to-date, this projection is likely to change, and staff will not perform these
transfers if they become unnecessary.
Table 3: Reserves Transfers for FY 2017 to FY 2027 ($000)
Reserve FY 2017 FY 2018 FY 2019 to FY 2027
Supply Reserves
Electric Special Projects (10,173) 3,000
Hydro Stabilization* (9,000) (2,400) -
Supply Rate Stabilization (5,411) (3,600) -
Supply Operations 10,084 5,500 7,000
Distribution Reserves
Capital Improvement Program
Distribution Operations 14,500 500 (10,000)
* A $9 million transfer from the Supply Rate Stabilization Reserve to the Supply Operations Reserve was
approved by Council when it adopted the FY 2016 Electric Utility Financial Plan
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2017:
1. Complete the proposed FY 2017 reserves transfers described Section 3D: Proposed
Reserve Transfers, as previously requested as part of the FY 2017 Electric Financial Plan
2. Request a new transfer of $10 million from the ESP reserve to the Distribution
Operations Reserve, to be repaid within five years.
Staff proposes the following actions for the Electric Utility in FY 2018:
1. Request the proposed FY 2018 reserves transfers described in Section 3D: Proposed
Reserve Transfers.
2. Increase rates effective July 1, 2017 for a 14% increase in system average rates, and
thereby increase sales revenues by 10% based upon current sales projections.
Note that while the projected rate increases and reserves transfers in this FY 2018 Financial
Plan are adequate to recover costs over the forecast period, the Supply Operations Reserves
are projected to be at or below the minimum Supply Operations Reserve level for FY 2017
through FY 2019, and lower sales have dropped Distribution Operations reserves to very low
levels requiring new transfer requests. While more aggressive increases could be requested,
staff still recommends proceeding with this plan for two reasons: first, recent rains and
7 | Page
favorable snowpack levels may result in favorable hydroelectric production, resulting in higher
reserves, and second, the presence of the Electric Special Projects Reserve with a balance of
$41 million means that a small temporary shortfall in the Operations Reserves should not affect
the Electric Utility’s financial health and bond ratings. In the event drought resurfaces or hydro
fails to materialize, staff will re-evaluate its projections at midyear of FY 2018 and may
recommend additional rate increases or the adoption of a hydroelectric rate adjuster.
SECTION 3: DETAIL OF FY 2018 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The rates discussed in the previous section are 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
proposed rates. The COSA is based on design guidelines adopted by Council on September 15,
2015 (Staff Report 6061).
SECTION 3B: CURRENT AND PROPOSED RATES
The current rates were adopted on July 1, 2016, when CPAU increased electric rates by 11%.
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, the PaloAltoGreen rates, and
solar net metering. Staff proposes a 14% overall increase in revenue, requiring 14% increase in
system 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.
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
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Table 4: Current and Proposed Electric Rates
Current Rates
Proposed Rates
(7/1/17)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.11029 0.12159 0.01130 10%
Tier 2 Energy ($/kWh) 0.16901 0.19001 0.02100 12%
Minimum Bill ($/day) 0.3067 0.2938 (0.0129) -4%
E-2 & E-2-G(Small Non-Residential)
Summer Energy ($/kWh) 0.16845 0.18885 0.02040 12%
Winter Energy ($/kWh) 0.11445 0.13267 0.01822 16%
Minimum Bill ($/day) 0.7657 0.7328 (0.0329) -4%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.10229 0.11673 0.01444 14%
Winter Energy ($/kWh) 0.08049 0.08890 0.00841 10%
Summer Demand ($/kW) 19.68 21.05 1.37 7%
Winter Demand ($/kW) 14.04 15.36 1.32 9%
Minimum Bill ($/day) 16.3216 14.8414 (1.4802) -9%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.08749 0.09802 0.01053 12%
Winter Energy ($/kWh) 0.06242 0.07188 0.00946 15%
Summer Demand ($/kW) 18.34 23.84 5.50 30%
Winter Demand ($/kW) 15.65 15.59 (0.06) 0%
Minimum Bill ($/day) 48.5054 42.3648 (6.1406) -13%
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).
SECTION 3C: RESERVES MANAGEMENT PRACTICES
No changes to the Electric Utility Reserves Management Practices (See Appendix B: Electric
Utility Reserves Management Practices) are proposed at this time.
SECTION 3D: PROPOSED RESERVE TRANSFERS
In the FY 2017 Electric Financial Plan, Council approved several proposed transfers for FY 2017:
•Transfer up to $1 million from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve. This transfer is to enable the City to spread necessary long term
rate increases over multiple years to reduce the short-term impact on ratepayers.
Current estimates are that the amount will be closer to $911,000.
•Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offset
potential costs associated with low hydroelectric generation. Some or all of this transfer
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may be unnecessary if weather conditions change, but current estimates still indicate
the full amount will be needed, since excess generation in the spring of 2017 may not
fully offset below-average generation in the summer and fall of 2016.
•Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution
Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve.
Staff will also request the following for FY 2017:
•Transfer up to $10 million from the ESP Reserve to the Distribution Operations Reserve.
This transfer will be construed as a temporary transfer, to be repaid to the ESP Reserve
within five years.
Proposed transfers for FY 2018 will not be requested by resolution at this time, but will be
requested as part of the FY 2019 Financial Plan, or at FY 2017 year-end should ending reserve
balances require it.
The impact of these transfers on reserves levels can be seen in Figure 8 (for Supply Fund
Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E: FY 2018 – FY 2027
Projections. Table 5 shows the projected balance of each of the Electric Utility reserves for the
period covered by this Financial Plan. The projected balances are also provided in. Appendix A:
Electric Utility Financial Forecast Detail
Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2016 to FY 2027
Ending Reserve
Balance ($000)
FY 2016
(Act.)
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Reappropriations - - - - - - - - - - - -
Commitments 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777
Underground Loan 729 729 729 729 729 729 729 729 729 729 729 729
Public Benefits 1,839 1,331 739 280 95 - - - - - - -
Special Projects 51,838 41,665 41,526 41,192 42,859 46,192 44,665 44,665 44,665 44,665 44,665 44,665
Hydro Stabilization 11,400 2,400 - - - - - - - - - -
Capital - - - - - - - - - - - -
Rate Stabilization 9,011 3,600 - - - - - - - - - -
Operations 21,850 21,570 28,477 31,328 31,984 32,727 36,734 36,600 36,226 38,957 40,471 41,658
Unassigned - - - 916 - - - - - - - -
TOTAL 100,444 75,072 75,248 78,222 79,444 83,425 85,906 85,771 85,397 88,128 89,642 90,830
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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
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Section 6: Details and Assumptions.
SECTION 4A: ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel
engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity
continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E
proved more economical than the diesel engines, and by the late 1920s CPAU was using its own
diesel engines only during peak demand periods. At that time CPAU owned 45 miles of
distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual
consumption. The diesel engines remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did
throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the
sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto,
which doubled the number of customers. Some was related to the proliferation of electric
appliances, as evidenced by the fact that residential customers were using three times more
electricity in 1970 than they had been in 1950. But the most notable factor was the growth of
industry in Palo Alto during that time. By 1970, commercial customers were using 20 times
more electricity per customer than they had been in 1950. These decades also saw several
other notable events, including:
• 1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of
Reclamation to purchase power from the Central Valley Project (CVP), a contract which
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
• 1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
• 1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement
program for its underground system in the early 1990s.
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In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and
in 1996 the State legislature passed Assembly Bill 1890, which, among other things, created the
California Independent System Operator (CAISO) to operate the transmission system and the
Power Exchange to facilitate wholesale energy transactions. This restructuring was anticipated
to bring lower costs to consumers, and while CPAU was not required to participate in the
industry restructuring, in 1997 the Council approved a Direct Access Program for the Electric
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 project and its
contract with WAPA for CVP hydropower.
