HomeMy WebLinkAboutStaff Report 9276
City of Palo Alto (ID # 9276)
City Council Staff Report
Report Type: Action Items Meeting Date: 6/11/2018
City of Palo Alto Page 1
Summary Title: FY 2019 Utility Rates and Financial Plans: Electric, Gas,
Water, Wastewater, Fiber, Storm Drain
Title: PUBLIC HEARING & PROPOSITION 218 HEARING: Staff
Recommendation That the City Council Adopt the Following Resolutions:
Approving the FY 2019 Electric Financial Plan; Adopting an Electric Rate
Increase of 6 Percent and Amending Utility Rate Schedules E-1, E-2, E-2-G, E-
4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU and E-14; Approving the FY 2019 Gas
Utility Financial Plan; Adopting a Gas Rate Increase of 4 Percent and
Amending Utility Rate Schedules G-1, G-2, G-3 and G10; Approving the FY
2019 Wastewater Collection Utility Financial Plan; Adopting a Wastewater
Collection Rate Increase of 11 percent and Amending Utility Rate Schedules
S-1, S-2, S-6 and S-7; Approving the FY 2019 Water Utility Financial Plan;
Adopting a Water Rate Increase of 3 Percent and Amending Utility Rate
Schedules W-1, W-2, W-3, W-4 and W-7; Amending Utility Rate Schedule D-1
to Increase Storm Drain Rates 2.9 Percent per Month per Equivalent
Residential Unit for FY 2019; Adopting a Dark Fiber Rate Increase of 2.9
Percent and Amending Utility Rate Schedules EDF-1 and EDF-2;
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Finance Committee recommend that the City Council approve and adopt the
following:
1. Resolutions of the City Council of the City of Palo Alto:
a. Approving the FY 2019 Electric Financial Plan (Attachments A, B & C);
b. Adopting an Electric Rate Increase of 6 Percent and Amending Utility Rate
Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU and E-14
(Attachments D & E);
c. Approving the FY 2019 Gas Utility Financial Plan (Attachment F & G);
d. Adopting a Gas Rate Increase of 4 Percent and Amending Utility Rate Schedules
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G-1, G-2, G-3 and G10 (Attachments H & I);
e. Approving the FY 2019 Wastewater Collection Utility Financial Plan (Attachments
J & K);
f. Adopting a Wastewater Collection Rate Increase of 11 percent and Amending
Utility Rate Schedules S-1, S-2, S-6 and S-7 (Attachments L & M);
g. Approving the FY 2019 Water Utility Financial Plan (Attachments N & O);
h. Adopting a Water Rate Increase of 3 Percent and Amending Utility Rate
Schedules W-1, W-2, W-3, W-4 and W-7 (Attachments P & Q);
i. Amending Utility Rate Schedule D-1 to Increase Storm Drain Rates 2.9 Percent
per Month per Equivalent Residential Unit for FY 2019 (Attachments R & S); and
j. Adopting a Dark Fiber Rate Increase of 2.9 Percent and Amending Utility Rate
Schedules EDF-1 and EDF-2 (Attachments T & U);
Executive Summary
During April and May 2018, the Finance Committee reviewed various rate changes
recommended by staff for Fiscal Year 2019. This report summarizes the hearings that occurred,
including all staff recommendations and changes to recommendations. This report includes
separate sections for each of the Utilities with recommended rate changes: electric, gas, dark
fiber, storm drain and surface water, water and wastewater collection. Each of these rate
changes is included in the FY 2019 budget assumptions. This report outlines the actions
requested, transmits the resolutions from these reviews, and requests City Council approval
and adoption.
Background
On April 3, 2018, Utilities and Public Works staff presented the Finance Committee two reports:
Utilities Advisory Commission Recommendation that the City Council Adopt: (1) a
Resolution Approving the Fiscal Year 2019 Water Utility Financial Plan; and (2) a
Resolution Increasing Water Rates by 4% by Amending Rate Schedules W-1 (General
Residential Water Service), W-2 (Water Service from Fire Hydrants), W-3 (Fire Service
Connections),W-4 (Residential Master-Metered and General Non-Residential Water
Service), and W-7 (Non-Residential Irrigation Water Service) (Staff Report #90301); and
Utilities Advisory Commission Recommend that the City Council Adopt: (1) a Resolution
Approving the Fiscal Year 2019 Wastewater Collection Financial Plan; and (2) a
Resolution Increasing Wastewater Rates by 11 Percent by Amending Rate Schedules S-1
(Residential Wastewater Collection and Disposal), S-2 (Commercial Wastewater
Collection and Disposal), S-6 (Restaurant Wastewater Collection and Disposal) and S-7
(Commercial Wastewater Collection and Disposal – Industrial Discharger) (Staff Report
#90162)
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2 https://www.cityofpaloalto.org/civicax/filebank/documents/64245
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The Finance Committee recommended approval of the wastewater collection rate increase on
April 3rd. The water rate increase was continued to April 17th (Staff Report #91433), with a
request for alternative rate increase proposals. Staff provided four alternative scenarios, and
the Finance Committee recommended Council approval of a plan with a 3% increase in FY 2019
(Alternative #2). The updated FY 2019 Water Financial Plan and Water Rate Schedules, as
recommended by the Finance Committee on April 17th, are provided at Attachments N through
Q.
As required by Article XIIID of the State Constitution (added by Proposition 218), the City mailed
a Notice of Public Hearing to property owners and customers on April 27, 2018 regarding the
proposed water and wastewater collection rate changes . This notice informed the public that
the proposed rate changes would be considered for Council adoption at a Public Hearing on
June 11, 2018 at 6 pm. All residents and interested persons may submit written or oral
testimony at the hearing, and may also submit written protests to any or all of the proposed
rate increases. Council may consider and adopt the proposed water and wastewater rates
unless written protests are filed by a majority of the affected customers. Any approved water
and/or wastewater collection rate changes will become effective July 1, 2018.
While in prior years rate change proposals have been considered during the Budget Adoption
Hearing, this year the Budget Adoption Hearing will occur on June 18th. The Public Hearing at
which Council will consider adoption of the proposed water and wastewater collection rates
must be opened on June 11th as stated in the notice, but may be continued, if needed.
Discussion
From March through May 2018, the Utilities Advisory Commission and Finance Committee
received and reviewed various utility financial plans, transfer requests, and rate changes
recommended by staff. This report outlines the actions requested, transmits the resolutions
from these reviews, and requests City Council approval and adoption.
Attached to this report are a number of documents, referenced throughout the
recommendation language and the report. In addition, this report also includes links to the
City’s website for all the staff reports presented throughout the review process to the Utilities
Advisory Commission, Finance Committee, and City Council.
Staff and the Finance Committee recommend that the City Council approve the Utility financial
plans and rate changes listed below. These financial plans and rate changes were reviewed and
approved by the Utilities Advisory Commission between March and April of 2018, and by the
Finance Committee between April and May of 2018.
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Proposed Rate Changes and Financial Plans (recommended for adoption in this report)
Electric
The FY 2019 Electric Utility Financial Plan (Attachment B) includes projections of the utility’s
costs and revenues through FY 2028. For FY 2019, a 6% overall rate increase is proposed,
although different customer classes will see increases ranging from 3% to 8%. Beyond FY 2019,
a 3% increase is projected for the following fiscal year. However, even with these increases,
residential electric rates will remain approximately 35% to 45% below Pacific Gas & Electric
(PG&E) rates and comparable to Santa Clara and Roseville, other publicly-owned utilities that
maintain very low bills for customers. The proposed Electric rate schedules are included as
Attachment E.
To maintain adequate Operations Reserves, the following FY 2018 transfers are requested: 1)
up to $9 million from the Supply Rate Stabilization Reserve to the Supply Operations Reserve, 2)
up to $1 million from the Hydroelectric Stabilization Reserve to the Supply Operations Reserve,
and 3) up to $6 million from the Electric Special Projects Reserve to the Distribution Operations
Reserve. In addition, the Electric Utility Reserves Management Practices (Attachment C) have
been updated to reflect changes to the Hydroelectric Rate Stabilization Reserve and are
presented for approval along with the Financial Plan. For more information, see Staff Report
#91584, approved by the Finance Committee on May 15, 2018.
Gas
The FY 2019 Gas Utility Financial Plan (Attachment G) includes projections of the utility’s costs
and revenues through FY 2028. The FY 2019 Gas Utility Financial Plan includes a distribution-
related gas rate increase which equates to a 4% overall bill increase. Distribution rates were last
increased in 2016. Future-year distribution-related rate increases are projected to be 7% to 8%
over the next three years. The proposed Gas rate schedules are included as Attachment I.
In addition, the Gas Utility Financial Plan includes proposed transfers to the Operations Reserve
of $129,000 and $2 million from the Rate Stabilization Reserve in FY 2018 and FY 2019,
respectively, to ensure that there are appropriate financial reserves for contingencies. For more
information, see Staff Report #91575, approved by the Finance Committee on May 15, 2018.
Wastewater Collection
The FY 2019 Wastewater Collection Utility Financial Plan (Attachment K) includes projections of
the utility’s costs and revenues through FY 2028. Staff originally proposed a 10% increase for FY
2019, but the Utilities Advisory Commission and Finance Committee approved an 11% increase,
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5 https://www.cityofpaloalto.org/civicax/filebank/documents/64920
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with the goal of keeping reserves above the minimum guideline levels. Rate increases of 10 to
12% are projected for the next two years to bring revenues in line with ongoing costs. The
annual sewer bill for a Palo Alto resident is currently about 33% lower than the average of
neighboring communities, and is projected to remain below the overall average, even with the
future rate increases. The proposed Wastewater Collection rate schedules are included as
Attachment M. For more information, see Staff Report #9016, approved by the Finance
Committee on April 3, 2018.
Water
The FY 2019 Water Utility Financial Plan (Attachment O) includes projections of the utility’s
costs and revenues for FY 2018 through FY 2028. Staff originally proposed a 4% rate increase to
the UAC on March 7, 2018. The proposal passed unanimously and was presented to the Finance
Committee on April 3, 2018. The Finance Committee expressed concern over the proposed
future rate increases of 6% to 7% over the next three years, and requested that staff return
with an alternate proposal at the April 17, 2018 meeting.
Staff provided the Finance Committee with additional alternatives, based on updated cost
projections from the San Francisco Public Utilities Commission, utilizing a greater portion of
existing reserves, as well as possible debt financing and cost reduction scenarios. After review,
the Finance Committee recommended ‘Alternative 2’, which results in a 3% rate increase for FY
2019 and tentative 4% increases over the next three years.
As this proposal was agreed upon at the Finance Committee, the Financial Plan and Rate
schedules from the April 3rd and 17th meetings do not reflect the agreed upon alternative. The
FY19 Financial Plan and Rate Schedules have been revised and are presented here as
Attachments O and Q, respectively. For more information on the original proposal, see Staff
Report #9030, presented to the Finance Committee on April 3, 2018.
Storm Water and Surface Water Drainage
On April 11, 2017, a majority of Palo Alto property owners approved a ballot measure
approving a monthly Storm Water Management Fee. This fee will fund thirteen storm drain
capital improvement projects listed in the ballot measure, enhanced maintenance of the storm
drain system, and a variety of storm water quality protection programs. The approved ballot
measure includes an annual adjustment based on the Consumer Price Index (CPI). The Storm
Water and Surface Drainage Rate will increase 2.9% to reflect the annual CPI change, and the
Storm Drain Rate can be found as Attachment S. See Staff Report #90746 for more information.
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Dark Fiber
Since 2007, the EDF-1 and EDF-2 rates for Dark Fiber (Attachment U) customers have increased
annually by the annual December change in the Consumer Price Index for All Urban Consumers
(CPI-U) in the San Francisco area, as stated in their dark fiber contract agreements. Based on
prior Utilities Advisory Committee and City Council direction, these rate changes are routinely
included as part of the Budget adoption process and rather than in a separate staff report. This
year’s change in CPI-U was 2.9%, as reported by the Bureau of Labor Statistics.
Timeline
Water and Wastewater Collection Rates
After the June 11 Public Hearing is opened and testimony from members of the public
accepted, City Council may choose to:
1. Close the hearing and take action; or
2. Close the hearing and defer action until the Budget Adoption Hearing on June 18th; or
3. Continue the hearing until the Budget Adoption Hearing on June 18th, then on the 18th
reconvene the hearing, take any additional water and wastewater collection rate
testimony, close the hearing, and take action.
The latter option has been used in prior years when the Budget Adoption process has spanned
multiple City Council meetings. It is customary in such circumstances to continue to accept
written protests up until the hearing is closed. Unless written protests are filed by a majority of
affected water and wastewater customers, Council may vote on the proposed rate actions. If
approved, the water and wastewater rates would become effective July 1, 2018.
Electric, Gas, Dark Fiber and Storm Drain rates, as well as Utility Financial Plans
The written majority protest process described above is set forth by the California Constitution
and applies to changes to the City’s water and refuse rates. The electric, gas, dark fiber and
storm drain rates and plans are will also be considered at the June 11, 2018 public hearing.
Should the City Council take action to approve any or all of these rates or plans, they will
become effective July 1, 2018.
Resource Impact
Resource impacts related to the proposed Water, Wastewater Collections, Electric, Gas, Dark
Fiber, and Storm Drain rate actions are detailed fully in the attached Finance Committee
reports and are in alignment with assumptions used in the development of the FY 2019 budget
that is to be considered by the City Council on June 18, 2018.
Policy Implications
Policy Implications related to the proposed Water, Wastewater Collections, Electric and Gas
rate actions are detailed fully in the linked Finance Committee reports.
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There are no policy changes contained in the adoption of the proposed new Dark Fiber and
Storm Drain Rates.
Environmental Review
Adoption of the attached Financial Plans and budgeted transfers does not meet the California
Environmental Quality Act’s definition of a project, pursuant to Public Resources Code Section
21065 and CEQA Guidelines Section 15378(b)(4) and (5), because it is a governmental fiscal and
administrative activity which will not cause a direct or indirect physical change in the
environment. Adoption of the proposed electric, gas, water, wastewater collection and dark
fiber rates to meet operating expenses, purchase supplies and materials, meet financial reserve
needs and obtain funds for capital improvements necessary to maintain service is not subject to
the California Environmental Quality Act (CEQA), pursuant to California Public Resources Code
Sec. 21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After
reviewing the staff report and all attachments presented to Council, the Council incorporates
these documents herein and finds that sufficient evidence has been presented setting forth
with specificity the basis for this claim of CEQA exemption.
Attachments:
Attachment A: Resolution Approving FY 2019 Electric Utility Financial Plan
Attachment B: FY 2019 Electric Utility Financial Plan
Attachment C: Proposed Changes to Electric Utility Reserve Policies
Attachment D: Resolution Amending Electric Utility Rates Effective FY 2019
Attachment E: Amended Electric 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: Resolution Approving FY 2019 Gas Utility Financial Plan
Attachment G: FY 2019 Gas Utility Financial Plan
Attachment H: Resolution Amending Gas Rates Utility for FY 2019
Attachment I: FY 2019 Amended Gas Rate Schedules G-1, G-2, G-3 and G-10
Attachment J: Resolution Approving FY 2019 Wastewater Collection Utility Financial Plan
Attachment K: FY 2019 Wastewater Collection Financial Plan
Attachment L: Resolution Amending FY 2019 Wastewater Collection Rates
Attachment M: Amended Wastewater Collection Rate Schedules S-1, S-2, S-6 and S-7
Attachment N: Resolution Adopting FY 2019 Water Financial Plan
Attachment O: Amended FY 2019 Water Utility Financial Plan
Attachment P: Resolution Adopting Water Rates Effective July 1, 2018
Attachment Q: Amended Water Rates W-1, W-2, W-3, W-4 and W-7
Attachment R: Resolution Amending Utilty Rate Schedule for Storm Surface Water
Attachment S: Amended General Storm and Surface Water Drainage Rate Schedule
Attachment T: Resolution Amending Dark Fiber Rates
Attachment U: Amended Dark Fiber Rate Schedules EDF-1 and EDF-2
Attachment V: Citizen Email Regarding Rate Changes
Attachment A
* NOT YET APPROVED *
6055013
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2019 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 2019 Electric Utility Financial Plan.
SECTION 2. The Council hereby approves the amended Electric Utility Reserves
Management Practices included in the FY 2019 Electric Utility Financial Plan.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
the California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental review is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
Attachment A
* NOT YET APPROVED *
6055013
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2019 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
ATTACHMENT B
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FY 2019 ELECTRIC UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2019 Rate and Reserves Proposals ....................................................... 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3C: Reserves Management Practices .............................................................................. 7
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................... 9
Section 4A: Electric Utility History ............................................................................................... 9
Section 4B: Customer Base ........................................................................................................ 11
Section 4C: Distribution System ................................................................................................. 11
Section 4D: Cost Structure and Revenue Sources ...................................................................... 12
Section 4E: Reserves Structure ................................................................................................... 13
Section 4F: Competitiveness ...................................................................................................... 14
Section 5: Utility Financial Projections ................................................................................. 15
Section 5A: Load Forecast .......................................................................................................... 15
Section 5B: FY 2013 to FY 2017 Cost and Revenue Trends ........................................................ 17
Section 5C: FY 2017 Results ....................................................................................................... 18
Section 5D: FY 2018 Projections ................................................................................................ 19
Section 5E: FY 2019 – FY 2028 Projections ................................................................................ 19
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Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 21
Section 5G: Long-Term Outlook ................................................................................................. 26
Section 6: Details and Assumptions ..................................................................................... 29
Section 6A: Electricity Purchases ............................................................................................... 29
Section 6B: Operations .............................................................................................................. 31
Section 6C: Capital Improvement Program (CIP) ....................................................................... 32
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 ......................................................................................................................... 37
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 38
Appendix B: Electric Utility Reserves Management Practices ................................................... 42
Appendix C: Description of Electric utility Operational Activities .............................................. 47
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 48
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SECTION 1: DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a
section of the distribution system operates. The transmission system operates at
115-500 kV, and this is lowered to 60 kV in the sub-transmission section of the
Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution
system, and finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum
electricity demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Sub-transmission System: The section of the Electric Utility’s distribution system that operates
at 60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115
kV or more. The voltage at the intersection of the Electric Utility’s distribution system
and PG&E’s transmission system is 115 kV. The Electric Utility does not own or
operate any transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
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SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’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 above average capital
investment costs in the short term.
Table 1: Electric Utility Expenses for FY 2017 to FY 2028
Expenses
($000)
FY 2017
(act.)
FY 2018
(est.)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Power Supply
Purchases 80,467 83,506 91,925 94,233 95,111 98,655 98,668 99,059 102,252 103,535 103,178 106,193
Operations 53,034 53,881 54,757 56,293 57,053 57,839 59,600 60,146 56,720 57,677 58,660 59,668
Capital
Projects 11,558 20,961 22,684 18,287 20,097 13,632 14,011 14,400 14,800 15,211 15,633 16,068
TOTAL 145,060 158,348 169,366 168,812 172,261 170,126 172,279 173,605 173,772 176,422 177,471 181,929
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
slightly higher over the forecast period than last year primarily due to lower actual and
projected sales, increases to transmission cost projections and increases to capital investment
spending.
Table 2: Projected Electric Rates, FY 2019 to FY 2028
Projection FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Current 6% 3% 2% 0% 1% 1% 1% 1% 1% 1%
Last Year 7% 0% 0% 1% 2% 1% 1% 1% 1% 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
also projected to be transferred from the Electric Special Projects (ESP) Reserve, and Council
approved the withdrawal of $10 million as part of the FY 2018 Electric Financial Plan. Any
transfers from the ESP Reserve require Council approval. Council also approved using all
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remaining funds ($11.2 million) from the Hydro Stabilization Reserve, but ending reserves show
that only $1 million is warranted at this point.
Table 3: Reserves Transfers for FY 2018 to FY 2028 ($000)
Reserve FY 2018 FY 2019 FY 2020 to FY 2028
Supply Reserves
Electric Special Projects (6,000) (771) (1,780)
Hydro Stabilization (1,000) - -
Supply Rate Stabilization (9,011) - -
Supply Operations 8,163
Distribution Reserves
Capital Improvement Program - - -
Distribution Operations 7,848 771 1,780
*
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2019:
1. Increase rates effective July 1, 2018 for a 6% increase in system average rates.
2. Approve a transfer of up to $771,000 from the Electric Special Projects Reserve for
Smart Grid related funding.
SECTION 3: DETAIL OF FY 2019 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 City adopted the current rates effective July 1, 2017, when CPAU increased electric rates by
14%. Table 4, below, summarizes the current and proposed rates for the four largest customer
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
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classes. The Electric Utility also has specialty rates for smaller groups of customers. These
include variations on its primary rates, such as time of use rates and solar net metering. Staff
proposes a 6% overall increase in revenue. Different customer classes may see different
percentage changes to their rates, based upon their usage of the system and cost to serve each
group.
Table 4: Current and Proposed Electric Rates
Current Rates
Proposed Rates
(7/1/18)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.12159 0.12871 0.00711 5.8%
Tier 2 Energy ($/kWh) 0.19001 0.19279 0.00277 1.5%
Minimum Bill ($/day) 0.2938 0.3040 0.0102 3.5%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.18885 0.20090 001205 6.4%
Winter Energy ($/kWh) 0.13267 0.13861 0.00594 4.5%
Minimum Bill ($/day) 0.7328 0.7740 0.0412 5.6%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.11673 0.12081 0.00408 3.5%
Winter Energy ($/kWh) 0.08890 0.09297 0.00407 4.6%
Summer Demand ($/kW) 21.05 24.11 3.06 14.5%
Winter Demand ($/kW) 15.36 18.52 3.16 20.6%
Minimum Bill ($/day) 14.8414 15.9946 1.1532 7.8%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.09802 0.10507 0.00705 7.2%
Winter Energy ($/kWh) 0.07188 0.07449 0.00261 3.6%
Summer Demand ($/kW) 23.84 26.77 2.93 12.3%
Winter Demand ($/kW) 15.59 17.01 1.42 9.1%
Minimum Bill ($/day) 42.3648 45.4758 3.111 7.3%
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
This financial plan proposes a change to Section 7 of the Electric Utility Reserves Management
Practices (See Appendix B: Electric Utility Reserves Management Practices), detailing a
procedure for calculating the amount of funds to transfer to or from the Hydroelectric
Stabilization Reserve.
8 | Page
SECTION 3D: PROPOSED RESERVE TRANSFERS
In the FY 2018 Electric Financial Plan, Council approved several proposed transfers for FY 2017
and FY 2018:
• Transfer up to $911 thousand from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve.
• Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offset
potential costs associated with low hydroelectric generation.
• 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.
• 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.
Ending reserve balances for FY 2017 were higher than projected. Because of this, and to keep
some funds in the Hydroelectric Stabilization Reserve in case of drought, staff only projects that
$1 million will need to be transferred out of the Hydroelectric Stabilization Reserve in FY 2018.
The Electric Special Projects (ESP) reserve in future years shows additional transfers of $2.5
million, to help cover the upgrade of the Electric metering system to AMI. This item has been
discussed in prior years as a possible project to be funded from the ESP.
Proposed transfers for FY 2019 will not be requested by resolution at this time, but will be
requested as part of FY 2019 year-end should ending reserve balances require it.
Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E:
FY 2019 – FY 2028 Projections show the impact of these transfers on reserves levels. Table 5
shows the projected balance of each of the Electric Utility reserves for the period covered by
this Financial Plan. See also: Appendix A: Electric Utility Financial Forecast Detail
Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2017 to FY 2028
Ending Reserve
Balance ($000)
FY 2017
(Act.)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Re-appropriations - - - - - - - - - - - -
Commitments 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971
Underground Loan 730 730 730 730 730 730 730 730 730 730 730 730
Public Benefits 681 - - - - - - - - - - -
Special Projects 51,838 45,838 45,067 42,757 43,247 42,847 42,847 42,847 42,847 42,847 42,847 42,847
Hydro Stabilization 11,400 10,400 10,400 10,400 10,400 13,900 13,900 13,900 13,900 13,900 13,900 13,900
Capital 880 880 880 880 880 880 880 880 880 880 880 880
Rate Stabilization 9,011 - - - - - - - - - - -
Operations 29,913 37,884 32,054 33,249 39,138 38,837 39,720 41,255 44,073 46,167 49,328 49,864
Unassigned - - - - - - - - - - - -
TOTAL 107,424 98,703 92,101 92,987 97,366 100,164 101,048 102,583 105,401 107,495 110,656 111,192
9 | Page
SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4A: ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel
engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity
continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E
proved more economical than the diesel engines, and by the late 1920s CPAU was using its own
diesel engines only during peak demand periods. At that time CPAU owned 45 miles of
distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual
consumption. The diesel engines remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did
throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the
sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto,
which doubled the number of customers. Some was related to the proliferation of electric
appliances, as evidenced by the fact that residential customers were using three times more
electricity in 1970 than they had been in 1950. But the most notable factor was the growth of
industry in Palo Alto during that time. By 1970, commercial customers were using 20 times
more electricity per 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
10 | Page
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement
program for its underground system in the early 1990s.
In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and
in 1996 the State legislature passed Assembly Bill 1890, which, among other things, created the
California Independent System Operator (CAISO) to operate the transmission system and the
Power Exchange to facilitate wholesale energy transactions. This restructuring was anticipated
to bring lower costs to consumers, and while CPAU was not required to participate in the
industry restructuring, in 1997 the Council approved a Direct Access Program for the Electric
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 manage its supply portfolio. CPAU began
purchasing power from marketers and also investigated building a power plant in Palo Alto or
partnering in the development of a gas-fired power plant elsewhere. Climate change was also
becoming more of a concern to the community, and gradually CPAU shifted its focus to the
procurement of renewable energy. In 2002 CPAU adopted a goal of achieving 20% of its energy
supply from renewables by 2015. Subsequently CPAU signed its first contract for renewable
power, a contract for energy from a wind generator commencing deliveries in 2005. In 2011 the
renewable energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a
plan to make its electric supply 100% carbon neutral, which it achieves through the
combination of its carbon-free hydroelectric supplies, purchases of long-term renewable energy
supplies, and short-term renewable energy purchases (RECs) to meet the balance of its needs.
2 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
11 | Page
Figure 1: Customer Consumption By Class (FY 2017)
16%
6%
36%
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 29,600 customers
connected to the electric system,
25,550 (86%) of which are residential
and 4,050 (14%) of which are non-
residential. Residential customers
consumed 147 gigawatt-hours (GWh)
in FY 2017, approximately 16% of the
electricity sold, while non-residential
customers consumed 84% or 771
GWh. Residential customers use
electricity primarily for lighting,
refrigeration, electronics, and air conditioning.3 Non-residential customers use the majority of
their electricity for cooling, ventilation, lighting, office equipment (offices), cooking
(restaurants), and refrigeration (grocery stores).4
As shown in Figure 1 large customer loads represent a large proportion of sales for the Electric
Utility. The proportion of sales to large vs. small customers is greater than for the City’s other
utilities. For example, the largest customers (the 71 customers on the E-7 rate schedule)
account for around 42% of CPAU’s sales. The next largest customer group (the 830 non-
residential customers on the E-4 rate schedule) represents another 36% of sales. In total, that
means that about 3% of customers account for nearly three quarters of the electric load.
SECTION 4C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 472 miles of
distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are
underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line
transformers, around 1,100 underground and substation transformers, and the associated
electric services (which connect the distribution lines to the customers’ homes and businesses).
These lines, substations, transformers, and services, along with their associated poles, meters,
3 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010 4 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
12 | Page
Figure 2: Cost Structure (FY 2017)
55%
37%
8%
Commodity
Supply
Operations
Capital
Figure 4: Hydroelectric Variability (FY 2019)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 3: Revenue Structure (FY 2017)
81%
19%
Sales of Electricity
Other Revenue
and 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 55% of the Electric Utility’s
costs in FY 2017. Operational costs
represented roughly 37%, 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. Staff projects commodity supply costs to be
approximately 56% of total costs in FY 2028.
While average year purchase
costs for the electric utility
are predictable due to its
long-term contracts,
variability in hydroelectric
generation can result in
increased or decreased
costs. This is by far the
largest source of variability
the utility faces. Figure 3
shows the difference in costs
under high, projected, and
low hydroelectric generation scenarios
for FY 2019. Additional costs associated
with a very low generation scenario can
range from $9-11 million per year. For
the current hydroelectric risk assessment
see Section 5F: Risk Assessment and
Reserves Adequacy.
As shown in Figure 4 the Electric Utility
receives 81% of its revenue from sales of
electricity and the remainder from
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connection fees, interest on reserves, cost recovery transfers from other funds for shared
services provided by the electric utility, and other sources. Some revenue sources are primarily
accounting entries that reflect things such as CPAU’s participation in a pre-funding program
associated with its contract with WAPA, as well as accounting entries associated with
occasional sales of surplus hydroelectric energy during wet years. Appendix A: Electric Utility
Financial Forecast Detail shows more detail on the utility’s cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 900 largest customers, which provide a similar share of the utility’s revenue stream.
The utility’s retail rate schedules have no fixed charges, although about 24% of the utility’s
revenue comes from peak demand charges on large non-residential customers. Due to
moderate weather and the prevalence of natural gas heating, however, loads (and therefore
revenues) are very stable for this utility, without the large seasonal air conditioning or winter
heating loads seen at some other utilities.
SECTION 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. The
City established this separation of supply and distribution costs as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) in the late 1990s and
early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues to
maintain separate funds to facilitate separation of supply and distribution costs in the rates.
This could be important if California ever decides to broadly reintroduce Direct Access, and may
also be useful for rate design as the nature of utility services evolves in response to higher
penetrations of distributed generation.
The summary below describes the various reserves, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserves for Commitments: Reserves equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserves for Reappropriations: Reserves for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve. This is currently an important
reserve for all utility funds, but changes in budgeting practices will change that in future
years, as described in Section 3C (Reserves Management Practices).
• Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which was accumulated during deregulation of California’s electric system to
fund the stranded costs associated primarily with the Calaveras hydroelectric resource
and the California-Oregon Transmission Project. When that reserve was no longer
needed for that purpose, the reserve was renamed and the purpose was changed to
14 | Page
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 2017 was
$589.02 under current CPAU rates, 38% lower than the annual bill for a PG&E customer with
the same consumption and approximately 12% higher than the annual bill for a City of Santa
Clara customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X,
which includes most surrounding comparison communities.
Table 6 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara
(Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown
below were in effect as of March 1, 2018.
15 | Page
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, 2018 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 3/1/18, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(March)
300 36.48 63.51 35.18
453 (Median) 63.50 104.49 53.78
650 100.93 159.64 77.73
1200 205.45 313.60 144.59
Summer
(July)
300 36.48 63.51 35.18
(Median) 330 40.12 71.70 38.83
650 100.93 161.28 77.73
1200 205.45 315.24 144.59
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 (3/1/18, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 161 245 181
160,000 23,732 30,413 20,850
500,000 62,190 83,820 62,956
2,000,000 268,475 361,753 256,247
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 5 shows a 33-year history of Palo Alto electricity consumption. Average electricity
consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then
electricity consumption has declined slowly as a result of a continuing focus on energy
efficiency, as well as the adoption of more stringent appliance efficiency standards and energy
standards in building codes.
16 | Page
Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2028. 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.
17 | Page
Figure 6: Forecasted Electricity Consumption
SECTION 5B: FY 2013 TO FY 2017 COST AND REVENUE TRENDS
The annual expenses for the Electric Utility remained fairly stable between FY 2013 and FY
2017, as shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail
Section 6A: Electricity Purchases discusses the factors influencing Electric Utility expenses. Since
FY 2012, total expenses for the utility have included the costs of renewable resources coming
online. In FY 2014 through FY 2015 commodity costs were higher due to lower than average
output from hydroelectric resources.
Commodity costs and capital investments are responsible for most of the changes in the
utility’s expenses over the last six years. Operational costs decreased during that time but will
increase once staffing levels return to normal levels.
Actual Projection
18 | Page
Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2017 and Projections through FY 2028
SECTION 5C: FY 2017 RESULTS
Total cost of purchasing electricity was lower than the forecast by approximately $3.9 million.
Capital improvement costs were lower than the forecasted level by $9.9 million. Sales revenues
were higher than the forecast by $2.9 million, but there was also $4.8 million in surplus sales
revenue beyond what was budgeted. While net revenues were still lower than cost by $3
million, the net reserve withdrawal was lower than originally anticipated ($25 million). The
lower withdrawal in FY 2017 will allow for reserves to be used in future years.
19 | Page
Table 8 FY 2017, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues higher than forecast $(2,881) Revenue increase
Wholesale and other revenues higher than
forecast
(5,978) Revenue increase
Lower capital improvement costs (9,932) Cost decrease
Lower purchased electricity costs (3,904) Cost decrease
Higher operations costs 344 Cost increase
Net Cost / (Benefit) of Variances $(22,352)
SECTION 5D: FY 2018 PROJECTIONS
Last year, staff recommended (and Council approved) a 14% rate change for July 1, 2017, the
start of FY 2018. Current sales revenue projections for 2018 are roughly $1.5 million higher than
expected in last year’s financial plan. Based on current hydro conditions, wholesale costs are
again expected to contribute to other revenues being higher by $5.5 million. Purchased
electricity cost projections for 2018 are anticipated to be $4.5 million lower than in last year’s
financial plan. However, capital cost estimates and operations cost estimates (which includes
other than purchased electricity costs) increased by $5.3 million and $3.8 million, respectively.
Table 9 FY 2018, Change in Projected Results, 2018 Forecast vs. 2019 Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues (1,454) Revenue increase
Wholesale and other revenues higher than
forecast
(5,476) Revenue increase
Capital improvement costs 5,388 cost increase
Purchased electricity costs (4,481) cost decrease
Operations costs 3,848 cost increase
Net Cost / (Benefit) of Variances $2,175
SECTION 5E: FY 2019 – FY 2028 PROJECTIONS
As shown in Figure 7 above, staff projects costs for the Electric Utility to increase at a fairly
steady rate through the forecast period. Revenue increases of 6% in FY 2019 and another 3% in
FY 2020 are projected to bring revenues in line with expenses. Rising electricity purchase costs
are the primary contributor to the increases. Electricity purchase costs have increased
substantially since FY 2013 as new renewable projects have come online to fulfill the City’s
environmental goals, and as transmission costs have increased due to improvements being
made to the California grid. Operations costs are expected to increase at or near the inflation
rate (2-4 %/year) through the forecast period. Projected capital expenses for FY 2018 through
FY 2023 are higher in FY 2018 through FY 2021 due to work on the Upgrade Downtown project,
as well as anticipated AMI and smart grid implementation. Once these larger, one-time project
20 | Page
cost increases are completed, annual CIPs are anticipated to decline back to levels seen in
recent years. 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 2018.
Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2017 and Projections through FY 2028
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Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2017 and Projections through FY 2028
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 above the reserve
minimum for the Distribution Operations Reserve throughout the forecast period. Reserve
levels also exceed the short-term risk assessment level for the Distribution Fund. The Supply
Operations Reserve, however, 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 10. Because
of the high range of uncertainty in energy price predictions more than three years in the future,
this risk assessment is only performed for the first two fiscal years of the forecast period. It is
important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 10 is very low.
22 | Page
Table 10: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2019 FY 2020
1. Production from Hydroelectric
Resources: Western 6.8 6.2 Lower than forecasted hydro
2. Production from Hydroelectric
Resources: Calaveras 3.3 2.6 Lower than forecasted hydro
3. Market Price (Energy) 2.2 0.8 Higher than forecasted market prices for
energy
4. Transmission/CAISO 3.3 3.3 High-end transmission forecast scenario
5. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
6. Western Cost 3.5 3.5 Risk of rate adjustments from Western
7. Regulatory and Legal 0.0 0.0 Risks associated with legislative uncertainties
Electric Supply Fund Risks $19.9
million
$17.4
million
Projected Supply Operations +
Hydro Stabilization Reserve
Levels
$65.6
million
$65.8
million
Of the risks faced by the Electric Utility’s Supply Fund in FY 2019, 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.
Of the remaining risks for FY 2019, $3.3 million is related to the projected costs if transmission
cost increases are higher than staff’s current forecast. $3.5 million is related to the uncertainty
to Western’s rates for Restoration costs.
As shown in Figure 10, the Supply Operations Reserve was below the minimum reserve
guidelines at the end of FY 2017. However, through reserve transfers and rate increases, staff
projects the Supply Operations Reserve to stay within the reserve guideline levels throughout
the forecast period. Figure 11 shows that the combined Hydro Stabilization and Supply
Operations Reserves are projected to be above what is needed for the risk assessment level.
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Figure 10: Electric Supply Operations Reserve Adequacy
24 | Page
Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 11 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2023. As shown in Figure 12, the Distribution Operations Reserve will stay within the
reserve guidelines over the course of the forecast period, although it was recorded below the
minimum reserve guidelines at the end of FY 2017. The risk assessment includes the revenue
shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 11: Electric Distribution Fund Risk Assessment ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Total non-commodity revenue $49,608 $49,928 $49,744 $50,068 $50,895
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $3,915 $3,941 $3,926 $3,952 $4,017
CIP Budget $22,684 $18,287 $20,097 $13,632 $14,011
CIP Contingency @10% $2,268 $1,829 $2,010 $1,363 $1,401
Total Risk Assessment value $6,184 $5,769 $5,936 $5,315 $5,418
25 | Page
Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, staff projects the CIP Reserve to be above the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels, CIP Commitments are nearly impossible to project that far out, and
adjustments to the reserve can be made in future years.
26 | Page
Figure 13: Electric CIP Reserve Adequacy
SECTION 5G: LONG-TERM OUTLOOK
This forecast covers the period from FY 2019 through FY 2028, 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
27 | Page
2021 and the last in 2028. These three contracts, plus one more expiring in 2030, currently
provide 17% to 18% of the energy for the utility’s supply portfolio at prices under $65 per
megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those
contracts expire. Although recent prices have been in that range (or even lower), and costs
may decrease in the future, current renewable projects also benefit from a wide range of tax
and other incentives that may or may not be available in the 2020s and beyond. However, staff
is in the process of procuring a replacement for the contract expiring in 2021 at a lower price
than any of the City’s current renewable contracts.
The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs
dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032
(assuming the Utility does not issue any new debt). The project will only be 40 years old at that
time. Calaveras debt service represents roughly 70% of the annual costs of that project (and
nearly 7% of the utility’s total costs), so when the debt is retired, the project could be a low-
cost asset for the utility, providing carbon-free energy equal to around 13% of the Electric
Utility’s supply needs in an average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to 5 million per year in revenue from
allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to
pay for energy efficiency programs and to purchase renewable energy to support the utility’s
Carbon Neutral Plan. Staff expects that revenue source to continue through 2020. However,
discussions at the state level are ongoing and will determine whether or not these allocations
continue past 2020, as well as any restrictions CARB may wish to enact on usage of allocation
sales revenues. If the Electric Utility no longer received these allowances or was limited in how
it could spend revenues, it would have to fund these programs from sales revenues.
Transmission costs are also continuing to rise. If the State continues to increase mandates or
incentives for renewable energy development, integrating these new projects into the
transmission grid will be an ever increasing challenge, some costs of which will be borne by Palo
Alto. The planned expansion of the CAISO to a larger regional grid control area may result in
additional transmission costs that could further increase CPAU’s transmission costs. In addition
to the costs of new transmission lines that will need to be built, flexible resources will be
required to balance rapid changes in wind or solar output throughout the day. Palo Alto will
likely bear some of the costs of these new lines and resources. CPAU is also currently
investigating installing a second transmission interconnection for Palo Alto, which could be
funded by the Electric Special Projects Reserve.
Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these
factors may begin to create notable increases in electric consumption and have a variety of
impacts on the distribution system. As housing stock is turned over, however, stricter building
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codes may help to counteract load growth, as may increasing numbers of rooftop solar
installations. The utility has already started to take some of these factors into account in its
long-term planning processes, but will need to 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. Staff are
undertaking initial analysis of these types of scenarios in the context of the Sustainability and
Climate Action Plan (S/CAP) development process. These types of scenarios require careful
planning for the associated load growth to make sure the distribution system does not end up
overloaded, or conversely, to avoid over investment, and the evaluation of changes to utility
distribution system management to accommodate integration of the various 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 50% in FY 2017. Staff expects contracts with
renewable sources to continue at approximately 50% of the portfolio for the forecast period.
The remainder comes from unspecified market sources. Under the City’s Carbon Neutral Plan,
CPAU purchases RECs corresponding to the amount of market energy it purchases.
Figure 12: 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, and FY 2017 and FY 2018 had lower hydroelectric costs. Increases in renewable
energy costs are expected 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 $85 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 13: 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 2013 to FY 2017, Operations costs stayed relatively flat. In 2013 there was a one-time
increase in expenses associated with an adjustment to the value of the City’s investment
portfolio. Debt service and transfers costs increase (reflecting transfers in from the ESP
reserve). However, over the forecast horizon, excluding debt service and transfers, staff project
costs to increase by roughly 2-3% per year.
Figure 14: Historical and Projected Electric Utility Operational Costs
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SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
Staff projects CIP spending for FY 2019 through FY 2024 to be consistent with last year’s
forecast, though there is a slight shift in the funding by project category. There will be a
reduction in capital cost and revenue related to the VA Hospital project as the VA will be
responsible for the installation, and associated costs, of electric facilities; there will be a
reduction in funding for Undergrounding as current projects are completed; there will be an
increase in funding for Underground Rebuilding and 4/12kV Conversion as improvements are
made to the system in portions of the Crescent Park/Duveneck/St. Francis/Community
Center/Leland Manor/Garland neighborhoods to facilitate rebuild of the Hopkins Substation;
and increase in funding for replacement of distribution system and substation facilities that are
at the end of their useful life. Other significant projects still slated to continue are deteriorated
wood pole replacements, pole relocations to facilitate the Caltrain Railway Electrification
project, Smart Grid upgrades, and ongoing capital investment in the electric distribution system
to maintain/improve reliability. This forecast assumes that the utility finances smart grid
projects from the Electric Special Projects Reserve and with additional funding from the water
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 2019 to FY 2023 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 2019 Utilities
Capital Budget. Figure 17 shows the FY 2018 projected budget and the five year CIP spending
plan, although these figures are preliminary pending budget discussions starting in May. The
‘committed’ column represents funds committed to contracts for which work has not yet been
completed or invoices paid.
Figure 15: Electric Utility CIP Spending ($000)
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
One-Time Projects 5,021 (128) 4,893 123 1,400 1,300 10,750 5,000 5,000
System Expansion 3,507 (27) 3,481 - - - - - -
Reliability 3,711 (129) 3,582 153 1,067 317 150 - -
Undergrounding 4,395 (40) 4,355 353 900 - 2,000 2,250 500
4/12 Kv Conversion 270 (1) 269 - - 1,750 800 - -
Underground Rebuilding 3,385 (3) 3,382 3 - 2,656 1,500 350 350
Ongoing Projects 6,714 (882) 5,832 3,255 3,145 3,625 3,280 3,280 3,230
Customer Connections
(Fee Funded)4,087 (1,149) 2,938 589 3,220 3,336 3,456 3,580 3,600
TOTAL 31,091 (2,359) 28,732 4,476 9,732 12,984 21,936 14,460 12,680
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year.
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
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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, the Electric Utility receives the RECs from
these projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are
interest free (the investors receive a tax credit from the federal government). This bond
issuance is secured by the net revenues of the Electric Utility. Debt service for this bond
continues through 2021, and for the financial forecast period is as follows:
Table 11: Electric Utility Debt Service ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2007 Clean Renewable
Energy Bonds 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 also pledges reserves and net revenue as security for the bond issuances
listed in Table 13, even though the Electric Utility is not responsible for the debt service
payments. The Electric Utility’s reserves or net revenues would only be called upon if the
responsible utilities are unable to make their debt service payments. Staff does not currently
foresee this occurring.
Table 12: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Electric Utility’s:
Net Revenues Reserves
1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water $1,457 No Yes
*Net of Federal interest subsidy
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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 19% comes
from other sources. Of these other sources, about 50 to 60% represents wholesale revenues of
surplus energy sales included solely for accounting purposes. These revenues have offsetting
electric supply purchase costs, and do not normally affect the utility’s net position. Of the
remaining revenues, the largest revenue sources are interest on reserves, connection fees for
new or replacement electric services, and carbon allowance revenues associated with the
State’s cap-and-trade program. In FY 2017 these sources represented roughly 28% of revenue
from sources other than electricity sales. The remaining FY 2017 revenues consisted of a variety
of one-time transfers.
Revenues from connection fees have increased since FY 2009 varying from year to year.
Revenue from connection fees decreased slightly during the recession, but has increased
substantially since then, peaking in FY 2016 and declining somewhat in FY 2017. Staff forecasts
slightly higher revenue from this source in 2018 through 2021 with revenue leveling out in
subsequent years.
Staff projects carbon allowance and interest income revenues to stay relatively stable through
the forecast period. However, both of these revenue sources are subject to some uncertainty.
The State’s cap-and-trade program regulations only describe the program through 2020. This
forecast assumes the program will remain in place with similar program design following 2020,
but that may not be the case. CARB is in the process of establishing post-2020 rules.
The forecast for interest income assumes current interest rates continue and there are no
major reserve reductions aside from what is anticipated in this Financial Plan. If interest rates
rise, interest income could increase, and if reserves decrease (due to drought or a withdrawal
from the ESP reserve for a major project), interest income would decrease.
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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SECTION 6G: SALES REVENUES
The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7
provide the basis for sales revenue projections. As discussed in Section 5A, sales revenues for
this utility stay relatively stable due to the mild climate in Palo Alto. 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
The FY 2019 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. 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.
In FY 2019, CPAU is proposing a nine percent 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 will be necessary in FY 2018 and again in FY 2019, as
these reserves drop below the reserve target level. Communications will focus on the reasons
why a rate increase is necessary, due to an increase in transmission fees and new renewable
projects coming online, rising operating and capital costs, and how drought affected the City’s
reserves. Palo Alto purchases a significant portion of its electricity from hydroelectric resources.
Several-year drought conditions reduced available hydroelectric supplies, requiring the City to
purchase more costly replacement electric supplies. Since the State may not received a great
deal of precipitation in the latter part of FY 2018, communications staff will now focus
messaging on how increased hydroelectric supplies could still impact and potentially change the
forecast for electric rates moving forward, at least in the short-term.
Despite these costs and increasing rates, CPAU’s electric utility 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 environmental benefits of the City’s carbon
neutral electric supply portfolio. Outreach includes apprising the public of major renewable
energy purchase agreements, which contribute toward Palo Alto’s long-term energy security
and commitment to sustainability. 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, staff expect these higher costs 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 promote CPAU’s electric efficiency services, rebates
and local renewable energy programs. Within the past few years, CPAU has launched new
programs that allow customers to better understand and manage their energy use. Programs
such as the Home Efficiency Genie and commercial energy efficiency programs help residents
and businesses better understand energy usage, activities and/or upgrades they can implement
to improve efficiency and reduce utility costs. CPAU will be launching an upgraded version of its
online utility account services portal (www.cityofpaloalto.org/myutilitiesaccount) this year,
which can provide customers with direct access and more information about utility account and
consumption data.
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APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
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APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
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1 FISCAL YEAR 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 FY 2028
2
3 ELECTRIC LOAD
4 Purchases (MWh)976,319 980,894 979,005 977,292 945,703 939,991 943,995 940,694 937,221 933,569 931,545 930,263 930,117 929,943 930,376 930,646
5 Sales (MWh)946,841 950,784 936,773 937,157 917,687 909,595 910,883 907,697 904,346 900,823 898,869 897,632 897,492 897,324 897,742 898,002
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1154$ 0.1164$ 0.1158$ 0.1156$ 0.1249$ 0.1421$ 0.1513$ 0.1557$ 0.1593$ 0.1598$ 0.1609$ 0.1625$ 0.1634$ 0.1650$ 0.1666$ 0.1683$
9 Change in System Average Rate 0%1%0%0%10%14%6%3%2%0%1%1%1%1%1%1%
10 Change in Average Residential Bill -4%-1%-5%3%11%11%6%2%2%0%0%1%0%1%1%1%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)1,886,000 305,000 - - - - - - - - - - - - - -
14 Commitments (Non-CIP)2,737,000 3,528,000 3,164,000 3,102,055 3,777,205 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955
15 Restricted for Debt Service - - - - - - - - - - - - - - - -
16 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - - -
17 Central Valley Project Reserve 314,000 313,000 329,000 - - - - - - - - - - - - -
18 Underground Loan Reserve 742,000 738,000 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147
19 Public Benefits Reserves 1,149,000 2,197,000 2,064,000 2,574,000 1,839,000 681,330 - - - - - - - - - -
20 Electric Special Projects Reserve 50,320,000 51,838,000 51,838,000 51,837,855 51,837,855 51,837,855 45,837,855 45,066,855 44,756,855 43,246,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855
21 Hydro Stabilization Reserve - - - 17,000,000 11,400,000 11,400,000 10,400,000 10,400,000 10,400,000 10,400,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000
22 Capital Reserves - - - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964
23 Rate Stabilization Reserves 74,609,000 69,029,000 70,049,000 14,410,840 9,010,840 9,010,840 - - - - - - - - - -
24 Operations Reserves - - - 22,497,607 21,850,187 29,912,981 37,884,461 32,053,564 33,249,194 39,138,346 38,836,530 39,719,824 41,254,722 44,072,659 46,167,305 49,327,672
25 Unassigned - - - - - - - - - - - - - - - -
26 TOTAL STARTING RESERVES 132,757,000 128,948,000 129,178,000 112,152,357 100,444,086 107,424,072 98,703,382 92,101,485 92,987,115 97,366,267 100,164,451 101,047,745 102,582,643 105,400,580 107,495,226 110,655,593
27
28 REVENUES
29 Net Sales 109,974,337 110,246,264 108,873,377 108,312,917 114,624,726 129,258,435 137,836,311 141,304,121 144,032,395 143,988,875 144,612,409 145,833,873 146,687,201 148,083,859 149,581,682 151,104,314
30 Wholesale Revenues 6,635,790 6,010,409 6,267,000 4,301,366 16,188,920 18,115,996 13,718,260 14,366,366 16,106,798 17,749,617 17,407,062 17,763,941 17,932,747 18,052,704 18,231,927 18,351,535
31 Other Revenues and Transfers In 9,624,213 13,669,185 9,688,480 11,714,494 11,225,911 13,776,378 12,781,199 15,649,312 18,168,427 12,895,834 12,896,707 13,341,185 13,815,444 14,273,124 14,759,484 15,001,446
32 TOTAL REVENUES 126,234,340 129,925,858 124,828,858 124,328,776 142,039,557 161,150,809 164,335,770 171,319,799 178,307,620 174,634,326 174,916,179 176,938,999 178,435,392 180,409,687 182,573,093 184,457,295
33
34 EXPENSES
35 Electric Supply Purchases 61,313,637 68,785,977 80,022,010 75,705,000 80,467,136 83,505,886 91,924,961 94,232,563 95,111,327 98,655,001 98,667,977 99,059,024 102,252,401 103,534,874 103,178,257 106,193,402
36 Operating Expenses
37 Administration
38 Allocated Charges 4,399,674 4,139,837 4,511,222 4,934,195 3,990,822 4,304,278 4,412,096 4,522,617 4,635,777 4,751,692 4,870,511 4,992,301 5,117,136 5,245,093 5,376,249 5,510,686
39 Rent 3,875,836 4,051,044 4,147,742 4,997,101 5,121,102 5,284,977 5,443,527 5,606,832 5,775,037 5,948,288 6,126,737 6,310,539 6,499,855 6,694,851 6,895,697 7,102,568
40 Debt Service 9,265,736 9,020,651 9,037,000 8,885,994 8,953,893 8,955,166 8,808,619 8,818,349 8,783,507 8,792,388 9,624,493 9,259,612 4,898,677 4,896,047 4,894,784 4,893,296
41 Transfers and Other Adjustments 16,797,054 11,329,973 11,004,636 11,798,865 12,702,945 13,041,626 13,305,787 14,190,505 14,194,567 14,198,730 14,202,997 14,207,370 14,211,853 14,216,448 14,221,158 14,225,986
42 Subtotal, Administration 34,338,299 28,541,506 28,700,600 30,616,155 30,768,762 31,586,048 31,970,028 33,138,304 33,388,889 33,691,098 34,824,738 34,769,822 30,727,521 31,052,439 31,387,888 31,732,535
43 Resource Management 3,024,268 3,541,524 2,138,615 2,083,812 1,985,620 3,446,889 3,569,550 3,697,054 3,806,324 3,905,053 4,007,389 4,112,406 4,220,176 4,330,770 4,444,262 4,560,728
44 Demand Side Management 3,529,529 3,187,875 3,491,470 3,643,924 4,271,786 4,327,895 4,214,985 3,955,387 3,913,776 3,888,167 3,989,346 4,050,076 4,111,910 4,174,870 4,238,976 4,304,249
45 Operations and Mtc 9,601,481 9,488,627 10,716,881 11,523,881 11,811,016 13,349,204 13,790,502 14,247,795 14,653,401 15,030,198 15,419,751 15,819,400 16,229,407 16,650,041 17,081,577 17,524,297
46 Engineering (Operating)1,114,945 1,102,008 1,230,160 1,592,024 1,656,522 1,963,752 2,016,569 2,070,856 2,124,317 2,177,782 2,232,696 2,288,996 2,346,715 2,405,890 2,466,557 2,528,754
47 Customer Service 2,007,322 2,032,231 1,548,851 1,540,884 2,540,424 2,253,647 2,338,475 2,426,869 2,500,743 2,566,062 2,633,909 2,703,550 2,775,032 2,848,403 2,923,715 3,001,018
48 Allowance for Unspent Budget - - - - - (1,523,291) (1,571,660) (1,621,727) (1,667,008) (1,709,687) (1,753,753) (1,798,955) (1,845,322) (1,892,885) (1,941,675) (1,991,722)
49 Subtotal, Operating Expenses 53,615,844 47,893,770 47,826,576 51,000,680 53,034,130 55,404,145 56,328,449 57,914,537 58,720,442 59,548,674 61,354,076 61,945,295 58,565,440 59,569,529 60,601,301 61,659,859
50 Capital Program Contribution 15,113,859 13,016,111 14,005,915 9,331,367 11,558,306 20,961,467 22,684,258 18,287,069 20,096,699 13,632,467 14,010,831 14,399,781 14,799,614 15,210,638 15,633,168 16,067,528
51 TOTAL EXPENSES 130,043,340 129,695,858 141,854,501 136,037,047 145,059,572 159,871,498 170,937,668 170,434,169 173,928,468 171,836,142 174,032,885 175,404,101 175,617,456 178,315,041 179,412,726 183,920,790
52
53 ENDING RESERVES
54 Reappropriations (Non-CIP)305,000 - - - - - - - - - - - - - - -
55 Commitments (Non-CIP)3,528,000 3,164,000 3,102,055 3,777,205 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955
56 Restricted for Debt Service - - - - - - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 1,000,000 - - - - - - - - - - - - - -
58 Central Valley Project Reserve 313,000 329,000 - - - - - - - - - - - - - -
59 Underground Loan Reserve 738,000 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147
60 Public Benefits Reserves 2,197,000 2,064,000 2,574,000 1,839,000 681,330 - - - - - - - - - - -
61 Electric Special Projects Reserve 51,838,000 51,838,000 51,837,855 51,837,855 51,837,855 45,837,855 45,066,855 44,756,855 43,246,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855
62 Hydro Stabilization Reserve - - 17,000,000 11,400,000 11,400,000 10,400,000 10,400,000 10,400,000 10,400,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000
58 Capital Reserve - - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964
59 Rate Stabilization Reserve 69,029,000 70,049,000 14,410,840 9,010,840 9,010,840 - - - - - - - - - - -
60 Operations Reserve - - 22,497,607 21,850,187 29,912,981 37,884,461 32,053,564 33,249,194 39,138,346 38,836,530 39,719,824 41,254,722 44,072,659 46,167,305 49,327,672 49,864,178
61 Unassigned - - - - - - - - - - - - - - - -
62 TOTAL ENDING RESERVES 128,948,000 129,178,000 112,152,357 100,444,086 107,424,072 98,703,382 92,101,485 92,987,115 97,366,267 100,164,451 101,047,745 102,582,643 105,400,580 107,495,226 110,655,593 111,192,099
63
64 OPERATIONS RESERVE
65 Min (60 days of non-capital expenses)23,548,140 23,011,890 25,284,688 26,254,697 27,887,150 28,525,288 28,948,137 29,816,058 30,267,979 30,586,285 30,716,392 31,257,049 31,536,939 32,379,720
66 Target (90 days of non-capital expenses)33,151,752 32,456,285 35,213,317 36,600,046 38,978,736 39,864,186 40,425,168 41,652,081 42,253,107 42,651,788 42,766,200 43,494,415 43,829,410 45,006,620
67 Max (120 days of non-capital expenses)42,755,364 41,900,681 45,141,947 46,945,394 50,070,321 51,203,084 51,902,198 53,488,104 54,238,235 54,717,290 54,816,007 55,731,781 56,121,881 57,633,519
68 Risk Assessment Value 4,645,297 4,193,350 4,338,548 5,838,255 6,183,701 5,769,290 5,935,703 5,314,839 5,417,963 5,563,442 5,671,929 5,824,643 5,981,673 6,143,144
6053706
1 FISCAL YEAR 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 FY 2028
2
3 REVENUES
4 Net Sales 87%85%87%87%81%80%84%82%81%82%83%82%82%82%82%82%
5 Other Revenues and Transfers In 13%15%13%13%19%20%16%18%19%18%17%18%18%18%18%18%
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%52%55%54%42%41%49%50%48%49%49%49%51%51%50%51%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%3%3%4%3%3%3%3%3%3%3%3%3%3%3%3%
13 Rent 3%3%3%4%4%3%3%3%3%3%4%4%4%4%4%4%
14 Debt Service 7%7%6%7%6%6%5%5%5%5%6%5%3%3%3%3%
15 Transfers and Other Adjustments 13%9%8%9%9%8%8%8%8%8%8%8%8%8%8%8%
16 Subtotal, Administration 26%22%20%23%21%20%19%19%19%20%20%20%17%17%17%17%
17 Resource Management 2%3%2%2%1%2%2%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 7%7%8%8%8%8%8%8%8%9%9%9%9%9%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%1%1%2%1%1%1%1%1%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 39%34%31%35%34%32%30%32%32%32%33%33%31%31%31%31%
23 Capital Program Contribution 12%10%10%7%8%13%13%11%12%8%8%8%8%9%9%9%
24 TOTAL EXPENSES 96%97%96%96%83%86%93%92%91%90%90%90%90%90%90%91%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR 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 FY 2028
28 1. Load Net Revenue 77,428 652,853 1,208,477
29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 3,397,119
30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 539,073
31 4. Carbon Neutral Cost 331,630 303,022 114,983
32 5. Market Price 909,196 775,584 1,138,589
33 6. Local Capacity 475,962 408,388 446,695
34 7. Transmission/CAISO 4,555,915 3,741,647 2,806,120
35 8. Plant Outage 1,000,000 1,000,000 1,000,000
36 9. Western Cost 3,130,000 2,704,738 2,973,619
37 10. Regulatory & Legal - - -
38 11. Supplier Default - - -
39 TOTAL 20,170,708 19,380,490 13,624,674
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 196%172%303%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 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 FY 2028
44 Distribution Revenue Variance 3,244,706 3,260,213 3,182,718 3,742,109 3,915,276 3,940,583 3,926,033 3,951,592 4,016,880 4,123,464 4,191,967 4,303,579 4,418,356 4,536,391
45 10% CIP Program Contingency 1,400,592 933,137 1,155,831 2,096,147 2,268,426 1,828,707 2,009,670 1,363,247 1,401,083 1,439,978 1,479,961 1,521,064 1,563,317 1,606,753
46 Total Risk Asssessment Value 4,645,297 4,193,350 4,338,548 5,838,255 6,183,701 5,769,290 5,935,703 5,314,839 5,417,963 5,563,442 5,671,929 5,824,643 5,981,673 6,143,144
47 Projected Operations Reserve 22,497,607 21,850,187 29,912,981 37,884,461 32,053,564 33,249,194 39,138,346 38,836,530 39,719,824 41,254,722 44,072,659 46,167,305 49,327,672 49,864,178
48 Operations Reserve, % of Risk Value 484%521%689%649%518%576%659%731%733%742%777%793%825%812%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- - 15,208,552 14,498,215 15,472,236 16,163,913 17,553,876 17,965,924 18,133,345 18,744,756 18,928,400 18,961,720 18,799,559 19,040,477 19,012,969 19,540,493
46 Target (90 days of non-capital expenses)- - 22,812,829 21,747,322 23,208,354 24,245,869 26,330,813 26,948,886 27,200,017 28,117,133 28,392,600 28,442,580 28,199,338 28,560,716 28,519,453 29,310,739
47 Max (120 days of non-capital expenses)- - 30,417,105 28,996,429 30,944,472 32,327,825 35,107,751 35,931,847 36,266,689 37,489,511 37,856,800 37,923,439 37,599,117 38,080,955 38,025,937 39,080,986
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- - 8,339,587 8,513,675 9,812,452 10,090,785 10,333,275 10,559,364 10,814,793 11,071,303 11,339,579 11,624,565 11,916,834 12,216,571 12,523,970 12,839,228
51 Target (90 days of non-capital expenses)- - 10,338,923 10,708,963 12,004,964 12,354,177 12,647,923 12,915,301 13,225,151 13,534,948 13,860,507 14,209,208 14,566,862 14,933,699 15,309,957 15,695,881
52 Max (120 days of non-capital expenses)- - 12,338,259 12,904,252 14,197,475 14,617,569 14,962,570 15,271,237 15,635,509 15,998,593 16,381,435 16,793,851 17,216,890 17,650,826 18,095,944 18,552,534
53 Risk Assessment Value 4,645,297 4,193,350 4,338,548 5,838,255 6,183,701 5,769,290 5,935,703 5,314,839 5,417,963 5,563,442 5,671,929 5,824,643 5,981,673 6,143,144
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1140%1193%1315%1326%1391%1451%1583%1625%1651%1699%1563%1639%3183%3231%3246%3330%
57 Available Reserves (5x Debt Service)*13.5 14.0 12.1 10.9 11.7 10.7 10.1 10.2 10.7 11.1 10.2 10.8 20.9 21.3 22.0 22.1
58 *For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants.
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APPENDIX B: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c) For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f) For operating contingencies, as described in Section 12 (Operations Reserves)
g) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserves for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c) As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d) To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 11.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
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h) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 14 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Commitments will be set to an amount equal to the total remaining spending
authority for all contracts in force for the Electric Supply Fund and Electric Distribution
Fund, respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Reappropriations will be set to an amount equal to the amount of all remaining
capital and non-capital budgets that will be reappropriated to the following fiscal year for
each Fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of
Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve
and Adoption of Electric Special Project Reserve Guidelines). These policies and timelines
are included from Resolution 9206 as amended to refer to the reserves structure set forth
in these Reserves Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2017;
f) Any uncommitted funds remaining at the end of FY 2022 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
Section 7. Hydroelectric Stabilization Reserve
The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts
associated with variations in generation from hydroelectric resources. Staff will manage the
Hydroelectric Stabilization Reserve as follows:
a) Projected Hydro Output: Near the end of each fiscal year, staff will determine the
actual and expected hydro output for that fiscal year, compare that to the long-term
average annual output level (495,957 MWh as of March 2018), and multiply the
difference by the average of the monthly round-the-clock forward market prices for
each month of the current fiscal year.
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June 2018 44 | Page
b) Changes in Reserves. Staff is authorized to transfer the amount described in Sec.
7(a) from the Operations Reserve to the Hydroelectric Stabilization Reserve for
hydro output deviations above long-term average levels, or transfer this amount
from the Hydroelectric Stabilization Reserve to the Operations Reserve for hydro
output deviations below long-term average levels.
c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after
the transfers described above shall be the basis for staff’s determination, with
Council approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-
HRA) for the following fiscal year.
d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve
according to the following guideline levels:
Minimum Level $3 million
Target Level $19 million
Maximum Level $35 million
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent 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.
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June 2018 45 | Page
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the 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
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June 2018 46 | Page
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were
funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 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 2018 47 | 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
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 1 | Page
APPENDIX A: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a)“Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b)“Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c)“Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d)“Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserve for Commitments)
b)For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c)For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d)For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e)For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f)For operating contingencies, as described in Section 12 (Operations Reserves)
g)Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserves for Commitments)
b)For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c)As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d)To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e)For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f)For rate stabilization, as described in Section 11) (Rate Stabilization Reserves)
ATTACHMENT C
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 2 | Page
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) Set a goal to commit funds by the end of FY 2017;
f) Any uncommitted funds remaining at the end of FY 2022 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
Section 7. Hydroelectric Stabilization Reserve
The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts
associated with variations in generation from hydroelectric resources. Staff will manage the
Hydroelectric Stabilization Reserve as follows:
a) Projected Hydro Output: Near the end of each fiscal year, staff will calculate the
actual/expected hydro output for that fiscal year, compare that to the long-term
average annual output level (495,957 MWh as of March 2018), and multiply the
difference by the average of the monthly round-the-clock forward market prices for
each month of the fiscal year.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 3 | Page
b) Changes in Reserves: Staff is authorized to transfer the amount described in Sec. 7(a)
from the Operations Reserve to the Hydroelectric Stabilization Reserve for hydro
output deviations above long-term average levels, or transfer this amount from the
Hydroelectric Stabilization Reserve to the Operations Reserve for hydro output
deviations below long-term average levels.
c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after
the transfers described above shall be the basis for staff’s determination, with
Council approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-
HRA) for the following fiscal year.
a)d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve
according to the following guideline levels:
Minimum Level $3 million
Target Level $19 million
Maximum Level $35 million
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period 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.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 4 | Page
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the 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
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 5 | Page
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were
funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 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.
Attachment D
* NOT YET APPROVED *
6055014 1
Resolution No. _________
Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Residential Master-Metered and Small Non-Residential
Electric Service), E-2-G (Residential Master-Metered and Small Non-
Residential Green Power Electric Service), E-4 (Medium Non-
Residential Electric Service), E-4-G (Medium Non-Residential Green
Power Electric Service), E-4 TOU (Medium Non-Residential Time of
Use Electric Service), E 7 (Large Non-Residential Electric Service), E-7-
G (Large Non-Residential Green Power Electric Service), E-7 TOU
(Large Non-Residential Time of Use Electric Service), 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 does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2018.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2 (Residential Master-Metered and Small Non-Residential Electric Service) is
hereby amended to read as attached and incorporated. Utility Rate Schedule E-2, as amended,
shall become effective July 1, 2018.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule
E-2-G, as amended, shall become effective July 1, 2018.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2018.
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Non-Residential Green Power Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall
become effective July 1, 2018.
Attachment D
* NOT YET APPROVED *
6055014 2
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Non-Residential Time of Use Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended,
shall become effective July 1, 2018.
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective
July 1, 2018.
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become
effective July 1, 2018.
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Non-Residential Time of Use Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become
effective July 1, 2018.
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, 2018.
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
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.
Attachment D
* NOT YET APPROVED *
6055014 3
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-1-1 dated 7-1-20176 Sheet No E-1-1
A. APPLICABILITY:
This schedule applies to separately metered single-family residential dwellings receiving Electric
retail energy sServices from the City of Palo Alto Utilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Eelectric Sservice.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Tier 1 usage $0.072146605 $0.05240164 $0.00417391 $0.128712159
Tier 2 usage
Any usage over Tier 1
0.11347253 0.075157358 0.00417391 0.1927919002
Minimum Bill ($/day) 0.30402938
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 Ccustomer’s bill
statement, the bill amount may be broken down into appropriate components ascalculated under Section C.
2. Calculation of Usage Tiers
Tier 1 Eelectricity usage shall be calculated and billed based upon a level of 11 kWh per
day, prorated by Mmeter reading days of Sservice. As an example, for a 30-day bill, theTier 1 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-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-2-1 dated 7-1-20167 Sheet No E-2-1
A. APPLICABILITY: This schedule applies to the following Customers receiving Electric Service from the City of Palo Alto Utilities:
1. Small non-residential Customers receiving Nnon-Ddemand Mmetered Eelectric Sservice;
and
1.2. for small non-residential Ccustomers with Accounts at Master-Metered and master-
metered mmulti-family facilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Eelectric Sservice. C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period
$0.1120510591 $0.0790308468 $0.0039100417 $0.1888520090
Winter Period 0.0767807520 0.0535605766 0.0039100417 0.1386113267
Minimum Bill ($/day)
0.73287740
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 cCustomer’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
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-2-2 dated 7-1-20167 Sheet No E-2-2
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.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum Ddemand Mmeter 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 Ddemand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Ddemand Mmeter which does not reset after a definite time interval may be
used at the City's option. The billing Ddemand to be used in computing charges under this schedule will be the actual maximum Ddemand in kilowatts for the current month. An exception is that the
billing Ddemand for Ccustomers with Thermal Energy Storage (TES) will be based upon
the actual maximum Ddemand of such Ccustomers between the hours of noon and 6 pm
on weekdays.
{End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-2-G-1 dated 7-1-2016 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-residential Customers receiving Non-Demand Metered Eelectric Sservice; and 2. Customers with Aaccounts at Master-Mmetered 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
$0.11205105
91
$0.07903084
68
$0.004173
91 $0.0020
$0.190852
0290
Winter Period
0.0752007678
0.0535605766
0.00417391 0.0020
$0.1346714061
Minimum Bill ($/day)
0.73287740
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$0.10591112
05
$0.07903084
68
$0.004173
91
$0.188852
0090
Winter Period
0.0752007678
0.0535605766
0.00417391
0.1346713861
Minimum Bill ($/day)
0.73287740
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-2-G-2 dated 7-1-2016 Sheet No E-2-G-2
Palo Alto Green Charge (per 1000 kWh block) $2.00
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewable
sources, and create a transparent and sustainable market that encourages new
development of wind and solar power. Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-2-G-3 dated 7-1-2016 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 if the Customer-s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option. The billing Demand to be used in computing charges under this schedule will be the
actual maximum Demand in kilowatts for the current month. An exception is that the
billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on weekdays.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-1 dated 7-1-20167 Sheet No E-4-1
A. APPLICABILITY: This schedule applies to Demand metered Ssecondary Electric Service for Ccustomers with a
mMaximum 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 sServices, 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) $3.382.98 $17.6721.13 $21.0524.11
Energy Charge (per kWh)
0.0952609893 0.0175601771 0.00417391 0.1167312081
Winter Period
Demand Charge (per kW) $1.931.87 $13.4316.65 $15.3618.52
Energy Charge (per kWh)
0.0674307109 0.0175601771 0.00417391 0.0889009297
Minimum Bill ($/day) 14.841415.9946 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-2 dated 7-1-20167 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 Mmeter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer-’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Mmeter 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 Ccustomers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Ccustomers between the hours of noon and 6 pm
on weekdays.
4. Power Factor For new or existing Ccustomers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing
applicable Mmetering to calculate a Power Factor. The City may remove such
Mmetering from the Service of a Ccustomer whose Demand has been below 200
kilowatts for four consecutive months.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-3 dated 7-1-20167 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 Ccustomer’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 Ccustomer’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
Mmetering is installed, the monthly Power Factor shall be the Power Factor coincident with the Ccustomer's Maximum Demand.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any City of Palo Alto full-service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Ccustomer'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 Ccustomer receiving the discount in this section. The
Ccustomer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non-
utility generation source.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-4 dated 7-1-20167 Sheet No E-4-4
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 Mmeter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-1 dated 7-1-20167 Sheet No E-4-G-1
A. APPLICABILITY: This schedule applies to Demand mMetered Secondary Electric Service for Customers with a
mMaximum 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 -mMetered 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) $2.983.38 $17.6721.13
$21.0524.11
Energy Charge (per kWh)
0.0952609893
0.0175601771
0.0039100417 0.0020
0.1228111873
Winter Period
Demand Charge (per kW) $1.931.87 $13.4316.65
$15.3618.52
Energy Charge (per kWh)
0.0674307109
0.0175601771
0.0039100417 0.0020
0.0909009497
Minimum Bill ($/day) 14.841415.9946
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-2 dated 7-1-20167 Sheet No E-4-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.382.98 $21.1317.67 $24.1121.05
Energy Charge (per kWh) 0.0952609893 0.0175601771 0.0039100417
0. 1167312081
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.931.87 $13.4316.65 $15.3618.52
Energy Charge (per kWh) 0.0674307109 0.0175601771 0.0039100417 0.0889009497
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 14.841415.9946 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-3 dated 7-1-20167 Sheet No E-4-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 if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter, which does not reset after a definite time interval, may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand.
5. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full-service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-4 dated 7-1-20167 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, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change the system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-utility generation source.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-5 dated 7-1-20167 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-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-1 dated 7-1-20176 Sheet No E-4-TOU-1
A. APPLICABILITY: This voluntary rate schedule applies to Demand metered Ssecondary Electric Service for
Ccustomers 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 Mmaster-Mmetered multi-family facilities or other facilities requiring Demand-metered Sservices, as
determined by the City. In addition, this rate schedule is applicable for Ccustomers who did not
pay Ppower Ffactor Aadjustments during the last 12 months. B. TERRITORY: This rate schedule applies everywhereanywhere 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 $2.121.76 $6.097.28 $8.219.04
Mid-Peak 0.6466 6.097.28 6.767.92
Off-Peak 0.6466 6.097.28 6.767.92
Energy Charge (per kWh)
Peak $0.1014409248 $0.0175601771 $0.00391417 $0.1229111436
Mid-Peak 0.0983511645 0.0175601771 0.00391417 0.1198213833
Off-Peak 0.0874807146 0.0175601771 0.00391417 0.1089509334
Winter Period
Demand Charge (per kW)
Peak $1.047 $7.499.28 $8.5610.32
Off-Peak 1.047 7.499.28 8.5610.32
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-2 dated 7-1-20176 Sheet No E-4-TOU-2
Commodity Distribution Public Benefits Total
Energy Charge (per kWh)
Peak $0.0816408187 $0.017561771 $0.00391417 $0.1031110375
Off-Peak 0.0573807028 0.017561771 $0.00391417 0.0788509216
Minimum Bill ($/day) 14.841415.9946 D. SPECIAL NOTES: 1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C. 2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays) All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-3 dated 7-1-20176 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 Mmeter 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 tTime periods as defined under Section D.2.
4. Power Factor Adjustment
Time of Use Ccustomers must not have had a Ppower Ffactor Aadjustment 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 pPower Ffactor Aadjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be subject to Ppower Ffactor Aadjustments, the Customer will be removed from the E-4-TOU rate schedule and placed on another applicable rate schedule as is suitable to their
kilowatt Demand and kilowatt-hour usage.
5. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 months, the
Customer may request a rate schedule change to any applicable City of Palo Alto full-
service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 6. Primary Voltage Discount
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-4 dated 7-1-20176 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, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Mmeter 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 Mmeter 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 Mmeter are not operating, the Maximum Demand will be reduced by the sum of the
Maximum Generation of those non-utility generators, but in no event shall the
Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-5 dated 7-1-20176 Sheet No E-4-TOU-5
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-1 dated 7-1-20176 Sheet No E-7-1
A. APPLICABILITY: This schedule applies to Demand Mmetered secondary Service for large non-residential
Customers with a Maximum Demand of at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months. B. TERRITORY:
This rate schedule applies everyanywhere 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) $3.143.49 $23.6320.35 $26.7723.84
Energy Charge (kWh) 0.1003709353 0.0005300058 0.0041700391 0.1050709802
Winter Period
Demand Charge (kW) $1.841.90 $15.1713.69 $17.0115.59
Energy Charge (kWh) 0.0697906739 0.0005300058 0.0041700391 0.0744907188
Minimum Bill ($/day) 45.475842.3648 D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-2 dated 7-1-20176 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
Aaccount or one Mmeter if the Aaccounts are on one site. A site shall be defined as one
or more utility Aaccounts 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 Mmeter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Mmeter which does not reset after a definite time interval may be used at
the City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-3 dated 7-1-20176 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
Mmetering to calculate a Power Factor. The City may remove such Mmetering 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 pPower fFactor Aadjustment 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
Mmetering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements , as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kVA size limitation.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-4 dated 7-1-20176 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 Mmeter 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 Mmeter 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 Mmeter are not operating, the Maximum Demand will
be reduced by the sum of the Maximum Generation of those non-utility
generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-5 dated 7-1-20176 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-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-1 dated 7-1-20167 Sheet No E-7-G-1
A. APPLICABILITY: This schedule applies to Demand mMetered Service for large non-residential Customers who
choose Service under the Palo Alto Green Program. A Customer may qualify for this rate
schedule if the Customer’s Maximum Demand is at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge ( per kW) $3.143.49 $23.6320.35 $26.7723.84
Energy Charge (per kWh) 0.1003709353 0.0005300058 0.0041700391 0.0020 0.1070710002
Winter Period
Demand Charge (per kW) $1.841.90 $15.1713.69 $17.0115.59
Energy Charge (per kWh) 0.0697906739 0.0005300058 0.0041700391 0.0020 0.0764907388
Minimum Bill ($/day) 45.475842.3648
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-2 dated 7-1-20167 Sheet No E-7-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.143.49 $23.6320.35 $26.7723.84
Energy Charge (per kWh) 0.1003709353 0.0005300058 0.0041700391 0.1050709802
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.901.84 $15.1713.69 $17.0115.59
Energy Charge (per kWh) 0.0697906739 0.0005300058 0.0041700391 0.0744907188
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 45.475842.3648 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C. 2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-3 dated 7-1-20167 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 if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Request for Service Qualifying Customers may request Service under this schedule for more than one
Account or one Meter if the Accounts are at one site. A site shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and have a common billing address. 5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to the computation of any primary voltage discount. The Ppower fFactor Aadjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-4 dated 7-1-20167 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, but the City is not required to supply Service at a qualified line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's Electrical requirements , as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change the system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
9. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(9)(e), applies to Customers that have a non-utility generation source
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-5 dated 7-1-20167 Sheet No E-7-G-5
interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-1 dated 7-1-20167 Sheet No E-7-TOU-1
A. APPLICABILITY: This voluntary rate schedule applies to Demand mMetered secondary Service for non-
residential Ccustomers 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 Customers who did not pay Ppower Ffactor Aadjustments 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 $1.922.22 $7.946.84 $9.869.06
Mid-Peak 0.6264 7.946.84 7.488.56
Off-Peak 0.6264 7.946.84 7.488.56
Energy Charge (per kWh)
Peak $0.1014910177 $0.0005300058 $0.0041700391 $0.1061910626
Mid-Peak 0.1277909868 0.0005300058 0.0041700391 0.1324910316
Off-Peak 0.0784208777 0.0005300058 0.0041700391 0.0831209226
Winter Period
Demand Charge (per kW)
Peak $0.9396 $7.686.93 $8.617.89
Off-Peak 0.9396 7.686.93 8.617.89
Energy Charge (per kWh)
Peak $0.0715008036 $0.0005300058 $0.0041700391 $0.0762008484
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-2 dated 7-1-20167 Sheet No E-7-TOU-2
Off-Peak 0.0613805647 0.0005300058 0.0041700391 0.0660806096
Minimum Bill ($/day) 42.364845.4758 D. SPECIAL NOTES:
1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving
Day, and Christmas Day. The dates will be those on which the holidays are legally observed.
SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-3 dated 7-1-20167 Sheet No E-7-TOU-3
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 Ccustomers may request Service under this schedule for more than one Aaccount or one Mmeter if the Aaccounts are on one site. A site shall be defined as one or more utility
Aaccounts 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 Mmeter 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 tTime periods as defined under Section D.2. 5. Power Factor Adjustment
Time of Use Ccustomers must not have had a pPower fFactor aAdjustment 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 Ppower Ffactor Aadjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be
subject to Ppower Ffactor Aadjustments, the Customer will be removed from the E-7-TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand
and kilowatt-hour usage.
6. Changing Rate Schedules Customers electing to be served under E-7 TOU must remain on said schedule for a minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a
rate schedule change to any applicable City of Palo Alto full-service rate schedule as is suitable
to their kilowatt Demand and kilowatt-hour usage.
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-4 dated 7-1-20167 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, but the City is not required to supply Service at a particular line voltage where it has, or will
install, ample facilities for supplying at another voltage equally or better suited to the Customer's
electrical requirements , as determined in the City’s sole discretion. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount)
through transformers to be supplied by the City subject to a maximum kilovolt-ampere size
limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Mmeter 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 mMeter 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 mMeter are not
operating, the Maximum Demand will be reduced by the sum of the Maximum
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-5 dated 7-1-20167 Sheet No E-7-TOU-5
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}
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No. E-14-1 dated 7-1-20176 Sheet No. E-14-1
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 9.668.28
200 watts 17.8315.29
250 watts 21.9218.79
310 watts 27.1223.25 400 watts 34.9229.94
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No. E-14-2 dated 7-1-20176 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 34.9432.58
High Pressure Sodium Vapor Lamps
70 watts 30.4825.72
100 watts 32.9327.82
150 watts 37.0233.32 250 watts 45.1938.33
Light Emitting Diode (LED) Lamps
70 watts-equivalent 25.0621.07
100 watts-equivalent 26.9122.66 150 watts-equivalent 28.6224.13
250 watts 33.3028.14
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.
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No. E-14-3 dated 7-1-20176 Sheet No. E-14-3
3. Switching: Switching will be performed by the Utility (on the Utility's side of points of
delivery) and no charge will be made for switching provided there are at least 10 kilowatts of
lamp load on each circuit separately switched, including all lamps on the circuit whether served under this schedule or not; otherwise, an extra charge of $2.50 per month will be made for each circuit separately switched unless such switching installation is made for the
Utility's convenience or the customer furnishes the switching facilities and, if installed on the
Utility's equipment, reimburses the Utility for installing and maintaining them.
4. Annual Burning Schedule: The above rates apply to lamps which will be turned on and off
once each night in accordance with a regular burning schedule agreeable to the customer but
not exceeding 4,100 hours per year. 5. Maintenance: The rates under Class C include all labor necessary for replacement of
glassware and for inspection and cleaning of the same. Maintenance of glassware by the Utility is limited to standard glassware such as is commonly used and manufactured in
reasonably large quantities. A suitable charge will be made for maintenance of glassware of a
type entailing unusual expense. Under Class C, the rates include maintenance of circuits
between lamp posts and of circuits and equipment in and on the posts, provided these are all
of good standard construction; otherwise, the Utility may decline to grant Class C rates. Class C rates applied to any agency other than the City of Palo Alto also include painting of
posts with one coat of good ordinary paint as required to maintain good appearance but do
not include replacement of posts broken by traffic accidents or otherwise.
10. . System Owned In-Part by Utility : Where, at customer's request, the Utility installs, owns, and maintains any portion of the lighting fixtures, supports, and/or interconnecting circuits,
an extra monthly charge of one and one-fourth percent of the Utility's estimate of additional
investment shall be made.
11. Rates For Lamps Not on Schedule: In the event a customer installs a lamp which is not presently represented on this schedule, the Utility will prepare an interim rate reflecting the
Utility's estimated costs associated with the specific lamp size. This interim rate will serve as
the effective rate for billing purposes until the new lamp rating is added to Schedule E-14.
{End}
ATTACHMENT F
*NOT YET APPROVED *
6055005
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2019 Gas 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 adopts the FY 2019 Gas Utility Financial Plan.
SECTION 2. The Council hereby approves the transfer of up to $129,000 in FY 2019
from the Rate Stabilization Reserve to the Operations Reserve, as described in the FY 2019 Gas
Utility Financial Plan approved via this resolution.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental assessment is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
Attachment F
*NOT YET APPROVED *
6055005
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2019 GAS
UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
ATTACHMENT G
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 2 | P a g e
GAS UTILITY FINANCIAL PLAN
FY 2019 TO FY 2028
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2018 Rate and Reserve Proposals ........................................................ 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3C: Proposed Reserve Transfers ...................................................................................... 9
Section 4: Utility Overview .................................................................................................. 10
Section 4A: Gas Utility History ................................................................................................... 10
Section 4B: Customer Base ........................................................................................................ 11
Section 4C: Distribution System ................................................................................................. 12
Section 4D: Cost Structure and Revenue Sources ...................................................................... 13
Section 4E: Reserves Structure ................................................................................................... 13
Section 4F: Competitiveness ...................................................................................................... 14
Section 4G: Gas Supply Rates .................................................................................................... 15
Section 5: Utility Financial Projections ................................................................................. 16
Section 5A: Load Forecast .......................................................................................................... 16
Section 5A: FY 2013 to FY 2017 Cost and Revenue Trends ........................................................ 17
Section 5B: FY 2017 Results ....................................................................................................... 18
Section 5C: FY 2018 Projections ................................................................................................. 19
Section 5D: FY 2019-FY 2028 Projections .................................................................................. 19
Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 20
Section 5F: Long-Term Outlook ................................................................................................. 22
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 3 | P a g e
Section 6: Details and Assumptions ..................................................................................... 23
Section 6A: Gas Purchase Costs ................................................................................................. 23
Section 6B: Operations .............................................................................................................. 24
Section 6C: Capital Improvement Program (CIP) ....................................................................... 25
Section 6D: Debt Service ............................................................................................................ 27
Section 6E: Equity Transfer ........................................................................................................ 28
Section 6F: Revenues ................................................................................................................. 28
Section 6G: Communications Plan ............................................................................................. 29
Appendices ......................................................................................................................... 31
Appendix A: Gas Financial Forecast Detail ................................................................................ 32
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 33
Appendix C: Gas Utility Reserves Management Practices ......................................................... 35
Appendix D: Description of Gas Utility Cost Categories ............................................................ 39
Appendix E: Gas Utility Communications Samples .................................................................... 40
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 4 | P a g e
SECTION 1: DEFINITIONS AND ABBREVIATIONS
ABS: Acrylonitirile butydene styrene, a plastic gas main material
AMI: Advanced Metering Infrastructure
CARB: California Air Resources Board
CIP: Capital Improvement Program
CNG: Compressed Natural Gas
CPAU: City of Palo Alto Utilities Department
CPUC: California Public Utilities Commission
Cross-bore: A cross-bore exists when one utility line has been drilled or “bored” through a portion
of another line. Gas cross-bores can occur in sewer lines as a result of “horizontal boring”
construction practices.
Distribution: transportation of gas to customers.
GMR Program: Gas Main Replacement Program
Local Transportation: transportation of gas to Palo Alto across PG&E’s distribution system from
PG&E City Gate.
Malin: a delivery hub referred to in gas purchase contracts and located in Malin, Oregon, where
the northern end of PG&E’s Redwood Transmission Pipeline is located.
MMBtu: Millions of British thermal units, a unit of gas measurement equal to ten therms.
Commonly used for high volume gas measurement. Wholesale purchases of gas from suppliers
are typically measured in MMBtu.
O&M: Operations and Maintenance
PE or HDPE: Polyethylene, a gas main material (more specifically, High-Density Polyethylene)
PG&E: Pacific Gas and Electric
PG&E Citygate, or Citygate: a delivery hub referred to in gas purchase contracts. Any gas delivered
to PG&E’s distribution system (such as gas delivered at the southern end of PG&E’s Redwood
Transmission Pipeline) is said to have been delivered at PG&E Citygate.
PVC: Polyvinyl chloride, a plastic gas main material
Summer: April 1 to October 31
Therms: The standard unit of measurement for natural gas sales to customers, equal to 100,000
British thermal units. Therms measure the heating value of the gas, rather than its volume.
Transmission: transportation of gas between major gas delivery hubs via a gas transmission
pipeline, such as PG&E’s Redwood pipeline.
UAC: Utilities Advisory Commission, an appointed body that advises the City Council on CPAU
issues.
Winter: November 1 to March 31
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 5 | P a g e
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Gas Utility for the next ten years. This
Financial Plan provides revenues to 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
This financial plan projects non-commodity costs to increase from FY 2019 through FY 2028 at
about 3.5% per year on average. In the short term, some of these cost increases are related to
the cross-bore inspection program, but capital improvement program (CIP) costs have also
increased as the economy has improved. The national and regional focus on infrastructure
improvement has created more demand, and the pool of skilled construction labor has not grown
at the same pace. While CPAU generally plans a new gas main replacement project every year,
recent larger than expected bids have required resizing and redesign of some existing planned
projects. Because of this (as well as the complexity of the project), CIP costs for FY 2018 increased
for the University Avenue Business District project, which is scheduled to begin construction in
mid-2018. Due to the amount of planning required for this project, no new CIP work was
budgeted for FY 2017, and because of the complexity of the University Avenue project, no CIP
work is budgeted for FY 2019, resulting in one-time cost savings. The next new main replacement
project after the University Avenue project will take place in FY 2020. Table 1 shows the Gas
Utility expenses over the period of this financial plan.
Table 1: Gas Utility Expenses for FY 2017 to FY 2028 (Thousand $’s)
Expenses
($000)
FY
2017
(act.)
FY
2018
(est.)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Commodity costs 12,563 14,137 13,022 12,851 13,040 13,233 13,499 13,855 14,188 14,576 14,731 14,932
Operations 21,050 20,302 20,509 21,133 20,579 21,874 22,508 23,270 24,048 24,879 24,303 24,649
Capital Projects 2,214 7,804 5,197 10,217 12,080 9,815 9,892 9,970 10,050 10,131 10,214 10,299
TOTAL 35,827 42,243 38,728 44,202 45,698 44,922 45,898 47,095 48,286 49,587 49,248 49,880
To ensure that revenues cover projected rising costs, the financial plan includes the rate
trajectory shown in Table 2.
Table 2: Projected Gas Rate Trajectory for FY 2019 to FY 2028
Projection FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Current Financial Plan 4% 8% 7% 7% 4% 4% 1% 1% 0% 2%
FY 2018 Financial Plan 4% 6% 6% 5% 3% 3% 2% 1% 0% N/A
FY 2017 Financial Plan 7% 4% 1% 1% 1% 1% 1% 1% N/A N/A
The Gas Utility has a Rate Stabilization Reserve, which can be used to smooth rate increases over
several years. This Financial Plan projects that these reserves will be exhausted by the end of FY
2020. The Gas Utility also has a CIP Reserve to help offset one-time and/or unanticipated, spikes
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in CIP spending which do not merit separate bond financing. Table 3 shows the projected reserve
transfers over the forecast period.
Table 3: Transfers To/(From) Reserves for FY 2018 to FY 2028 ($000)
Reserve FY 2018 FY 2019 FY 2020 to FY 2028
Rate Stabilization (129) (2,006) (4,404)
CIP - - (3,820)
Operations 129 2,006 8,224
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Gas Utility in FY 2018:
1. Amend the proposal of a $1.2 million transfer from the Rate Stabilization Reserve to the
Operations Reserve, as proposed in the FY 2018 Gas Financial Plan, to a transfer of
$129,000, based on projected ending Operations Reserve levels.
Staff proposes the following actions for the Gas Utility in FY 2019:
2. Increase distribution rates by 6% (a 4% overall increase) for FY 2019, primarily reflecting
increases to capital expenditures and also increased operations costs. See Section 3B:
Current and Proposed Rates for more details.
3. Transfer $2 million from the Rate Stabilization Reserve to the Operations Reserve. See
Section 3D: Proposed Reserve Transfers for more details.
SECTION 3: DETAIL OF FY 2018 RATE AND RESERVE PROPOSALS
SECTION 3A: RATE DESIGN
The Gas Utility’s rates are evaluated and implemented in compliance with cost of service
requirements. The Gas Utility’s current rates are based on the methodology from the April 2012
Gas Utility Cost of Service Study completed by Utility Financial Solutions.1 In preparation for an
update to the study, staff discussed a proposed scope with the Utilities Advisory Commission in
October 2016, and the Council in November 2016 2. The updated study is projected to be
completed by late FY 2018 or the early part of FY 2019, and will provide guidance for the next
proposed rate action.
SECTION 3B: CURRENT AND PROPOSED RATES
On July 1, 2012 CPAU restructured its rates so that the commodity component varied monthly to
match changes in gas market prices.3 In addition, CPAU increased monthly service charges to
recover the cost of providing gas service to customers. In January 2015, the Council adopted a
1 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
2 Staff Report 7416 11/14/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54576
3 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
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new rate component to collect the costs of purchasing allowances for the purpose of compliance
with the State’s cap-and-trade program.4 This component changes depending on the cost of
allowances and gas demand. In October 2016, the Council adopted a resolution changing the
Local Transportation rate (which had been collapsed into the Distribution rate in 2015 to
streamline bill presentation), to be a pass-through of PG&E’s Gas Transportation Rate to
Wholesale/Resale Customers (G-WSL) charge to Palo Alto.5 This went into effect November 1,
2016. In December 2016, Council approved a carbon neutral gas plan, with a goal of achieving a
carbon neutral gas portfolio by FY 2018.6 The plan is for costs associated with the plan to be a
passed through directly to customers as well, although the rate impact is not to exceed $0.10 per
therm. Three years’ worth of volumetric rate history can be found on Palo Alto’s website.7
CPAU has four rate schedules: one for separately metered residential customers (G-1), one for
small commercial and master-metered multi-family residential customers (G-2), one for
customers using over 250,000 therms per year (G-3) and a specific schedule for the Compressed
Natural Gas station (G-10). All customers pay a monthly service charge, which represents meter
reading, billing, and other customer service costs, as well as a portion of operations and
maintenance cost. All customers are also charged for each therm of gas used. Separately metered
residential customers are charged on a tiered basis, differentiated by season. During the winter
months, the first 2 therms per day (60 therms for a 30 day billing period) are charged a base price
per CCF, and all additional units charged a higher price per therm. During the summer months,
the first tier level is 0.667 therms per day, or 20 therms for a 30 day billing period. Commercial
customers pay a uniform price for each therm used.
Table 4 shows the current monthly service charges for all rate schedules. Table 95 shows the
consumption charges related to distribution charges. As mentioned earlier, commodity charges
change monthly, and transportation charges are tied to the PG&E G-WSL rate schedule. Some
recent commodity price history is discussed in Section 6A: Gas Purchase Costs.
4 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537
5 Staff Report 7260 10/17/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54165
6 Staff Report 7533 12/05/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54882
7 Monthly Gas Commodity & Volumetric Rates http://www.cityofpaloalto.org/civicax/filebank/documents/30399
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Table 4: Current and Proposed Monthly Service Charges
Rate Schedule
Monthly Service Charge
($/month)
Change
Current (as of
7/1/16)
Proposed for
FY 2019
($) (%)
G-1 (Residential) $10.32 $10.94 $0.62 6%
G-2 (Small Commercial) 78.23 82.94 4.69 6%
G-3 (Large Commercial) 377.43 400.08 22.65 6%
G-10 (CNG) 52.93 56.11 3.18 6%
Table 5: Current and Proposed Gas Distribution Charges
Change
Current (as of
11/1/16)
Proposed
for FY 2019
($) (%)
G-1 (Residential)
Tier 1 Rates $0.3933 $0.4239 $0.0306 7.8%
Tier 2 Rates 0.9319 0.9948 0.0629 6.7%
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.5767 0.6183 0.0416 7.2%
G-3 (Large Commercial)
Uniform Rate 0.5687 0.6098 0.0411 7.2%
G-10 (Compressed Natural Gas)
Uniform Rate 0.0093 0.0100 0.0007 7.2%
SECTION 3C: BILL IMPACT OF PROPOSED RATE CHANGES
Table 6 shows the impact of the proposed July 1, 2018 rate changes on the median residential
bill. The average increase is roughly 4% based on prices in February 2018, but some customers
may see slightly higher or lower increases due to slight changes in the composition of the utility’s
costs, as well as prevailing market prices.
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Table 6: Impact of Proposed Gas Rate Changes on Residential Bills
Usage
(Therms/month)
Bill under
Current Rates
Bill under
Proposed Rates
Change
$/mo. %
Winter (Using February 2018 commodity prices)
30 $36.93 $ 38.47 $ 1.54 4%
54 (median) 58.21 60.49 2.28 4%
80 94.20 98.04 3.84 4%
150 193.98 202.23 8.25 4%
Summer (Using July 2017 commodity prices)
10 18.73 $ 19.90 $ 1.17 6%
18 (median) 25.45 27.08 1.63 6%
30 40.57 43.16 2.59 6%
45 61.26 65.17 3.91 6%
Table 7 shows the impact of the proposed July 1, 2018 rate changes on various representative
commercial customer bills.
Table 7: Impact of Proposed Gas Rate Changes on Commercial Bills
(Using February 2018 commodity prices)
Usage
(Therms/month)
Bill under Current
Rates
Bill under
Proposed Rates
Change
%
500 613 639 4%
5,000 5,430 5,642 4%
10,000 10,781 11,202 4%
50,000 53,493 55,571 4%
SECTION 3D: PROPOSED RESERVE TRANSFERS
The FY 2018 Financial Plan proposed a $1.2 million transfer from the Rate Stabilization Reserve
into the Operations Reserve in FY 2018. Lower actual expenses in FY 2017 resulted in higher
ending reserve balances than initially projected, so staff recommends revising the transfer down
to $129,000 at this time. A tentative transfer of $2 million in FY 2019, followed by $4.4 million in
FY 2020, is included in the financial projections in this Financial Plan. In addition, $3.8 million in
the CIP Reserve may need to be utilized in FY 2021. This will help mitigate additional, one-time
costs related to the replacement of gas meters for AMI deployment. The transfers in general will
enable CPAU to maintain adequate Operations Reserve levels while moderating the pace of
increase in gas rates. The impact of these transfers on reserves levels can be seen in Appendix A:
Gas Utility Financial Forecast Detail.
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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 and to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4A: GAS UTILITY HISTORY
On September 22, 1917, the City of Palo Alto issued a bond to purchase the property of Palo Alto
Gas Company and continue it as a municipal enterprise. At the time, the system was comprised
of 21 miles of mains, 1,900 meters, and was valued at $65,500. PG&E supplied the gas, which
was synthesized from coal at its Potrero gasification facility. Almost immediately the City faced
challenges. Losses were at nearly 25% according to PG&E’s master meter, and PG&E had filed
with the Railroad Commission (the forerunner to today’s CPUC) to increase rates by nearly 72.5%.
Despite these initial hurdles, Palo Alto’s system grew tremendously, and by 1924 revenues had
exceeded those of the electric utility. Sales were such that the annual reports of the time noted
gas usage “appears to be greater than that of any other city in the state, showing that gas is a
very popular form of fuel in Palo Alto.” Just prior to the acquisition of the neighboring town of
Mayfield’s gas system (centered around today’s California Avenue) in 1929, the miles of main in
service and customers connections had doubled.
Notable changes to the gas supply itself came in 1930, when PG&E ceased supplying purely
manufactured (or coal) gas from its Potrero Hill facility in San Francisco and instead switched to
natural gas. In 1935, a supplementary butane injection system (later retired) was purchased from
Standard Oil to mitigate large wintertime peaks. Gas sales were at 248,658 million cubic feet
(MCF) with 4,849 active services.
Early gas mains in Palo Alto were made of steel, but in the 1950s, like many other utilities, CPAU
switched to ABS plastic. CPAU switched to PVC plastic in the early 1970s, but around 100 miles
of ABS mains had already been installed. A 1990 evaluation of the system found a steadily
increasing rate of gas leaks associated with those mains, something that other gas utilities had
also been experiencing. To reduce leaks, CPAU accelerated its main replacement program from
7,000 feet (1.3 miles) of replacements per year to 20,000 feet (3.8 miles) per year. This would
enable the utility to replace all of its ABS and its most vulnerable steel and PVC mains with
polyethylene (PE) mains over the course of the following 36 years.8 As of 2015 the Gas Utility
had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic
protection was not effective. Current main replacement projects will target the last ~800 feet of
remaining ABS main as well as tackling PVC replacement. A PVC risk analysis to determine the
appropriate footage of annual PVC replacement for future CIP projects is currently being
conducted. This is an example of how local control of its Gas Utility has provided Palo Alto
residents with substantial benefits. During the 1990s and 2000s, while CPAU was increasing its
8 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990
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main replacement rate to ensure a robust gas distribution system, PG&E was underspending on
safety-related infrastructure, according to a past audit.9
In the 1990s, while grappling with the issues surrounding its distribution system, CPAU was also
participating in major changes to the structure of the gas industry in California. Until 1988 CPAU
had a formal policy of setting its rates equal to PG&E’s rates and successfully did so with the
exception of one year in the mid-1970s. At times this led to inadequate revenue (1974 to 1981)
as PG&E, the City’s only gas supplier, regularly filed requests with the CPUC to increase the
wholesale gas supply rates charged to the Gas Utility. In the 1990s, as the CPUC began
deregulating the natural gas industry in California, the Gas Utility began purchasing gas from
suppliers other than PG&E. In 1997 the CPUC adopted the “Gas Accord,”10 which enabled the Gas
Utility (along with other local transportation-only customers) to obtain transmission rights on
PG&E’s Redwood transmission pipeline running from Malin, Oregon into California.
In 2000/2001 the California energy crisis occurred, causing major disruptions to the Gas Utility’s
supply costs. Wholesale gas prices rose over 500% between January 2000 and January 2001. The
Council approved drawing down reserves to provide ratepayer relief and, for two years following
the crisis, CPAU rates were above PG&E’s as reserves were replenished. In April 2001 the Council
approved a hedging practice of buying fixed price gas one to three years into the future. After
reaching a low point in October 2001, prices continued to rise, and as a result the CPAU hedging
strategy frequently resulted in a wholesale supply cost advantage compared to PG&E until prices
began to decline steeply in mid-2008. At that point the Gas Utility’s wholesale supply costs
became higher than market gas prices due to fixed price contracts entered into prior to 2008. As
a result the Gas Utility’s wholesale supply costs were higher than PG&E’s for several years. In
2012 Council approved a plan to formally cease the hedging strategy and purchase all gas on the
short-term (“spot”) markets. As of July 1, 2012, the commodity portion of the gas rates changes
every month based on the spot market gas price.
SECTION 4B: CUSTOMER BASE
CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas
customers in Palo Alto. Close to 23,600 customers are connected to the natural gas system,
approximately 22,000 (93%) of which are residential and 1,600 (7%) of which are non-residential.
Residential customers consume about 11 to 13 million therms of gas per year, roughly 45% of the
gas sold, while non-residential customers consume 55% (about 14 to 16 million therms).
Residential customers use gas primarily for space heating (46% of gas consumed) and water
heating (42%), with the remainder consumed for other purposes such as cooking, clothes drying,
9 Focused Financial Audit of The Pacific Gas & Electric Company’s Gas Distribution Operations, Overland Consulting,
made available through a CPUC Administrative Law Judge’s ruling on A12-11-009/I13-03-007 on 5/31/2013
10 CPUC decision 97-08-055. Since then, the Gas Accord has been amended four times, with the most recent being
Gas Accord V, application A.09-09-013
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and heating pools and spas.11 Non-residential customers use gas for space and water heating
(73% of gas consumed), cooking (20%), and industrial processes (6%).12
The Gas Utility receives gas at the four receiving stations within Palo Alto where CPAU’s
distribution system connects with Pacific Gas and Electric’s (PG&E’s) system. These receiving
stations are jointly operated by CPAU and PG&E. CPAU purchases gas from various natural gas
marketers, with PG&E providing only local transportation service (transportation from the PG&E
City Gate gas delivery hub to Palo Alto). CPAU also has transmission rights on PG&E’s transmission
pipeline from Malin, Oregon to PG&E City Gate, allowing it to purchase lower priced gas at that
location. CPAU does not produce or store any natural gas, and purchases gas in the monthly and
daily spot markets. The cost of the purchased gas is passed through directly to customers through
a rate adjuster that varies monthly with market prices. In a similar fashion, the cost for local
transportation is now tied to PG&E’s G-WSL rate schedule, and varies when and if PG&E changes
its rate schedule. The cost of purchased gas and PG&E local transportation service usually
account for roughly one third of the utility’s expenditures.
SECTION 4C: DISTRIBUTION SYSTEM
To deliver gas from the receiving stations to its customers, the utility owns 210 miles of gas mains
(which transport the gas to various parts of the city) and close to 23,600 gas services (which
connect the gas mains to the customers’ gas lines). These mains and services, along with their
associated valves, regulators, and meters, represent the vast majority of the infrastructure used
to deliver gas in Palo Alto. CPAU has an ongoing CIP to repair and replace its infrastructure over
time, the expense of which normally accounts for around 15 to 20% of the utility’s expenditures.
Costs for main replacements have been going up in recent years.
In addition to the CIP, the Gas Utility performs a variety of maintenance activities related to the
system, such as monitoring the system for leaks, testing and replacing meters, monitoring the
condition of steel pipe, and building and replacing gas services for buildings being built or
redeveloped throughout the city. The utility also shares the costs of other system-wide
operational activities (such as customer service, billing, meter reading, supply planning, energy
efficiency, equipment maintenance, and street restoration) with the City’s other utilities. These
maintenance and operations expenses, as well as associated administration, debt service, rent,
and other costs, make up roughly half of the utility’s expenses. In addition to these ongoing
activities, CPAU has conducted a program to find and replace cross-bores over the last several
years. Currently, $1 million is budgeted per year for the cross-bore program through FY 2021.
However, the ongoing cross-bore investigation may require additional funding, or extend for
longer into the future, as the remaining sewer lines are more difficult to examine than the
majority of the wastewater collection system that has been examined to date.
11 http://energyalmanac.ca.gov/naturalgas/overview.html
12 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Statistics shown are for
end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located.
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SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 1, the Gas
Utility receives 95% of its revenue
from sales of gas and the
remainder from capacity and
connection fees, interest on
reserves, and other sources.
Appendix A: Gas Utility Financial
Forecast Detail shows more detail
on the utility’s cost and revenue
structures.
As shown in Figure 2, in FY 2017,
gas purchase costs accounted for
roughly 31% of the Gas Utility’s
costs. This percentage can vary
widely from year to year, as this
cost is based upon market
purchases, and now also includes
costs related to cap and trade.
Operational costs in FY 2017
represented roughly 51%, of
expenses and capital investment
was responsible for the remaining
18%. CIP is normally about 20% of
expenses, but this may be lower in
times when new budgeting for
projects is deferred, as happened in FY 2017.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains six reserves for its Gas Utility to manage various types of contingencies. The
summary below describes each of these briefly. See Appendix C: Gas Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
Reserve for Commitments: A reserve equal to the utility’s outstanding contract liabilities
for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
Reserve for Reappropriations: A reserve 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.
Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to accumulate
funds for future expenditure on CIP projects and is anticipated to be empty unless a major
one-time CIP expenditure is expected in future years. This CIP can also act as a
Figure 2: Cost Structure (FY 2017)
51%
31%
18%
Operations
Gas Purchases
Capital
Figure 1: Revenue Structure (FY 2017)
95%
5%
Sales of Gas
Other Revenue
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contingency reserve for the CIP. This type of reserve is used in other utility funds (Electric,
Water, and Wastewater Collection) as well.
Rate Stabilization Reserve: This reserve is 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 (Electric, Water, and Wastewater
Collection) as well.
Operations Reserve: This is the primary contingency reserve for the Gas Utility, and is
used to manage yearly variances from budget for operational gas costs. This type of
reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as well.
Unassigned Reserve: This reserve is for any funds not assigned to the other reserves and
is normally empty.
SECTION 4F: COMPETITIVENESS
Table 8 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of July 2017 (to illustrate a summer month bill) and
February 2018 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2017 was $469.05, about 14% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 8: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(February 2018)
30 36.93 42.39 -12.9%
(Median) 54 58.21 76.31 -23.7%
80 94.20 126.58 -25.6%
150 193.98 264.07 -26.5%
Summer
(July 2017)
10 18.73 13.01 44.0%
(Median) 18 25.45 23.41 8.7%
30 40.57 45.24 -10.3%
45 61.26 72.72 -15.8%
Table 9 shows the monthly gas bills for commercial customers for various usage levels for rates in
effect as of February 2018. Bills for CPAU customers at the usage levels shown are around 2% to
27% higher for commercial customers than for PG&E customers. This is a substantial
improvement over the calendar year 2013 bill comparison, when commercial gas bills for CPAU
customers were 27% to 44% higher than for PG&E customers. This is primarily attributable to
PG&E’s higher distribution rates as the commodity rates for CPAU and PG&E are very similar, both
being based on spot market gas prices.
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Table 9: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect February 2018)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 613 600 2%
5,000 5,430 5,242 4%
10,000 10,781 9,211 17%
50,000 53,493 42,036 27%
SECTION 4G: GAS SUPPLY RATES
Starting in July 2012, CPAU replaced a “laddering” hedging strategy for purchasing gas supplies
with a strategy to buy gas on the short-term, or “spot” markets and pass the commodity cost to
customers on a monthly basis. Figure 3 shows the actual commodity prices charged. Commodity
prices have fluctuated by around $0.20 over the last two years, but have generally been lower
than prices seen in 2013 and 2014.
Figure 3: Gas Commodity Rates from July 2012 through February 2018
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SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Gas usage in Palo Alto is volatile, varying with both economic and weather conditions. As shown
in Figure 4, in the early 1970’s, gas purchases reached over 45 million therms per year. Usage
dropped dramatically in the 1976/1977 drought when customers saved significant amounts of
(hot) water by upgrading to efficient showerheads. During the 1980s and 90s average gas usage
was around 36 million therms per year. Usage dropped again in the early 2000’s. In FY 2001, gas
prices escalated during the California energy crisis and Palo Alto’s rates increased by nearly 200%.
From 2003 to 2011, usage decreased by 2.3% mainly as a result of continued customer
investments in energy efficiency.
In 2014 and 2015, unusually warm winters, as well as ongoing drought, caused gas usage to
tumble to historic lows. In FY 2017 and FY 2018, as the drought has eased, gas usage has started
to increase again.
Figure 4: Historic Gas Consumption
Gas consumption, as denoted by the dotted line in Figure 5, is projected to recover somewhat
and resume the long run trend of decreasing usage over the forecast period, although changes
such as replacement of gas appliances with electric appliances or customer behavior may result
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in lower long run usage. As with prior drought/gas usage declines in the past, it is likely that
consumption will not come back to pre-conservation levels. It is too early to tell, however, where
the new ‘normal’ level of consumption will be.
Figure 5: Forecast Gas Consumption
SECTION 5A: FY 2013 TO FY 2017 COST AND REVENUE TRENDS
Figure 6 and Appendix A: Gas Utility Financial Forecast Detail show how costs have changed
during the last five years as well as how staff project costs to change over the next decade.
The annual expenses for the gas utility decreased substantially between 2013 and 2017. Lower
gas sales in conjunction with the drought, as well as lower gas market prices in FY 2015 and FY
2016 (as shown in Figure 3 above) resulted in lower overall commodity expenses. FY 2014, FY
2015 and FY 2017 were notable due to the fact that no new funding was added for main
replacement projects. In FY 2014 and FY 2015, this was due to the fact that staff was completing
a prior major gas main replacement project, the largest in utility history, which completed
replacement of ABS gas mains in Palo Alto. The FY 2016 project included replacements of gas
mains on University Avenue, a project that has evolved into the Upgrade Downtown project
involving a coordinated replacement of several different types of infrastructure to avoid multiple
disruptions to the business district. This has been a multi-year planning effort that did not allow
for design of other new projects. This allowed the Gas Utility to temporarily keep rates lower
than they will need to be to fund future operations and capital replacement.
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Revenues have generally matched expenses in most years and were higher than expenses in FY
2017. As shown in Figure 6 below, revenues were below cost in FY 2013 and nearly at cost in FY
2016. The absence of new budget funding for main replacement projects for several years, as
well as the availability of relatively large reserves, forestalled the need for rate increases until
now.
As shown in Figure 6, the last adjustment to gas distribution rates was in July 2016 when CPAU
increased rates by 8%. In FY 2012, commodity rates were changed to a market-based, monthly
pass-through cost—and commodity rates (and usage) fell, so revenues (and gas supply costs)
actually declined in FY 2013 after the rate increase. Figure 6 assumes no change in gas supply
costs over the forecast period to illustrate the impact of proposed distribution rate changes on
the overall customer bill. In reality, gas supply costs are uncertain and are passed through to
customers as they change month to month.
Figure 6: Gas Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2017 and Projections through FY 2028
SECTION 5B: FY 2017 RESULTS
Sources of funds for FY 2017 were lower than projections by $885,000, but operational expenses
came in well below the expected budget. Total FY 2017 expenses were $32.7 million compared
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to projections of $36.9 million in the FY 2018 Financial Plan. Table 10 summarizes the variances
from forecast.
Table 10: FY 2017, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Purchase costs lower than forecast (479) Cost savings
Operations cost savings (3,774) Cost savings
Decreased interest income and other
non-sales revenues 1,753
Revenue decrease
Increased sales revenues (867) Revenue increase
Net Cost / (Benefit) of Variances (3,368)
SECTION 5C: FY 2018 PROJECTIONS
Current projections indicate that sales revenues will be slightly higher than last year’s forecast,
but other revenues have been revised downwards based on prior year actuals. While gas
purchase costs are not projected to increase appreciably during the forecast period, the current
financial plan anticipates CIP costs will be substantially higher in FY 2018 than projected in the
prior financial plan. Table 11 summarizes the current and projected variances from the FY 2018
Financial Plan.