In 2001 CPAU began planning for the impacts associated with the new terms of its contract with
WAPA, set to take effect in 2005. The previous contract had provided 90% of Palo Alto’s power
supply at favorable rates, and PG&E, as a party to the contract, had provided supplemental
power 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 managine 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 Base (FY 2016)
16%
7%
35%
42%
Residential
Small Comm
Med. Comm
Large Comm
SECTION 4B: CUSTOMER BASE
The City of Palo Alto’s Electric Utility
provides electric service to the
residents, businesses, and other
electric customers in Palo Alto. There
are roughly 29,750 customers
connected to the electric system,
25,700 (86%) of which are residential
and 4,050 (14%) of which are non-
residential. Residential customers
consumed 148 gigawatt-hours (GWh)
in FY 2016, approximately 16% of the
electricity sold, while non-residential
customers consumed 88% or
759 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 larger proportion of sales for the Electric
Utility than they do for the City’s other utilities. The largest customers (the 72 customers on the
E-7 rate schedule) account for over 40% of CPAU’s sales. The next largest customer group (the
835 non-residential customers on the E-4 rate schedule) represents another 35% of sales. In
total, that means that about 3% of customers account for nearly three quarters of the electric
load.
SECTION 4C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 470 miles of
distribution lines, of which 223 miles (48%) are overhead lines and 245 miles (52%) are
underground. The Electric Utility also maintains six substations, roughly 2,000 overhead line
transformers, 1,075 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
3 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010 4 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
14 | Page
Figure 2: Cost Structure (FY 2016)
58%
34%
8%
Commodity Supply
Operations
Capital
Figure 3: Hydroelectric Variability (FY 2018)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 4: Revenue Structure (FY 2016)
87%
13%
Sales of Electricity
Other Revenue
other associated electric equipment, represent the vast majority of the infrastructure used to
deliver electricity in Palo Alto.
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 58% of the Electric Utility’s
costs in FY 2016. Operational costs
represented roughly 34%, and
capital investment was responsible
for the remaining 8%. 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. Commodity supply costs are projected to be roughly
54% of total costs in FY 2027.
While average year purchase
costs for the electric utility
are predictable due to its
long-term contracts,
variability in hydroelectric
generation can result in
increased or decreased
costs. This is by far the
largest source of variability
the utility faces. Figure 3
shows the difference in costs
under high, projected, and
low hydroelectric generation scenarios for FY 2018. 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 4 the Electric Utility
receives 87% 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
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revenue sources are primarily 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. Without these entries sales revenues represent roughly 91% of total revenues. Appendix
A: Electric Utility Financial Forecast Detail
shows more detail on the utility’s cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 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 4E: 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. This
separation of supply and distribution costs was established as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) back 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 in case California ever decides to 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 various reserves are summarized below, 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 was accumulated during deregulation of California’s electric system to
fund the stranded costs associated primarily with the Calaveras hydroelectric resource
and the California-Oregon Transmission Project. When that reserve was no longer
16 | Page
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.
• 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 forecast period. In
that case, funds can be accumulated to spread the impact of those future rate increases
across multiple years. This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Supply and Distribution Operations Reserves: These are the primary contingency
reserves for the Electric Utility, and are used to manage yearly variances from budget
for operational costs and electric supply costs (aside from variances related to
hydroelectric generation). This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves
are for any financial resources not assigned to the other reserves and are normally
empty.
SECTION 4F: COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2016 was
$551.65 under current CPAU rates, 38% lower than the annual bill for a PG&E customer with
the same consumption and roughly the same as 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
17 | Page
below were in effect as of March 1, 2017. PG&E rates were recently increased, and their
residential tiers moved from three to two.
Over the next several years low usage customers in PG&E territory are expected to continue to
see higher percentage rate increases than high usage customers as PG&E compresses its tiers
from the highly exaggerated levels that have been in place since the energy crisis. This is likely
to make the bill for the median Palo Alto consumer look even more favorable compared to
most PG&E customers. Even with the compressed tiers, bills for high usage Palo Alto consumers
are likely to remain substantially lower than the bills for high usage PG&E customers.
The bill calculations show bills under the existing rates, not the proposed July 1, 2017 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 3/1/17, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(March)
300 33.09 57.04 35.18
453 (Median) 57.18 97.81 53.78
650 90.48 154.38 77.73
1200 183.43 374.19 144.59
Summer
(July)
300 33.09 57.04 35.25
(Median) 330 36.40 63.85 38.83
650 90.48 159.66 77.73
1200 183.43 380.43 144.59
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 (3/1/17, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 142 240 181
160,000 21,366 29,108 20,562
500,000 54,473 87,015 62,956
2,000,000 200,895 333,041 243,390
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 5 shows a 40-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
18 | Page
efficiency, as well as the adoption of more stringent appliance efficiency standards and energy
standards in building codes.
Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2027. Sales after the July
2016 rate change decreased by 6% from projections. To be conservative, the forecast assumes
that current trends continue and sales through the forecast period decline slightly.
800
850
900
950
1,000
1,050
1,100
1,150
19
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9
19
9
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19
9
1
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9
2
19
9
3
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9
4
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5
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6
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19
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20
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20
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1
6
Gw
h
19 | Page
Figure 6: Forecasted Electricity Consumption
SECTION 5B: FY 2012 TO FY 2016 COST AND REVENUE TRENDS
The annual expenses for the Electric Utility declined between FY 2009 and FY 2012, as shown in
Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail.
These decreases were partly related to declines in electricity market prices due to the impact of
shale gas and partly due to above average output from hydroelectric resources. These factors
are discussed in more detail in Section 6A: Electricity Purchases. Since FY 2012, total expenses
for the utility have been increasing as renewable resources come online. In FY 2014 through FY
2015 costs were higher due to lower than average output from hydroelectric resources.
Commodity costs are responsible for most of the changes in the utility’s expenses over the last
six years. Operational costs and capital investment increased at less than 1% per year over that
time.
Actual Projection
20 | Page
Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2016 and Projections through FY 2027
SECTION 5C: FY 2016 RESULTS
California’s drought, with its corresponding lower hydroelectric energy output, continued to
increase electricity costs in FY 2016. Offsetting this were lower operations and capital program
spending. FY 2016 expenses were $9.2 million lower than in the FY 2017 Financial plan, with
revenues being roughly equal.
SECTION 5D: FY 2017 PROJECTIONS
Last year, staff recommended (and Council approved) an 11% rate change for July 1, 2016, the
start of FY 2017. Based on hydroelectric conditions at the time, staff forecasted a roughly $15.2
million deficit for FY 2017. This deficit was primarily related to low hydroelectric output, and
was to be funded from the Rate Stabilization and Hydroelectric Stabilization reserves. Staff’s
current forecast for FY 2017 is for a deficit of $25.4 million, $10.2 million more than forecast
21 | Page
last year. This change is mainly due to sales decreasing by 6% after the last rate increase,
cutting projected revenues by $11 million. The onset of wet weather and a forecast for a
reversal in hydro conditions has brought down electric purchase cost projections, but the full
impact of better hydro conditions likely won’t be felt until next fiscal year.
With Operations reserves projected to be below minimum, several transfers, including a
temporary loan from the Electric Special Projects Reserve, proposed. These transfers are
discussed in Section 3D: Proposed Reserve Transfers.
SECTION 5E: FY 2018 – FY 2027 PROJECTIONS
As shown in Figure 7 above, costs for the Electric Utility are projected to increase at a fairly
steady rate through the forecast period. Revenues will have to increase 10% in FY 2018 and
another 7% in FY 2019 to bring revenues in line with expenses. The largest increases are
primarily related to electricity purchase costs, which have been increasing since FY 2013 and
will continue to increase through FY 2018 as new renewable projects come online to fulfill the
City’s environmental goals and as transmission costs increase. 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 2023 are about $4.6 million lower than last year’s forecast as
one large, customer driven project has been put on hold. The project would have been funded
mostly through customer reimbursement. This forecast also assumes that smart grid costs are
funded from the Electric Special Projects Reserves.
Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund
reserves) and Figure 9 (for Distribution Fund reserves), below. The Supply Rate Stabilization
Reserve will be empty by the end of FY 2017. The Distribution Operations reserve will require a
short term transfer of $10 million from the Electric Special Projects reserve to remain adequate
through the forecast period. The $10 million is projected to be transferred back between FY
2020 and FY 2021. The Supply Operations Reserve, however, is forecasted to be below
minimum levels. This is discussed in more detail in Section 5F: Risk Assessment and Reserves
Adequacy. The Hydro Stabilization reserve is projected to be depleted by the end of FY 2017.
Staff will bring plans to Council in spring or summer for a Hydro rate adjustment mechanism to
better utilize, and fund, this particular reserve.
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Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2016 and Projections through FY 2027
Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2016 and Projections through FY 2027
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SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two contingency reserves, the Supply Operations Reserve and
the Distribution Operations Reserve. This Financial Plan maintains reserves in excess of the
reserve minimum for the Distribution Operations Reserve throughout the forecast period.
Reserve levels also exceed the short-term risk assessment level for the Distribution Fund. The
Supply Operations Reserve, however, may end up below minimum levels and below the short-
term risk assessment level.
There are a variety of risks associated with the Supply Fund as are shown in Table 8. Because of
the high range of uncertainty in energy price predictions more than three years in the future,
this risk assessment is only performed for the first two fiscal years of the forecast period. It is
important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 8 is very low.
Table 8: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2018 FY 2019
1.Load Net Revenue 0.9 1.0 Revenue loss from load decreases (net of
reduction in energy purchases)
2.Production from Hydroelectric
Resources: Western & Calaveras 9.3 13.7 Lower than forecasted hydro
3.Renewable Production: Landfill &
Wind 0.5 2.0 Additional cost of renewable output that is
higher than forecasted
4.Carbon Neutral Cost 0.0 0.0 Higher than forecasted market prices for RECs
5.Market Price (Energy)0.7 0.6 Higher than forecasted market prices for
energy
6.Local Capacity 0.6 1.5 Higher than forecasted market prices for local
capacity
7.Transmission/CAISO 3.2 3.3 High-end transmission forecast scenario
8.Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
9.Western Cost 2.4 3.5 Risk of rate adjustments from Western
10.Regulatory and Legal 0.0 0.0 Risks associated with legislative uncertainties
11.Supplier Default 0.2 0.2 Estimate of supplier default risks
Electric Supply Fund Risks $18.8
million
$26.8
million
Projected Supply Operations +
Hydro Stabilization Reserve Levels
$16.0
million
$17.5
million
Of the risks faced by the Electric Utility’s Supply Fund in FY 2018, the risk of a dry year with very
low hydroelectric output is normally the largest, accounting for nearly half 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 needs to
buy power to replace the lost output. The converse happens when hydroelectric output is
higher than average.
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Of the remaining risks for FY 2018, $3.2 million is related to the projected costs if transmission
cost increases are higher than staff’s current forecast. Another $2.4 million is related to the
possibility of drought-related changes to Western rates for CVP hydropower.
As shown in Figure 10, the Supply Operations Reserve will drop below the minimum reserve
guidelines by as much as $3.9 million over the course of the forecast period. In addition, as
shown in Figure 11, the combined hydro stabilization and supply operations reserves will drop
below the risk assessment level. It is acceptable under the Electric Utility Reserves Management
Practices to drop below minimum reserve guidelines so long as Council approves the Financial
Plan. Staff recommends proceeding with this plan for two reasons: first, due to larger than
normal rains and snowpack to date, there is a chance of better hydro conditions will result in
higher reserves, and second, the presence of the Electric Special Projects Reserve means that a
small temporary shortfall in the Supply Operations Reserve should not affect the Electric
Utility’s bond ratings. In the event drought re-emerges, staff will re-evaluate its projections for
FY 2019 and may recommend additional rate increases or the adoption of a hydroelectric rate
adjuster.
Figure 10: Electric Supply Operations Reserve Adequacy
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Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 9 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2022. 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.
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Table 9: Electric Distribution Fund Risk Assessment ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Total non-commodity revenue $46,877 $49,044 $48,931 $48,812 $49,612
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $3,700 $3,871 $3,862 $3,852 $3,916
CIP Budget $15,574 $15,869 $25,150 $19,048 $17,449
CIP Contingency @10% $1,557 $1,587 $2,515 $1,905 $1,745
Total Risk Assessment value $5,257 $5,458 $6,377 $5,757 $5,661
Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, the CIP Reserve is projected to be at or above the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels in later years, CIP Commitments are nearly impossible to project that far out,
and adjustments to the reserve can be made in future years.
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Figure 13: Electric CIP Reserve Adequacy
SECTION 5G: LONG-TERM OUTLOOK
This forecast covers the period from FY 2018 through FY 2027, 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
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provide 17% to 18% of the energy for the utility’s supply portfolio at prices under $65 per
megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those
contracts expire. Although recent prices have been in that range (or even lower), and costs
may decrease in the future, current renewable projects also benefit from a wide range of tax
and other incentives that may or may not be available in the 2020s and beyond. However, staff
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 no new debt is issued). 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 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 and to purchase renewable energy to support the utility’s Carbon
Neutral Plan. That revenue source is expected to continue through 2020, but provisions for
whether or not these allocations continue past 2020 are still being discussed. If the Electric
Utility no longer received these allowances, 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
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long-term planning processes, but will need to continue to incorporate them into its planning
methodologies.
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. Initial
analysis of these types of scenarios is being undertaken 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 did not end up
overloaded, or conversely, to avoid over investment, and the evaluation of changes to utility
distribution system management to accommodate integration of the various technologies
involved in electrification.
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SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: ELECTRICITY PURCHASES
As shown in Figure 14 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 are projected to rise to roughly 50% starting in FY
2017. 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 14: Electricity Supply by Source
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Figure 15 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. Even if hydroelectric generation returns to normal levels, costs will increase in
FY 2017 due to increases in renewable energy costs as various renewable projects come online
to fulfill the City’s carbon neutral and RPS goals. 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 $77.8 million by
FY 2020, at which point all currently contracted renewable projects will be online. Supply costs
are only projected to change slightly in subsequent years.
Figure 15: Electric Supply Portfolio Costs, Historical and Projected
5 Costs are shown net of wholesale revenues, and cannot be directly compared with the electric supply purchase
figures shown in Appendix A: Electric Utility Financial Forecast Detail 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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SECTION 6B: OPERATIONS
CPAU’s Electric Utility operations include the following activities:
•Administration, including financial management of charges allocated to the Electric
Utility for administrative services provided by the General Fund and for Utilities
Department administration, as well as debt service and other transfers. Additional detail
on Electric Utility debt service is provided in Section 6D (Debt Service)
•Customer Service
•Engineering work for maintenance activities (as opposed to capital activities)
•Operations and Maintenance of the distribution system; and
•Resource Management
Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 2012 to FY 2015, Operations costs increased by less than 1% per year on average. In
2013 there was a one-time increase in expenses associated with an adjustment to the value of
the City’s investment portfolio. Over the forecast horizon, excluding debt service and transfers,
costs are projected to increase by roughly 2 to 4 % per year.
Figure 16: Historical and Projected Electric Utility Operational Costs
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SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
CIP spending for FY 2018 through FY 2023 is projected to decrease somewhat from last year’s
forecast, primarily due to the removal of some major one-time projects, including service
connection upgrades for a few major customers. Other projects still slated to continue are pole
replacements related to the Fiber to the Home project, and Smart Grid upgrades. Ongoing
capital investment in the electric distribution system is also increasing. This forecast assumes
that smart grid projects are financed from the Electric Special Projects Reserve and with
additional funding from the water and gas funds, but it would also be possible to use bond
financing.
Excluding the one-time projects listed above, the CIP plan for FY 2018 to FY 2022 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 2018 Utilities
Capital Budget. Figure 16 shows the adopted / proposed / projected capital budgets as well as
actual and projected capitalized administrative overhead associated with the program.