Table 11: FY 2018 Projected Results vs. Current Financial Plan Forecast ($000)
Net Cost/ (Benefit) Type of change
Sales revenues higher than forecast (160) Revenue increase
Other revenues and interest lower than forecast 1,272 Revenue decrease
Purchase cost decrease (2,108) Cost decrease
Operations & maintenance and customer service
cost decreases
(1,477) Cost decrease
Capital Improvement Cost increases 5,730 Cost increase
Net Cost / (Benefit) of Variances 3,259
SECTION 5D: FY 2019-FY 2028 PROJECTIONS
Figure 6 above shows that staff projects costs for the Gas Utility to rise substantially in FY 2018,
and then to increase at around 2.9% per year on average through FY 2028. In Operations, there
is a short run addition of $1 million, starting in FY 2019, for cross-bore inspections (this expense
is projected to continue for at least three years), as well as general inflationary increases of
around 2 to 3% per year. Salaries and benefits expenses are projected to rise at 3 to 4% per year,
per the City’s Long Range Financial Plan. Construction costs continue to increase, which resulted
in increased costs in FY 2018 for the University Avenue Business District project, which is
scheduled to begin construction in mid-2018. Due to the amount of planning required for this
project, no new CIP work was budgeted for FY 2017, and because of its complexity, no CIP work
is budgeted for FY 2019, resulting in one-time cost savings. The next new main replacement
project after the University Avenue project will take place in FY 2020, and ongoing main
replacement is expected to be more expensive. In addition to these trends, additional costs
related to AMI deployment are projected in FY 2020 and 2021. Gas commodity costs are the most
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variable component but are currently projected to increase by less than 2% annually. Since this
is a pass-through cost to customers, the risk of these costs being higher or lower than expected
has a minimal impact on reserves.
As shown in Figure 7, this financial plan projects the Rate Stabilization Reserves to be depleted
by FY 2020.
Figure 7: Gas Utility Reserves
Actual Reserve Levels for FY 2017 and Projections through FY 2028
SECTION 5E: RISK ASSESSMENT AND RESERVES ADEQUACY
This financial plan projects the Gas Utility’s primary contingency reserve, the Operations Reserve,
to be within guideline levels throughout the forecast period, barring either short-run budget
savings and/or larger future increases. Figure 8 shows the Operations Reserve within the
guideline levels.
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Figure 8: Operations Reserve Adequacy
Forecasted Operations Reserve levels also exceed the short-term risk assessment for the Utility.
Table 12 summarizes the risk assessment calculation for the Gas Utility through FY 2023. The
same methodology is used for FY 2024 through FY 2028 as well. The risk assessment includes the
revenue shortfall that could accrue due to:
1. Lower than forecasted distribution sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 12: Gas Risk Assessment ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Total non-commodity revenue $21,457 $23,226 $25,843 $28,443 $29,930
Max. revenue variance, previous ten years 16% 16% 16% 16% 16%
Risk of revenue loss $3,441 $3,725 $4,144 $4,561 $4,799
CIP Budget $3,894 $8,875 $10,697 $8,391 $8,425
CIP Contingency @10% $389 $888 $1,070 $839 $842
Total Risk Assessment value $3,830 $4,612 $5,214 $5,400 $5,642
Finally, the City created the CIP Reserve at the end of FY 2015 to act as a contingency reserve for
capital improvement projects. Current guidelines state that the balance of this reserve should fall
between 12 and 24 months of budgeted CIP expense, but staff will continue to review this reserve
and the appropriateness of the current minimum and maximum guideline levels.
At the end of FY 2017, the sum of the CIP Reserve and existing Commitments was $8 million, as
shown in Figure 7.
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SECTION 5F: LONG-TERM OUTLOOK
In the longer term (5 to 35 years out) it is very difficult to predict the Gas Utility’s commodity
costs. A variety of long-term trends could affect commodity costs either positively or negatively.
Continuing improvement in gas extraction technology, such as fracking, could continue to create
generous supplies of gas, but these technologies are also under greater scrutiny with respect to
their environmental impacts. On the demand side, a continued shift from coal to natural gas for
electricity generation, an expansion of export capabilities, or an increase in manufacturing in the
U.S. might drive up natural gas prices, but other factors, such as generally more mild winters,
might drive gas demand lower. It is also difficult to predict the magnitude of the additional cost
impacts associated with the State’s cap-and-trade program over the long term. In the face of this
uncertainty, CPAU is able to protect the financial position of the Gas Utility by continuing its
current strategy of passing these costs directly to its customers via month-varying rate
adjustment mechanisms. The City pursues a policy of purchasing offsets to make gas usage in
Palo Alto carbon neutral. The cost is not to exceed $0.10/therm.
Future CIP investment needs for the Gas Utility may be lower than in the past, although costs per
foot for main replacement have been increasing substantially. The Gas Utility has replaced nearly
all of its ABS gas mains and its most problematic steel and PVC mains as well. The PE pipe being
used now is expected to have at least a fifty-year lifetime, and there is growing evidence that it
may last much longer than that. This would result in lower CIP investment over the long term.
CPAU is considering performing a study in the near future to develop its future main
replacements priorities and strategy.
Long-term state or local climate goals could also have a major impact on the Gas Utility. The
Global Warming Solutions Act, Assembly Bill 32 (AB32), set a goal of reducing greenhouse gas
(GHG) emissions to 1990 levels by 2020. In its December 2007 Climate Protection Plan, the City
set a goal of lowering emissions to 15% below 2005 levels by 2020. As a community Palo Alto
achieved these goals in 2012 even with continued use of natural gas for heating, cooking, and
industrial processes. However, to achieve the recently adopted Sustainability and Climate Action
Plan (S/CAP) goal of an 80% reduction in carbon emissions by 2030, or the State’s adopted goal
of an 80% reduction in emissions by 2050, extensive electrification of gas-using appliances is
necessary. If significant amounts of electrification occurred, stranded investment and higher
rates could be required as the costs of the distribution system are recovered over a lower sales
base. It is instructional that, in the recent discussion draft of its scoping plan update, CARB says,
to meet those goals, natural gas use would have to be “mostly phased out.”13 Staff intends to
begin evaluating how to manage potential impacts of these trends over the next few years.
13 Climate Change Scoping Plan, First Update, Discussion Draft for Public Review and Comment, California Air
Resources Board, October 2013, pg 88.
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SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: GAS PURCHASE COSTS
The Gas Utility purchases much of its gas for delivery at Malin, Oregon which is almost always
cheaper than delivery at PG&E Citygate, even including the costs of transmission from Malin to
Citygate. The Gas Utility purchases gas on a month-ahead and day-ahead basis in the spot market.
The last few years have seen gas prices in a relatively narrow but low band. High levels of natural
gas in storage, along with warmer than normal weather on the West coast has kept prices low,
as shown in Figure 9.
Figure 9: Gas Market Prices at PG&E Citygate
Gas commodity costs are expected to increase slowly but steadily over the next several years.
Figure 10 shows the projected gas prices used to generate this forecast. Projections for
transmission costs associated with transporting gas over PG&E’s Redwood transmission pipeline
(from Malin, Oregon to the PG&E Citygate) are based on rates adopted in the most recent update
to the Gas Accord.
Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary
adder to PG&E’s local transportation rate,14 but in December 2014 PG&E applied to the CPUC to
14 California Public Utilities Commission Advice Letter 3430-G, effective January 1, 2014. Also see CPUC Decision
12-12-30 regarding the Pipeline Safety Enhancement Plan Adder.
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more than double local transportation costs. The application was not settled until late 2016. As
these charges are dictated by PG&E and are outside of Palo Alto’s control, staff proposed making
these costs pass-through charge, similar to the commodity charge, and this became effective in
November 2016.
Figure 10: Wholesale Gas Price Projections
SECTION 6B: OPERATIONS
Operations costs include the Customer Service, Demand Side Management, Operations and
Maintenance (including Engineering), Resource Management, and Administration categories in
Figure 11, below. Debt service, rent, and transfers are also included in Operations costs
(excluding the General Fund equity transfer). Appendix D: Description of Gas Utility Cost
Categories includes detailed descriptions of the activities associated with these cost categories.
Operations costs are projected to increase by 2 to 4% per year. Salary and benefits, inflation, and
other assumptions match those used in the City’s long-range financial forecast.
Operations costs for FY 2019 to FY 2021 include funding for the cross-bore program. In the 1970s
CPAU, like many other utilities, adopted horizontal drilling as an alternative to trenching when
installing new gas services. This created the possibility of cross-bores, which can happen when a
gas service is bored through a sewer lateral. Though cross-bores are very rare, they can create a
dangerous situation when a contractor attempts to clear a blocked sewer line, because if the
cross-bored gas service is damaged during the line, clearing it can result in a gas leak. CPAU has
been inspecting new gas services since 2001, and in 2011 began video inspections of the sewer
laterals at the location of horizontally-drilled gas services installed before 2001. This inspection
program has cost roughly $1 million per year since FY 2012. While a majority of sewer laterals
have been inspected, staff has come across several services which are not able to be scoped,
either due to infiltration by roots or broken/collapsed pipe segments. Staff has included $3
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million in additional funding between FY 2019 and FY 2021 for this program, but the program will
likely require additional funding in future years to complete.
Figure 11: Historical and Projected Operational Costs
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
The Gas Utility’s CIP program consists of the following programs and budgets:
The Gas Main Replacement Program, under which the Gas Utility replaces aging gas
mains ranked to have the highest threat scores within the system.
Customer Connections, which covers the cost when the Gas Utility installs new services
or upgrades existing services at a customer’s request in response to development or
redevelopment. The Gas Utility charges a fee to these customers to cover the cost of
these projects.
Ongoing Projects, which covers the cost of routine meter, regulator, and service
replacement, minor projects to improve reliability or increase capacity, and other general
improvements.
Tools and Equipment, which covers the cost of capitalized equipment, such as directional
boring, gas pipeline maintenance and emergency equipment.
One-time Projects, which represents occasional large projects that do not fall into any
other category.
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Table 13 shows the current status of these project categories and future projected spending.
Table 13: Budgeted Gas CIP Spending ($000)
The Gas Main Replacement (GMR) Program is in the final stages of completing a major milestone
with the replacement of gas mains made from Acrylonitrile-Butadiene-Styrene (ABS) plastic. The
program to replace ABS and other low-performing materials within the gas system started in the
1990s (see Section 4A: Gas Utility History for more detail). CPAU temporarily slowed down its FY
2014 and 2015 CIP appropriations in this category in order to finalize the last major ABS main
replacement project and to catch up on projects that had accumulated due to staffing issues.
With the replacement of all ABS mains with Polyethylene (PE) plastic near completion, the
material most at risk for failure is the remaining Polyvinyl chloride (PVC) plastic and steel
(wrapped, with cathodic protection). The next focus of the GMR program will be the replacement
of all PVC mains with PE mains. CPAU is considering updating the Gas System Master Plan to
determine which sections of pipeline to prioritize and assist in determining the pace of main
replacement (approximately three miles of main each year, or 1.5% of the system).
The current budget for the gas main replacement program takes into account the recent rise in
construction costs. Several factors are contributing to the increase in construction costs and
include economic recovery in the Bay Area, a greater focus on infrastructure improvement by
many municipal agencies, and the higher demand for utility contractors within these fields. CPAU
has seen the replacement cost per linear foot increase by 25% to 50% over the last couple of
years. The Gas Utility posted the most recent project for competitive bid (the Upgrade Downtown
Project) and this resulted in very few contractor bids and an eventual contract price that was
much higher than estimated (staff has requested $6.7 million additional funding in FY 2018
related to this project) . Staff is beginning to include the higher construction cost in future project
estimates in order to maximize the amount of pipe replaced, as well as insuring the overall
integrity of the gas system. Currently, CPAU plans to replace as many aging mains as possible
within its current budget. However, if this trend of higher construction cost continues, the Gas
Utility may require larger CIP budgets and as a result, an increase in rates.
Staff has also included projections for costs related to AMI deployment, primarily centered
around meter replacement costs in FY 2021.
Staff projects ongoing projects, tools and equipment, and customer connections to cost
approximately $2.7 million in FY 2019 and remain relatively flat through the end of the forecast
period. In practice, these projects can fluctuate dramatically depending on prices of material,
system conditions and the pace of development and redevelopment in the city. It is worth noting
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
One Time Projects 129 (1) 128 42 1,680 530 2,320 - -
Gas Main Replacement 10,913 (225) 10,688 311 600 7,150 7,150 7,150 7,150
Tools And Equipment 89 (5) 84 15 370 120 120 100 100
Ongoing Projects 1,455 (164) 1,291 134 1,044 1,075 1,107 1,141 1,175
Customer Connections 1,414 (418) 997 99 1,303 1,342 1,383 1,424 1,467
TOTAL 14,001 (812) 13,189 600 4,997 10,218 12,080 9,815 9,892
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
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that fee revenue pays for the Customer Connections program, so when costs go up fees will be
adjusted as well. .
Aside from customer connections and transfers from other funds, the CIP plan for FY 2019 to FY
2023 is funded by utility rates. Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
shows the details of the plan.
SECTION 6D: DEBT SERVICE
The Gas Utility currently makes debt service payments on one bond issuance, the 2011 Series A
Utility Revenue Refunding Bonds. This bond issuance was to refinance the $18 million principal
remaining on the Utility Revenue Bonds, 2002 Series A issued for the Gas and Water Utilities to
finance various improvements to the distribution systems. $9.4 million of this issuance was
secured by the net revenues of the Gas Utility. Table 14 shows debt service for this bond for the
financial forecast period. Debt service on this bond will continue through 2026.
Table 14: Gas Utility Debt Service
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
2011 Utility Revenue
Refunding Bonds, Series A
802 801 801 803 804 805 803 800 803 1
The 2011 bonds include two covenants stating that 1) the Gas Utility will maintain a debt
coverage ratio of 125% of debt service, and 2) that the City will maintain “Available Reserves”15
equal to five times the annual debt service. The current financial plan complies with these
covenants throughout the forecast period, as shown in Table 15 and
Table 16.
Table 15: Debt Service Coverage Ratio ($000)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Revenues 37,112 36,361 38,526 41,445 44,381 46,250 47,956 48,837 49,742 49,505
Expenses
(Excluding CIP and
Debt Service)
(26,079) (25,309) (25,572) (25,192) (25,765) (26,408) (27,104) (27,763) (28,489) (28,865)
Net Revenues 11,033 11,052 12,954 16,253 18,616 19,842 20,852 21,074 21,253 20,639
Debt Service 802 801 801 803 804 805 803 800 803 1
Coverage Ratio 1375% 1381% 1618% 2023% 2315% 2464% 2596% 2633% 2648% N/A
15 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities
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Table 16: Debt Service Minimum Reserves ($000)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Gas Utilitya 22,986 20,619 14,943 10,690 10,149 10,501 11,362 11,913 12,882 13,140
Debt Serviceb 802 801 801 803 804 805 803 800 803 1
Reserves Ratioc 29x 26x 19x 13x 13x 13x 14x 15x 16x N/A
a) CIP, Rate Stabilization, Operations, and Unassigned Reserves
b) Gas Utility’s share of the debt service on the 2011 bonds.
c) Calculated using only Gas Utility reserves. The actual reserves ratio for the 2011 bonds is calculated based on the
combined Electric, Gas, and Water Utility reserves and total debt service and is higher than shown here.
The Gas Utility’s reserves and net revenue are also pledged as security for the bond issuances
listed in Table 17, even though the Gas Utility is not responsible for the debt service payments.
The Gas 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 17: Other Issuances Secured by Gas Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Gas Utility’s:
Net Revenues Reserves
1995 Series A Utility
Revenue Bonds Storm Drain $680 Yes No
1999 Utility Revenue
Bonds, Series A
Wastewater Collection
Wastewater Treatment
Storm Drain
$1,207 No Yes
2009 Water Revenue
Bonds (Build America
Bonds)
Water $1,977* No Yes
*Net of Federal interest subsidy
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Gas Utility based on a methodology adopted by
Council in 2009 that has remained unchanged since.16 Each year it is calculated according to the
2009 Council-adopted methodology, and does not require additional Council action.
SECTION 6F: REVENUES
The Gas Fund receives most of its revenues from sales of gas, but about 5% comes from other
sources. The largest of these comes from service connection and capacity fees, followed closely
by sales of allowances related to California’s cap-and-trade program. Another revenue item
related to the cap-and-trade program is collected in customers’ bills. While the State provides
CPAU with a certain number of free allowances each year, the Gas Utility is required to sell a
portion of those in accordance with the regulations. In order to have enough allowances to cover
16 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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customers’ natural gas emissions, CPAU must buy allowances at market, and subsequently passes
through the cost of those allowances to customers. The regulations do not allow the revenue
derived from the sale of the free allowances to offset allowance purchases, thus the pass-through
rate component.
This financial plan bases sales revenue projections on the load forecast in Section 5A: Load
Forecast. Except where stated otherwise, these load forecasts are based on normal weather.
Weather can vary substantially, however, and this can affect revenues substantially. Also,
changes in customer behavior, as well as changes to more efficient gas appliances, or switching
to electric appliances, will modify these forecasts. Staff continually evaluate forecasts to see
when new trends emerge.
SECTION 6G: COMMUNICATIONS PLAN
The FY 2019 communications strategy covers four primary areas: operations, infrastructure,
safety, efficiency, renewables and rates. Since moving to market pricing for commodity rates, the
City’s website posts changes to the commodity rates monthly. The City promotes gas use
efficiency incentives year-round, but most heavily during winter months to impact heating
activities. Promotional methods include community outreach events, print ads in local
publications, utility bill inserts, messaging on the bills and envelopes, website pages, email blasts,
videos for the web and use of social media.
To keep customers apprised of the status and accomplishments of capital improvement projects,
the City maintains a network of project web pages. Print and digital ads, social media and email
blasts drive traffic to the website. CPAU emphasizes safety topics year-round. CPAU is engaging
in several campaigns and programs in FY 2019 to promote gas utility efficiency and awareness of
the City’s carbon neutral natural gas utility. Programs such as the Home Efficiency Genie and
commercial energy efficiency programs help residents and businesses better understand energy
usage, activities and/or upgrades they can implement to improve efficiency and reduce utility
costs. CPAU will be launching an upgraded version of its online utility account services portal
(www.cityofpaloalto.org/myutilitiesaccount) this year, which can provide customers with direct
access and more information about utility account and consumption data.
Stepping up efforts to promote gas safety education, staff is focusing outreach among
stakeholders to increase awareness of the need to call USA (811) before digging for anyone who
may excavate in and around Palo Alto, such as plumbers and contractors. Staff is also focusing
outreach on the importance of contacting CPAU to check for potential sewer and gas line cross-
bores prior to clearing a sewer line. Additional outreach messaging includes keeping fats, oils and
greases out of drains, and ensuring clear access to meters. CPAU has developed a number of
safety outreach materials to distribute to customers at community outreach events, emergency
preparedness fairs, school and business meetings. The use of materials featuring photos of some
unusual ways people obstruct access to their meters, including using them as bike racks and
building storage sheds around them, highlights meter access awareness.
CPAU will continue to promote safety, infrastructure, operations, efficiency and rate adjustment
messages through a variety of marketing and media channels. Every year, CPAU publishes an
updated gas safety awareness brochure and mails it to all customers in Palo Alto, as well as to
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plumbers, contractors and excavators that may work in and around the area. Staff talk with
business customers at special facilities meetings, attend neighborhood safety and emergency
preparedness fairs and offer presentations to school and community groups. While print
materials and website pages still feature prominently, CPAU is increasing emphasis on outreach
through email newsletters, direct mail, newspaper inserts, social media and online videos. The
Gas Safety Public Awareness Plan contains saved copies of all outreach materials and logs of
activities; the Department of Transportation reviews this Plan at least once per year.
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APPENDICES
Appendix A: Gas Financial Forecast Detail
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
Appendix C: Gas Utility Reserves Management Practices
Appendix D: Description of Gas Utility Cost Categories
Appendix E: Gas Utility Communications Samples
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APPENDIX A: GAS FINANCIAL FORECAST DETAIL
($'000)($'000)
Actual Actual Actual
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
1 RATE CHANGE (%)*12%0%0%0%8%0%4%8%7%8%4%4%1%1%0%1%
2 SALES IN THOUSAND THERMS 28,901 28,117 28,881 26,719 27,829 27,434 27,289 26,752 26,847 26,547 26,245 25,939 25,726 25,507 25,095 25,071
3
4 Utilities Retail Sales 33,759 34,843 29,515 28,065 34,110 34,012 33,096 34,849 37,506 40,126 41,690 43,082 43,663 44,218 43,971 44,693
5 Service Connection & Capacity Fees 731 654 748 961 940 1,048 1,079 1,111 1,145 1,179 1,179 1,179 1,179 1,179 1,179 1,179
6 Other Revenues & Transfers In 830 313 414 2,346 694 1,508 1,818 2,261 2,599 2,895 3,185 3,467 3,740 4,074 4,079 4,205
7 Interest plus Gain or Loss on Investment (239)706 450 730 13 545 368 304 196 181 196 228 255 272 276 284
8 Total Sources of Funds 35,081 36,517 31,127 32,102 35,758 37,112 36,361 38,526 41,445 44,381 46,250 47,956 48,837 49,742 49,505 50,361
9
10 Purchases of Utilities:
11 Supply Commodity 12,461 12,992 9,537 6,648 9,720 9,998 8,587 8,226 8,205 8,200 8,268 8,429 8,569 8,708 8,855 9,001
12 Supply Transportation 994 1,333 982 (1,051)2,843 3,331 3,507 3,473 3,482 3,490 3,497 3,504 3,510 3,515 3,520 3,524
13 Total Purchases 13,455 14,325 10,519 5,597 12,563 13,329 12,094 11,699 11,687 11,690 11,765 11,933 12,079 12,223 12,375 12,525
14
15 Administration (CIP + Operating)4,273 3,988 4,007 3,337 2,450 2,519 2,577 2,640 2,707 2,775 2,845 2,906 2,968 3,051 3,106 3,178
16 Customer Service 1,358 1,338 1,195 1,097 1,581 1,643 1,700 1,781 1,858 1,925 1,992 2,051 2,107 2,155 2,184 2,237
17 Demand Side Management 630 438 632 566 855 879 900 922 945 969 993 1,015 1,036 1,065 1,084 1,110
18 Engineering (Operating)340 352 369 426 355 367 377 390 404 416 428 439 450 461 469 480
19 Operations and Maintenance 4,940 4,119 4,403 4,153 4,321 5,482 5,651 5,871 5,087 5,261 5,433 5,586 5,732 5,868 5,953 6,094
20 Resource Management 506 516 556 3,002 566 1,393 1,530 1,777 1,999 2,210 2,420 2,626 2,830 3,093 3,107 3,176
21 Debt Service Payments 296 805 804 249 227 802 801 801 803 804 805 803 800 803 1 1
22 Rent 219 419 431 443 455 467 480 492 505 519 532 546 561 574 587 601
23 Transfers to General Fund 5,971 5,811 5,730 6,194 6,594 7,035 6,888 7,069 7,069 7,972 8,214 8,629 9,072 9,547 9,539 9,538
24 Other Transfers Out 207 606 151 303 510 523 533 543 554 566 579 590 601 617 628 642
25 Capital Improvement Programs 7,620 1,026 1,832 6,889 2,214 7,804 5,197 10,217 12,080 9,815 9,892 9,970 10,050 10,131 10,214 10,299
26 Total Uses of Funds 39,814 33,743 30,629 32,256 32,690 42,243 38,728 44,202 45,698 44,922 45,898 47,095 48,286 49,587 49,248 49,880
27
28 Into/ (Out of) Reserves (4,733)2,773 498 (154)3,067 (5,131)(2,367)(5,676)(4,253)(541)352 861 551 155 257 481
29
30 Reappropriations + Commitments 19,363 11,305 6,491 6,255 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209
31 Plant Replacement 1,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
32 CIP Reserve 0 0 1,591 3,820 3,820 3,820 3,820 3,820 0 0 0 0 0 0 0 0
33 Rate Stabilization 11,318 15,981 7,215 6,018 6,539 6,411 4,291 0 0 0 0 0 0 0 0 0
34 Operations Reserve 0 0 10,847 10,296 13,549 8,547 8,300 6,915 6,482 5,941 6,293 7,153 7,705 8,673 8,930 9,411
35 Unassigned 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 1
36 Total Reserves 31,681 27,286 26,144 26,389 28,117 22,986 20,619 14,943 10,690 10,149 10,501 11,362 11,913 12,882 13,140 13,621
37 (1,142)245 1,728 (5,131)(2,367)(5,676)(4,253)(541)352 861 551 968 258 481
38 Short Term Risk Assessment Value 1,226 3,753 3,516 3,928 3,830 4,612 5,214 5,400 5,642 5,843 5,919 5,991 5,935 6,034
39
40 Operations Reserve Guidelines
41 Min (60 Days Commodity + O&M) 5,620 5,000 5,690 5,698 5,533 5,576 5,488 5,706 5,828 5,986 6,142 6,308 6,242 6,328
42 Target (90 Days Commodity + O&M) 8,429 7,500 8,535 8,547 8,300 8,364 8,232 8,560 8,742 8,978 9,213 9,462 9,362 9,492
43 Max (120 Days Commodity + O&M) 11,239 10,000 11,380 11,396 11,067 11,152 10,976 11,413 11,656 11,971 12,284 12,616 12,483 12,656
44
City of Palo Alto Gas Utility
Fiscal Year
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 33 | P a g e
APPENDIX B: GAS UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
ONE TIME PROJECTS
GS-15001 Security at Receiving Stations 64,700 64,700 - (1,101) 128,299 41,534 - - - - -
Unk AMI Project 180,000 530,000 2,320,000 - -
GS-18000 Gas ABS/Tenite Replacement - 1,500,000 - - - -
Subtotal, One-time Projects 64,700 64,700 - (1,101) 128,299 41,534 1,680,000 530,000 2,320,000 - -
GAS MAIN REPLACEMENT (GMR) PROGRAM
GS-11000 GMR - Project 21 100,000 100,000 - - 200,000 - - - - - -
GS-12001 GMR - Project 22 (150,372) 3,104,410 6,722,029 (224,576) 9,451,491 310,563 600,000
GS-13001 GMR - Project 23 337,000 700,000 - - 1,037,000 - - 6,500,000 - - -
GS-14003 GMR - Project 24 - - - - - - - 650,000 6,500,000 - -
GS-15000 GMR - Project 25 - - - - - - - - 650,000 6,500,000 -
GS-16000 GMR - Project 26 - - - - - - - - - 650,000 6,500,000
GS-20000 GMR - Project 27 - - - - - - - - - - 650,000
GS-20001 GMR - Project 28 - - - - - - - - - - -
Subtotal, Gas Main Replacement Program 286,628 3,904,410 6,722,029 (224,576) 10,688,491 310,563 600,000 7,150,000 7,150,000 7,150,000 7,150,000
TOOLS AND EQUIPMENT
GS-13002 General Shop Equipment/Tools - 50,000 - - 50,000 - 350,000 100,000 100,000 100,000 100,000
GS-14004 Gas Distribution System Model 19,574 19,574 - (4,660) 34,488 14,914 20,000 20,000 20,000
Subtotal, Tools and Equipment 19,574 69,574 - (4,660) 84,488 14,914 370,000 120,000 120,000 100,000 100,000
ONGOING PROJECTS
GS-11002 Gas System Improvements 75,624 555,672 - (114,215) 517,081 37,979 246,036 253,417 261,020 268,851 276,916
GS-03009 System Ext. - Unreimbursed - 204,455 - (19,127) 185,328 - 421,180 433,816 446,830 460,234 474,042
GS-80019 Gas Meters and Regulators 126,772 492,453 - (30,676) 588,549 96,096 376,652 387,952 399,591 411,579 423,926
Subtotal, Ongoing Projects 202,396 1,252,580 - (164,018) 1,290,958 134,075 1,043,868 1,075,185 1,107,441 1,140,664 1,174,884
CUSTOMER CONNECTIONS (FEE FUNDED)
GS-80017 Gas System Extensions 74,468 1,339,823 - (417,703) 996,588 98,562 1,303,315 1,342,415 1,382,688 1,424,169 1,466,894
Subtotal, Customer Connections 74,468 1,339,823 - (417,703) 996,588 98,562 1,303,315 1,342,415 1,382,688 1,424,169 1,466,894
GRAND TOTAL 647,766 6,631,087 6,722,029 (812,058) 13,188,824 599,648 4,997,183 10,217,600 12,080,129 9,814,833 9,891,778
Funding Sources
Connection Fees 1,017,000 - 1,078,935 1,111,303 1,144,642 1,178,981 266,894
Utility Rates 5,614,087 6,722,029 3,918,248 9,106,297 10,935,487 8,635,852 9,624,884
CIP-RELATED RESERVES DETAIL
6/30/2017
(Actual)
6/30/2018
(Unaudited)
Reappropriations 298,178 12,589,176
Commitments 349,588 599,648
GAS UTILITY FINANCIAL PLAN
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APPENDIX C: GAS UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Gas Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015
to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets
as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Gas Utility’s Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
Section 3. Distribution Fund Reserves
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Gas Utility’s Capital
Improvement Program (CIP), as described in Section 6 (CIP Reserve)
d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 8 (Operations Reserve)
f) Any funds not included in the other reserves will be considered Unassigned Reserves and
shall be returned to ratepayers or assigned a specific purpose as described in Section 9
(Unassigned Reserves)
Section 4. Reserve for Commitments
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Commitments will be set to an amount equal to the total remaining spending authority for
all contracts in force for the Wastewater Collection Utility at that time.
Section 5. Reserve for Reappropriations
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Reappropriations will be set to an amount equal to the amount of all remaining capital and
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 36 | P a g e
non-capital budgets, if any, that will be re-appropriated to the following fiscal year for each
fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. 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 12 months of budgeted CIP expense
Maximum Level 24 months 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 Council approval to hold funds
in this reserve in excess of the maximum level, if they are held for a specific future purpose
related to the CIP.
Section 7. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and held
to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate
Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization
Reserve at the end of any fiscal year, any subsequent Gas Utility Financial Plan must result in
the withdrawal of all funds from this Reserve by the end of the Financial Planning Period.
Section 8. Operations Reserve
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 37 | P a g e
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves
described in Section 4-Section 7 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for that
year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months of
the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Gas Utility’s Fund Balance
shall be automatically included in the Unassigned Reserve described in Section 9, below.
Section 9. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas Utility’s
Fund Balance will be held in the Unassigned Reserve. If there are any funds in the Unassigned
Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council
must include a plan to assign them to a specific purpose or return them to the Gas Utility
ratepayers by the end of the first fiscal year of the next Financial Planning Period. For
example, if there were funds in the Unassigned Reserves at the end of FY 2015, and the next
Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a plan
to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff may
present an alternative plan that retains these funds or returns them over a longer period of
time.
Section 10. Intra-Utility Transfers Between Supply and Distribution Funds
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 38 | P a g e
The Gas Utility records costs in two separate funds: the Gas Supply Fund and the Gas
Distribution Fund. At the end of each fiscal year staff is authorized to transfer an amount
equal to the difference between Gas Supply Fund costs and Gas Supply Fund Revenues from
the Gas Distribution Fund Operations Reserve to the Gas Supply Fund, or vice versa. Such
transfers shall be included in the ordinance closing the budget for the fiscal year.
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 39 | P a g e
APPENDIX D: DESCRIPTION OF GAS UTILITY COST CATEGORIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Gas 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 gas services.
Resource Management: This category includes gas procurement, contract management, rate
setting, and tracking of legislation and regulation related to the gas industry.
Operations and Maintenance: This category includes the costs of a variety of distribution system
maintenance activities, including:
surveying the gas system (50% of the system each year) and repairing any leaks found;
investigating reports of damaged mains or services and perform emergency repairs;
building and replacing gas services for new or redeveloped buildings; and
testing and replacing meters to ensure accurate sales metering.
This category also includes a variety of functions the utility shares with other City utilities,
including:
the Field Services team (which does field research of various customer service issues);
the Cathodic Protection team (which monitors and maintains the systems that prevent
corrosion in metal pipes and reservoirs); and
the General Services team (which manages and maintains equipment, paves and restores
streets after gas, water, or sewer main replacements, and provides welding services,
including certified gas line welding services)
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services and Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering gas efficiency programs and the
direct cost of rebates paid.
Engineering (Operating): The Gas Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX E: GAS UTILITY COMMUNICATIONS SAMPLES
ATTACHMENT H
*NOT YET APPROVED *
6055006
Resolution No. _________
Resolution of the Council of the City of Palo Alto Increasing Gas
Rates by Amending Rate Schedules G-1 (Residential Gas Service),
G-2 (Residential Master-Metered and Commercial Gas Service), G-3
(Large Commercial Gas Service), and G-10 (Compressed Natural Gas
Service Service)
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.
B.On June 11, 2018, the City Council heard and approved the proposed rate increase
at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-1 (Residential Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-1, as amended, shall become effective July 1, 2018.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-2 (Residential Master-Metered and Commercial Gas Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule G-2, as amended, shall
become effective July 1, 2018.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-3 (Large Commercial Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-3, as amended, shall become effective July 1, 2018.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-10 (Compressed Natural Gas Service Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule G-10, as amended, shall become effective
July 1, 2018.
SECTION 5. The City Council finds as follows:
a.Revenues derived from the gas rates approved by this resolution do not exceed the
funds required to provide gas service.
b.Revenues derived from the gas rates approved by this resolution shall not be used
for any purpose other than providing gas service, and the purposes set forth in
Article VII, Section 2, of the Charter of the City of Palo Alto.
Attachment H
*NOT YET APPROVED *
6055006
SECTION 6. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
SECTION 7. The Council finds that the adoption of this resolution changing gas rates
to meet operating expenses, purchase supplies and materials, meet financial reserve needs and
obtain funds for capital improvements necessary to maintain service is not subject to the
California Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec.
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After reviewing
the staff report and all attachments presented to Council, the Council incorporates these
documents herein and finds that sufficient evidence has been presented setting forth with
specificity the basis for this claim of CEQA exemption.
Attachment H
*NOT YET APPROVED *
6055006
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-1 Effective 97-1-20187
dated 119-1-20176 Sheet No G-1-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from City of Palo Alto
Utilities:
1. Separately-metered single-family residential Customers.
2.Separately-metered multi-family residential Customers in multi-family residential facilities.
B. TERRITORY:
This schedule applies anywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ....................................................................................................$10.9432
Tier 1 Rates: Per Therm
Supply Charges:
1.Commodity (Monthly Market Based) .......................................... $0.10-$2.00
2.Cap and Trade Compliance Charge ..................................................$0.00-$0.25
3. Transportation Charge........................................................................$0.00-$0.15
4.Carbon Offset Charge ........................................................................$0.00-$0.10
Distribution Charge: .............................................................................................$0.42393933
Tier 2 Rates: (All usage over 100% of Tier 1)
Supply Charges:
1.Commodity (Monthly Market Based) .......................................... $0.10-2.00
2.Cap and Trade Compliance Charge ...................................................$0.00-$0.25
3. Transportation Charge........................................................................$0.00-$0.15
4.Carbon Offset Charge ........................................................................$0.00-$0.10
Distribution Charge: .............................................................................................$0.99489319
D. SPECIAL NOTES:
1. Calculation of Cost Components
ATTACHMENT I
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-2 Effective 97-1-20187
dated 119-1-20176 Sheet No G-1-2
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance
with the state’s Cap and Trade Program, including the cost of acquiring compliance
instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap
and Trade Compliance Charge will change in response to changing market conditions,
retail sales volumes and the quantity of allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse
gases produced in the burning of natural gas. The Carbon Offset Charge will change in
response to changing market conditions, changing sales volumes and the quantity of
offsets purchased within the Council-approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges
will fall within the minimum/maximum ranges set forth in Section C.
2. Seasonal Rate Changes:
The Summer period is effective April 1 to October 31 and the Winter period is effective from
November 1 to March 31. When the billing period includes use in both the Summer and the
Winter periods, the usage will be prorated based on the number of days in each seasonal
period, and the charges based on the applicable rates for each period. For further discussion
of bill calculation and proration, refer to Rule and Regulation 11.
3. Calculation of Usage Tiers Tier 1 natural gas usage shall be calculated and billed based upon a level of 0.667 therms per
day during the Summer period and 2.0 therms per day during the Winter period, rounded to
the nearest whole therm, based on meter reading days of service. As an example, for a 30
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-3 Effective 97-1-20187
dated 119-1-20176 Sheet No G-1-3
day bill, the Tier 1 level would be 20 therms during the Summer period and 60 therms during
the Winter period months. For further discussion of bill calculation and proration, refer to
Rule and Regulation 11.
{End}
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-1 Effective 97-1-20187
dated 119-1-20176 Sheet No G-2-1
A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use less than 250,000 therms per year at one site.
2. Master-metered residential Customers in multi-family residential facilities.
B. TERRITORY: This schedule applies anywhere the City of Palo Alto provides Gas Service. C. UNBUNDLED RATES: Per Service Monthly Service Charge: ...............................................................................................$82.9278.23
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................... $0.10-$2.00
2. Cap and Trade Compliance Charges ................................................. $0.00-0.25
3. Transportation Charge........................................................................$0.00-$0.15
4. Carbon Offset Charge ........................................................................$0.00-$0.10
Distribution Charge: ........................................................................................................$0.61835767
D. SPECIAL NOTES:
1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with
the state’s Cap and Trade Program, including the cost of acquiring compliance instruments
sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade
Compliance Charge will change in response to changing market conditions, retail sales
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-2 Effective 97-1-20187
dated 119-1-20176 Sheet No G-2-2
volumes and the quantity of allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced in the burning of natural gas. The Carbon Offset Charge will change in response to
changing market conditions, changing sales volumes and the quantity of offsets purchased
within the Council-approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges will
fall within the minimum/maximum ranges set forth in Section C.
{End}
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-1 Effective 97-1-20187
dated 119-1-20176 Sheet No G-3-1
A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from the City of Palo
Alto Utilities:
1. Commercial Customers who use at least 250,000 therms per year at one site. 2. Customers at City-owned generation facilities.