Figure 17: Electric Utility CIP Spending
SECTION 6D: 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 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 Electric Utility. Debt service for this bond continues through
2021, and for the financial forecast period is as follows:
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Table 10: Electric Utility Debt Service ($000)
FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
2007 Clean Renewable
Energy Bonds 100 100 100 100 100 -
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’s reserves and net revenue are also pledged as security for the bond
issuances listed in Table 11, 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 11: 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 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.7 Each year it is calculated
according to the 2009 Council-adopted methodology, and does not require additional Council
action.
SECTION 6F: WHOLESALE REVENUES AND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 13% comes
from other sources. Of these other sources, about a third represent wholesale “revenues” that
are included solely for accounting purposes. These revenues have offsetting electric supply
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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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 2016 these sources represented roughly 50% of revenue from sources other
than electricity sales. The remaining FY 2016 revenues consisted of a variety of one-time
transfers.
Revenues from connection fees have more than doubled since FY 2009. Revenue from these
sources decreased slightly during the recession, but has increased substantially since then,
peaking in FY 2014. Staff is forecasting slightly lower revenue from this source in subsequent
years.
Carbon allowance revenues are projected to stay stable through the forecast period, as is
interest income. 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 decreased (due to drought or a withdrawal
from the ESP reserve for a major project), interest income would decrease.
SECTION 6G: SALES REVENUES
Sales revenue projections are based on the load forecast in Section 5A: Load Forecast and the
projected rate changes shown in Figure 7. As discussed in Section 5A, sales revenues for this
utility stay relatively stable due to the mild climate in Palo Alto, but decreased significantly in
FY 2017. In addition, Palo Alto is a built out City, with incremental growth in population and
relatively stable commercial customer loads.
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SECTION 7: COMMUNICATIONS PLAN
CPAU communication methods include use of the Utilities website, utility bill inserts, messaging
on bills and envelopes, email newsletters, print ads in local publications, videos and
participation in community outreach events. The FY 2018 Electric Utility communications
strategy covers these primary areas: rates, efficiency, renewables, operations, infrastructure,
safety, and changes to utility economic conditions in the wake of the drought.
In FY 2018, CPAU is proposing an 12% increase in electric utility rates. Prior to FY 2017, electric
utility rates had not increased since 2009, as the City has been drawing down reserves from the
Electric Fund. The rate increase was necessary last year and again in FY 2018, as these reserves
are below the minimum reserve level. Communications will focus on the reasons why a rate
increase is necessary, and how this percentage has been impacted due to the drought,
renewable projects, capital improvement and other costs. Palo Alto purchases a significant
portion of its electricity from hydroelectric resources. Severe drought conditions over the past
few years reduced available hydroelectric supplies, requiring the City to purchase more costly
replacement electric supplies. Since the State received a great deal of precipitation in the latter
part of FY 2017, communications staff will now focus messaging on how increased hydroelectric
supplies will impact and potentially change the forecast for electric rates moving forward, at
least in the short-term.
Reliability and safety are primary concerns for CPAU and City Council has placed increasing
emphasis on capital improvement investments for utility infrastructure. In order to maintain
system integrity, continued capital improvement costs are necessary. Deferring such costs to
future years would not be prudent, as deferred investment in maintenance, operations and
capital improvement upgrades could potentially jeopardize the safety and reliability of the
electric utility system. Despite these costs and increasing rates, CPAU’s rates 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 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.
Recent power purchase agreements have allowed CPAU to procure long-term renewable
electric supplies at low costs. While upfront capital costs to bring these renewable projects
online may initially contribute towards some increase in CPAU’s electric rates, these higher
costs are expected to taper off once 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 and local renewable energy programs. From January 2015 to December 2016, CPAU
encouragedcommunity participation in the Georgetown University Energy Prize competition, a
friendly, national campaign for energy efficiency. This two-year campaign encouraged the
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community to reduce energy use and compete for a $5 million prize. Within the past one to two
years, CPAU launched new programs thatallow customers to better understand and manage
their energy use. These programs include the Home Efficiency Genie; a free utility bill analysis
service with option for a subsidized in-depth home energy assessment; and an online utility
portal for customers to view consumption history, learn about efficiency tips and CPAU
programs they can take advantage of for home energy efficiency.
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APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
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APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
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1 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
2
3 ELECTRIC LOAD
4 Purchases (MWh)969,519 976,319 980,894 979,005 977,292 945,703 960,601 940,860 938,688 936,402 934,369 934,369 934,369 934,369 934,369 934,369
5 Sales (MWh)942,562 946,841 950,784 936,773 937,157 906,562 908,459 907,858 905,762 903,556 901,594 901,594 901,594 901,594 901,594 901,594
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1156$ 0.1154$ 0.1164$ 0.1158$ 0.1156$ 0.1233$ 0.1407$ 0.1506$ 0.1506$ 0.1506$ 0.1516$ 0.1553$ 0.1568$ 0.1579$ 0.1589$ 0.1600$
9 Change in System Average Rate -1%0%1%0%0%10%14%7%0%0%1%2%1%1%1%1%
10 Change in Average Residential Bill -1%-4%-1%-5%3%10%11%6%-1%-1%0%2%1%0%0%0%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)343,000 1,886,000 305,000 - - - - - - - - - - - - -
14 Commitments (Non-CIP)1,593,000 2,737,000 3,528,000 3,164,000 3,102,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000
15 Restricted for Debt Service - - - - - - - - - - - - - - - -
16 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - -
17 Central Valley Project Reserve 305,000 314,000 313,000 329,000 - - - - - - - - - - - -
18 Underground Loan Reserve 736,000 742,000 738,000 734,000 730,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000
19 Public Benefits Reserves 3,139,000 1,149,000 2,197,000 2,064,000 2,574,000 1,839,000 1,330,970 739,050 279,587 94,959 - - - - - -
20 Electric Special Projects Reserve 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,838,000 41,665,260 41,525,693 41,192,360 42,859,027 46,192,360 44,665,260 44,665,260 44,665,260 44,665,260 44,665,260
21 Hydro Stabilization Reserve - - - - 17,000,000 11,400,000 2,400,000 - - - - - - - - -
22 Capital Reserves - - - - - - - - - - - - - - - -
23 Rate Stabilization Reserves 66,331,000 74,609,000 69,029,000 70,049,000 14,411,000 9,011,000 3,600,000 - - - - - - - - -
24 Operations Reserves - - - - 22,498,000 21,850,000 21,570,031 28,477,295 31,328,331 31,984,129 32,727,128 36,734,340 36,600,128 36,226,077 38,957,005 40,470,904
25 Unassigned - - - - - - - - 915,938 (0) 0 0 - - - -
26 TOTAL STARTING RESERVES 129,005,000 132,757,000 128,948,000 129,178,000 112,153,000 100,444,000 75,072,262 75,248,039 78,222,216 79,444,115 83,425,489 85,905,601 85,771,388 85,397,337 88,128,265 89,642,164
27
28 REVENUES
29 Net Sales 109,309,318 109,974,337 110,246,264 108,873,377 108,312,917 111,743,300 127,804,839 136,731,078 136,415,457 136,083,191 136,693,648 139,980,910 141,364,099 142,326,185 143,276,966 144,246,140
30 Wholesale Revenues 7,189,218 6,635,790 6,010,409 6,267,000 5,534,000 11,422,865 16,360,219 13,481,291 15,723,490 16,405,058 17,841,074 17,242,448 17,467,779 17,643,588 17,905,633 19,002,541
31 Other Revenues and Transfers In 7,027,230 9,624,213 13,669,185 9,688,480 10,129,274 10,013,826 14,509,829 12,934,637 21,875,693 18,854,966 15,870,577 12,946,907 13,320,702 13,772,401 14,201,802 14,631,713
32 TOTAL REVENUES 123,525,766 126,234,340 129,925,858 124,828,858 123,976,191 133,179,991 158,674,887 163,147,006 174,014,640 171,343,215 170,405,299 170,170,265 172,152,580 173,742,173 175,384,402 177,880,394
33
34 EXPENSES
35 Electric Supply Purchases 58,724,136 61,313,637 68,785,977 80,022,010 79,114,644 84,371,202 87,986,828 89,065,816 90,840,796 90,727,608 92,220,793 91,758,113 92,924,517 93,903,644 95,224,116 96,464,584
36 Operating Expenses
37 Administration
38 Allocated Charges 3,416,423 4,399,674 4,139,837 4,511,222 5,148,470 3,376,852 3,461,365 3,547,989 3,636,783 3,727,743 3,820,946 3,916,481 4,014,404 4,114,776 4,217,658 4,323,112
39 Rent 3,839,201 3,875,836 4,051,044 4,147,742 4,997,101 5,121,102 5,274,735 5,432,977 5,595,966 5,763,845 5,936,761 6,114,864 6,298,310 6,487,259 6,681,877 6,882,333
40 Debt Service 8,902,751 9,265,736 9,020,651 9,037,000 8,985,994 8,889,090 8,868,768 8,471,091 8,480,048 8,444,315 8,453,684 9,299,046 8,893,834 4,898,677 4,896,047 4,894,784
41 Transfers and Other Adjustments 11,603,695 16,797,054 11,329,973 11,003,993 5,920,297 12,078,949 13,226,214 13,275,892 14,159,863 14,163,159 14,166,536 14,169,998 14,173,547 14,177,184 14,180,913 14,184,734
42 Subtotal, Administration 27,762,069 34,338,299 28,541,506 28,699,957 25,051,862 29,465,993 30,831,082 30,727,949 31,872,660 32,099,063 32,377,926 33,500,388 33,380,095 29,677,896 29,976,494 30,284,963
43 Resource Management 2,654,024 3,024,268 3,541,524 2,138,615 2,035,834 3,240,541 3,356,945 3,476,405 3,600,582 3,707,001 3,803,153 3,902,819 4,005,096 4,110,053 4,217,761 4,328,292
44 Demand Side Management 4,541,531 3,529,529 3,187,875 3,491,470 3,723,605 3,690,063 3,773,952 3,639,388 3,357,212 3,297,042 3,255,251 3,339,598 3,384,926 3,431,076 3,478,065 3,525,906
45 Operations and Mtc 9,288,490 9,601,481 9,488,627 10,716,881 11,514,846 13,702,158 14,158,618 14,626,674 15,111,694 15,541,894 15,941,538 16,354,711 16,778,592 17,213,460 17,659,598 18,117,300
46 Engineering (Operating)1,057,783 1,114,945 1,102,008 1,230,160 1,578,022 1,840,073 1,889,674 1,940,499 1,992,737 2,044,182 2,095,630 2,148,473 2,202,649 2,258,191 2,315,133 2,373,512
47 Customer Service 1,908,493 2,007,322 2,032,231 1,548,851 1,538,363 2,212,967 2,297,149 2,383,613 2,473,714 2,549,014 2,615,594 2,684,750 2,755,735 2,828,597 2,903,385 2,980,150
48 Allowance for Unspent Budget - - - - - (1,461,604) (1,508,656) (1,556,914) (1,606,879) (1,651,905) (1,694,232) (1,737,944) (1,782,784) (1,828,782) (1,875,967) (1,924,370)
49 Subtotal, Operating Expenses 47,212,389 53,615,844 47,893,770 47,825,933 45,442,532 52,690,192 54,798,765 55,237,614 56,801,721 57,586,290 58,394,860 60,192,796 60,724,308 57,690,491 58,674,470 59,685,754
50 Capital Program Contribution 13,837,241 15,113,859 13,016,111 14,005,915 11,128,015 21,490,335 15,573,950 15,869,398 25,150,225 19,047,944 17,449,100 18,353,570 18,877,806 19,417,110 19,971,917 20,542,674
51 TOTAL EXPENSES 119,773,766 130,043,340 129,695,858 141,853,858 135,685,191 158,551,729 158,359,542 160,172,828 172,792,742 167,361,841 168,064,753 170,304,478 172,526,631 171,011,245 173,870,503 176,693,012
52 22,058,000.0 26,659,398 15,868,470 16,320,285 16,784,774
53 ENDING RESERVES
54 Reappropriations (Non-CIP)1,886,000 305,000 - - - - - - - - - - - - - -
55 Commitments (Non-CIP)2,737,000 3,528,000 3,164,000 3,102,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000
56 Restricted for Debt Service - - - - - - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - - -
58 Central Valley Project Reserve 314,000 313,000 329,000 - - - - - - - - - - - - -
59 Underground Loan Reserve 742,000 738,000 734,000 730,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000
60 Public Benefits Reserves 1,149,000 2,197,000 2,064,000 2,574,000 1,839,000 1,330,970 739,050 279,587 94,959 - - - - - - -
61 Electric Special Projects Reserve 50,320,000 51,838,000 51,838,000 51,838,000 51,838,000 41,665,260 41,525,693 41,192,360 42,859,027 46,192,360 44,665,260 44,665,260 44,665,260 44,665,260 44,665,260 44,665,260
62 Hydro Stabilization Reserve - - - 17,000,000 11,400,000 2,400,000 - - - - - - - - - -
58 Capital Reserve - - - - - - - - - - - - - - - -
59 Rate Stabilization Reserve 74,609,000 69,029,000 70,049,000 14,411,000 9,011,000 3,600,000 - - - - - - - - - -
60 Operations Reserve - - - 22,498,000 21,850,000 21,570,031 28,477,295 31,328,331 31,984,129 32,727,128 36,734,340 36,600,128 36,226,077 38,957,005 40,470,904 41,658,286
61 Unassigned - - - - - - - 915,938 (0) 0 0 - - - - -
62 TOTAL ENDING RESERVES 132,757,000 128,948,000 129,178,000 112,153,000 100,444,000 75,072,262 75,248,039 78,222,216 79,444,115 83,425,489 85,905,601 85,771,388 85,397,337 88,128,265 89,642,164 90,829,546
63
64 OPERATIONS RESERVE
65 Min (60 days of non-capital expenses)23,548,140 23,951,699 25,106,757 25,973,915 26,332,908 26,857,109 27,090,134 27,593,969 27,942,086 28,353,037 28,150,419 28,667,754 29,179,891
66 Target (90 days of non-capital expenses)33,151,752 33,702,675 35,379,286 36,622,631 37,102,294 37,828,286 38,116,222 38,808,965 39,266,545 39,816,759 39,444,963 40,151,398 40,848,296
67 Max (120 days of non-capital expenses)42,755,364 43,453,651 45,651,816 47,271,347 47,871,681 48,799,463 49,142,310 50,023,961 50,591,003 51,280,480 50,739,507 51,635,042 52,516,702
68 Risk Assessment Value 4,645,297 4,373,014 5,295,861 5,257,153 5,457,746 6,376,895 5,757,260 5,660,508 6,010,401 6,256,453 6,469,660 6,600,181 6,733,749
69
70 DEBT SERVICE COVERAGE RATIO
71 Net Revenues (125% of Debt Service)1090% 1140% 1193% 1315%1286% 1442% 1510% 1603% 1641% 1656% 1682% 1534% 1628% 2995% 3043% 3090%
72 Available Reserves (5x Debt Service)*14.4 13.5 14.0 12.1 10.8 8.0 8.1 8.8 8.9 9.4 9.7 8.8 9.2 17.2 17.5 17.8
*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.