B. TERRITORY:
This schedule applies anywhere the City of Palo Alto provides Nnatural Ggas Sservice.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: $400.08377.43
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................................... $0.10-$2.00
2. Cap and Trade Compliance Charges ...................................................... $0.00-0.25
3. Transportation Charge .......................................................................... $0.00-$0.15 4. Carbon Offset Charge ........................................................................... $0.00-$0.10
Distribution Charge: .....................................................................................................$0.60985687
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as
calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance
with the state’s Cap and Trade Program, including the cost of acquiring compliance
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-2 Effective 97-1-20187
dated 119-1-20176 Sheet No G-3-2
instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap
and Trade Compliance Charge will change in response to changing market conditions,
retail sales volumes and the quantity of allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases produced in the burning of natural gas. The Carbon Offset Charge will change in
response to changing market conditions, changing sales volumes and the quantity of
offsets purchased within the Council-approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges
will fall within the minimum/maximum ranges set forth in Section C. 2. Request for Service A qualifying Customer may request service under this schedule for more than one
account or meter if the accounts are located on one site. A site consists of one or more
contiguous parcels of land with no intervening public right-of- ways (e.g. streets). 3. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable City of Palo Alto full-service rate schedule.
{End}
COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-1 Effective 97-1-20187
dated 119-1-20176 Sheet No.G-10-1
A. APPLICABILITY:
This schedule applies to the sale of natural gas to the City-owned compressed natural gas (CNG) fueling station at the Municipal Service Center in Palo Alto.
B. TERRITORY: Applies to the City’s CNG fueling station location located at the Municipal Service Center in City of Palo Alto.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ...............................................................................................$56.1152.93
Per Therm
Supply Charges:
Commodity (Monthly Market Based) ................................................................ $0.10-$2.00
Cap and Trade Compliance Charges .............................................................. $0.00 to $0.25
Transportation Charge........................................................................................ $0.00-$0.15
Carbon Offset Charge ........................................................................................ $0.00-$0.10
Distribution Charge ....................................................................................................$0.01000.0093
D. SPECIAL CONDITIONS
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for
any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount
may be broken down into appropriate components as calculated under Section C. The Commodity charge is based on the monthly natural gas Bidweek Price Index for delivery at
PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the
state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to
cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will
COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-2 Effective 97-1-20187
dated 119-1-20176 Sheet No.G-10-2
change in response to changing market conditions, retail sales volumes and the quantity of
allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases produced
in the burning of natural gas. The Carbon Offset Charge will change in response to changing market
conditions, changing sales volumes and the quantity of offsets purchased within the Council-
approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for
delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges will fall
within the minimum/maximum range set forth in Section C.
{End}
ATTACHMENT J
NOT YET APPROVED
180315 jb 6054066
Resolution No. ____
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2019 Wastewater Collection Utility Financial Plan
R E C I T A L S
A.Each year the City of Palo Alto (“City”) assesses the financial position of its
utilities with the goal of ensuring adequate revenue to fund operations. This includes making
long-term projections of market conditions, the physical condition of the system, and other
factors that could affect utility costs, and setting rates adequate to recover these costs. It does
this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial 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 a
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 2019 Wastewater Utility Financial
Plan.
SECTION 2. The Council hereby approves the transfer of $342,000in FY 2019 from the
Rate Stabilization Reserve to the Operations Reserve, as described in the FY 2019 Wastewater
Utility Financial Plan approved via this resolution.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s definition of a project under Public Resources Code
Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
/ /
/ /
/ /
/ /
NOT YET APPROVED
180315 jb 6054066
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental review is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
ATTACHMENT J
FY 2019 WASTEWATER
COLLECTION UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
ATTACHMENT K
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 2 | Page
FY 2019 WASTEWATER COLLECTION
UTILITY FINANCIAL PLAN
FY 2019 TO FY 2028
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 4
Section 2A: Overview of Financial Position .................................................................................. 4
Section 2B: Summary of Proposed Actions .................................................................................. 5
Section 3: Detail of FY 2018 Rate and Reserves Proposals ....................................................... 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3C: Bill Impact of Proposed Changes .............................................................................. 7
Section 3D: Proposed Reserve Transfers ..................................................................................... 7
Section 4: Utility Overview .................................................................................................... 8
Section 4A: Wastewater Utility History ....................................................................................... 8
Section 4B: Customer base .......................................................................................................... 9
Section 4C: Collection System ...................................................................................................... 9
Section 4D: Cost Structure and Revenue Sources ...................................................................... 10
Section 4E: Reserves Structure ................................................................................................... 10
Section 4F: Competitiveness ...................................................................................................... 11
Section 5: Utility Financial Projections ................................................................................. 12
Section 5A: FY 2013 to FY 2017 Cost and Revenue Trends ........................................................ 12
Section 5B: FY 2017 Results ....................................................................................................... 13
Section 5C: FY 2018 Projections ................................................................................................. 13
Section 5D: FY 2019 – FY 2028 Projections ................................................................................ 13
Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 15
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 3 | Page
Section 5F: Alternate Scenarios ................................................................................................. 16
Section 5G: Long-Term Outlook ................................................................................................. 18
Section 6: Details and Assumptions ..................................................................................... 18
Section 6A: Wastewater Treatment Costs ................................................................................. 18
Section 6B: Operations .............................................................................................................. 19
Section 6C: Capital Improvement Program (CIP) ....................................................................... 19
Section 6D: Debt Service ............................................................................................................ 21
Section 6E: Other Revenues ....................................................................................................... 23
Section 7: Communications Plan .......................................................................................... 23
Appendices ......................................................................................................................... 24
Appendix A: Wastewater Collection Financial Forecast Detail .................................................. 25
Appendix B: Wastewater Collection Utility Capital Improvement Program (CIP) Detail .......... 27
Appendix C: Wastewater Collection Utility Reserves Management Practices .......................... 28
Appendix D: Map (CPA Wastewater Collection System - Sewer Mains Replaced or
Rehabilitated since 1990) .......................................................................................................... 31
Appendix E: Sample of Wastewater Collection Outreach Materials ......................................... 32
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 4 | Page
SECTION 1: DEFINITIONS AND ABBREVIATIONS
CCF The standard unit of measurement for water delivered to water customers, equal to
one hundred cubic feet, or roughly 748 gallons. When water usage is used to assess
wastewater charges for commercial customers, it is measured in CCF.
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
FOG Fats, oils, and grease. When flushed into the sewer system, these materials
accumulate in parts of the sewer system and create blockages.
O&M Operations and Maintenance
RWQCP Regional Water Quality Control Plant, the wastewater treatment plant owned and
operated by the City of Palo Alto that serves Palo Alto and several surrounding
communities.
UAC Utilities Advisory Commission
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City of Palo Alto’s Wastewater Collection Utility
for the next ten years. The Financial Plan provides revenues to 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
Overall costs in the Wastewater Collection Utility are expected to rise by an average of
approximately 6.9% per year from fiscal year (FY) 2018 to FY 2028. Wastewater treatment costs
are projected to rise by an average of approximately 6.6% annually and collection system CIP
costs are projected to rise substantially by FY 2019 as new sewer main replacement projects
begin. While CPAU aims to complete one main replacement project each year, no project was
budgeted for FY 2017 and FY 2018 to allow staff to complete previous year projects that had
been delayed. After FY 2019, staff project CIP costs to rise at approximately 1.5% annually
through the projection period. Table 1 below shows the costs for the Wastewater Collection
Utility.
Table 1: Expenses for FY 2017 to FY 2028
Expenses
($000)
FY
2017
(act.)
FY
2018
(est.)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Treatment
Costs
8,391 10,418 10,798 11,846 12,888 13,571 14,005 14,692 15,676 16,083 16,453 16,914
Operations 5,536 5,923 6,086 6,270 6,455 6,629 6,803 6,828 6,979 7,143 7,250 7,407
Capital
Projects
1,332 2,955 6,629 5,936 6,133 6,296 6,486 6,681 6,882 7,088 7,302 7,521
TOTAL 15,258 19,296 23,513 24,051 25,476 26,497 27,294 28,201 29,536 30,315 31,005 31,842
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 5 | Page
The increase in CIP expenses also reflects higher contract bid prices for underground
construction. Going forward, to ensure that revenues cover rising costs and reserves remain
healthy, the financial plan includes the proposed and projected rate changes shown in Table 2.
The table also shows rate projections from last year’s Financial Plan. Last year’s plan projected
lower increases through FY 2028 because of lower treatment cost projections and lower capital
budget estimates.
Staff originally proposed a 10% rate increase for FY 2019 at the March 7, 2018 UAC meeting.
The UAC voted instead to recommend an 11% increase (Alternative Scenario 1 from the FY
2019 Wastewater Financial Plan to the UAC, Section 5F: Alternate Scenarios), and Staff
concurred with the recommendation. This financial plan has been revised to reflect the 11%
proposal.
Table 2: Proposed / Projected Wastewater Collection Rate Trajectory for FY 2019 to FY 2028
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Current Plan 11% 12% 10% 6% 4% 3% 3% 3% 3% 1%
FY 2018 Plan 7% 7% 7% 7% 7% 5% 5% 4% 3% N/A
The Wastewater Collection Utility has a small balance in its Rate Stabilization Reserve. This
reserve is used to phase in rate increases over multiple years to reduce rate impacts to
customers. The FY 2018 Financial Plan projected a transfer from the Rate Stabilization Reserve
would not be needed until 2020. However, this Financial Plan anticipates that transfer in FY
2019. The Operations Reserve was above its target level in FY 2017, but will decline in FY 2019
through 2021, going below the minimum guideline levels in FY 2020 and going back above the
reserve minimum in FY 2023 (see more detail in Figure 5).
Table 3: Transfers To/(From) Reserves for FY 2018 to FY 2028 ($000)
Reserve FY 2018 FY 2019 FY 2020 to FY 2028
CIP Reserve - - (978)
Rate Stabilization - (342) -
Operations - 342 978
Unassigned - - -
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Wastewater Collection Utility in FY 2019:
1. Increase rates by 11%, primarily reflecting increases to capital expenditures. This is
described in more detail in Section 3B: Current and Proposed Rates.
2. Transfer $342,000 from the Rate Stabilization Reserve to the Operations Reserve in FY
2019.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 6 | Page
SECTION 3: DETAIL OF FY 2018 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The Wastewater Collection Utility’s rates are evaluated and implemented in compliance with
the cost of service requirements and procedural rules set forth in the California Constitution
(Proposition 218). Current rates were structured based on staff’s annual assessment of the
wastewater utility’s financial position, as well as the methodology from the January 2011
Wastewater Collection Utility Cost of Service & Rate Study completed by Utility Financial
Solutions (Staff Report 1399). Staff plans to review and update this cost of service study in FY
2019. Before conducting any new cost of service study, staff will review current rates and the
scope of the study with the Utilities Advisory Commission (UAC) and Council to determine the
City’s policy priorities.
SECTION 3B: CURRENT AND PROPOSED RATES
The current rates were adopted July 1, 2016, when the City increased sewer rates by 9%.
CPAU has three sewer rate schedules: one for residents (S-1), one for commercial customers
(S-2), and a special schedule for restaurants (S-6), which discharge higher than average amounts
of grease and oil and, therefore, have a greater impact on the sewer system. Residential
customers are billed a monthly service charge, while commercial customers are billed based on
their winter month water usage (previous January through March). This closely approximates
non-irrigation water consumption, which represents actual sewer use. Restaurant customers are
billed monthly based on water usage. CPAU also maintains a rate schedule for industrial
dischargers (S-7), but there are currently no customers required to be on this rate schedule.
CPAU proposes an 11% rate increase in FY 2019 in order to fund upcoming capital projects and
operations costs. Table 4, below, summarizes the current and proposed rates for all customer
classes. Section 4F: Competitiveness discusses comparisons with neighboring communities.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 7 | Page
Table 4: Current Sewer Rates
Current
(as of 7/1/2016)
Proposed
(effective 7/1/2018
Monthly Service and Minimum Charges ($/month)
S-1 (Residential) Service charge $34.83 $38.66
S-2 (Commercial),
S-6 (Restaurant)
Minimum 34.83 38.66
Quantity Rates: based on winter water usage (average
for January - March bill period)
S-2 (Commercial) $/CCF 6.71 7.45
S-6 (Restaurant) $/CCF 10.38 11.52
S-7 (Industrial) $/CCF 3.08 3.42
SECTION 3C: BILL IMPACT OF PROPOSED CHANGES
Table 5 below shows the impact of the proposed July 1, 2018 rate changes:
Table 5: Impact of Proposed Sewer Changes
Current
(as of
7/1/2016)
Proposed
(effective
7/1/2018)
Change
$/mo. %
Residential $34.83 $38.66 $3.83 11%
General Commercial (14
CCF)
93.94 104.30 10.36 11%
Restaurant (56 CCF) 581.28 645.12 63.84 11%
SECTION 3C: PROPOSED RESERVE TRANSFERS
In the FY 2017 Financial Plan, staff recommended a $1.95 million transfer from the Rate
Stabilization Reserve in FY 2016. This left a small amount, $342,000, which was originally to be
transferred in FY 2017 to bring the Rate Stabilization Reserve balance to zero.
However, because new main replacement projects were deferred in FY 2017 and FY 2018,
resulting in one-time cost savings, the Operation Reserve ended above the maximum guideline
level, and the transfer was not needed. Staff anticipates it will need to transfer the remaining
$342,000 in FY 2019. In addition, staff will propose transferring the remaining $978,000 from
the CIP Reserve to the Operation Reserve in FY 2020.
These transfers are included in the financial projections in this Financial Plan, and will enable
CPAU to maintain adequate Operations Reserve levels while moderating the pace of increase in
Wastewater Collection rates. Appendix A: Wastewater Collection Financial Forecast Detail
shows the impact of these transfers on reserves levels.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 8 | Page
SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information and to help readers better understand the forecasts in later sections.
SECTION 4A: WASTEWATER UTILITY HISTORY
The Wastewater Utility commenced operation in 1899 to serve Palo Alto and Stanford. In its
first three decades the system grew to 60 miles of sewers. Raw sewage was discharged into
Mayfield Slough at the edge of the Bay. In the 1930s, at the behest of the State Department of
Health, Palo Alto built the South Bay’s first wastewater treatment plant. At that time the sewer
system served 20,500 Stanford and Palo Alto residents and a cannery. The plant was upgraded
twice in the 1940s and 1950s to increase capacity.1 At the same time, the postwar population
and industrial boom in the 1950s required rapid expansion of the sewer system. In the first half
of the 1960s Palo Alto’s area doubled, as did wastewater flows, overwhelming the capacity of
several of the utility’s “trunk lines,” which are the largest diameter main sewer lines carrying
wastewater to the treatment plant. This prompted the City, in 1965, to perform the first of its
sewer master plans to identify needed capacity improvements. At that point the Wastewater
Utility’s system comprised more than 150 miles of sewer mains.2
In 1968 the City signed agreements with the Cities of Mountain View and Los Altos to build a
new regional treatment plant, the RWQCP, which is still in operation today. Since 1940 the City
had been providing treatment services to the East Palo Alto Sanitary District through an existing
agreement, and was also serving Stanford University by transporting wastewater across the
City’s sewer system to the treatment plant. Both of these organizations became partners in the
RWQCP as well. At the same time the Town of Los Altos Hills became the sixth partner as it
signed an agreement with the City to connect the Town’s sewer system to the City’s sewer
system to carry wastewater to the new RWQCP. The current agreements for the RWQCP
extend through 2035.3
In the 1980s the City directed increased attention to the condition of its sewer system,
performing a series of studies of groundwater inflow and infiltration into the system. The
studies found high rates of infiltration, estimating that as much as 40% of the water going to
the RWQCP from Palo Alto’s system was groundwater and stormwater rather than
wastewater.4 In some parts of Palo Alto the land surface had subsided due to groundwater
pumping by the water utility, and though that practice had ceased many years earlier as the
water utility switched to the Hetch Hetchy Regional Water System, parts of the city had already
subsided two to five feet. This subsidence had damaged several parts of the sewer collection
system, leading to reduced slopes for sewer mains that caused reductions in capacity. In
1 Long Range Facilities Plan for the Regional Water Quality Control Plant, August 2012, Carollo Engineers, pp 2-1
through 2-2 2 Wastewater Collection and Storm Drainage, 1965, Brown and Caldwell Consulting Engineers, pp 4, 6-7, 143 3 Long Range Facilities Plan for the Regional Water Quality Control Plant, August 2012, Carollo Engineers, pg 2-2 4 Wastewater Collection System Master Plan – Capacity Assessment, January 2004, MWH Americas, Inc., pg ES-2
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 9 | Page
response to these studies the City commenced an accelerated sewer system rehabilitation
program.5 At that point the sewer system comprised over 190 miles of mains.6
A Master Plan study in 1988 recommended a variety of capacity expansions, and in the 1990s
the City completed about half of them. However, a 2004 Master Plan update found that the
accelerated sewer rehabilitation plan started in the early 1990s had substantially reduced
infiltration, easing the capacity problems that had led the to the recommended capacity
increases in the 1988 study. Several of the outstanding projects were canceled and replaced
with a different set of projects.7 At the same time the City updated its hydraulic model and
developed greater capacity to do system planning in house.
SECTION 4B: CUSTOMER BASE
The City of Palo Alto’s Wastewater Collection Utility provides sewer service to the residents and
businesses of Palo Alto. It is distinct from the Wastewater Treatment Utility, which provides
treatment services for surrounding communities in addition to Palo Alto. Nearly 22,500
customers are connected to the sewer system, approximately 20,650 (92%) of which are
residential and 1,850 (8%) of which are non-residential. Residential customers pay a flat fee for
service. Non-residential customers are billed for sewer service based on their metered winter
water usage. There is relatively little variability in revenues for this utility.
SECTION 4C: COLLECTION SYSTEM
The Wastewater Collection Utility delivers all the wastewater it collects to the Regional Water
Quality Control Plant (RWQCP) operated by the City of Palo Alto under a partnership agreement
with several surrounding communities. Palo Alto is responsible for 35% to 40% of the
wastewater sent to the RWQCP. This Financial Plan does not describe the cost of running the
RWQCP in detail as this cost is contained in the Wastewater Treatment Utility; however since
these costs are a major driver of CPAU’s sewer rates, Section 6A: Wastewater Treatment Costs
provides some discussion of future trends in treatment costs. Treatment costs make up nearly
half of the Wastewater Collection Utility’s expenses as shown in Table 1 above.
To collect wastewater from its customers and deliver it to the RWQCP, CPAU owns roughly
18,140 sewer laterals (which collect wastewater from customers’ plumbing systems) and 217
miles of sewer mains (which transport the waste to the treatment plant). These laterals and
mains, along with the associated manholes and cleanouts, represent the vast majority of
infrastructure used to collect wastewater in Palo Alto. CPAU conducts a sewer rehabilitation
and replacement program to replace mains over time as they deteriorate or to increase
capacity. For more discussion of this program, see Section 6C: Capital Improvement Program
(CIP). CIP expense accounts for roughly a quarter of the utility’s expenditures.
In addition to its CIP, CPAU performs various maintenance activities on the sewer system.
These include inspecting and repairing sewer laterals, responding to sewer overflows, regularly
5 CMR 183:90, Infrastructure Review and Update, March 1, 1990 6 Master Plan of the Wastewater Collection System, December 1988, Camp Dresser & McKee, Inc., pg 1-2 7 Wastewater Collection System Master Plan – Capacity Assessment, January 2004, MWH Americas, Inc., pg ES-3
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 10 | Page
cleaning sections of the system heavily impacted by fats, oils, and grease (FOG), and building
and replacing sewer laterals for new or redeveloped buildings. The utility also shares the costs
of other operational activities (such as customer service, billing, equipment maintenance, and
street restoration) with the City’s other utilities. These maintenance and operations expenses,
as well as associated administration, debt service, rent, and other costs, make up approximately
another quarter of the utility’s expenses.
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
In FY 2017, treatment costs represented slightly more than half of the Wastewater Collection
Utility’s costs (54%), and Operations costs represented nearly a third (37%), while Capital
spending was relatively low (9%). Figure 1 shows these expenditures. The utility’s revenue in FY
2017, shown in Figure 2, came primarily from sewer charges (92%), with the remainder coming
mainly from capacity and connection fees and other sources (8%).
Figure 1: Cost Structure (FY 2017) Figure 2: Revenue Structure (FY 2017)
SECTION 4E: RESERVES STRUCTURE
CPAU maintains six reserves for its Wastewater Collection Utility to manage various types of
contingencies. Below is a summary of these reserves and Appendix C: Wastewater Collection
Utility Reserves Management Practices provides more detailed definitions and guidelines for
reserve management:
• Reserve for Commitments: A reserve equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserve for Reappropriations: A reserve 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.
• Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to
accumulate funds for future expenditure on CIP projects and is anticipated to be empty
unless a major one-time CIP expenditure is expected in future years. It also acts as a
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 11 | Page
contingency reserve for the CIP. This type of reserve is used in other utility funds
(Electric, Gas, and Water) as well.
• Rate Stabilization Reserve: This reserve is 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 (Electric, Gas, and Water) as well.
• Operations Reserve: This is the primary contingency reserve for the Wastewater
Collection Utility, and is used to manage yearly variances from budget for operational
costs. This type of reserve is used in other utility funds (Electric, Gas, and Water) as well.
• Unassigned Reserve: This reserve is for any funds not assigned to the other reserves
and is normally empty.
SECTION 4F: COMPETITIVENESS
Table 6 shows the monthly sewer bills for residential customers compared to what they would
be in surrounding communities. The annual sewer bill for a Palo Alto customer is $418 under
current rates, 33% lower than the average neighboring community. Palo Alto has the second
lowest bill of the group.
Table 6: Residential Monthly Equivalent Sewer Bill Comparison ($)
Palo Alto
Neighboring Communities Neighboring
Community
Average
Menlo
Park
Redwood
City
Mountain
View Los Altos
Santa
Clara Hayward
34.83 89.33 76.68 37.75 36.27 41.65 31.29 52.16
Based on rates as of February 2018
Table 7 compares the sewer bills for two classes of commercial customers to what they would
be under surrounding communities’ rate schedules. Note that other communities often have
specific rates for industrial customers that discharge high intensity wastewater, such as food
processors or chemical or electronics manufacturers, but Palo Alto does not currently have any
customers that require these special rates. Palo Alto is less competitive with surrounding cities
with regards to commercial sewer rates, but is not the most expensive jurisdiction in all cases.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 12 | Page
Table 7: Commercial Monthly Sewer Bill Comparison ($)
Palo Alto
Neighboring Communities Neighboring
Community
Average
Menlo
Park
Redwood
City
Mountain
View Los Altos
Santa
Clara Hayward
General
Commercial
93.94 133.84 101.22 69.16 50.76 65.94 71.12 82.01
Restaurant 581.28 815.36 969.36 539.84 137.70 590.24 514.64 594.52
Based on rates as of February 2018
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: FY 2013 TO FY 2017 COST AND REVENUE TRENDS
Figure 3 shows the Wastewater Collection Utility’s actual expenses and revenues for the past
five years and projections through FY 2028. Collections operations expenses have fluctuated
but on average have grown around 2% per year. Wastewater collection capital investment
fluctuated greatly during this time period: FY 2014 saw a reduction in investment mainly due to
delayed main replacement projects, and FY 2015 and 2016 saw increased capital investment as
those capital projects were completed. Treatment operations costs and capital expense stayed
relatively flat during this timeframe.
Since the revenue for this utility is very stable, revenue changes closely follow rate changes. The
other large revenue item of note is the continued connection and capacity fees from new
construction. These fees have grown dramatically between FY 2010 and FY 2015 and then
plateaued.
Figure 3: Wastewater Collection Utility Expenses, Revenues and Rate Changes
Actual Costs through FY 2017 and Projections through FY 2028
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 13 | Page
SECTION 5B: FY 2017 RESULTS
Actual revenues for FY 2017 were lower than forecast revenues ($18.4 million actual vs. $19.0
million projected). Total FY 2017 expenses were $15.3 million compared to projections of $17
million in the FY 2018 Financial Plan. Table 8 summarizes the variances from forecast.
Table 8: FY 2017, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/
(Benefit)
Type of
Change
Wastewater treatment costs lower than forecast $(1,464) Cost decrease
Sales revenues higher than forecast $(121) Revenue increase
Interest, Connection, capacity fees and other revenues $723 Revenue decrease
Operations, capital and other cost decreases $(245) Cost decrease
Net Cost / (Benefit) of Variances $(1,108)
SECTION 5C: FY 2018 PROJECTIONS
This year staff is estimating higher costs for FY 2018. Capital Improvement costs increased by
around $0.8 million for main replacement project design costs not included in last year’s
projections. Another contributing factor is staff projects higher treatment costs due to
increasing capital and operations costs at the RWQCP. Additionally, actual revenues from
connection and capacity fees and interest were lower than projected in FY 2017; for this reason
staff projects less revenue from these sources in FY 2019. Table 9 summarizes the variances
from the prior forecast.
Table 9: FY 2018, Updated Projections vs. Financial Plan Forecast ($000)
Net Cost/
(Benefit)
Type of
Change
Wastewater treatment cost increases $486 Cost increase
Higher Capital Improvement and Operations costs $1,197 Cost increase
Reduced Revenues $478 Revenue decrease
Net Cost / (Benefit) of Variances $2,162
SECTION 5D: FY 2019 – FY 2028 PROJECTIONS
As shown in Figure 3 above (and, in more detail, in Appendix A: Wastewater Collection Financial
Forecast Detail), the Wastewater Collection Utility’s total costs are projected to increase by
roughly 5.3% per year on average for FY 2018 through FY 2028. The majority of this increase is
due to projected capital cost increases for treatment as well as collection. The treatment plant
itself is facing the need for major upgrades in coming years, due to aging equipment and
changing environmental regulations. The costs of the plant are shared among member
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 14 | Page
agencies, with members expected to see average cost increases of around 5% per year over the
forecast horizon. As noted previously, capital expenses were lower than usual in FY 2017 and
FY 2018 as sewer main replacement projects were delayed to enable staff to complete previous
year projects, but regular annual main replacement will resume in FY 2019. However,
underground construction costs for all utilities have increased significantly. This means that the
FY 2019 capital budget for a main replacement project is 30.7% higher than in FY 2016, which
was the most recent “normal” year in the CIP program (a year when an annual sewer main
replacement project was budgeted). This increase in construction costs is a partial contributor
to future year rate increases. After FY 2019, staff expects overall collection system capital costs
to increase on average by 1.3% for FY 2020 through 2028.
The red line in Figure 3 shows revenue levels and the figure shows that there have been several
years where costs exceeded revenues. This trend is projected to continue every year from 2018
through 2021. This will result in a fairly rapid reduction of reserves. Staff projects annual rate
increases of 11% to 12% in the near term, decreasing in later years, are required to keep
reserves from dropping below minimum reserve guidelines. Figure 4 below shows the relative
drop in reserves through FY 2021, which begin to recover starting in FY 2022.
Figure 4: Wastewater Collection Reserves Projections
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February 2018 15 | Page
SECTION 5E: RISK ASSESSMENT AND RESERVES ADEQUACY
The Wastewater Collection Utility currently has one contingency reserve, the Operations
Reserve. This Financial Plan as presented results in the Operations Reserve nearing the
minimum guideline level, but reaching the Target level by the end of the forecast period.
Alternative plans could result in reserves being higher, but these would result in larger rate
increases. Similarly, lower rate increases would result in lower reserves for a longer period.
Figure 5 below shows the proposed Staff plan.
Figure 5: Operations Reserve Adequacy
Staff performs an annual assessment of risks for the Wastewater Collection Utility. For this
evaluation, staff estimates the revenue shortfall due to:
1. the maximum observed budget-to-actual variance in one year during the past five years;
2. an increase of 10% in system improvement CIP expenditures for the year; and
3. an increase of 10% in treatment costs.
Table 10 summarizes the risk assessment calculation for the Wastewater Collection Utility
through FY 2023. The Operations Reserve is projected to be adequate to manage these levels
of risk over the entire forecast period.
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February 2018 16 | Page
Table 10: Wastewater Collection Risk Assessment
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Total Revenue ($000) 18,988 21,259 23,401 24,840 25,854
Max. Historical Budget-to-Actual variance 4% 4% 4% 4% 4%
Budget-to-Actual Risk ($000) 760 850 936 994 1,034
System Rehabilitation CIP Budget ($000) 6,211 5,505 5,690 5,840 6,015
CIP Contingency @10% ($000) 621 551 569 584 602
Treatment Budget ($000) 10,798 11,846 12,888 13,571 14,005
Treatment Cost Contingency @10% ($000) 1,080 1,185 1,289 1,357 1,401
Total risk assessment value ($000) 2,460 2,585 2,794 2,935 3,036
Projected Operations Reserve Level ($000) 3,461 3,503 3,269 3,373 3,884
SECTION 5F: ALTERNATE SCENARIOS
When utilizing a combination of reserves and rate changes, many possible alternatives exist.
Alternative scenario 1 explores a revised set of rate increases that brings reserves below the
minimum guideline level for three years (This 10% proposal was originally brought to the UAC
on March 7, 2018, but the UAC instead voted for the Current Plan of 11%). Table 11 below
shows the rate increases associated with this scenario and Figure 6 show the reserves dropping
below the minimum guideline level.
Table 11: Alternative Scenario 1 – Reserves Below Minimum Guideline
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Current Plan 11% 12% 10% 6% 4%
Alternative 10% 11% 11% 9% 4%
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February 2018 17 | Page
Figure 6: Alternative Scenario 1 – Reserves Below Minimum Guideline
Similarly, another possible alternative would be to try and keep rate increases below 10%. In
alternative scenario 2, a series of 9% rate increases from FY 2019 to FY 2024 would result in
reserves nearly going to zero in FY 2022. While useful for purposes of illustration, this is not a
course Staff would recommend. Figure 7 below shows the impact of alternative scenario 2 on
reserves.
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February 2018 18 | Page
Figure 7: Alternative Scenario 2 – Keep Rate Increases Below 10%
SECTION 5G: LONG-TERM OUTLOOK
In the longer term (5 to 35 years) the primary factor that could lead to increased costs for the
Wastewater Collection Utility are major upgrades at the RWQCP, a share of which will be
allocated to the utility as part of treatment costs. These upgrades includes replacement or
rehabilitation of the parts of the facility that pump raw sewage to the main treatment works
(the headworks), separate out primary sludge (the primary settling tank), process sludge (the
bio-solids facility), and treat wastewater (the fixed film reactors). Upgrades to the laboratories
and operational buildings are planned as well. In addition, the 72-inch regional trunk sewer line
flowing into the plant needs to be evaluated and rehabilitated.
SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: WASTEWATER TREATMENT COSTS
Treatment expenses represent the Wastewater Collection Utility’s share of the costs of
operating the RWQCP. Per the partnership agreements between Palo Alto and its partner
agencies, these charges are assessed based on a formula that takes into account the total
amount of wastewater delivered, the amount of organic material in it, its ammonia content,
and the total suspended solids it is carrying. The Wastewater Collection Utility’s assessed share
of the RWQCP’s revenue requirement fluctuates in the 38% to 40% range. Mountain View is
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 19 | Page
the other large agency served by the RWQCP (39% of the revenue requirement for FY 2014)
with the smaller agencies (Stanford, Los Altos, East Palo Alto, and Los Altos Hills) making up the
remainder of the flow to the treatment plant.
Based on detailed project cost projections provided by RWQCP staff, treatment costs are likely
to continue to increase by roughly 5% per year through at least 2030. Wastewater Treatment
Fund costs are increasing due to rising salary and benefit costs as well as the attendant
allocated charges for centralized city services needed to support wastewater treatment fund
operations. Additional expenses include increased water and air permitting fees from the
Regional Water Quality Control Board and the Bay Area Air Quality Management District.
Commodity and utility rates to operate the facility are also increasing with the largest increases
in FY 2019 for electrical, water, gas, and storm rates. Chemical expenses, needed to adjust
water quality and meet permit requirements, are also increasing modestly per the latest
chemical market conditions and procurement contract conditions.
Capital projects, parts, and materials are increasing at about 3% per year to keep up with
ongoing replacement of aging equipment. Larger increases to capital expenses are expected to
begin in FY 2020 in the form of new debt service for major projects to implement the Plant’s
capital program. The Plant’s major project in FY 2018 will be making progress constructing the
Sludge Dewatering and Truck Loadout Facility, which will allow (in about 2019) the retirement
of the Plant’s two sewage sludge incinerators that have been in operation since 1972.
SECTION 6B: OPERATIONS
Operations costs include the Customer Service, Distribution Operations, Engineering, and
Allocated Charges categories in Appendix A: Wastewater Collection Financial Forecast Detail.
Debt service, rent, and transfers are also included in this category. Customer Service costs are
primarily related to the call center and collections on delinquent accounts. The Distribution
Operations category includes preventative and corrective maintenance on sewer mains and
laterals, investigation of sewer overflows, regular cleaning of heavily impacted sections of the
sewer system, and services shared with other utilities (such as street restoration and
equipment maintenance). Allocated Charges include the costs of accounting, purchasing, legal,
and other administrative functions provided by the City’s General Fund staff, as well as shared
communications services and Utilities Department administrative overhead and billing system
maintenance costs.
Operations costs are projected to increase by 2.7% per year, on average, over the forecast
period. Underlying these projections are salary and benefit, consumer price index, and other
cost projections used in the City’s long-range financial forecast.
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
The Wastewater Collection Utility’s CIP consists of the following programs:
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February 2018 20 | Page
• The Sanitary Sewer Replacement/Rehabilitation (SSR) Program, under which the
Wastewater Collection Utility replaces aging sewer mains.
• Customer Connections, which covers the cost when the Wastewater Collection Utility
installs new laterals or upgrades existing laterals at a customer’s request in response to
development or redevelopment. CPAU charges a fee to these customers to cover the
cost of these projects.
• Ongoing Projects, which covers the cost of replacing deteriorated manholes and sewer
laterals, as well as the cost of capitalized tools and equipment.
The Sanitary Sewer Replacement and Rehabilitation Program funds the replacement of
deteriorating sewer mains to increase capacity or improve pipe condition in various parts of the
sewer system. The sewer system consists of over 217 miles of mains, and CPAU uses a variety
of tools to establish which sections are in need of replacement. The 2004 Master Plan study
identified wastewater mains with capacity deficiency and they have been corrected in past CIP
projects. For condition assessment, maintenance statistics (such as records of the location and
number of sewer overflows on the system) and videotape of sewer mains from a past video
inspection of sewer main project or during regular cleaning can reveal areas with deteriorating
pipe. CPAU uses a structural rating system to grade the pipe defects. The video-inspection
data and maintenance records are used to plan and prioritize sewer main replacement and
rehabilitation.
Utilities also coordinates with the Public Works street maintenance program to avoid cutting
into newly repaved streets. A major goal of the replacement program is to minimize sewer
overflow and reduce groundwater and rainwater infiltration. As mains deteriorate they begin
to allow roots into the pipe joints to create blockages, permitting groundwater and rainwater to
infiltrate the system. Some level of infiltration is expected on any sewer system, but if there is
too much, the combined flow of wastewater and groundwater/rainwater can overwhelm the
capacity of various parts of the sewer system. Reducing infiltration can reduce the need to
expand the system to accommodate increased flow, as well as reducing unnecessary amounts
of water to be treated at the treatment plant. To achieve this goal, deteriorating mains are
either rehabilitated with a plastic lining or replaced with new HDPE pipe. Staff has been
replacing/rehabilitating the mains as needed according to their condition. In addition,
Wastewater Operations’ routine maintenance continues to stay on schedule to minimize sewer
overflows.
Over the last few years, main replacement costs have been increasing for utilities due to
economic activity in the Bay Area causing construction cost inflation. It is likely that this trend
will continue in the short term.
This increase in cost is a partial reason for a one year delay in projects. Staff deferred its FY
2018 replacement project because all Field Inspectors were busy providing inspection services
for one water and two previous wastewater construction projects. Several Engineers were also
focusing on designing, coordinating amongst all departments, and setting up the contract for
the complicated Upgrade Downtown project. However, Utilities Engineering has been
consistently replacing aging sewer mains since the early 90’s. The proactive replacement
program keeps the collection system in good condition. Between 1990 and 2017, 67 miles or
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February 2018 21 | Page
31% of the collection system has been replaced or rehabilitated (the red-colored lines shown in
the attached map in Appendix D: Map (CPA Wastewater Collection System - Sewer Mains
Replaced or Rehabilitated since 1990). This is an average of approximately 13,530 feet (~2.6
miles), or 1.2% of the system, of sewer main being replaced or rehabilitated per year. Given
sewer main expected lifetimes, this is a sustainable replacement rate.
In many cases, annual projects get combined together to save administrative time/cost and to
make the project more attractive for contractors to bid. The most recent Sanitary Sewer
Replacement (SSR) projects SSR 24/25/26 and SSR 27 were substantially completed in April of
2017. Staff is currently working on re-evaluating and re-prioritizing the scope of future projects
based on the structural rating system and available budget. Part of the assessment is to
evaluate whether a slightly reduced replacement rate would jeopardize the integrity of the
system, since large portions of the mains that have not been replaced or rehabilitated are
located in sub-divisions that were developed between 1950 and 1970.
Customer Connections costs are projected to increase steadily by around 3% each year through
the end of the forecast period. Actual expenses for these projects fluctuate annually depending
on how many defective laterals and manholes are discovered during routine maintenance, as
well as how much development and redevelopment is going on that prompts the replacement
or upgrade of sewer laterals. It is worth noting that property owners pay a fee for sewer lateral
replacement or expansion during redevelopment, so when the number of projects increases, so
does fee revenue.
Table 12 displays projected CIP spending for the 5-year financial forecast period.
Table 12: Projected CIP Spending
Aside from Customer Connections, the CIP plan for FY 2019 to FY 2023 is funded by sewer rates
and capacity fees. Appendix B: Wastewater Collection Utility Capital Improvement Program
(CIP) Detail shows the details of the plan.