6053706
1 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
2
3 REVENUES
4 Net Sales 88%87%85%87%87%84%81%84%78%79%80%82%82%82%82%81%
5 Other Revenues and Transfers In 12%13%15%13%13%16%19%16%22%21%20%18%18%18%18%19%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 46%46%52%55%54%50%46%47%45%46%46%46%46%47%47%47%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%3%3%3%4%2%2%2%2%2%2%2%2%2%2%2%
13 Rent 3%3%3%3%4%3%3%3%3%3%4%4%4%4%4%4%
14 Debt Service 7%7%7%6%7%6%6%5%5%5%5%5%5%3%3%3%
15 Transfers and Other Adjustments 10%13%9%8%4%8%8%8%8%8%8%8%8%8%8%8%
16 Subtotal, Administration 23%26%22%20%18%19%19%19%18%19%19%20%19%17%17%17%
17 Resource Management 2%2%3%2%2%2%2%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 8%7%7%8%8%9%9%9%9%9%9%10%10%10%10%10%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 2%2%2%1%1%1%1%1%1%2%2%2%2%2%2%2%
21 Allowance for Unspent Budget 0%0%0%0%0%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 36%39%34%31%31%31%32%32%31%32%33%33%33%32%32%32%
23 Capital Program Contribution 12%12%10%10%8%14%10%10%15%11%10%11%11%11%11%12%
24 TOTAL EXPENSES 94%96%97%96%93%94%88%89%90%90%89%90%90%90%90%90%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
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%176%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
44 Distribution Revenue Variance 3,244,706 3,260,213 3,146,827 3,699,758 3,870,807 3,861,873 3,852,466 3,915,598 4,175,044 4,368,672 4,527,949 4,602,989 4,679,481
45 10% CIP Program Contingency 1,400,592 1,112,802 2,149,034 1,557,395 1,586,940 2,515,022 1,904,794 1,744,910 1,835,357 1,887,781 1,941,711 1,997,192 2,054,267
46 Total Risk Asssessment Value 4,645,297 4,373,014 5,295,861 5,257,153 5,457,746 6,376,895 5,757,260 5,660,508 6,010,401 6,256,453 6,469,660 6,600,181 6,733,749
47 Projected Operations Reserve 22,498,000 21,850,000 21,570,031 28,477,295 28,507,266 31,984,129 32,727,129 36,734,340 36,600,128 36,226,077 38,957,005 40,470,904 41,658,286
48 Operations Reserve, % of Risk Value 484%500%407%542%522%502%568%649%609%579%602%613%619%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- - - 15,208,552 15,033,113 16,240,825 16,860,400 17,001,701 17,325,251 17,328,711 17,602,415 17,709,305 17,862,689 17,395,887 17,642,251 17,876,454
46 Target (90 days of non-capital expenses)- - - 22,812,829 22,549,669 24,361,237 25,290,599 25,502,552 25,987,877 25,993,067 26,403,622 26,563,958 26,794,033 26,093,831 26,463,376 26,814,681
47 Max (120 days of non-capital expenses)- - - 30,417,105 30,066,225 32,481,649 33,720,799 34,003,403 34,650,502 34,657,422 35,204,830 35,418,611 35,725,378 34,791,775 35,284,501 35,752,908
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- - - 8,339,587 8,918,586 8,865,932 9,113,516 9,331,206 9,531,858 9,761,423 9,991,554 10,232,781 10,490,348 10,754,532 11,025,503 11,303,437
51 Target (90 days of non-capital expenses)- - - 10,338,923 11,153,006 11,018,050 11,332,032 11,599,742 11,840,409 12,123,155 12,405,343 12,702,586 13,022,725 13,351,132 13,688,022 14,033,616
52 Max (120 days of non-capital expenses)- - - 12,338,259 13,387,426 13,170,167 13,550,548 13,868,279 14,148,960 14,484,888 14,819,131 15,172,392 15,555,102 15,947,732 16,350,541 16,763,794
53 Risk Assessment Value 4,645,297 4,373,014 5,295,861 5,257,153 5,457,746 6,376,895 5,757,260 5,660,508 6,010,401 6,256,453 6,469,660 6,600,181 6,733,749
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1090%1140%1193%1315%1286%1442%1510%1603%1641%1656%1682%1534%1628%2995%3043%3090%
57 Available Reserves (5x Debt Service)*14.4 13.5 14.0 12.1 10.8 8.0 8.1 8.8 8.9 9.4 9.7 8.8 9.2 17.2 17.5 17.8
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
(This section includes the proposed amendments to this section. This section will be finalized
following Council adoption of the final amended version.)
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a)“Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b)“Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c)“Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d)“Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserve for Commitments)
b)For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c)For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d)For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e)For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f)For operating contingencies, as described in Section 12 (Operations Reserves)
g)Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserves for Commitments)
b)For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c)As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d)To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
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June 16, 2014 44 | Page
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)
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, requiring funding of at least
$1 million;
e) The preferred projects to be funded by the ESP Reserve must be identified by end of
FY 2015;
f) Any uncommitted funds remaining at the end of FY 2020 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed; and
g) Funds may be used for analysis and pilot projects which would be the basis for planned
large projects.
Section 7. Hydroelectric Stabilization Reserve
Supply cost savings and surplus energy sales revenue associated with higher than average
generation from hydroelectric resources may be added to the Electric Supply Fund’s
Hydroelectric Stabilization Reserve by action of the City Council and held to offset higher
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 45 | Page
commodity supply costs during years of lower than average generation. Withdrawal of
funds from the Hydroelectric Stabilization Reserve requires action by the City Council.
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a)The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period 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.
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
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June 16, 2014 46 | Page
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period.
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 Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
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
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June 16, 2014 47 | Page
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e)Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were
funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an
alternative plan that retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 48 | Page
APPENDIX C: DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL ACTIVITIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Electric Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process.
It does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
•monitoring the substations and performing routine maintenance;
•performing preventative maintenance on the system;
•monitoring the system’s status from the UCC using SCADA;
•maintaining the SCADA system;
•investigating outages and other customer complaints and performing emergency
repairs;
•clearing vegetation near overhead power lines; and
•testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX D: SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
570 Kirkland Way, Suite 100
Kirkland, Washington 98033
Telephone: 425 889-700 Facsimile: 425 889-2725
A registered professional engineering corporation with offices in
Kirkland, WA and Portland, OR
March 29, 2017
TO: Jon Abendschein, City of Palo Alto
Eric Keniston, City of Palo Alto
FROM: Anne Falcon, EES Consulting
SUBJECT: 2017 COSA Model and Rate Design Update
Introduction
The City’s COSA and Rate Design models consist of four components: a FERC Account Model
that translates the City’s budget accounts, a Cost of Service (COS) model that allocates the
budgeted costs to customer classes, a Lighting and Traffic Signal COS and Rate Model that
allocates costs to lighting and traffic signal customers, and a Rate Design Model that generates
the rates for all other customer classes. As part of the annual budget process, the FERC Account
Model, Electric COS Model, Lighting and Traffic Signal Model, and Rate Design models were
updated for the FY 2018 budget year. This update included updating financial and load data as
well as reviewing other inputs that impact the City of Palo Alto’s cost of providing electric
service. The underlying methodology of the COSA was not changed. rather EES assisted the City
of Palo Alto with updating the inputs to the existing methodology to reflect FY 2018 sales and
budget projections, and streamline one rate schedule to remove redundancies (e.g. removing
rate schedule E-18).
Summary of Updates
As part of the update, the City staff provided updated budget and load forecasts for the years
FY 2018 through FY 2020. After reviewing the budget data, the revenue requirement and load
forecast in the FERC Account Model and COSA model were updated based on the projected FY
2018 budget. Projected revenues from current rates were forecast for each rate schedule
based on the updated load data staff provided. Rate schedule 18 (Municipal Electric Service)
was removed as customers historically in that rate schedule have been reclassified, as of July
2017to Rate Schedule E-4 (Medium Commercial Electric Service) and E-7 (Large Commercial
Electric Service), to more accurately reflect the costs of serving municipal customers.
ATTACHMENT C
MEMORANDUM TO Jon Abendschein & Eric Keniston
March 29, 2017
Page 2
The Lighting and Traffic Signal Model was updated with FY 2018 transmission and distribution
Operation and Maintenance costs, power supply costs and total overhead costs. This model
determines the total cost of service for the street lighting and traffic lighting rate classes based
on individual bulb type and O&M requirements. This model was then used to determine the
costs associated with providing service to the traffic light rate customers only. The share of
costs associated with traffic lights service will collected as a transfer from the City’s General
Fund to its Electric Utility and is reflected in the Electric COSA model under “Other Revenues”.
The final model update was the rate design model. This model takes the updated COS Model
cost allocation results by rate class and develops rates for each class that meet the allocated
revenue requirement for each rate class. The updates included updated FY 2018 allocated
costs, updated seasonal power cost splits, updated billing data (such as load in each residential
rate tier, Non-Coincident Peaks and energy consumption) and Time of Use (TOU) marginal
costs.
Using the same methodology that was developed in 2016, the following rates were updated:
• E-1: Tier 1 and Tier 2 Energy charges, minimum bill and PBC
• E-1 TOU: TOU energy rates by period and season
• E-2: Energy by season, minimum bill and PBC
• E-4: Energy and demand by season, minimum bill and PBC
• E-4 TOU: TOU energy and demand rates by period and season
• E-7: Energy and demand rates by season, minimum bill and PBC
• E-7 TOU: TOU energy and demand rates by period and season
An updated rate comparison is provided below.
Summary of Results
The following provide the updated rates compared to current rates:
Residential
Energy Rates
Existing
($/kWh)
New
($/kWh) Percent Change
Tier 1 $0.11029 $0.12159 10.2%
Tier 2 $0.16901 $0.19001 12.4%
MEMORANDUM TO Jon Abendschein & Eric Keniston
March 29, 2017
Page 3
Please let me know if you have any questions.
Commercial Existing Rates
Demand ($/kW)Energy ($/kWh)
Summer Winter Summer Winter
E-2 $0.16845 $0.11445
E-4 $19.68 $14.04 $0.10229 $0.08049
E-7 $18.34 $15.65 $0.08749 $0.06242
Commercial New Rates
Demand ($/kW)Energy ($/kWh)
Summer Winter Summer Winter
E-2 $0.18885 $0.13267
E-4 $21.05 $15.36 $0.11673 $0.08890
E-7 $23.84 $15.59 $0.09802 $0.07188
Difference (%)
Demand Energy
Summer Winter Summer Winter
E-2 12.1%15.9%
E-4 7.0%9.4%14.1%10.5%
E-7 30.0%-0.4%12.0%15.1%
Attachment D
Not Yet Approved
170329 jb 6053934 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 (Small Commercial Electric Service), E-2-G (Small
Commercial Green Power Electric Service), E-4 (Medium Commercial
Electric Service), E-4-G (Medium Commercial Green Power Electric
Service), E-4 TOU (Medium Commercial Time of Use Electric Service),
E 7 (Large Commercial Electric Service), E-7-G (Large Commercial
Green Power Electric Service), E-7 TOU (Large Commercial Time of
Use Electric Service), and E-14 (Street Lights)
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 hereby RESOLVES 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, 2017.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2 (Small Commercial Electric Service) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-2, as amended, shall become effective July 1, 2017.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2-G (Small Commercial 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, 2017.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Commercial Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2017.
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Commercial Green Power Electric Service) is hereby amended to
Attachment D
Not Yet Approved
170329 jb 6053934 2
read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall become
effective July 1, 2017.
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Commercial 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, 2017.
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Commercial Electric Service) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-7, as amended, shall become effective July 1, 2017.
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Commercial 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, 2017.
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Commercial 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, 2017.
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, 2017.
SECTION 11. The Council makes the following findings:
a. The revenue derived from the adoption of this resolution shall be used only for the
purpose set forth in Article VII, Section 2, of the Charter of the City of Palo Alto.
b. The fees and charges adopted by this resolution are charges imposed for a specific
government service or product provided directly to the payor that are not provided
to those not charged, and do not exceed the reasonable costs to the City of
providing the service or product.
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
Attachment D
Not Yet Approved
170329 jb 6053934 3
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:
___________________________ ___________________________
Senior Deputy 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
Effective 7-1-20176
Supersedes Sheet No E-1-1 dated 7-1-201609 Sheet No E-1-1
A. APPLICABILITY:
This schedule applies to separately metered single-family residential dwellings receiving retail
energy services 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 $0.06605883 $0.05164795 $0.0039151 $0.1102912159
Tier 2 usage
Any usage over Tier 1
0.1125309728 0.0682207358 0.0039151 0.169001
Minimum Bill ($/day) 0.30672938
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 billstatement, 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 perday, prorated by meter reading days of service. As an example, for a 30-day bill, the Tier1 level would be 330 kWh. For further discussion of bill calculation and proration, refer
to Rule and Regulation 11.
{End}
ATTACHMENT E
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-1 dated 7-1-201609 Sheet No E-2-1
A. APPLICABILITY: This schedule applies to non-demand metered electric service for small non-residentialcommercial customers and 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
$0.1059109094 $0.0740007903 $0.0039151 $0.1684518885
Winter Period 0.0641707520 0.0467705356 0.0039151 0.132671445
Minimum Bill ($/day)
0.7328657
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 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.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-2 dated 7-1-201609 Sheet No E-2-2
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 in case the Customer’s
load is intermittent or subject to violent 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-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-1 dated 7-1-201609 Sheet No E-2-1
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-G-1 dated 7-1-20164 Sheet No E-2-G-1
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-residentialcommercial 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
$0.10591090
94
$0.07903400
$0.003915
1 $0.0020
$0.170451
9085
Winter Period 0.075206417 0.053564677 0.0035191 0.0020
$0.116451
3467
Minimum Bill ($/day)
0.7328657
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$0.09094105
91
$0.07903074
00
$0.003915
1
$0.168451
8885
Winter Period
0.0641707520 0.053564677 0.0039151
0.1144513467
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-G-2 dated 7-1-20164 Sheet No E-2-G-2
Minimum Bill ($/day)
0.7328657
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-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-G-3 dated 7-1-20164 Sheet No E-2-G-3
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 ifin case the Customer-s load is intermittent or subject to violent 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-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-1 dated 27-51-20136 Sheet No E-4-1
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 services, 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) $2.533.38 $17.1467 $19.6821.05
Energy Charge (per kWh)
0.0821809526 0.0166101756 0.0035100391 0.1022911673
Winter Period
Demand Charge (per kW) $1.9355 $12.4913.43 $14.0415.36
Energy Charge (per kWh)
0.0603706743 0.016610176 0.0035100391 0.0804908890
Minimum Bill ($/day) 16.321614.8414 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-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-2 dated 27-51-20136 Sheet No E-4-2
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 in case the Customer-s
load is intermittent or subject to violent 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-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-3 dated 27-51-20136 Sheet No E-4-3
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,allowed provided 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 a the discount in this
sectionhereunder and affected by such change. 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-
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-4 dated 27-51-20136 Sheet No E-4-4
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 (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.