SECTION 6D: DEBT SERVICE
The Wastewater Collection Utility currently pays its share of one bond issuance, the 1999 Utility
Revenue Bonds, Series A, which is due to be retired in 2024. This $17.7 million issuance
refinanced various earlier Storm Drain, Wastewater Treatment, and Wastewater Collection
Utility bond issuances. The Wastewater Collection Utility’s share of the issuance was roughly
$1.9 million. This amount represented the second refinancing of the remaining principal of a
1990 bond issuance, which itself was a refinancing of a 1985 issuance that financed a variety of
improvements to the sewer system. The cost of debt service for the Wastewater Collection
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Sewer Rehab/Augmentation 2,665 (960) 1,704 1,416 4,800 4,520 4,675 4,796 4,939
Ongoing Projects 1,626 (290) 1,336 535 959 985 1,015 1,043 1,073
Customer Connections 458 (136) 321 54 418 431 443 457 470
TOTAL 4,748 (1,386) 3,362 2,005 6,176 5,936 6,133 6,296 6,483
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 22 | Page
Utility’s share of this bond issuance for the financial forecast period is roughly $128,000 per
year as shown in Table 13 below.
Table 13: Wastewater Collection Utility Debt Service ($000)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
1999 Utility Revenue Bonds, Series A 128 128 129 129 129 0
The 1999 Utility Revenue Bonds include two covenants stating that 1) the Wastewater
Collection Utility will maintain a debt coverage ratio of 125% of debt service, and 2) that the
City will maintain “Available Reserves”8 equal to five times the annual debt service. The current
financial plan maintains compliance with both covenants throughout the forecast period. Table
14, below, shows compliance with the first covenant. Due to the small size of the annual debt
service payment for these bonds, the Wastewater Collection Utility’s Operations Reserve alone
more than satisfies the second covenant at more than 30 times annual debt service throughout
the forecast period.
Table 14: Debt Service Coverage Ratio ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Revenues 17,167 18,978 21,249 23,391 24,830 25,844
Expenses (Excl. CIP
and Debt Service)
14,214 14,320 15,531 16,732 17,560 18,024
Net Revenues 2,952 4,658 5,718 6,658 7,270 7,819
Debt Service 128 128 128 129 129 129
Coverage Ratio 2299% 3633% 4477% 5179% 5632% 6049%
The Wastewater Collection Utility’s reserves (but not its net revenues) are also considered
security for the Storm Drain and Wastewater Treatment Utilities’ shares of the debt service on
the 1999 bonds. Throughout the term of the bonds there remains a small risk that the
Wastewater Collection Utility’s reserves could be called upon to make a debt service payment
on behalf of one of those utilities if it cannot meet its debt service obligations. Staff does not
foresee this occurring based on the current financial condition of those utilities. If the
Wastewater Collection Utility’s reserves were used this way, any amounts advanced would
have to be repaid by the borrowing utility.
One other bond series is secured by the net revenues (but not the reserves) of the Wastewater
Collection Utility. The 1995 Series A Utility Revenue Bonds issued for the Storm Drain utility
were secured by the net revenues of the City’s “Enterprise,” which was defined as the City’s
water, gas, wastewater, storm drain, and electric utilities, and are senior to the 1999 bonds
referenced above. Debt service payments of roughly $680,000 per year are made on the 1995
Series A bonds by the City’s Storm Drain Utility, and staff does not currently foresee any risk of
that utility being unable to make payment.
8 Available Reserves as defined in the 1999 Utility Revenue Bonds included reserves for the Water, Wastewater
Treatment, Wastewater Collection, Refuse, Storm Drain, Electric, and Gas Utilities
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February 2018 23 | Page
SECTION 6E: OTHER REVENUES
The utility has seen substantial increases in connection and capacity fee revenues in recent
years. These fees are imposed to cover the cost of installing new service lines and the
customer’s impact on the overall system capacity. These are assumed to continue, albeit
slightly reduced from current levels. Income from interest and transfers in are projected to
remain steady through the forecast horizon.
SECTION 7: COMMUNICATIONS PLAN
The FY 2019 Wastewater Collection Utility communications strategy covers three primary areas:
rates, maintenance and operations, and safety. Communication about wastewater rate
adjustments will highlight the important infrastructure and operations upgrades that are
occurring at the Regional Water Quality Control Plant to improve wastewater collection utility
services. To keep customers apprised of the status and accomplishments of CIP projects, a
network of project web pages are maintained and updated as needed. Traffic is driven to the
website via ads in newspapers and local publications, utility bill inserts, social media and email
newsletters.
An important communications topic for the wastewater utility is avoiding sewer back-ups due
to FOG (fats, oil and grease) and trash being dumped down drains and toilets. Safety topics are
emphasized year-round. Staff continues its outreach goal of educating customers about the
utility’s gas-sewer line cross-bore inspection program, including the importance of calling
Utilities prior to clearing sewer lines in the event of a sewer back-up.
Promotional activity about wastewater utility maintenance and safety operations includes use
of bill inserts, ads in local print publications, website pages, email newsletters and social
media. While print materials and website pages feature prominently, CPAU is increasing the
outreach emphasis on more direct communication with customers, including through use of
social media, email newsletters, digital ads and videos, including featuring actual staff who
work in the Wastewater division. Staff is also attending more community safety/emergency
preparation events and neighborhood meetings.
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February 2018 24 | Page
APPENDICES
Appendix A: Wastewater Collection Financial Forecast Detail
Appendix B: Wastewater Collection Utility Capital Improvement Program (CIP) Detail
Appendix C: Wastewater Collection Utility Reserves Management Practices
Appendix D: Map (CPA Wastewater Collection System - Sewer Mains Replaced or Rehabilitated
since 1990)
Appendix E: Sample of Wastewater Collection Outreach Materials
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 25 | Page
APPENDIX A: WASTEWATER COLLECTION FINANCIAL FORECAST DETAIL
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 26 | Page
($'000)
Actual Actual Actual Actual Actual
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
1
2 % CHANGE IN RETAIL RATE 5%0%0%9%9%0%11%12%10%6%4%4%4%4%3%1%
3 PROJECTED CHANGE IN RETAIL SALES REVENUE 715 - - 1,352 1,416 - 1,889 2,288 2,135 1,409 996 1,036 1,077 1,120 874 300
4
5 RETAIL SALES REVENUE 15,019 14,588 14,658 15,648 17,126 17,167 18,978 21,249 23,391 24,830 25,844 26,878 27,953 29,072 29,956 30,280
6 CONNECTION AND CAPACITY FEES 1,609 1,703 1,392 794 1,047 906 918 930 943 957 970 985 999 1,014 1,030 1,045
7 OTHER / TRANSFERS IN 545 361 753 321 355 291 261 324 291 261 324 291 261 324 291 261
8 INTEREST (211) 339 315 475 (88) 328 287 212 217 153 152 161 164 180 199 210
9 TOTAL SOURCES OF FUNDS 16,963 16,991 17,119 17,238 18,441 18,692 20,444 22,715 24,842 26,201 27,290 28,314 29,378 30,590 31,476 31,797
10
11 PURCHASES/CHARGES OF UTILITIES (TREATMENT)8,314 6,863 8,589 8,770 8,391 10,418 10,798 11,846 12,888 13,571 14,005 14,692 15,676 16,083 16,453 16,914
12 ALLOCATED CHARGES (CIP&OPERATING)1,926 2,359 1,062 1,900 1,477 1,612 1,645 1,676 1,711 1,749 1,788 1,823 1,859 1,913 1,950 1,995
CUSTOMER SERVICE 1 133 (324) (22) 345 358 371 389 406 421 435 448 461 471 477 489
13 DISTRIBUTION OPERATIONS 2,617 2,570 2,646 2,635 2,759 2,859 2,950 3,071 3,188 3,295 3,400 3,494 3,583 3,670 3,724 3,812
ENGINEERING (OPERATING)271 310 319 347 292 302 311 323 335 346 357 366 376 385 391 400
14 DEBT SERVICE 128 129 51 47 43 128 128 128 129 129 129 - - - - -
15 RENT 110 217 223 293 300 317 334 337 340 343 347 350 354 357 361 364
16 OTHER/ TRANSFERS OUT 147 241 108 230 320 346 346 346 346 346 346 346 346 346 346 346
17 CAPITAL IMPROVEMENT FUNDING 4,094 989 3,477 4,985 1,332 2,955 6,629 5,936 6,133 6,296 6,486 6,681 6,882 7,088 7,302 7,521
ALLOWANCE FOR UNSPENT CAPITAL FUNDS - - - - - (400) (400) (400) (400) (515) (515) (515) (515) (515) (515)
18 TOTAL USES OF FUNDS 17,610 13,811 16,150 19,184 15,259 19,296 23,113 23,651 25,076 26,097 26,779 27,686 29,021 29,800 30,490 31,327
19
20 INTO / (OUT OF) RESERVES (647) 3,180 969 (1,946) 3,182 (605) (2,669) (936) (235) 104 511 628 356 790 986 469
21
24 ENDING COMMITMENTS & REAPPROPRIATIONS 11,228 8,312 8,291 11,088 1,922 1,922 1,922 1,922 1,922 1,922 1,922 1,922 1,922 1,922 1,922 1,922
23 ENDING PLANT REPLACEMENT RESERVE 1,000 - - - - - - - - - - - - - - -
ENDING CIP RESERVE - - 2,551 978 978 978 978 - - - - - - - - -
22 ENDING RATE STABILIZATION RESERVE 4,104 4,556 4,292 342 342 342 - - - - - - - - - -
ENDING OPERATIONS RESERVE - 3,728 2,431 3,211 6,393 5,788 3,461 3,503 3,269 3,373 3,884 4,512 4,868 5,658 6,644 7,113
25 UNASSIGNED RESERVES - - - - - - - - - - - - - - - -
26 RISK ASSESSMENT VALUE 2,736 2,230 2,722 1,814 1,618 1,984 2,460 2,585 2,794 2,935 3,036 3,164 3,324 3,429 3,521 3,601
27
28 OPERATIONS RESERVE GUIDELINES
29 MIN (60 DAYS TREATMENT/O&M EXP)2,253 1,915 2,083 2,224 2,305 2,686 2,775 2,978 3,180 3,321 3,421 3,538 3,724 3,818 3,896 3,998
TARGET (105 DAYS TREATMENT/O&M EXP)1,831 3,352 3,646 3,891 4,034 4,701 4,857 5,211 5,565 5,811 5,986 6,191 6,517 6,681 6,819 6,996
30 MAX (150 DAYS TREATMENT/O&M EXP)4,506 4,788 5,208 5,559 5,762 6,715 6,939 7,445 7,949 8,301 8,551 8,844 9,310 9,545 9,741 9,995
31
City of Palo Alto
Wastewater Collection
Fiscal Year
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 27 | Page
APPENDIX B: WASTEWATER COLLECTION UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Proposed
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
SEWER SYSTEM REHABILITATION AND AUGMENTATION (SSR/A) PROGRAM
WC-07004 SSR/A - Project 20 - - - - - - - - - - -
WC-08012 SSR/A - Project 21 - - - - - - - - - - -
WC-09001 SSR/A - Project 22 - - - - - - - - - - -
WC-10002 SSR/A - Project 23 - - - - - - - - - - -
WC-11000 SSR/A - Project 24 250,609 - - (121,353) 129,256 94,404 - - - - -
WC-12001 SSR/A - Project 25 468,772 - - (262,897) 205,875 186,531 - - - - -
WC-13001 SSR/A - Project 26 428,130 - - (166,536) 261,594 518,475 - - - - -
WC-14001 SSR/A - Project 27 717,106 97,440 - (409,505) 405,041 616,220 - - - - -
WC-15001 SSR/A - Project 28 - 702,600 - - 702,600 - 4,390,000 - - - -
WC-16001 SSR/A - Project 29 - - - - - 409,849 4,098,490 - - -
WC-17001 SSR/A - Project 30 - - - - - - - 421,684 4,209,845 - -
WC-19001 SSR/A - Project 31 - - - - - - - - 465,185 4,348,150 -
WC-20000 SSR/A - Project 32 - - - - - - - - - 448,249 4,477,495
WC-21000 SSR/A - Project 33 - - - - - - - - - - 461,696
Subtotal, Sewer Rehab./Augmentation 1,864,617 800,040 - (960,291) 1,704,366 1,415,630 4,799,849 4,520,174 4,675,030 4,796,399 4,939,191
ONGOING PROJECTS
WC-13002 Fusion & Gen. Equip./Tools 22,854 50,000 - - 72,854 22,854 50,000 50,000 50,000 50,000 50,000
WC-15002 WW System Improvements 5,452 246,000 - - 251,452 185,453 253,000 260,000 269,000 276,875 285,181
WC-99013 Sewer / Manhole Rehab.664,965 636,540 - (289,730) 1,011,775 326,662 655,636 675,305 695,564 716,431 737,924
Subtotal, Ongoing Projects 693,271 932,540 - (289,730) 1,336,081 534,969 958,636 985,305 1,014,564 1,043,306 1,073,105
CUSTOMER CONNECTIONS (FEE FUNDED)
WC-80020 Sewer System Extensions 51,900 405,820 - (136,328) 321,392 54,418 417,995 430,534 443,450 456,754 470,457
Subtotal, Customer Connections 51,900 405,820 - (136,328) 321,392 54,418 417,995 430,534 443,450 456,754 470,457
GRAND TOTAL 2,609,788 2,138,400 - (1,386,349) 3,361,839 2,005,017 6,176,480 5,936,013 6,133,044 6,296,459 6,482,754
Funding Sources
Connection/Capacity Fees 405,820 - 417,995 430,534 443,450 456,754 470,457
Funded by Rates and Other Revenue 1,732,580 - 5,758,485 5,505,479 5,689,594 5,839,705 6,012,297
CIP-RELATED RESERVES DETAIL 6/30/2017
6/30/2018
(Unaudited)
Reappropriations 159,316 1,356,822
Commitments 2,450,472 2,005,017
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 28 | Page
APPENDIX C: WASTEWATER COLLECTION UTILITY RESERVES
MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Wastewater
Collection 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. Reserves
The Wastewater Collection Utility’s Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 3 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 4 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Wastewater Collection
Utility’s Capital Improvement Program (CIP), as described in Section 5 (CIP Reserve)
d) For rate stabilization, as described in Section 6 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 7 (Operations Reserve)
f) 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 8 (Unassigned Reserves).
Section 3. Reserve for Commitments
At the end of each fiscal year the Reserve for Commitments will be set to an amount equal
to the total remaining spending authority for all contracts in force for the Wastewater
Collection Utility at that time.
Section 4. Reserve for Re-appropriations
At the end of each fiscal year the Reserve for Re-appropriations will be set to an amount
equal to the amount of all remaining capital and non-capital budgets, if any, that will be re-
appropriated to the following fiscal year in accordance with Palo Alto Municipal Code
Section 2.28.090.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 29 | Page
Section 5. 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 12 months of budgeted CIP expense
Maximum Level 24 months 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 or removed from to that reserve
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
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 6. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and held
to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate
Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization
Reserve at the end of any fiscal year, any subsequent Wastewater Collection Utility
Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the
Financial Planning Period.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 30 | Page
Section 7. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Wastewater Collection Utility’s Fund Balance not
included in the reserves described in Section 3-Section 6 above will be included in the
Operations Reserve unless this reserve has reached its maximum level as set forth in Section
7(d) below. Staff will manage the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for
that year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 105 days of O&M and commodity expense
Maximum Level 150 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months
of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Wastewater Collection Utility
shall be designed to return the Operations Reserve to its target level within four years.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Wastewater Collection
Utility’s Fund Balance shall be automatically included in the Unassigned Reserve
described in Section 8, below.
Section 8. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the
Wastewater Collection Utility’s Fund Balance will be held in the Unassigned Reserve. If
there are any funds in the Unassigned Reserve at the end of any fiscal year, the next
Financial Plan presented to the City Council must include a plan to assign them to a specific
purpose or return them to the Wastewater Collection Utility ratepayers by the end of the
first fiscal year of the next Financial Planning Period. For example, if there were funds in the
Unassigned Reserves at the end of FY 2015, and the next Financial Planning Period is
FY 2016 through FY 2020, the Financial Plan shall include a plan to return or assign any
funds in the Unassigned Reserve by the end of FY 2016. Staff may present an alternative
plan that retains these funds or returns them over a longer period of time.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 31 | Page
APPENDIX D: MAP (CPA WASTEWATER COLLECTION SYSTEM - SEWER
MAINS REPLACED OR REHABILITATED SINCE 1990)
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2018 32 | Page
APPENDIX E: SAMPLE OF WASTEWATER COLLECTION OUTREACH
MATERIALS
Not Yet Approved
180312 jb 6054068
Resolution No. _____
Resolution of the Council of the City of Palo Alto Increasing Wastewater
Rates by 11% by Amending Rate Schedules S-1 (Residential Wastewater
Collection and Disposal), S-2 (Commercial Wastewater Collection and
Disposal), S-6 (Restaurant Wastewater Collection and Disposal) and S-7
(Commercial Wastewater Collection and Disposal – Industrial Discharger)
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.
B.On April 3, 2018, the City Council held a full and fair public hearing regarding the
proposed rate increase and considered all protests against the proposals.
C. As required by Article XIIID, Section 6 of the California Constitution and
applicable law, notice of the June 11, 2018 public hearing was mailed to all City of Palo Alto
wastewater customers and property owners on April 27, 2018.
D.The City Clerk has tabulated the total number of written protests presented by
the close of the public hearing, and determined that it was less than fifty percent (50%) of the
total number of customers and property owners subject to the proposed wastewater rate
amendments, therefore a majority protest does not exist against the proposal.
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 S-1 (Residential Wastewater Collection and Disposal) is hereby amended to read as
attached and incorporated. Utility Rate Schedule S-1, as amended, shall become effective July
1, 2018.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule S-2 (Commercial Wastewater Collection and Disposal) is hereby amended to read as
attached and incorporated. Utility Rate Schedule S-2, as amended, shall become effective July
1, 2018.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule S-6 (Restaurant Wastewater Collection and Disposal) is hereby amended to read as
attached and incorporated. Utility Rate Schedule S-6, as amended, shall become effective July
1, 2018.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule S-7 (Commercial Wastewater Collection and Disposal – Industrial Discharger) is hereby
amended to read as attached and incorporated. Utility Rate Schedule S-7, as amended, shall
become effective July 1, 2018.
ATTACHMENT L
Not Yet Approved
180312 jb 6054068
SECTION 5. The Council finds that the revenue derived from the wastewater rates
approved by this resolution do not exceed the funds required to provide wastewater service,
and the revenue derived from the adoption of this resolution shall be used only for the
purposes set forth in Article VII, Section 2, of the Charter of the City of Palo Alto.
SECTION 6. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
SECTION 7. The Council finds that the adoption of this resolution changing wastewater
collection rates to meet operating expenses, purchase supplies and materials, meet financial
reserve needs and obtain funds for capital improvements necessary to maintain service is not
subject to the California Environmental Quality Act (CEQA), pursuant to California Public
Resources Code Sec. 21080(b)(8) and Title 14 of the California Code of Regulations Sec.
15273(a). After reviewing the staff report and all attachments presented to Council, the Council
incorporates these documents herein and finds that sufficient evidence has been presented
setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ __________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
____________________________
Director of Utilities
____________________________
Director of Administrative Services
ATTACHMENT L
RESIDENTIAL WASTEWATER COLLECTION AND DISPOSAL
UTILITY RATE SCHEDULE S-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No S-1-1 Effective 7-1-20186
dated 7-1-20165 Sheet No S-1-1
A. APPLICABILITY:
This schedule applies to each Ooccupied Domesticresidential Ddwelling unit.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Wwastewater Sservice.
C. RATES:
Per Month
Each Occupied Ddomestic Ddwelling unit ............................................................................
$34.8338.66
D. SPECIAL NOTES:
1. Any dwelling unit being individually served by a Wwater, Ggas, or Eelectric mMeter will be
considered continuously occupied.
2.For two or more Ooccupied Domestic Ddwelling units served by one Wwater Mmeter, the
monthly wWastewater charge will be calculated by multiplying the current wWastewater rate
by the number of dwelling units.
3.Each developed separate lot shall have a separate service lateral to a sanitary main or
manhole.
{End}
ATTACHMENT M
COMMERCIAL WASTEWATER COLLECTION AND DISPOSAL
UTILITY RATE SCHEDULE S-2
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No S-2-1 Effective 7-1-20186
dated 7-1-20165 Sheet No S-2-1
A. APPLICABILITY: This schedule applies to all commercial establishments other than those served under Utility Rate Schedule S-1 (Residential Wastewater Collection and Disposal), Rate Schedule S-6 (Restaurant Wastewater Collection and Disposal) or Rate Schedule S-7 (Commercial Establishments
Wastewater Disposal – Industrial Discharger). B. TERRITORY: This schedule applies everywhere the City of Palo Alto provides Wwastewater Sservices. C. RATES: 1. Minimum Charge per connection per month .............................................................$34.8338.66 2. Quantity Rates, per 100 cubic feet (See Section D.1) .............................................$6.717.45 D. SPECIAL NOTES: 1. The monthly charge for the quantity rate set forth in Section C.2 of this rate schedule will be based upon the average Wwater usage for the months of January, February and March, and applied in the following July. If a Wwater Mmeter is identified as exclusively serving irrigation landscaping, such Mmeter will be exempted from Wwastewater charge calculations. Customers without an applicable usage history will be charged at the minimum monthly charge until such time as such usage may reasonably be established by the City of Palo Alto Utilities Department. 2. The City of Palo Alto Utilities Department may require Wwastewater Mmetering facilities, in which case Sservice will be governed by terms of a special agreement between the City and the Customer. {End}
RESTAURANT WASTEWATER COLLECTION AND DISPOSAL
UTILITY RATE SCHEDULE S-6
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No S-6-1 Effective 7-1-20186
dated 7-1-20165 Sheet No S-6-1
A. APPLICABILITY: This schedule applies to all restaurants.
B. TERRITORY: This schedule applies everywhere the City of Palo Alto provides Wwastewater Sservices. C. RATES:
1. Minimum charge per connection per month ......................................................... $34.8338.66
2. Quantity Rates, per 100 cubic feet of monthly metered Wwater usage ..................... $
10.3811.52
D. SPECIAL NOTES: 1. The City of Palo Alto Utilities Department may require Wwastewater Mmetering facilities, in which case Sservice will be governed by terms of a special agreement between the City and the Customer. {End}
COMMERCIAL WASTEWATER COLLECTION AND DISPOSAL – INDUSTRIAL DISCHARGER
UTILITY RATE SCHEDULE S-7
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No S-7-1 Effective 7-1-20186
dated 7-1-20165 Sheet No S-7-1
A. APPLICABILITY:
This schedule applies to any establishment requiring sampling of industrial discharges in excess
of 25,000 gallons per day, or special discharge monitoring, as defined in Rule and Regulation 23, Section D.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Wwastewater Sservices.
C. RATES:
1. Collection System Operation, Maintenance, and Infiltration Inflow:
$1.942.15 per 100 cubic feet of metered water use.
2. Advanced Waste Treatment Operations and Maintenance Charge:
$1.141.27 per 100 cubic feet of metered water use
3. $ 247.56 per 1000 pounds (lbs) of COD (Chemical Oxygen Demand) 4. $ 596.62 per 1000 lbs of SS (Suspended Solids)
5. $ 3,983.85 per 1000 lbs of NH3 (Ammonia)
6. $ 14,781.25 per 1000 lbs of toxics (chromium, copper, cyanide, lead, nickel, silver, and zinc) D. SPECIAL NOTES: 1. Water usage will be determined as defined in Rule and Regulation 23, Section D. If a Wwater Mmeter is identified as exclusively serving irrigation landscaping, such Mmeter will be exempted from Wwastewater charge calculations. 2. The City of Palo Alto Utilities Department may require Wwastewater Mmetering facilities, in which case Sservice will be governed by terms of a special agreement between the City of Palo Alto and the Customer. 3. Charges for large discharges will be determined on the basis of sampling as outlined in Utilities Rule and Regulation 23, Section D. However, for purposes of arriving at an accurate flow estimate, discharge Mmeters, if installed, can be utilized to measure outflow for billing purposes. Annual charges will be determined and allocated monthly for billing purposes.
{End}
*NOT YET APPROVED *
6054073
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2019 Water 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 adopts the FY 2019 Water Utility Financial Plan.
SECTION 2. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment,, and therefore, no environmental review is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
ATTACHMENT N
Attachment N
*NOT YET APPROVED *
6054073
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
ATTACHMENT O
FY 2019 WATER
UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
WATER UTILITY FINANCIAL PLAN
M a y 2 0 1 8 2 | P a g e
FY 2019 WATER UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 4
Section 2A: Overview of Financial Position .................................................................................. 4
Section 2B: Summary of Proposed Actions .................................................................................. 5
Section 3: Detail of FY 2019 Rate and Reserves Proposals ....................................................... 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3C: Bill Impact of Proposed Rate Changes ...................................................................... 8
Section 3D: Proposed Reserve Transfers ..................................................................................... 9
Section 4: Utility Overview .................................................................................................... 9
Section 4A: Water Utility History ............................................................................................... 10
Section 4B: Customer Base ........................................................................................................ 10
Section 4C: Distribution System ................................................................................................. 11
Section 4D: Cost Structure and Revenue Sources ...................................................................... 11
Section 4E: Reserves Structure ................................................................................................... 12
Section 4F: Competitiveness ...................................................................................................... 12
Section 5: Utility Financial Projections ................................................................................. 13
Section 5A: Load Forecast .......................................................................................................... 13
Section 5B: FY 2012 to FY 2016 Cost and Revenue Trends ........................................................ 14
Section 5C: FY 2017 Results ....................................................................................................... 15
Section 5D: FY 2018 Projections ................................................................................................ 16
Section 5E: FY 2019 – FY 2028 Projections ................................................................................ 16
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 18
Section 5G: Alternate Scenarios................................................................................................. 19
WATER UTILITY FINANCIAL PLAN
M a y 2 0 1 8 3 | P a g e
Section 5H: Long-Term Outlook ................................................................................................. 20
Section 6: Details and Assumptions ..................................................................................... 20
Section 6A: Water Purchase Costs ............................................................................................. 20
Section 6B: Operations .............................................................................................................. 22
Section 6C: Capital Improvement Program (CIP) ....................................................................... 23
Section 6D: Debt Service ............................................................................................................ 26
Section 6E: Other Revenues ....................................................................................................... 27
Section 6F: Sales Revenues ........................................................................................................ 27
Section 7: Communications Plan .......................................................................................... 28
Appendices ......................................................................................................................... 29
Appendix A: Water Utility Financial Forecast Detail ................................................................. 30
Appendix B: Water Utility Capital Improvement Program (CIP) Detail ..................................... 32
Appendix C: Water Utility Reserves Management Practices ..................................................... 33
Appendix D: Description of Water Utility Operational Activities ............................................... 36
Appendix E: Sample of Water Utility Outreach Communications ............................................. 37
WATER UTILITY FINANCIAL PLAN
M a y 2 0 1 8 4 | P a g e
SECTION 1: DEFINITIONS AND ABBREVIATIONS
BAWSCA Bay Area Water Supply and Conservation Agency
CCF The standard unit of measurement for water delivered to water customers, equal to
one hundred cubic feet, or roughly 748 gallons.
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
O&M Operations and Maintenance
RFC Raftelis Financial Consultants, Inc.
SFPUC San Francisco Public Utilities Commission
SFWD San Francisco Water Department
UAC Utilities Advisory Commission
WSIP The SFPUC’s Water System Improvement Program to seismically strengthen the
transmission lines of the Hetch Hetchy regional water system.
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Water Utility for the next ten years. This
Financial Plan provides revenues to 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
Based on staff’s most recent analysis, staff expects overall costs in the Water Utility to rise by
about 3.3% per year from fiscal year (FY) 2018 to 2028. Excluding FY 2017 (which, unlike normal
years, did not include a water main replacement project), most costs are projected to rise by 2-
4% annually through the projection period. Water supply costs, the largest component of the
utility’s costs, are projected to remain relatively flat through FY 2022, based on current SFPUC
projections, then rise steeply thereafter due to a series of major capital projects on the Hetch
Hetchy water system. See Section 6A: Water Purchase Costs for more information. Capital
projects, with several reservoir and tank rehabilitation projects scheduled for FY 2019 through
FY 2021, as well as increases to main replacement project costs to reflect rising construction
costs. More detail on CIP costs is discussed in Section 6C: Capital Improvement Program (CIP)
below. Table 1 below shows the costs for the Water Utility from FY 2017 through FY 2028.
Table 1: Expenses for FY 2017 to FY 2028 (Thousand $’s)
Expenses
($000)
FY
2017
(act.)
FY
2018
(est.)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Water
Purchases
20,075 22,062 22,611 22,366 22,124 21,884 23,401 25,915 26,874 28,261 29,212 30,624
Operations 15,965 18,627 19,087 19,559 20,032 20,472 20,916 21,306 21,684 22,095 22,371 22,766
Capital
Projects
4,110 8,267 13,695 13,210 16,765 10,709 11,023 11,344 11,675 12,024 12,373 12,737
TOTAL 40,151 48,956 55,394 55,135 58,920 53,065 55,340 58,566 60,233 62,380 63,956 66,127
WATER UTILITY FINANCIAL PLAN
M a y 2 0 1 8 5 | P a g e
This proposed financial plan projects that the Water Utility needs the rate increases shown in
Table 2 to ensure that revenues cover rising costs and reserves remain healthy. While costs are
increasing roughly 3.4% per year through FY 2024, staff projects a need for sales revenue
increases averaging roughly 4% per year over that period. This is due to the fact that revenue is
currently slightly below costs and also because little or no increase is expected in non-sales
revenue (e.g. interest, connection fees).
The table also shows rate projections from last year’s Financial Plan. Last year’s plan projected
earlier, generally higher rate increases. However, the delay of FY 2017 water main replacement
projects as well as post-drought sales revenues resulted in an increase in reserves, which
enabled the more gradual increases projected in the current plan. The current plan assumes
that the Rate Stabilization Reserve will be drawn down faster and the Operations Reserve run
closer to the minimum guideline level for the next several years, in accordance with the
Finance Committee’s direction on April 17, 2018.
Table 2: Proposed and Projected Water Rate Changes for FY 2019 to FY 2028
Projection FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Current 3% 4% 4% 4% 5% 6% 5% 5% 4% 4%
Last year 6% 6% 6% 6% 6% 2% 2% 2% 1% N/A
2 years 9% 6% 2% 2% 2% 3% 5% 3% N/A N/A
The Water Utility has a Rate Stabilization Reserve that can be used to smooth rate increases
over several years. This Financial Plan projects that these reserves will be exhausted by the end
of FY 2021. The Water Utility also has a Capital Improvement Program (CIP) Reserve that can be
used to offset one-time unanticipated capital costs. This Financial Plan assumes that the CIP
Reserve will be used for unanticipated capital expenses or returned to the Operations Reserve
by the end of FY 2020. The Water Utility Operations Reserve was above the maximum guideline
level at the end of FY 2017, mainly due to larger than anticipated drought surcharge revenue.
However, these funds will be needed to fund the Water Utility in FY 2018 and FY 2019, bringing
the Operations Reserve within guidelines by FY 2020. Table 3 shows the projected reserve
transfers over the forecast period.
Table 3: Transfers To/(From) Reserves for FY 2018 to FY 2028 ($000)
Reserve FY 2018 FY 2019 FY 2020 to FY 2028
Capital Improvement - - (2,726)
Rate Stabilization - - (4,069)
Operations - - 6,785
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Water Utility in FY 2019:
1. Increase rates to raise an additional 3% in revenue to fund increases to capital
expenditures and increased operations costs. Section 3B: Current and Proposed Rates
describes this increase in more detail.
WATER UTILITY FINANCIAL PLAN
M a y 2 0 1 8 6 | P a g e
SECTION 3: DETAIL OF FY 2019 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The Water Utility’s rates are evaluated and implemented in compliance with the cost of service
requirements and procedural rules set forth in the California Constitution under Article 13 (per
Proposition 218). The City structured current rates based on staff’s assessment of the financial
position of the Water Utility, and updated current rates using the methodology from the March
2012 Palo Alto Water Cost of Service & Rate Study by Raftelis Financial Consultants, Inc. (RFC)
(Staff Report 2676), as well as RFC’s 2015 Memorandum: Proposed Water Rates updating the
2012 Study and analyzing drought rates (Staff Report 5951). Staff plans to review and update
this cost of service study in 1 to 2 years, unless any major changes occur to the utility’s
operations or customer base that would necessitate an earlier study. Before conducting any
new cost of service study, staff will review current rates and the scope of the study with the
Utilities Advisory Commission (UAC) and Council to determine the City’s policy priorities.
In 2015 Council adopted a drought surcharge to assist the water utility in recovering its costs
due to decreased revenue resulting from lower water consumption as customers conserved.
With the State declaring the drought over in FY 2017, the drought surcharge was discontinued
as of July 1, 2017.
SECTION 3B: CURRENT AND PROPOSED RATES
The current rates and surcharges were effective on July 1, 2017. Current rates reflect
adjustments in accordance with the results of an updated cost of service study performed by
RFC in 2015. The 2015 study developed the drought surcharges and evaluated the City’s water
rate methodology and structure in light of court decisions interpreting provisions of the State
Constitution applicable to water rates. RFC validated the City’s rate structure, recommending
only minor adjustments to ensure that peaking costs were equitably allocated to each customer
class and residential rate tier.
CPAU has five rate schedules: separately metered residential customers (W-1), commercial and
master-metered multi-family residential customers (W-4), irrigation-only services (W-7),
services to fire sprinkler systems in buildings and private hydrants (W-3), and service to fire
hydrant rental meters used for construction (W-2). All customers pay a monthly service charge
based on the size of their inlet meter. This charge represents meter reading, billing, and other
customer service costs, but also the cost of maintaining the capability to deliver a peak flow for
that customer corresponding to their meter size. All customers are also charged for each CCF
(one hundred cubic feet) of water used. Separately metered residential customers are charged
on a tiered basis, with the first 0.2 CCF per day (6 CCF for a 30 day billing period) charged at the
first tier price per CCF, and all additional units charged a higher tier price per CCF. Commercial
customers pay a uniform price for each CCF used, and a higher price for separately metered
irrigation service.
For July 1, 2018 staff is proposing an increase in rates of approximately three percent. Water
rates are composed of two general types of costs: commodity and distribution. Commodity
WATER UTILITY FINANCIAL PLAN
M a y 2 0 1 8 7 | P a g e
costs are mainly volumetric in nature and charged by the San Francisco Public Utilities
Commission (SFPUC). In late December 2017, the SFPUC provided a preliminary estimate that
their FY 2019 W-25 wholesale rate for agencies with long-term contracts would remain at
$4.10/CCF in FY 2019. The SFPUC will not determine its final rate until May or June. However,
in order to have the City’s water rates in place for July 1, staff must notify customers by the end
of April. Staff is using the SFPUC’s December 2017 estimate in this forecast.
For FY 2018, early indications were that the SFPUC would raise their rates to $4.37/CCF, and
this was what was used in CPAU staff’s rate setting analysis. Since the SFPUC’s actual rate
increase was lower, and FY 2019 indications forecast no change, staff will reduce the
commodity portion of CPAU’s rates accordingly.
Distribution rates cover all the costs to deliver water within the City, such as operations,
maintenance, metering and billing, and capital improvement. Capital improvement costs have
been increasing by about 5% annually, are projected to continue rising in the future, and staff is
reflecting these changes in distribution costs. Operations costs are discussed in Section 6B:
Operations, below. The decrease in commodity rates partially offsets the distribution increases,
thus the percentage change differs between volumetric rates and monthly service charges.
Table 4 shows the current and proposed consumption charges.
Table 4: Current and Proposed Water Consumption Charges
Current
(7/1/17)
Proposed
(7/1/18)
Change
$/CCF %
W-1 (Residential) Volumetric Rates ($/CCF)
Tier 1 Rates 6.66 6.64 (0.02) 0%
Tier 2 Rates 9.18 9.44 0.26 3%
W-2 (Construction) Volumetric Rates ($/CCF)
Uniform Rate 7.68 7.77 0.09 1%
W-4 (Commercial) Volumetric Rates ($/CCF)
Uniform Rate 7.68 7.77 0.09 1%
W-7 (Irrigation) Volumetric Rates ($/CCF)
Uniform Rate 9.08 9.33 0.25 3%
Table 5 shows the current and proposed monthly service charges for rate schedules W-1, W-4,
and W-7.
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Table 5: Current and Proposed Monthly Service Charges for W-1, W-4, and W-7
Meter
Size
Monthly Service Charge
($/month based on meter size)
Change
Current (7/1/17)
Residential (W-1)
Commercial (W-4)
Irrigation (W-7)
Proposed (7/1/18)
Residential (W-1)
Commercial (W-4)
Irrigation (W-7)
$ %
5/8” $16.77 $18.43 $1.66 9.9%
3/4” $22.60 $24.83 $2.23 9.9%
1” $34.26 $37.64 $3.38 9.9%
1 ½” $63.40 $69.66 $6.26 9.9%
2” $98.37 $108.08 $9.71 9.9%
3” $209.11 $229.75 $20.64 9.9%
4” $372.31 $409.05 $36.74 9.9%
6” $762.81 $838.09 $75.28 9.9%
8” $1,403.94 $1,542.50 $138.56 9.9%
10” $2,219.92 $2,439.01 $219.09 9.9%
12” $2,919.34 $3,207.45 $288.11 9.9%
Table 6 shows the current and proposed monthly service charges for rate schedule W-3
Table 6: Current and Proposed Monthly Service Charges for Fire Services (W-3)
Meter
Size
Monthly Service Charge
($/month based on meter size)
Change
Current (7/1/17) Proposed (7/1/18) $ %
2” $3.79 $4.16 $0.37 9.9%
4” $23.42 $25.73 $2.31 9.9%
6” $68.03 $74.74 $6.71 9.9%
8” $144.97 $159.28 $14.31 9.9%
10” $260.70 $286.43 $25.73 9.9%
12” $421.11 $462.67 $41.56 9.9%
SECTION 3C: BILL IMPACT OF PROPOSED RATE CHANGES
Table 7 shows the impact of the proposed July 1, 2018 rate changes on the median residential
bill. The average increase is projected to be about three percent, but some customers may see
slightly higher or lower increases due to slight changes in the composition of the utility’s costs.