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-5 dated 27-51-20136 Sheet No E-4-5
{End}
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-1 dated 7-1-20164 Sheet No E-4-G-1
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 Services, 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) $2.533.38 $17.6714
$19.6821.05
Energy Charge (per kWh)
0.0821809526 0.01756661 0.0039151 0.0020
0.118730429
Winter Period
Demand Charge (per kW) $1.5593 $12.4913.43
$15.3614.04
Energy Charge (per kWh)
0.0603706743 0.01756661 0.0039151 0.0020
0.090908249
Minimum Bill ($/day) 16.321614.8414
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-2 dated 7-1-20164 Sheet No E-4-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.382.53 $17.6714 $21.0519.68
Energy Charge (per kWh) 0.095268218 0.01756661 0.0039151 0.116730229
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.9355 $12.4913.43 $15.3614.04
Energy Charge (per kWh) 0.06743037 0.01756661 0.0039151 0.08890049
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 14.841416.3216 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
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-3 dated 7-1-20164 Sheet No E-4-G-3
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 in case if the Customer’s
load is intermittent or subject to violent 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-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-4 dated 7-1-20164 Sheet No E-4-G-4
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,allowed provided 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 a the discount in this sectionhereunder and affected by such change. 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-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-5 dated 7-1-20164 Sheet No E-4-G-5
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-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-1 dated 27-51-20136 Sheet No E-4-TOU-1
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 services, 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 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)
Peak $2.121.52 $6.095.91 $8.217.42
Mid-Peak 0.6654 6.095.91 6.7644
Off-Peak 0.6654 6.095.91 6.7644
Energy Charge (per kWh)
Peak $0.1014408819 $0.01756661 $0.0039151 $0.122910830
Mid-Peak 0.098358367 0.01756661 0.0039151 0.119820378
Off-Peak 0.087487332 0.01756661 0.0039151 0.1089509344
Winter Period
Demand Charge (per kW)
Peak $1.070.87 $7.496.96 $8.567.83
Off-Peak 1.070.87 7.496.96 8.567.83
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-2 dated 27-51-20136 Sheet No E-4-TOU-2
Commodity Distribution Public Benefits Total
Energy Charge (per kWh)
Peak $0.081646566 $0.01756661 $0.0039151 $0.1031108577
Off-Peak 0.057386167 0.01756661 $0.0039151 0.078858178
Minimum Bill ($/day) 16.321614.8414 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 Years 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-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-3 dated 27-51-20136 Sheet No E-4-TOU-3
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-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-4 dated 27-51-20136 Sheet No E-4-TOU-4
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,allowed provided 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 a the discount in
this sectionhereunder and affected by such change. 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
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-5 dated 27-51-20136 Sheet No E-4-TOU-5
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-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-1 dated 27-51-20163 Sheet No E-7-1
A. APPLICABILITY: This schedule applies to Demand metered secondary Service for non-residentialcommercial
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 anywhere 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) $3.492.50 $20.3515.85 $23.8418.34
Energy Charge (kWh) 0.093538311 0.0005887 0.0039151 0.098028749
Winter Period
Demand Charge (kW) $1.9053 $13.6914.11 $15.5965
Energy Charge (kWh) 0.067395804 0.0005887 0.0039151 0.071886242
Minimum Bill ($/day) 42.364848.5054 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-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-2 dated 27-51-20163 Sheet No E-7-2
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 in case if the Customer’s load is intermittent or subject to violent 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-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-3 dated 27-51-20163 Sheet No E-7-3
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,allowed provided 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 a the discount in
this section hereunder and affected by such change. 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-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-4 dated 27-51-20163 Sheet No E-7-4
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.4) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-5 dated 27-51-20163 Sheet No E-7-5
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-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-1 dated 7-1-20164 Sheet No E-7-G-1
A. APPLICABILITY: This schedule applies to Demand Metered Service for large non-residentialcommercial
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) $3.492.50 $20.3515.85 $23.8418.34
Energy Charge (per kWh) 0.093538311 0.0005887 0.0039151 0.0020 0.1000208949
Winter Period
Demand Charge (per kW) $1.9053 $13.6914.11 $15.5965
Energy Charge (per kWh) 0.067395804 0.0005887 0.0039151 0.0020 0.073886442
Minimum Bill ($/day) 42.364848.5054
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-2 dated 7-1-20164 Sheet No E-7-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.492.50 $20.3515.85 $23.8418.34
Energy Charge (per kWh) 0.093538311 0.0005887 0.0039151 0.098028749
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.9053 $13.6914.11 $15.5965
Energy Charge (per kWh) 0.067395804 0.0005887 0.0039151 0.071886242
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 42.364848.5054 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-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-3 dated 7-1-20164 Sheet No E-7-G-3
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 in case if the load is
intermittent or subject to violent 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-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-4 dated 7-1-20164 Sheet No E-7-G-4
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, butallowed; provided, however, 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 a the discount in this section hereunder and affected by such change. The Customer then has the option
to change the system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a
maximum kilovolt-ampere size limitation.
9. Standby Charge
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-5 dated 7-1-20164 Sheet No E-7-G-5
a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-6 dated 7-1-20164 Sheet No E-7-G-6
{End}
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-1 dated 72-15-20163 Sheet No E-7-TOU-1
A. APPLICABILITY: This voluntary rate schedule applies to Demand metered secondary Service for non-
residentialcommercial 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 $2.221.48 $6.845.33 $9.066.80
Mid-Peak 0.6451 6.845.33 7.485.84
Off-Peak 0.6451 6.845.33 7.485.84
Energy Charge (per kWh)
Peak $0.1017709267 $0.0005887 $0.0039151 $0.1062609705
Mid-Peak 0.098688792 0.0005887 0.0039151 0.1031609230
Off-Peak 0.087777705 0.0005887 0.0039151 0.092268143
Winter Period
Demand Charge (per kW)
Peak $0.9678 $6.937.15 $7.892
Off-Peak 0.9678 6.937.15 7.892
Energy Charge (per kWh)
Peak $0.080366009 $0.0005887 $0.0039151 $0.084846447
Off-Peak 0.056473 0.0005887 0.0039151 0.0609681
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-2 dated 72-15-20163 Sheet No E-7-TOU-2
Minimum Bill ($/day) 42.364848.5054 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 period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-3 dated 72-15-20163 Sheet No E-7-TOU-3
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-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-4 dated 72-15-20163 Sheet No E-7-TOU-4
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,
butallowed provided 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 a the discount in this section hereunder and affected by such change.
The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum
Generation of those non-utility generators, but in no event shall the Customer’s
Maximum Demand be reduced below zero.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-5 dated 72-15-20163 Sheet No E-7-TOU-5
(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}
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No. E-14-2 dated 7-1-200916 Sheet No. E-14-2
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 8.599.66
200 watts 15.8717.83
250 watts 19.5021.92
310 watts 24.1327.12
400 watts 31.0734.92
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No. E-14-2 dated 7-1-200916 Sheet No. E-14-2
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 32.5834.94
High Pressure Sodium Vapor Lamps
70 watts 28.6130.48
100 watts 30.7932.93
150 watts 34.4337.02
250 watts 41.7045.19 Light Emitting Diode (LED) Lamps
70 watts-equivalent 23.7925.06
100 watts-equivalent 25.4426.91
150 watts-equivalent 26.9628.62 250 watts 31.1233.30
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No. E-14-14 dated 7-1-200916 Sheet No. E-14-14
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.
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.
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No. E-14-24 dated 7-1-200916 Sheet No. E-14-24
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.
{End}
EXCERPTED DRAFT MINUTES OF THE APRIL 5, 2017 UTILITIES ADVISORY COMMISSION
ITEM 4. ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt 1) a Resolution Approving the Fiscal Year 2018 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 and E-14 Rate Schedules
Senior Resource Planner Eric Keniston gave an overview of the proposed Financial Plan and rate
changes. The preliminary forecast had changed. Staff was now proposing a 14% overall rate
increase, but he noted the residential increase was only 12%. The proposal included various
reserves transfers to mitigate the overall rate increase and prevent having to increase rates
further this year. This included transfers from the hydro stabilization reserve and a loan from
the Electric Special Projects reserve. These would be used to keep the Supply and Distribution
Reserves within operating guidelines. The Electric Special Projects Reserve would normally not
be used for operational reasons, since it was set aside for special projects, but this plan involved
repaying the loan from that fund by 2020. He gave an overview of the reasons for the rate
changes. Operations costs were increasing as a result of accumulated deferred maintenance
related to difficulty filling positions, and additional capital investment was required due to aging
infrastructure. In addition, new renewable projects were coming online and transmission costs
were increasing. Even with the increases, however, Palo Alto’s electric rates would be
substantially lower than PG&E’s.
Commissioner Schwartz noted there may be increased customer sensitivity to changes on their
bills due to the recent error in gas billing. It would be worthwhile to run a report to identify
people who would see a substantial increase and reach out in advance to let them know that
the bill changes were not due to a billing error. Posting on Nextdoor and other online
information sources would be important.
ACTION: Commissioner Ballantine made a motion to recommend Council approve the staff
recommendation. Vice Chair Danaher seconded the motion. The motion passed unanimously
(5-0, with Chair Cook, Vice Chair Danaher and Commissioners Ballantine, Johnston, and
Schwartz voting yes and Commissioners Forssell and Trumbull absent.)
ATTACHMENT F