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Table 7: Impact of Proposed Water Rate Changes on Residential Bills
Usage
(CCF/month)
Bill under
Current Rates
(7/1/17)
Bill under
Proposed
Rates (7/1/18)
Change
$/mo. %
4 $43.41 $44.99 $1.58 3.6%
(Winter median) 7 $65.91 $67.71 $1.80 2.7%
(Annual median) 9 $84.27 $86.59 $2.32 2.7%
(Summer median) 14 $130.17 $133.79 $3.62 2.8%
25 $231.15 $237.63 $6.48 2.8%
Table 8 shows the impact of the proposed July 1, 2018 rate changes on various representative
commercial customer bills.
Table 8: Impact of Proposed Water Rate Changes on Commercial Bills
Usage
(CCF/month)
Bill under
Current Rates
(7/1/17)
Bill under
Proposed
Rates
(7/1/18)
Change
$/mo. %
Commercial (W-4) (5/8” meters)
(Annual median) 12 $108.93 $111.67 $2.74 2.5%
(Annual average) 64 $508.29 $515.71 $7.42 1.5%
Irrigation (W-7) (1 ½” meters)
(Winter median) 9 $ 145.12 $ 153.63 $ 8.51 5.9%
(Summer median) 37 $ 399.36 $ 414.87 $ 15.51 3.9%
(Winter average) 56 $ 571.88 $ 592.14 $ 20.26 3.5%
(Summer average) 199 $ 1,870.32 $ 1,926.33 $ 56.01 3.0%
SECTION 3D: PROPOSED RESERVE TRANSFERS
In the FY 2018 Financial Plan, staff proposed transferring $1.87 million from the Rate
Stabilization Reserve to the Operations Reserve in FY 2018. This transfer was not necessary as
increased sales during FY 2017 resulted in larger than expected revenues, largely from the
drought surcharge. The drought surcharge was discontinued at the start of FY 2018. Customer
sales recovery after the drought continues to be more robust than staff’s initial projections.
Section 4E: Reserves Structure and Appendix A: Water Utility Financial Forecast Detail shows
details of reserves levels.
SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It provides general
background information and helps readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
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SECTION 4A: WATER UTILITY HISTORY
The Water Utility was established on May 9, 1896, two years after the city was incorporated.
Voters of the 750 person community approved a $40,000 bond to buy local, private water
companies who operated one or more shallow wells to serve the nearby residents. The city
grew and the well system expanded until nine wells were in operation in 1932. Palo Alto began
receiving water from the San Francisco Water Department (SFWD) in 1937 to supplement these
sources.
A 1950 engineering report noted, “the capricious alternation of well waters and the San
Francisco Water Department water…has made satisfactory service to the average customer
practically impossible”. By 1950, only eight wells were still in operation. Despite this,
groundwater production increased in the 1950’s leading to lower groundwater tables and water
quality concerns. In 1962, a survey of water softening costs to CPAU customers determined that
CPAU should purchase 100% of its water supply needs from the SFWD. CPAU signed a 20-year
contract with SFWD, and CPAU’s wells were placed in standby condition. The SFWD later
became known as the SFPUC. Since 1962 (except for some very short periods) CPAU’s entire
supply of potable water has come from the SFPUC.
As the city grew, so did the number of mains in the water system. The system of mains
expanded along with the city, while existing sections of the system continued to age. In the
mid-1980s, the number of breaks in cast iron mains installed during the 1940s and earlier
started to accelerate. In FY 1994, to combat deterioration of older sections of the system, CPAU
performed an analysis of cost effective system improvements and increased the rate of main
replacement from one mile per year to three. CPAU began a plan to replace 75 miles of
deficient mains within 25 years.
In 1999, a study of system reliability concluded that major upgrades were needed to the
distribution system to provide adequate water supply during a natural disaster. This ultimately
resulted in the $40 million Emergency Water Supply and Storage Project, completed in 2013,
which involved a new underground reservoir in El Camino Park, the siting and construction of
several emergency supply wells, and the upgrade of several existing wells and the Mayfield
pump station. Upon completion, the city began to focus reliability efforts on its system of water
storage reservoirs and transmission lines in the Foothills.
At the same time that CPAU was evaluating the reliability of its own system, the SFPUC, in
consultation with BAWSCA members, was evaluating the reliability of the Hetch Hetchy water
system, which crosses two major fault lines between the Sierras and the Bay Area. That
evaluation concluded that major upgrades to the system were required. This planning process
culminated in the SFPUC’s $4.8 billion Water System Improvement Project (WSIP), which is
ongoing. The SFPUC continues to evaluate its aging system for other needed infrastructure
improvements.
SECTION 4B: CUSTOMER BASE
CPAU’s Water Utility provides water service to the residents and businesses of Palo Alto, plus a
handful of residential customers not in Palo Alto (Los Altos Hills, primarily). Nearly 20,300
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Figure 1: Cost Structure (FY 2017)
50%
40%
10%
Water Purchases
Operations
Capital
Figure 2: Revenue Structure (FY 2017)
99%
1%
Sales of Water
Other Revenue
customers are connected to the water system, approximately 16,500 (81%) of which are
separately metered residential customers and 3,800 (19%) of which are commercial, master-
metered residential, irrigation and fire service customers.
Judging from seasonal consumption patterns, between 35% and 50% of Palo Alto’s water is
used for irrigation, and that consumption is heavily weather dependent. It also varies
significantly by season. As a result of these two factors, there is significant variability in the
amount of water that is demanded from the system month to month and year to year.
SECTION 4C: DISTRIBUTION SYSTEM
To deliver water to its customers, CPAU owns roughly 233 miles of mains (which transport the
water from the SFPUC meters at the city’s borders to the customer’s service laterals and
meters), eight wells (to be used in emergencies), five water storage reservoirs (also for
emergency purposes) and several tanks used to moderate pressure and deal with peaks in flow
and demand (due to fire suppression, heavy usage times, etc.). These represent the vast
majority of the infrastructure used to distribute water in Palo Alto.
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 1, water purchase
costs accounted for roughly 50% of the
Water Utility’s costs in FY 2017.
Operational costs represented roughly
40%, and capital investment was
responsible for the remaining 10%. These
percentage distributions are projected to
remain similar over the forecast period
with the capital investment increasing to
approximately 20% of the Water Utility’s
costs and operations declining to
approximately 35%.
The Water Utility receives nearly all of its
revenue from sales of water and the
remainder from capacity and connection
fees, interest on reserves, and other
sources. Appendix A: Water Utility
Financial Forecast Detail shows more
detail on the utility’s cost and revenue
structures. Roughly 15% of the utility’s
revenues come from fixed service
charges, though most of its costs are
fixed.
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SECTION 4E: RESERVES STRUCTURE
CPAU maintains six reserves for its Water Utility to manage various types of contingencies. The
descriptions below summarize these reserves; see Appendix C: Water Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
Reserve for Commitments: A reserve equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
Reserve for Reappropriations: A reserve 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.
Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to
accumulate funds for future expenditure on CIP projects and is anticipated to be empty
unless a major one-time CIP expenditure is expected in future years. This CIP can also
act as a contingency reserve for the CIP. This type of reserve is used in other utility funds
(Electric, Gas, and Wastewater Collection) as well.
Rate Stabilization Reserve: This reserve is intended to be empty unless the city
anticipates one or more large rate increases 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 (Electric, Gas, and Wastewater
Collection) as well.
Operations Reserve: This is the primary contingency reserve for the Water Utility, and is
used to manage yearly variances from the budget for operational water supply costs.
This type of reserve is used in other utility funds (Electric, Gas, and Wastewater
Collection) as well.
Unassigned Reserve: This reserve is for any funds not assigned to the other reserves
and is normally empty.
SECTION 4F: COMPETITIVENESS
Table 9 shows the current water bills for residential customers compared to what they would
be under surrounding communities’ rate schedules. CPAU has the highest monthly bills of the
group, although bills for smaller water users are less than in some surrounding communities.
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Table 9: Residential Monthly Water Bill Comparison
Usage
(CCF/month)
Residential monthly bill comparison ($/month)*
As of January 2018
Palo
Alto
Menlo
Park
Mountain
View Hayward
Redwood
City
Santa
Clara
4 43.41 50.51 37.10 33.20 50.10 22.76
(Winter median) 7 65.91 73.36 57.50 54.62 70.56 39.83
(Annual median) 9 84.27 88.60 71.10 68.90 84.20 51.21
(Summer median) 14 130.17 126.70 105.10 106.51 128.86 79.66
25 231.15 210.50 220.70 199.02 247.97 142.25
* All comparisons use the 5/8” meter size.
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 3 shows 40 years of water consumption history. Average water use has trended
downward over time even as Palo Alto’s population has grown. Significant water use reductions
over the 40-year history were in response to requests to reduce water use in the 1976-77 and
1988-92 drought periods. During these periods, customers invested in efficient equipment and
modified behavior to achieve water reduction goals. Reductions in usage achieved during these
drought periods endured even after those periods. More recently, water sales decreased
substantially during the 2007-2009 recession and during the 2014 - 2017 drought. Usage has
started to recover after the drought, though the level at which usage will finally plateau is
unknown.
Figure 3: Historical Water Consumption
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Figure 4 shows the forecast of water consumption through FY 2028, as denoted by the dotted
line.
Figure 4: Forecast Water Consumption
California has until recently been experiencing drought conditions, and the State had mandated
a 24% water use restriction for Palo Alto up until May 2016. Customers continue to conserve,
but water usage has been increasing. Based on patterns experienced in previous droughts and
in recognition of continued state-level calls for conservation, this forecast assumes
consumption will only rebound by 50% of the difference between pre-drought and drought
levels, then resume with the previous trend of decreasing usage over time.
SECTION 5B: FY 2012 TO FY 2016 COST AND REVENUE TRENDS
Figure 5 and the tables in Appendix A: Water Utility Financial Forecast Detail show how costs
have changed during the last five years as well as how staff projects they will change over the
next decade.
The annual expenses for the water utility rose substantially between 2013 and 2017. The
increases were primarily related to water purchase costs, which increased 21% from $16.6
million in FY 2013 to $20.1 million in FY 2017. Section 6A: Water Purchase Costs contains a
more in-depth discussion of water purchase costs. Operations costs have remained fairly steady
since FY 2014, while CIP costs have generally increased but fluctuated down in certain years.
For example, in FY 2013 a new water main replacement project was delayed to permit
completion of a backlog of projects budgeted in prior years. In FY 2017, delays were in part due
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to the rising CIP costs; during that year a water main replacement project that was put out for
bid resulted in very few contractors competing, and project bids that were higher than
budgeted.
Figure 5: Water Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2017 and Projections through FY 2028
SECTION 5C: FY 2017 RESULTS
Actual revenues for FY 2017 were higher than projected ($47.5 million vs. $41.8 million). The
drought was declared over by the Governor during FY 2017, and customers started consuming
more water. Higher sales, along with the drought surcharge in place until the beginning of FY
2018, resulted in higher revenue. The trend of higher connection and capacity fee income
continued during FY 2017. Costs were also lower during FY 2017, mainly due to savings in
operations, administrative fees and some CIP savings, although increased purchase costs from
higher sales offset some of this. Table 10 summarizes the variances from forecast.
Actual Projected
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Table 10: FY 2017, Actual Results vs. Financial Plan Forecast
Net Cost/
(Benefit) (000)
Type of
change
Higher sales revenues $(3,185) Revenue increase
Increased connection and capacity fees, other income (2,453) Revenue increase
Operations and maintenance, general admin costs lower
than expected
(1,634) cost savings
Purchase costs higher than expected 833 cost increase
Net Cost / (Benefit) of Variances $(6,439)
SECTION 5D: FY 2018 PROJECTIONS
Sales levels for FY 2018 were increased based on recent usage trends, and estimated sales
revenues are also estimated to increase by about $4.2 million. Other revenues are also
expected to increase, partially due to the trend of higher connection and capacity fee income,
but also from higher interest income resulting from larger reserve balances. On the expense
side, the most notable change from the FY 2018 budget identified at this time are increases for
CIP expenditures. The effort to rehabilitate mains along University Avenue is anticipated to
have much higher costs than initially projected, and some additional projects were included
after last year’s financial plan was created. Additional expense increases are anticipated from
higher water supply costs associated with higher water sales, as well as some increases to
operations and administrative costs. Table 11 summarizes the changes from last year’s forecast.
Table 11: FY 2018 Change in Projected Results, 2018 Forecast vs 2019 Forecast
Net Cost/
(Benefit)
Type of
Change
Higher sales revenues $(4,232) revenue increase
Higher misc. revenues (1,269) revenue increase
Increase in capital projects 4,185 cost increase
Higher operations and purchase budgets 1,233 cost increase
Net Cost / (Benefit) of Variances $(83)
SECTION 5E: FY 2019 – FY 2028 PROJECTIONS
Figure 5 above shows that costs for the Water Utility are increasing through the rest of the
forecast period, though mainly after FY 2022 based on current estimates from the SFPUC.
Water supply costs are the largest component, and are generally projected to grow steadily by
about four percent over the forecast period. Operations and capital investment costs are also
expected to increase at the same rate of inflation used in the City’s long-term financial plans
(2.5% to 3.0% per year). While future CIP costs have been revised upwards to reflect the higher
construction costs seen in recent projects, there is still uncertainty with regard to the utility’s
future costs for main replacement. See Section 6: Details and Assumptions for more detail on
the costs that make up these projections, as well as the various assumptions underlying the
projections.
As shown in Figure 5, above, staff currently projects revenues to be below expenses for FY 2018
and for the three subsequent years. Revenues exceeded expenses in FY 2017 due to delays in
water main replacement projects, leading to lower annual CIP spending in that year, as well as
drought surcharge revenue that made up for reduced distribution revenue as a result of
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drought conservation. As main replacement resumes, the Water Utility requires rate increases
of between 4% and 6% per year through FY 2024 to bring revenues up to match annual
expenses. This forecast assumes the use of the Rate Stabilization Reserve to spread the
increases over multiple years.
Figure 6 below shows reserves trends based on these revenue projections. Staff projects the
Rate Stabilization Reserve to have a zero balance by the end of FY 2021, and the CIP Reserve to
decrease by $2.7 million by the end of FY 2020. Assuming these increases in revenue, staff
expects the Operations Reserve, the main contingency reserve, to be at or near the minimum
reserve level during the forecast period, and that this reserve will be adequate to meet all
identified risks, as discussed in Section 5F: Risk Assessment and Reserves Adequacy. In addition,
the Unassigned reserve reflects reserve funds in the Operations reserve above the maximum
guideline level. With the expected increase in costs between FY 2018 and FY 2019, these excess
reserves will be utilized quickly and moderate the pace of increases going forward, but must be
used before Rate Stabilization Reserve funds are utilized.
These projections assume that drought restrictions are not re-imposed by the State.
Figure 6: Water Utility Reserves
Actual Reserve Levels for FY 2017 and Projections through FY 2028
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SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY
The Water Utility currently has one contingency reserve, the Operations Reserve, and this
Financial Plan proposes using funds and raising rates slowly such that reserves hover at or near
the minimum guidelines throughout the forecast period, as shown in Figure 7. Funds in excess
of the maximum as of the end of FY 2018 will be recommended to be moved to the Unassigned
Reserve. While the Operations Reserve may drop below the minimum reserve level periodically,
it is expected to exceed the short term risk assessment for the utility.
Figure 7: Operations Reserve Adequacy
Table 12 summarizes the risk assessment calculation for the Water Utility through FY 2023.
Staff used the same methodology for FY 2024 through FY 2028 as well. 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 12: Water Risk Assessment ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Total non-commodity revenue $20,284 $21,501 $22,748 $24,045 $24,525
Max. revenue variance, previous ten years 13% 13% 13% 13% 13%
Risk of revenue loss $2,004 $2,125 $2,248 $2,376 $2,423
CIP Budget $13,695 $13,210 $16,765 $10,709 $11,023
CIP Contingency @10% $1,369 $1,321 $1,676 $1,071 $1,102
Total Risk Assessment value $3,374 $3,446 $3,924 $3,447 $3,526
SECTION 5G: ALTERNATE SCENARIOS
Staff had originally proposed a 4% rate increase for FY 2019, which the Utilities Advisory
Commission approved at its March 7, 2018 meeting. At its April 3, 2018 meeting, the Finance
Committee had a concern that future rate increases of 6 to 7% were rather large, and
requested that staff return with some possible alternate proposals at the April 17, 2018
meeting. Four alternatives were brought back to the Finance Committee.
The first scenario was the original proposal presented at the March 7 UAC meeting (Item #21).
The second scenario is the one shown in this current version of the Financial Plan.
The third scenario added the financing of two large, one-time CIP projects (the Advanced
Metering Infrastructure and Reservoir rehabilitation/replacement projects) totaling $13 million.
These items would be financed internally from the Electric Special Projects Reserve for a term
of 20 years and create the following long-term cost and revenue profile.
The fourth scenario also included reducing the amount allocated for capital investments by $2
million per year. This would extend the current 20 year capital plan to 30 years, and lengthen
the rate of system main replacement to over 100 years. Staff recommended against this
particular plan.
A recap of the various proposals and how they were anticipated to affect rates is shown in the
table below:
1 https://www.cityofpaloalto.org/civicax/filebank/documents/63751
Water Rate Proposal Alternatives
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Alternative 1 4%7%7%6%4%4%1%3%1%2%
Alternative 2 3%4%4%4%5%6%5%5%4%4%
Alternative 3 3%3%4%4%4%5%5%5%5%5%
Alternative 4 2%3%3%3%4%5%4%4%5%5%
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The Finance Committee chose Alternative 2, and that is the proposal shown in this amended
Financial Plan.
SECTION 5H: LONG-TERM OUTLOOK
CPAU has put its Water Utility on strong footing by investing in its distribution system
infrastructure and emergency water facilities over the last 20 years. The Water System Master
Plan, recently completed and under review, will give CPAU a better picture of the long-term
outlook for its infrastructure and will result in a plan for an appropriate schedule for
infrastructure replacement and upgrades. In addition, CPAU’s water supplier, the SFPUC, has
replaced and seismically strengthened its water transmission infrastructure, which will benefit
Palo Alto and all Hetch Hetchy customers over the long term.
The opportunities for CPAU’s Water Utility to obtain additional supplies over the long term may
be in alternative water supplies such as recycled water, groundwater, and water from the Santa
Clara Valley Water District. These alternatives have been analyzed in the past, and will be
analyzed again in an upcoming update to the Water Integrated Resource Plan. Some of these
alternatives may provide cost savings or increased drought protection.
Climate change may begin to present challenges for the Water Utility over the next 20 to 40
years. Availability of water from SFPUC’s Regional Water System may change with changing
seasonal precipitation patterns. Water consumption patterns may change. Consumption could
increase due to drier weather or decrease as customers become even more focused on water
conservation. Droughts may become more frequent. The risk of wildfire in the foothills could
increase, possibly threatening utility infrastructure or placing greater demands on it. Sea level
rise could result in greater exposure of utility infrastructure to saltwater intrusion or the need
to protect infrastructure from inundation, possibly resulting in higher maintenance and
replacement costs. It could also affect the groundwater aquifer that the utility relies on in
emergencies. Any of these could result in increases to the costs of operating the Water Utility.
As part of the Sustainability/Climate Action Plan, CPAU is currently working on a Climate
Change Adaptation Roadmap that will begin to assess some of these risks.
SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: WATER PURCHASE COSTS
CPAU purchases all of the potable water supplies from the SFPUC, which owns and operates the
Hetch Hetchy Regional Water System. CPAU is one of several agencies that purchase water
from the SFPUC, all of whom are members of the Bay Area Water Supply and Conservation
Agency (BAWSCA). Palo Alto uses roughly 7% of the water delivered by the SFPUC to BAWSCA
member agencies.
The Hetch Hetchy Regional Water System begins with a system of reservoirs and tunnels in the
high Sierra in Yosemite County and water is transported by a gravity-fed pipeline to the Bay
Area. Currently, the SFPUC is in the midst of a $4.8 billion bond-financed capital improvement
program (the Water System Improvement Program, or WSIP) to seismically retrofit the facilities
that transport water to the Bay Area. As of September 2017, nearly 60% of the program (by
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dollar value) had been completed, while 40% was under construction.2 This has resulted in large
increases in the annual debt service costs assigned to wholesale customers like Palo Alto. The
wholesale customer debt service share of the WSIP is increasing from $53 million in FY 2010 to
over $200 million in FY 2020. As a result, the SFPUC’s wholesale water rate has already
increased from $1.43 per CCF in FY 2009 to $4.10 per CCF in FY 2018, and is forecast to increase
to over nearly $6.00 per CCF by FY 2027 (these projections are subject to change based on
future SFPUC budget estimates). Figure 8 shows the SFPUC’s actual wholesale water rate since
FY 2009 and a projection through FY 2027. Note that the wholesale water rate decreased in FY
2014, but the apparent rate decrease is due to a part of the debt being directly paid by the
BAWSCA agencies. This cost is paid in addition to the wholesale water rate and adds about
$0.35 to $0.45 per CCF to the wholesale rate.
The SFPUC’s water rate projections show a less steeply increasing rate trajectory after all of the
debt for the WSIP has been issued. Still, debt service costs are projected to nearly double
between FY 2019 and FY 2028. Parts of SFPUC’s system not included in the WSIP will also need
rehabilitation after the WSIP is completed, and some of these projects are already included in
the SFPUC’s rate projections, such as additional Transmission, Supply & Storage and Treatment
system upgrade projects, slated to start after the WSIP ends. The SFPUC is also conducting
condition assessments of other “up-country” facilities, located in the Sierras, in the coming
years. Current estimates are that $1.8 billion will be needed between FY 2019 and FY 2028 for
these non-WSIP projects, but if these assessments identify other facilities that need
replacement, it may result in additional rate increases as new debt is issued to finance the
projects. For comparison, the WSIP was $4.8 billion.
In December 2017, the SFPUC provided an early estimate for FY 2019 wholesale water rates to
remain at $4.10 per CCF. Staff received a subsequent estimate which anticipates no change to
the SFPUC volumetric rate for several years. However, there is much uncertainty surrounding
continued water usage by the BAWSCA agencies. While drought restrictions ended in May
2016, customers’ behavior changes are showing a steady increase during the dry winter of
2018.
As the drought ended in FY 2017 and sales have started increasing, if that trend continues in
upcoming years, rate projections may level out. However, if snow and rain do not materialize in
future years further calls for restricted usage may reoccur.
2 First Quarter FY 2017-18 WSIP Regional Quarterly Report, http://www.sfwater.org/index.aspx?page=307
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Figure 8: Historical and Projected SFPUC Wholesale Water Rate
SECTION 6B: OPERATIONS
CPAU’s Water Utility operations include the following activities:
Administration, a category that includes charges allocated to the Water 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 Water
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 D: Description of Water Utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 2013 to FY 2017 Operations costs (excluding debt service, rent, and transfers)
increased 3.5% per year on average (see Figure 9). Operations costs were the main driver. Debt
service costs increased by $2.4 million per year as a result of a bond issued to finance the
Emergency Water Supply and Storage Project. Transfers have varied from year to year, but are
expected to remain relatively low and stable through the forecast period.
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Staff project inflationary increases for Operations costs with underlying assumptions for salary
and benefit costs, consumer price index, and other cost projections that match the City’s
long-range financial forecast.
Figure 9: Historical and Projected Operational Costs
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
The Water Utility’s CIP consists of the following types of projects:
One time projects, or large, non-recurring replacement of system assets (such as
reservoir rehabilitation).
Water main replacement, which represents the ongoing replacement of aging water
mains, and sometimes the services associated with those mains.
Ongoing projects, which represent the cost of replacing aging and under-recording
meters and degraded boxes and covers, minor replacements of various types of
distribution system equipment, and the cost of capitalized tools and equipment.
Customer connections, which represents the cost when the Water Utility installs new
services or upgrades existing services at a customer’s request in response to
development or redevelopment. CPAU charges a fee to these customers to cover the
cost of these projects.
Actual
Regio
nal
Water
Syste
m
Projected
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Table 13 shows the FY 2018 projected budget and the five year CIP spending plan, although
these figures are preliminary pending budget discussions starting in May. The ‘committed’
column represents funds committed to contracts for which work has not yet been completed or
invoices paid.
Table 13: Budgeted Water Utility CIP Spending ($000)
The water main replacement program funds the replacement of deteriorating water mains. The
water system consists of over 236 miles of mains, approximately 2,000 fire hydrants, and over
20,000 metered service connections spanning 9 pressure zones over a 26 square mile service
area. CPAU utilizes an asset management database in conjunction with hydraulic modeling
software to prioritize capital improvements. CPAU selects mains for replacement by
researching the maintenance history of the system and identifying those that are undersized,
corroded, and subject to recurring breaks. CPAU uses a scoring system based on criticality in
order to prioritize which mains to replace first, and coordinates with the Public Works street
maintenance program to avoid cutting into newly repaved streets. CPAU replaces
approximately 3 miles of main per year, or 1.3% of the system.
Costs for the water main replacement program are increasing for a variety of reasons:
Fire Code regulations now mandate fire sprinklers for new residential units. To
accommodate increased fire flows, new main replacement projects require larger
diameter pipe.
CPAU has switched to high-density polyethylene (HDPE) for its mains. Installation costs
for this material are slightly higher, though lifecycle costs are lower, and the material
performs better. Joints in distribution mains are the most likely place for failure, and
sections of HDPE pipe can be fused together rather than connected with fittings. In the
long run, this will reduce losses and maintenance costs.
To take full advantage of HDPE’s fusibility, CPAU is now replacing the services along
with the water mains with new HDPE services. In the past, the existing services were
reconnected, regardless of the material. This new practice costs more in the short run,
but will provide long term benefits.
Lastly, costs have escalated after the recession. The regional and even national focus
on infrastructure improvement has created labor shortages in the construction market,
leading to higher bids than were seen in the past.
These factors have created some uncertainty in future water main replacement costs. As bids
for new projects, such as upgrades to University Avenue, have consistently come in higher over
the last few years, future main replacement project budgets have been increased from prior
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
One Time Projects 6,123 (606) 5,516 3,578 2,200 2,200 2,200 - -
Water Main Replacement 10,637 (1,387) 9,251 4,780 7,685 6,454 6,647 6,847 7,055
Ongoing Projects 3,086 (518) 2,568 749 2,025 1,982 2,039 2,099 2,161
Customer Connections 773 (373) 401 72 732 754 777 800 824
TOTAL 20,619 (2,884) 17,736 9,180 12,642 11,389 11,663 9,746 10,040
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
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year’s estimates to reflect expected bid estimates. If the cost of water main replacement
continues to rise at its current levels, budgets may need to be revised further. However, CPAU
is nearing the end of a long term water main replacement program initiated in 1993 to replace
the oldest and most degraded parts of the system. Roughly 25% of the system has been
replaced, and the rate of water leaks has decreased 50%. CPAU initiated a master planning
process in FY 2015 that was completed in 2016 to evaluate the current state of the distribution
system and determine the necessary rate of main replacement in future years. Currently the
replacement rate of about 1.3% of the system each year is an 80-year replacement cycle.
In last year’s financial forecast, staff projected a two year delay in new main replacement
projects. However, some of these delayed projects are now moving forward. The University
Avenue Business District project is progressing, and may require a budget increase of $3 million
in FY 2018 to continue. However, there still could be delays due to rising construction costs and
also the ongoing issue with keeping and maintaining qualified staff to design and work on
projects. The Water CIP estimates assume the resumption of annual main replacement
projects, starting in FY 2019. Staff assumes capital investment cost increases in 2024 and
beyond of approximately 3% annually.
Included in the one-time project budget is seismic water system upgrades and/or replacement
for the Corte Madera, Park, Boronda and Dahl reservoirs to improve earthquake resistance.
This work will improve protection from water loss at these reservoirs in a seismic event. If an
earthquake caused a significant water leak, this could lead to loss of water for firefighting, loss
of water storage for drinking, property damage from flooding or mudslides, and environmental
damages. Staff estimates this work will cost $2 million each year for three years beginning in FY
2019. In FY 2021, as part of the Electric fund CIP plan, there is an initiative to move meters to an
Advanced Metering Infrastructure, or AMI, to allow for more advanced monitoring, metering
and billing of the electric usage. This AMI network, however, can also be used to read water
and gas meters as well, and thus the plan to transition all Utility meters to the AMI platform.
Staff has included an additional $1.5 million in FY 2019 and FY 2020 for preparatory work and
meter testing, and $4.16 million for general meter replacement costs in FY2021.
One project not included in this forecast is the seismic strengthening of a large water
transmission line in the foothills. Staff has engaged a consultant to investigate alternatives for
this project. The consultant is analyzing an alternative that involves installing a valve and hose
system that could be used to bypass breaks in the line while they are repaired after an
earthquake. This is a relatively low cost alternative that would not substantially affect the
financial forecast. The study is not finalized yet, however, and if it is determined that the entire
pipeline needs to be replaced, it could cost between $15 million and $20 million, which would
likely require bond financing and would substantially affect the financial forecast.
Ongoing Projects and Customer Connections are projected to cost approximately $2.8 million in
FY 2019 and increase by an average of 2% per year through the end of the forecast period.
Actual expenses for these projects fluctuate annually depending on how many defective meters
are discovered and replaced during routine maintenance, as well as how much development
and redevelopment is going on that prompts the replacement or upgrade of water services. It is
worth noting that property owners pay a fee for water service replacement or expansion during
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redevelopment, so when the number of projects go up (meaning higher costs for this activity),
so does fee revenue.
Aside from customer connections, the CIP plan for FY 2019 to FY 2023 is funded by revenue
from utility rates and capacity fees. Appendix B: Water Utility Capital Improvement Program
(CIP) Detail shows the details of the plan.
SECTION 6D: DEBT SERVICE
The Water Utility’s annual debt service is roughly $3.2 million per year. This is related to two
bond issuances, one requiring payments through 2026, the other through 2035. CPAU is in
compliance with all covenants on both bonds.
The first bond is the 2009 Water Revenue Bond, Series A, issued for $35 million to finance
construction of the Emergency Water Supply and Storage project (the El Camino Reservoir, new
wells, rehabilitation of existing wells and tanks, etc.) and to be retired by 2035. As part of the
‘Build America’ bond program, there is an interest payment subsidy from the Federal
Government of 35%. There is always the possibility that the federal government will choose to
stop payment on this subsidy. The automatic federal spending cuts under the Budget Control
Act (BCA) of 2011 have already reduced the subsidy by $50,000 per year, and if planned cuts
through 2021 proceed without amendment, staff estimates that the subsidy would be reduced
by over $200,000 per year by 2021. The Bipartisan Budget Act of 2013, which relieved some of
the discretionary spending cuts in the 2011 BCA, did not affect automatic cuts to the subsidy,
and actually extended the automatic cuts through 2023.
The second bond issuance is the 2011 Utility Revenue Refunding Bond, Series A, which is to be
retired in 2026. This $17.2 million issuance refinanced an earlier Water and Gas Utility bond
issuance, the 2002 Utility Revenue Bonds, Series A, which was issued to finance various capital
improvements for both systems. The Water Utility’s share of the issuance was roughly $7.8
million.
Table 14 shows the cost of debt service for the Water Utility’s share of these bond issuances for
the financial forecast period:
Table 14: Water Utility Debt Service ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
2009 Water Revenue Bonds,
Series A (net of grants)
2,066 2,081 2,097 2,114 2,132 2,151 2,151 2,151
2011 Utility Revenue Bonds,
Series A
656 654 654 656 657 658 658 658
Both the 2009 and 2011 Bonds include the following covenants: 1) net revenues plus Available
Reserves shall at least equal 125% of the maximum annual debt service, and 2) Available
Reserves shall be at least 5 times the maximum annual debt service. Note that “Available
Reserves,” as defined for both bonds, include the reserves for the Gas and Electric systems, not
just the Water system. This Financial Plan maintains compliance with these covenants
throughout the forecast period, as shown in Appendix A: Water Utility Financial Forecast Detail.
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The net revenues (but not the reserves) of the Water Utility are also pledged for one other
bond as shown in Table 15 below, even though the Water Utility is not responsible for the debt
service payments. The Water 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. Requirements of the California Constitution require that any amounts
advanced from one utility to pay debt service for another utility must be repaid by the
borrowing fund.
Table 15: Other Issuances Secured by the Water Utility’s Revenues or Reserves
Bond Issuance Responsible
Utilities
Annual Debt
Service ($000)
Secured by Water Utility’s:
Net Revenues Reserves
1995 Series A Utility
Revenue Bonds Storm Drain $680 Yes No
SECTION 6E: OTHER REVENUES
The Water Utility receives most of its revenues from sales of water. The next largest source is
connection and capacity fees, which in FY 2017 represented 58% of revenue from sources other
than water sales. The remainder consisted of a variety of miscellaneous charges, transfers and
interest income.
Revenues from connection and capacity fees have more than doubled since FY 2009.
Connection fees are charged to new developments that need new or replacement service
connections, while capacity fees are charged to development that put additional demands on
the water distribution system. Revenue from these sources decreased slightly during the
recession, but has increased substantially since then. Staff is forecasting lower revenue from
these sources in subsequent years, but has increased connection fees that are expected to
offset these reductions to some extent.
Other revenue sources are projected to stay stable through the forecast period, though interest
income always fluctuates depending on changes in interest rates. Some uncertainty also exists
related to the Federal government’s commitment to continuing to pay the interest subsidy on
the Build America Bonds.
SECTION 6F: SALES REVENUES
Staff based the sales revenue projections on the load forecast in Section 5A: Load Forecast and
the projected rate changes shown in Figure 5. Except where stated otherwise, these load
forecasts are based on normal precipitation. Precipitation can vary substantially, and this can
affect revenues substantially. In dry years customers use more water, increasing revenues, and
in wet years they use less. One factor that is difficult to predict is customer usage recovery
post-drought. Usage will continue to rise until customers reach their level of desired
consumption. Where this new ‘normal’ level plateaus at, and the speed with which it reaches
level, is difficult to predict. Staff will continue to monitor these patterns and adjust projections
accordingly.
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SECTION 7: COMMUNICATIONS PLAN
In FY 2019, communications will continue to focus on water utility rate increases, including the
reasons why and how rates may change contingent upon varying precipitation levels.
Additionally, we will focus on how infrastructure costs and rising rates from our wholesale
water supplier, the San Francisco Public Utilities Commission, increases CPAU costs and must be
recovered through rate increases. Rates communications will include a substantial update to
information on a webpage dedicated to Utilities rates, “breaking news” on the Utility home
webpage, discussion in the Proposition 218 rate adjustment notice, bill insert and frequent
educational updates to internal and external stakeholders (customer service, marketing, City
Manager’s Office, UAC, City Council, business and residential customers). Other
communications vehicles will include financial plans, presentations to UAC, Finance Committee,
City Council and any media coverage as a result of the rate increases. CPAU will continue its
outreach about continuing to make water conservation a way of life, regardless of drought or
rain conditions. Messaging will reinforce the importance of water use efficiency, and that
although rates are increasing, efficient usage should mean that a customer should not see a
significant increase in water utility costs on their bills.
Water conservation outreach will promote water use efficiency rebates, incentives and easy
water-saving behaviors through bill inserts, web updates, email newsletters, videos for the web
and television, presentations to customer groups and the use of social media. To keep
customers apprised of the status and accomplishments of CIP projects, a network of project
web pages are maintained. Traffic is driven to the website via ads in publications, newspaper
inserts, and through the comprehensive portfolio of outreach strategies as outlined above.
Safety topics are also emphasized year-round. For all utility outreach, while print materials and
website pages still feature prominently, CPAU is placing more emphasis on digital advertising
content, direct mail, community safety/emergency preparation events and presentations.
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APPENDICES
Appendix A: Water Utility Financial Forecast Detail
Appendix B: Water Utility Capital Improvement Program (CIP) Detail
Appendix C: Water Utility Reserves Management Practices
Appendix D: Description of Water Utility Operational Activities
Appendix E: Sample of Water Utility Outreach Communications
APPENDIX A: WATER UTILITY FINANCIAL FORECAST DETAIL
1 FISCAL YEAR 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 FY 2028
2
3 WATER SUPPLY
4 Purchases 5,532,947 5,507,153 4,671,433 4,127,085 4,172,038 4,852,150 4,986,189 4,926,355 4,867,238 4,808,832 4,751,126 4,694,112 4,637,783 4,582,129 4,527,144 4,472,818
5 Sales 5,097,392 5,047,148 4,433,016 3,858,825 3,852,185 4,580,430 4,706,962 4,650,479 4,594,673 4,539,537 4,485,063 4,431,242 4,378,067 4,325,530 4,273,624 4,222,340
6
7 BILL AND RATE CHANGES
8 Variable Charge (Supply)11%-16%25%22%9%7%-6%5%5%6%5%7%2%4%2%2%
9 Variable Charge (Distribution)17%30%-16%10%5%-1%13%8%9%6%3%2%1%3%1%2%
10 Service Charge (Distribution)75%9%0%-10%3%0%12%7%7%5%2%1%1%2%2%4%
11 Change in System Average Rate 22%8%0%11%7%2%4%7%7%6%4%4%1%3%1%2%
12 Change in Average Residential Bill 21%7%-1%17%4%-2%3%5%5%5%3%3%1%2%2%3%
13
14 STARTING RESERVES
15 Reappropriations (Non-CIP)- - - - - - - - - - - - - - - -
16 Commitments (Non-CIP)714,000 2,000 347,000 347,000 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273
17 Restricted for Debt Service 3,225,000 3,225,000 3,331,000 3,316,000 3,299,194 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000
18 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - - -
19 Capital Reserve - - - 4,000,000 2,726,096 2,726,096 2,726,096 2,726,096 - - - - - - - -
20 Rate Stabilization Reserve 7,996,000 17,272,000 20,133,000 6,567,000 1,877,437 4,069,000 4,069,000 4,069,000 4,069,000 - - - - - - -
21 Operations Reserve - - - 11,663,836 14,606,828 12,734,948 13,741,000 12,896,930 11,728,634 9,937,852 11,244,928 12,473,900 13,253,905 13,498,028 13,525,556 13,122,780
22 Unassigned - - - - - 7,056,052 4,986,007 - - - - - - - - -
23 TOTAL STARTING RESERVES 12,935,000 21,499,000 24,811,000 25,893,836 22,686,828 30,023,369 28,959,376 23,129,299 19,234,907 13,375,125 14,682,201 15,911,173 16,691,178 16,935,301 16,962,829 16,560,053
24
25 REVENUES
26 Net Sales 36,647,924 39,029,262 33,654,549 36,136,644 41,657,382 43,189,169 45,946,518 48,550,827 51,381,619 53,992,359 55,490,378 56,986,955 57,211,828 58,435,519 58,630,830 59,331,362
27 Other Revenues and Transfers In 6,811,461 4,053,920 7,504,848 3,258,936 5,829,851 4,702,923 3,671,998 3,735,314 3,800,902 3,870,756 3,942,093 4,034,793 4,129,947 4,227,619 4,327,878 4,430,793
28 TOTAL REVENUES 43,459,385 43,083,182 41,159,397 39,395,579 47,487,233 47,892,092 49,618,516 52,286,141 55,182,521 57,863,115 59,432,471 61,021,747 61,341,775 62,663,138 62,958,709 63,762,155
29
30 EXPENSES
31 Water Purchases 16,605,351 15,705,288 15,669,935 17,626,020 20,075,322 22,061,917 22,611,475 23,355,859 24,190,148 25,318,382 26,207,075 27,533,642 27,680,356 28,458,072 28,558,184 28,658,677
32 Operating Expenses 679.9%2.9%5.8%-54.7%158.5%
33 Administration
34 Allocated Charges 2,422,880 2,366,077 2,342,985 2,953,291 3,151,373 2,438,768 2,490,375 2,540,960 2,597,475 2,657,609 2,719,082 2,773,765 2,829,463 2,911,318 2,966,458 3,034,716
35 Rent 1,911,963 2,192,454 2,249,457 1,803,087 1,720,711 2,931,563 3,092,799 3,120,634 3,148,720 3,177,058 3,208,829 3,240,917 3,273,326 3,306,059 3,339,120 3,372,511
36 Debt Service 3,219,165 3,220,208 3,218,869 3,222,606 3,219,316 3,222,669 3,220,858 3,220,638 3,222,843 3,223,563 3,224,553 3,224,553 3,224,553 3,224,553 3,224,553 3,224,553
37 Transfers and Other Adjustments 2,241,793 335,808 63,612 (377,200) (256,608) 391,302 399,129 407,111 415,253 423,558 432,030 432,030 432,030 432,030 432,030 432,030
38 Subtotal, Administration 9,795,801 8,114,546 7,874,923 7,601,785 7,834,792 8,984,302 9,203,160 9,289,342 9,384,290 9,481,788 9,584,493 9,671,264 9,759,372 9,873,960 9,962,160 10,063,809
39 Resource Management 557,910 570,040 488,331 592,744 868,038 1,089,530 1,121,904 1,163,283 1,204,080 1,241,610 1,278,957 1,312,198 1,344,159 1,378,016 1,399,695 1,432,650
40 Operations and Mtc 4,944,064 4,986,274 5,283,426 5,038,570 5,290,549 6,426,788 6,623,269 6,878,570 7,128,663 7,356,594 7,583,011 7,784,574 7,977,523 8,175,463 8,301,450 8,497,350
41 Engineering (Operating)338,659 381,502 358,128 282,472 355,852 397,451 409,827 426,073 441,926 456,290 470,543 483,234 495,348 507,516 515,230 527,406
42 Customer Service 1,584,759 1,677,926 1,821,447 2,076,559 1,616,008 2,193,588 2,262,089 2,352,159 2,439,994 2,519,510 2,598,397 2,668,637 2,735,657 2,802,749 2,845,252 2,912,511
43 Allowance for Unspent Budget - - - - - (464,458) (477,834) (494,626) (511,325) (526,854) (542,343) (556,130) (569,447) (583,993) (593,360) (607,300)
44 Subtotal, Operating Expenses 17,221,192 15,730,288 15,826,254 15,592,128 15,965,239 18,627,201 19,142,414 19,614,801 20,087,627 20,528,938 20,973,059 21,363,777 21,742,612 22,153,711 22,430,426 22,826,428
45 Capital Program Contribution 1,068,841 8,335,605 8,580,372 9,082,021 4,110,131 8,266,967 13,694,704 13,209,873 16,764,528 10,708,718 11,023,365 11,344,323 11,674,684 12,023,827 12,372,875 12,736,548
46 TOTAL EXPENSES 34,895,385 39,771,182 40,076,561 42,300,170 40,150,692 48,956,085 55,448,593 56,180,534 61,042,304 56,556,039 58,203,499 60,241,742 61,097,652 62,635,610 63,361,485 64,221,653
47 9.04
48 ENDING RESERVES
49 Reappropriations (Non-CIP)- - - - - - - - - - - - - - - -
50 Commitments (Non-CIP)2,000 347,000 347,000 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273
51 Restricted for Debt Service 3,225,000 3,331,000 3,316,000 3,299,194 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000
52 Emergency Plant Replacement 1,000,000 1,000,000 - - - - - - - - - - - - - -
53 Capital Reserve - - 4,000,000 2,726,096 2,726,096 2,726,096 2,726,096 - - - - - - - - -
54 Rate Stabilization Reserve 17,272,000 20,133,000 6,567,000 1,877,437 4,069,000 4,069,000 4,069,000 4,069,000 - - - - - - - -
55 Operations Reserve - - 11,663,836 14,606,828 12,734,948 13,741,000 12,896,930 11,728,634 9,937,852 11,244,928 12,473,900 13,253,905 13,498,028 13,525,556 13,122,780 12,663,281
56 Unassigned - - - - 7,056,052 4,986,007 - - - - - - - - - -
57 TOTAL ENDING RESERVES 21,499,000 24,811,000 25,893,836 22,686,828 30,023,369 28,959,376 23,129,299 19,234,907 13,375,125 14,682,201 15,911,173 16,691,178 16,935,301 16,962,829 16,560,053 16,100,554
58
59 OPERATIONS RESERVE
60 Min (60 days of non-capital expenses)- - 5,230,611 5,145,323 6,320,551 7,015,601 7,197,171 7,403,859 7,625,531 7,890,478 8,116,649 8,398,943 8,485,334 8,680,756 8,742,700 8,824,316
61 Target (90 days of non-capital expenses)- - 9,395,240 8,698,557 9,527,750 10,378,300 10,847,792 11,159,004 11,493,609 11,893,618 12,235,541 12,668,887 12,808,565 13,116,527 13,219,432 13,354,222
62 Max (120 days of non-capital expenses)- - 13,559,870 12,251,790 12,734,948 13,741,000 14,498,412 14,914,150 15,361,686 15,896,759 16,354,432 16,938,832 17,131,796 17,552,298 17,696,164 17,884,127
63 Risk Assessment Value 2,481,768 2,677,436 2,229,786 2,645,469 3,404,677 3,498,658 4,006,561 3,517,485 3,605,222 3,662,346 3,720,662 3,806,640 3,893,630 4,036,251
64
65 DEBT SERVICE COVERAGE RATIO
66 Net Revenues (125% of Debt Service)951%876%878%931%1020%1163%1196%1234%1274%1322%1363%1416%1433%1470%1481%1497%
67 Available Reserves (5x Debt Service)*5.7 6.6 6.9 6.0 8.3 7.9 6.1 4.9 3.1 3.5 3.9 4.1 4.2 4.2 4.1 3.9
Appendix A (continued)
1 FISCAL YEAR 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 FY 2028
2
3 REVENUES
4 Net Sales 84%91%82%92%88%90%93%93%93%93%93%93%93%93%93%93%
5 Other Revenues and Transfers In 16%9%18%8%12%10%7%7%7%7%7%7%7%7%7%7%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Water Purchases 48%39%39%42%50%45%41%42%40%45%45%46%45%45%45%45%
10 Operating Expenses
11 Administration
12 Allocated Charges 7%6%6%7%8%5%4%5%4%5%5%5%5%5%5%5%
13 Rent 5%6%6%4%4%6%6%6%5%6%6%5%5%5%5%5%
14 Debt Service 9%8%8%8%8%7%6%6%5%6%6%5%5%5%5%5%
15 Transfers and Other Adjustments 6%1%0%-1%-1%1%1%1%1%1%1%1%1%1%1%1%
16 Subtotal, Administration 28%20%20%18%20%18%17%17%15%17%16%16%16%16%16%16%
17 Resource Management 2%1%1%1%2%2%2%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 14%13%13%12%13%13%12%12%12%13%13%13%13%13%13%13%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 5%4%5%5%4%4%4%4%4%4%4%4%4%4%4%5%
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 49%40%39%37%40%38%35%35%33%36%36%35%36%35%35%36%
23 Capital Program Contribution 3%21%21%21%10%17%25%24%27%19%19%19%19%19%20%20%
24 TOTAL EXPENSES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
25
26 RISK ASSESSMENT DETAIL
27 Distribution Revenue Variance 1,623,731 1,769,234 1,818,772 1,818,772 2,035,206 2,177,671 2,330,108 2,446,613 2,502,885 2,527,914 2,553,193 2,604,257 2,656,342 2,762,596
28 10% CIP Program Contingency 858,037 908,202 411,013 826,697 1,369,470 1,320,987 1,676,453 1,070,872 1,102,337 1,134,432 1,167,468 1,202,383 1,237,287 1,273,655
29 Total Risk Asssessment Value 2,481,768 2,677,436 2,229,786 2,645,469 3,404,677 3,498,658 4,006,561 3,517,485 3,605,222 3,662,346 3,720,662 3,806,640 3,893,630 4,036,251
30 Projected Operations Reserve 11,663,836 14,606,828 12,734,948 13,741,000 12,896,930 11,728,634 9,937,852 11,244,928 12,473,900 13,253,905 13,498,028 13,525,556 13,122,780 12,663,281
31 Operations Reserve, % of Risk Value 470%546%571%519%379%335%248%320%346%362%363%355%337%314%
32
33 OPERATIONS RESERVE
34 Min (60 days of non-capital expenses)- - 5,230,611 5,145,323 6,320,551 7,015,601 7,197,171 7,403,859 7,625,531 7,890,478 8,116,649 8,398,943 8,485,334 8,680,756 8,742,700 8,824,316
35 Target (90 days of non-capital expenses)- - 9,395,240 8,698,557 9,527,750 10,378,300 10,847,792 11,159,004 11,493,609 11,893,618 12,235,541 12,668,887 12,808,565 13,116,527 13,219,432 13,354,222
36 Max (120 days of non-capital expenses)- - 13,559,870 12,251,790 12,734,948 13,741,000 14,498,412 14,914,150 15,361,686 15,896,759 16,354,432 16,938,832 17,131,796 17,552,298 17,696,164 17,884,127
37 Risk Assessment Value 2,481,768 2,677,436 2,229,786 2,645,469 3,404,677 3,498,658 4,006,561 3,517,485 3,605,222 3,662,346 3,720,662 3,806,640 3,893,630 4,036,251
38
39 DEBT SERVICE COVERAGE RATIO
40 Net Revenues (125% of Debt Service)951%876%878%931%1020%1163%1196%1234%1274%1322%1363%1416%1433%1470%1481%1497%
41 Available Reserves (5x Debt Service)*5.7 6.6 6.9 6.0 8.3 7.9 6.1 4.9 3.1 3.5 3.9 4.1 4.2 4.2 4.1 3.9
42 *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.
WATER UTILITY FINANCIAL PLAN
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APPENDIX B: WATER UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
Project #Project Name
Reappropriated / Carried
Forward from Previous
Years
Current Year
Funding
Proposed Budget
Amendments
Spending, Current
Year
Remaining in CIP
Reserve Fund Commitments FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
ONE TIME PROJECTS
WS-07000 Regulation Station Imp.776,358 196,054 - - 972,412 624,149 - - - - -
WS-07001 Water Recycling Facilities - 395,649 - - 395,649 - - - - - -
WS-08001 Water Reservoir Coating 1,130,852 - - (152,532) 978,320 621,825 - - - - -
WS-09000 Seismic Water System 2,495,234 1,128,594 - (453,807) 3,170,021 2,332,347 2,000,000 2,000,000 2,000,000 - -
WS-15004 Water System Master Plan 16 - - - 16 16 - - - - -
WS-19000 Mayfield Reservoir - - - - - - 200,000 200,000 200,000 - -
Subtotal, One-time Projects 4,402,460 1,720,297 - (606,339) 5,516,418 3,578,337 2,200,000 2,200,000 2,200,000 - -
WATER MAIN REPLACEMENT PROGRAM
WS-11000 WMR-Project 25 381,939 - - - 381,939 - - - - - -
WS-12001 WMR- Project 26 5,410,048 1,143,000 3,027,320 (1,386,803) 8,193,565 4,780,180 600,000 - - - -
WS-13001 WMR - Project 27 80,000 595,000 - - 675,000 - 6,500,000 - - - -
WS-14001 WMR - Project 28 - - - - - - 585,107 5,851,070 - - -
WS-15002 WMR - Project 29 - - - - - - - 602,660 6,026,602 - -
WS-16001 WMR - Project 30 - - - - - - - - 620,740 6,207,400 -
WS-19001 WMR - Project 31 - - - - - - - - - 639,362 6,396,320
WS-20000 WMR - Project 32 - - - - - - 658,820
Subtotal, Water Main Replacement Prog.5,871,987 1,738,000 3,027,320 (1,386,803) 9,250,504 4,780,180 7,685,107 6,453,730 6,647,342 6,846,762 7,055,140
ONGOING PROJECTS
WS-80014 Services/Hydrants 11,158 412,000 - (231,440) 191,718 30,534 424,360 437,091 450,204 463,710 477,621
WS-80015 Water Meters - 565,000 - (87,733) 477,267 - 500,000 515,000 530,450 546,364 562,755
WS-02014 W-G-W Utility GIS Data 148,826 402,628 - (43,526) 507,928 405,300 442,890 456,177 469,862 483,958 498,477
WS-13002 Equipment/Tools - 50,000 - - 50,000 - 50,000 50,000 50,000 50,000 50,000
WS-11003 Dist. Sys. Improvements 863,136 247,000 - (128,810) 981,326 126,122 354,000 261,620 269,469 277,553 285,880
WS-11004 Supply Sys. Improvements 139,213 247,000 - (26,493) 359,720 187,227 254,000 261,620 269,469 277,553 285,880
Subtotal, Ongoing Projects 1,162,333 1,923,628 - (518,002) 2,567,959 749,183 2,025,250 1,981,508 2,039,454 2,099,138 2,160,613
CUSTOMER CONNECTIONS (FEE FUNDED)
WS-80013 Water System Extensions 62,665 710,700 - (372,686) 400,679 71,918 732,021 753,981 776,601 799,899 823,896
Subtotal, Customer Connections 62,665 710,700 - (372,686) 400,679 71,918 732,021 753,981 776,601 799,899 823,896
GRAND TOTAL 11,499,445 6,092,625 3,027,320 (2,883,830)17,735,560 9,179,618 12,642,378 11,389,219 11,663,397 9,745,799 10,039,649
Funding Sources
Connection/Capacity Fees 902,280 - 929,348 957,228 985,946 1,015,524 1,045,990
Other Utility Funds (Asset Mgmt, GIS Systems)268,418 - 295,260 304,118 313,242 322,640 332,320
Water Service Hydrant Replacement 1,224,608 1,261,346 1,299,188 1,338,164 1,378,310
Utility Rates 4,921,927 3,027,320 10,193,162 8,866,527 9,065,021 7,069,471 7,283,029
CIP-RELATED RESERVES DETAIL
6/30/2017
(Actual)
6/30/2018
(Unaudited)
Reappropriations (excl. Bond Funded)1,292,081 8,555,942
Commitments (excl. Bond Funded)10,207,364 9,179,618
WATER UTILITY FINANCIAL PLAN
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APPENDIX C: WATER UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Water 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, for the Water Utility Financial Plan
delivered in conjunction with the FY 2015 budget, FY 2015 to FY 2021 is 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. Reserves
The Water Utility’s Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 3 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 4 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Water Utility’s Capital
Improvement Program (CIP), as described in Section 5 (CIP Reserve)
d) For rate stabilization, as described in Section 6 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 7 (Operations Reserve)
f) 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 8 (Unassigned Reserves).
Section 3. Reserve for Commitments
At the end of each fiscal year the Reserve for Commitments will be set to an amount equal
to the total remaining spending authority for all contracts in force for the Water Utility at
that time.
Section 4. Reserve for Re-appropriations
At the end of each fiscal year the Reserve for Re-appropriations will be set to an amount
equal to the amount of all remaining capital and non-capital budgets, if any, that will be re-
appropriated to the following fiscal year in accordance with Palo Alto Municipal Code
Section 2.28.090.
WATER UTILITY FINANCIAL PLAN
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Section 5. 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 12 months of budgeted CIP expense
Maximum Level 24 months 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 or removed from to that reserve
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
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 6. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and
held to manage the trajectory of future year rate increases. Withdrawal of funds from
the Rate Stabilization Reserve requires Council action. If there are funds in the Rate
Stabilization Reserve at the end of any fiscal year, any subsequent Water Utility
Financial Plan must result in the withdrawal of all funds from this Reserve by the end of
the next Financial Planning Period.
WATER UTILITY FINANCIAL PLAN
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Section 7. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Water Utility’s Fund Balance not included in the reserves
described in Section 3-Section 6 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 7(d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for
that year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months
of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Water Utility shall be designed
to return the Operations Reserve to its target level within four years.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Water Utility’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
8, below.
Section 8. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Water
Utility’s Fund Balance will be held in the Unassigned Reserve. If there are any funds in the
Unassigned Reserve at the end of any fiscal year, the next Financial Plan presented to the
City Council must include a plan to assign them to a specific purpose or return them to the
Water Utility ratepayers by the end of the first fiscal year of the next Financial Planning
Period. For example, if there were funds in the Unassigned Reserves at the end of FY 2015,
and the next Financial Planning Period is FY 2016 through FY 2021, the Financial Plan shall
include a plan to return or assign any funds in the Unassigned Reserve by the end of
FY 2016. Staff may present an alternative plan that retains these funds or returns them over
a longer period of time.
WATER UTILITY FINANCIAL PLAN
F e b r u a r y , 2 0 1 7 36 | P a g e
APPENDIX D: DESCRIPTION OF WATER UTILITY OPERATIONAL ACTIVITIES
This appendix describes the activities associated with the various operational activities referred
to in Section 6B: Operations of this Financial Plan.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, CPAU administrative
overhead, and billing system maintenance costs. This category also includes Water Utility debt
service and rent paid to the General Fund for the land associated with reservoirs and various
other facilities.
Customer Service: This category includes the Water 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 water services.
Engineering (Operating): The Water Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
investigating reports of damaged mains or services and performing emergency repairs;
testing and operating valves;
monitoring water quality and reservoir levels;
monitoring the status of the different pressure zones;
flushing water at hydrants and other closed end points of the system;
building and replacing water services for new or redeveloped buildings; and
testing and replacing meters to ensure accurate sales metering.
This category also includes a variety of functions the utility shares with other City utilities,
including:
the Field Services team (which does field research of various customer service issues);
the Cathodic Protection team (which monitors and maintains the systems that prevent
corrosion in metal tanks and reservoirs); and
the General Services team (which manages and maintains equipment, paves and
restores streets after gas, water, or sewer main replacements, and provides welding
services)
Resource Management: This category includes water procurement, contract management,
water resource planning, interaction with BAWSCA, the SFPUC, and the SCVWD, and tracking of
legislation and regulation related to the water industry.
F e b r u a r y , 2 0 1 7 37 | P a g e
APPENDIX E: SAMPLE OF WATER UTILITY OUTREACH COMMUNICATIONS
180308 jb 6054082 1
Resolution No. _____
Resolution of the Council of the City of Palo Alto Increasing Water Rates by 3%
by Amending Rate Schedules W-1 (General Residential Water Service), W-2
(Water Service from Fire Hydrants), W-3 (Fire Service Connections), W-4
(Residential Master-Metered and General Non-Residential Water Service),
and W-7 (Non-Residential Irrigation Water Service)
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.
B. On June , 11, 2018, the City Council held a full and fair public hearing regarding the
proposed rate increase and considered all protests against the proposals.
C. As required by Article XIIID, Section 6 of the California Constitution and applicable
law, notice of the June 11, 2018 public hearing was mailed to all City of Palo Alto water customers
and property owners on April 27, 2018.
D.The City Clerk has tabulated the total number of written protests presented by the
close of the public hearing, and determined that it was less than fifty percent (50%) of the total
number of customers and property owners subject to the proposed water rate amendments,
therefore a majority protest does not exist against the proposal.
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 W-1 (General Residential Water Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule W-1, as amended, shall become effective July 1, 2018.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule W-2 (Water Service from Fire Hydrants) is hereby amended to read as attached and
incorporated. Utility Rate Schedule W-2, as amended, shall become effective July 1, 2018.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule W-3 (Fire Service Connections) is hereby amended to read as attached and incorporated.
Utility Rate Schedule W-3, as amended, shall become effective July 1, 2018.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule W-4 (Residential Master-Metered and General Non-Residential Water Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule W-4, as amended, shall become
effective July 1, 2018.
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule W-7 (Non-Residential Irrigation Water Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule W-7, as amended, shall become effective July 1, 2018.
SECTION 6. The City Council finds as follows:
ATTACHMENT P
180308 jb 6054082 2
Attachment P
a. Revenues derived from the water rates approved by this resolution do not exceed the
funds required to provide water service.
b.Revenues derived from the water rates approved by this resolution shall not be used
for any purpose other than providing water service, and the purposes set forth in Article VII, Section 2,
of the Charter of the City of Palo Alto.
c.The amount of the water rates imposed upon any parcel or person as an incident of
property ownership shall not exceed the proportional cost of the water service attributable to the
parcel.
SECTION 7. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor that are
not provided to those not charged, and do not exceed the reasonable costs to the City of providing
the service or product.
SECTION 8. The Council finds that the adoption of this resolution changing water rates
to meet operating expenses, purchase supplies and materials, meet financial reserve needs and
obtain funds for capital improvements necessary to maintain service is not subject to the California
Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec. 21080(b)(8) and
Title 14 of the California Code of Regulations Sec. 15273(a). After reviewing the staff report and all
attachments presented to Council, the Council incorporates these documents herein and finds that
sufficient evidence has been presented setting forth with specificity the basis for this claim of CEQA
exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
____________________________ City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
_____________________________
Assistant City Attorney City Manager
_____________________________
Director of Utilities
____________________________
Director of Administrative Services
GENERAL RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-1-1 Effective 7-1-20187
dated 7-1-20176 Sheet No W-1-1
A. APPLICABILITY:
This schedule applies to all separately metered single -family residential dwellings receiving Wwater
Sservices from the City of Palo Alto Utilities.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Wwater Sservices.
C. RATES:
Per Meter
Monthly Service Charge: Per Month
For 5/8-inch meter ..................................................................................................... $ 16.7718.43
For 3/4 inch meter ..................................................................................................... 22.6024.83
For 1 inch meter ........................................................................................................ 34.2637.64
For 1 1/2 inch meter .................................................................................................. 63.4069.66
For 2-inch meter ........................................................................................................ 98.37108.08
For 3-inch meter ........................................................................................................ 209.11229.75
For 4-inch meter ........................................................................................................ 372.31409.05
For 6-inch meter ........................................................................................................ 762.81838.09
For 8-inch meter ........................................................................................................1,403.94542.50
For 10-inch meter ......................................................................................................2,219.92439.01
For 12-inch meter .......................................................................................................32,919.34207.45
Commodity Rate: (To be added to Service Charge and applicable to all pressure zones.)
Per Hundred Cubic Feet (ccf)
Per Month All Pressure Zones
Tier 1 usage ........................................................................................................................ $6.646
Tier 2 usage (All usage over 100% of Tier 1) ........................................................................ 9.4418
ATTACHMENT Q
GENERAL RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-1-2 Effective 7-1-20187
dated 7-1-20176 Sheet No W-1-2
Drought Surcharges (deactivated):
A drought surcharge will be added to the Customer’s applicable cCommodity Rrate for Tier 1 and
Tier 2 Wwater usage when the City Council has determined that a Wwater reduction level is in effect
for the City as described in Section D.3. The drought surcharges in the table below are measured in
dollars per hundred cubic feet (ccf).
Water Usage
Reduction level Level 1 (10/15%) Level 2 (20%) Level 3 (25%)
Tier 1 0.20 0.43 0.64
Tier 2 0.58 1.21 1.85
Temporary Service – Developers
Temporary unmetered service to residential
subdivision developers, per connection ........................................................................ $6.00
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 Ccustomer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Calculation of Usage Tiers
Tier 1 Wwater usage shall be calculated and billed based upon a level of 0.2 ccf per day
rounded to the nearest whole ccf, based on Mmeter reading days of Sservice. As an
example, for a 30 day bill, the Tier 1 level would be 0 through 6 ccf. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
GENERAL RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-1-3 Effective 7-1-20187
dated 7-1-20176 Sheet No W-1-3
3. Drought Surcharge
During period of Wwater shortage or restrictions on local Wwater use, the City Council
may, by resolution, declare the need for citywide Wwater conservation at the 10/15%,
20% or 25% level. While such a resolution is in effect, a drought surcharge will apply.
The purpose of the dDrought sSurcharge is to recover revenues lost as a result of reduced
consumption.
{End}
WATER SERVICE FROM FIRE HYDRANTS
UTILITY RATE SCHEDULE W-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-2-1 Effective 7-1-20187
dated 7-1-20167 Sheet No W-2-1
A. APPLICABILITY: This schedule applies to all Wwater taken from fire hydrants for construction, maintenance, and
other uses in conformance with provisions of a Hydrant Meter Permit.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Wwater Sservices.
C. RATES: 1. Monthly Service Charge.
METER SIZE
5/8 inch ........................................................................................................................... 50.00
3 inch ........................................................................................................................... 125.00 2. Commodity Rate: (per hundred cubic feet) ................................................................ $7.687.77 3. Drought Surcharges (deactivated):
A drought surcharge will be added to the Customer’s applicable CCommodity Rrate when the
City Council has determined that a Wwater reduction level is in effect for the City as described
in Section D.5. The drought surcharges in the table below are measured in dollars per hundred
cubic feet (ccf).
Water Usage
Reduction level Level 1 (10/15%) Level 2 (20%) Level 3 (25%)
Surcharge 0.26 0.53 0.77
D. SPECIAL NOTES: 1. Monthly charges shall include the applicable monthly Sservice Ccharge in addition to usage billed
at the commodity rate. 2. Any person or company applicant using a hydrant without first obtaining a valid Hydrant Meter
WATER SERVICE FROM FIRE HYDRANTS
UTILITY RATE SCHEDULE W-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-2-2 Effective 7-1-20187
dated 7-1-20167 Sheet No W-2-2
Permit or any permittee using a hydrant without a Hydrant Meter Permit shall pay a fee of $50.00
for each day of such use in addition to all other costs and fees provided in this schedule. A hydrant
permit may be denied or revoked for failure to pay such fee. 3. A Mmeter deposit of $750.00 may be charged any applicant for a Hydrant Meter Permit as a
prerequisite to the issuance of a permit and Mmeter(s). A charge of $50.00 per day will be added
for delinquent return of hydrant Mmeters. A fee will be charged for any Mmeter returned with
missing or damaged parts. 4. Any person or company using a fire hydrant improperly or without a permit, or who draws Wwater
from a hydrant without a Mmeter installed and properly recording usage shall, in addition to all
other applicable charges be subject to criminal prosecution pursuant to the Palo Alto Municipal
Code.
5. During period of Wwater shortage or restrictions on local Wwater use, the City Council may, by
resolution, declare the need for citywide Wwater conservation at the 10/15%, 20% or 25% level.
While such a resolution is in effect, a drought surcharge will apply. The purpose of the dDrought
sSurcharge is to recover revenues lost as a result of reduced consumption.
{End}
FIRE SERVICE CONNECTIONS
UTILITY RATE SCHEDULE W-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-3-1 Effective 7-1-20186
dated 97-1-20165 Sheet No W-3-1
A. APPLICABILITY:
This schedule applies to all public fire hydrants and private fire Sservice connections.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Wwater Sservices.
C. RATES:
1. Monthly Service Charges
Public Fire Hydrant .................................................................................................... $5.00
Private Fire Service:
2-inch connection .......................................................................................................$3.794.16
4-inch connection .......................................................................................................23.4225.73
6-inch connection ....................................................................................................... 68.0374.74
8-inch connection .......................................................................................................144.97159.28
10-inch connection .....................................................................................................260.70286.43
12-inch connection .....................................................................................................421.11462.67
2. Commodity (To be added to Service Charge unless Wwater is used for fire extinguishing
or testing purposes.)
Per Hundred Cubic Feet
All water usage........................................................................................................... $10.00
D. SPECIAL NOTES:
1. Service under this schedule may be discontinued if Wwater is used for any purpose other
than fire extinguishing or testing and repairing the fire extinguishing facilities. Using
hydrants and fire Sservices for other purposes is illegal and will be subject to the
commodity charge as noted above, fines, and criminal prosecution pursuant to the Palo
Alto Municipal Code.
2. For a combination Wwater and fire Sservice, the general Wwater Sservice schedule shall
FIRE SERVICE CONNECTIONS
UTILITY RATE SCHEDULE W-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-3-2 Effective 7-1-20186
dated 97-1-20165 Sheet No W-3-2
apply.
3. Utilities Rule and Regulation No. 21 provides additional information on Automatic Fire
Services.
4. Repairs and testing of fire extinguishing facilities are not considered unauthorized use of
Wwater if records and documentation are supplied by the Ccustomer.
{End}
RESIDENTIAL MASTER-METERED AND
GENERAL NON-RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-4-1 Effective 7-1-20178
dated 7-1-20176 Sheet No W-4-1
A. APPLICABILITY:
This schedule applies to Water Services to non-residential buildings, and multi-family residential
dwellings served through a Master-Meter. water service in the City of Palo Alto and its distribution
area. This schedule is also applicable to multi-family residential customers served through a master
meter.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Wwater Sservices.
C. RATES: Per Meter
Monthly Service Charge Per Month
For 5/8-inch meter .................................................................................... $ 16.7718.43
For 3/4-inch meter .................................................................................... 22.6024.83
For 1-inch meter .................................................................................... 34.2637.64
For 1 ½-inch meter .................................................................................... 63.4069.66
For 2-inch meter .................................................................................... 98.37108.08
For 3-inch meter .................................................................................... 209.11229.75
For 4-inch meter .................................................................................... 372.31409.05
For 6-inch meter .................................................................................... 762.81838.09
For 8-inch meter ....................................................................................1,403.94542.50
For 10-inch meter ....................................................................................2,219.92439.01
For 12-inch meter ....................................................................................32,919.34207.45
Commodity Rates: (to be added to Service Charge)
Per Hundred Cubic Feet (ccf)
Per Month All Pressure Zones
Per ccf ............................................................................................................ $ 7.687.77
RESIDENTIAL MASTER-METERED AND
GENERAL NON-RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-4-2 Effective 7-1-20178
dated 7-1-20176 Sheet No W-4-2
Drought Surcharges (deactivated):
A drought surcharge will be added to the Customer’s applicable Ccommodity Rrate when the City
Council has determined that a Wwater reduction level is in effect for the City as described in
Section D.2. The drought surcharges in the table below are measured in dollars per hundred cubic
feet (ccf).
Water Usage
Reduction level Level 1 (10/15%) Level 2 (20%) Level 3 (25%)
Surcharge 0.26 0.53 0.77
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 Ccustomer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Drought Surcharge
During period of Wwater shortage or restrictions on local Wwater use, the City Council
may, by resolution, declare the need for citywide Wwater conservation at the 10/15%,
20% or 25% level. While such a resolution is in effect, a drought surcharge will apply.
The purpose of the Ddrought sSurcharge is to recover revenues lost as a result of reduced
consumption.
{End}
NON-RESIDENTIAL IRRIGATION WATER SERVICE
UTILITY RATE SCHEDULE W-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-7-1 Effective 7-1-20187
dated 7-1-20176 Sheet No W-7-1
A. APPLICABILITY:
This schedule applies to non-residential Wwater Wservice supplying dedicated irrigation Mmeters in
the City of Palo Alto and its distribution area.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides Wwater Sservices.
C. RATES:
Per Meter
Monthly Service Charge Per Month
For 5/8-inch meter .................................................................................... $ 16.7718.43
For 3/4-inch meter .................................................................................... 22.6024.83
For 1-inch meter .................................................................................... 34.2637.64
For 1 1/2 inch meter .................................................................................... 63.4069.66
For 2-inch meter .................................................................................... 98.37108.08
For 3-inch meter .................................................................................... 209.11229.75
For 4-inch meter .................................................................................... 372.31409.05
For 6-inch meter .................................................................................... 762.81838.09
For 8-inch meter ....................................................................................1,403.94542.50
For 10-inch meter ....................................................................................2,219.92439.01
For 12-inch meter ....................................................................................32,919.34207.45
Commodity Rates: (to be added to Service Charge)
Per Hundred Cubic Feet (ccf)
Per Month All Pressure Zones
Per ccf ............................................................................................................ $ 9.089.33
Drought Surcharges (deactivated):
A drought surcharge will be added to the Customer’s applicable cCommodity Rrate when the City
Council has determined that a Wwater reduction level is in effect for the City as described in Section
D.2. The drought surcharges in the table below are measured in dollars per hundred cubic feet (ccf).
NON-RESIDENTIAL IRRIGATION WATER SERVICE
UTILITY RATE SCHEDULE W-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-7-2 Effective 7-1-20187
dated 7-1-20176 Sheet No W-7-2
Water Usage
Reduction level Level 1 (10/15%) Level 2 (20%) Level 3 (25%)
Surcharge 0.53 1.25 2.02
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 Ccustomer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Drought Surcharge
During period of Wwater shortage or restrictions on local Wwater use, the City Council
may, by resolution, declare the need for citywide Wwater conservation at the 10/15%,
20% or 25% level. While such a resolution is in effect, a drought surcharge will apply.
The purpose of the Ddrought Ssurcharge is to recover revenues lost as a result of reduced
consumption.
{End}
ATTACHMENT R
Resolution No.
Resolution of the Council of the City of Palo Alto Amending Utility Rate
Schedule D-1 (Storm and Surface Water Drainage) Increasing the
Storm Water Management Fee Rates by 2.9% Per Month Per Equivalent
Residential Unit for Fiscal Year 2019
The Council of the City of Palo Alto RESOLVES as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule D-1 (Storm and Surface Water Drainage) is hereby amended to read in
accordance with sheet D-1-1, attached hereto and incorporated herein. The foregoing Utility
Rate Schedule, as amended, shall become effective July 1, 2018.
SECTION 2. The Council finds as follows:
a. This annual inflation adjustment is being imposed to offset the effects of inflation on
labor and material costs, as authorized by the voter-approved Storm Water Management
Fee, which was approved by a majority of Palo Alto property owners on April 11, 2017.
b. Revenues derived from the Fee approved by this resolution do not exceed the funds
required to provide storm and surface water drainage service.
c. Revenues derived from the Fee approved by this resolution shall not be used for any
purpose other than providing storm and surface water drainage service, and the
purposes set forth in Article VII, Section 2, of the Charter of the City of Palo Alto.
d. The amount of the Fee imposed upon any parcel or person as an incident of property
ownership shall not exceed the proportional cost of providing the storm and surface
water drainage service attributable to the parcel.
SECTION 3. The Council finds that modification and approval of this change to the
Utility Rate Schedule D-1 (General Storm and Surface Water Drainage) for the purpose of meeting
operating expenses, purchase supplies and materials, meet financial reserve needs and obtain
funds for capital improvements necessary to maintain service is not subject to the California
Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec. 21080(b)(8)
and Title 14 of the California Code of Regulations Sec. 15273(a). After reviewing the staff report
and attachments presented to Council regarding the Storm Water Management Fee, the Council
incorporates these documents and finds that sufficient evidence has been presented setting forth
with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
Assistant City Attorney City Manager
Director of Public Works
Director of Administrative Services
GENERAL STORM AND SURFACE WATER DRAINAGE
UTILITY RATE SCHEDULE D-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 76-1-20187
Supersedes Sheet No.D-1-1 dated 67-1-20176 Sheet No. D-1-1
A. APPLICABILITY:
This schedule applies to all storm and surface water drainage service, excepting only those
users and to the extent that they are constitutionally exempt under the Constitution of the
State of California or who are determined to be exempt pursuant to Rule and Regulation 25.
B. TERRITORY:
Inside the incorporated limits of the city of Palo Alto and land owned or leased by the city.
C. RATES:
Per Month:
Storm Drainage Fee per Equivalent Residential Unit (ERU) ............................................... $14.0513.65
D. SPECIAL NOTES:
1.An Equivalent Residential Unit (ERU) is the basic unit for computation of storm
drainage fees for residential and non-residential customers. All single-family residential
properties shall be billed the number of ERUs specified in the following table, based on
an analysis of the relationship between impervious area and lot size for Palo Alto
properties.
RESIDENTIAL RATES (Single-Family Residential Properties
PARCEL SIZE (sq.ft.) ERU
<6,000 sq.ft. 0.8 ERU
6,000 - 11,000 sq.ft. 1.0 ERU
>11,000 sq.ft. 1.4 ERU
All other properties will have ERU's computed to the nearest 1/10 ERU using the
following formula:
No. of ERU = Impervious Area (Sq. Ft.)
2,500 Sq. Ft.
2.For more details on the storm drainage fee, refer to Utilities Rule and Regulation 25.
{End}
ATTACHMENT S
Attachment T
* NOT YET APPROVED *
180524 jb 6055044 1
Resolution No. ______
Resolution of the Council of the City of Palo Alto Adopting a Dark
Fiber Rate Increase and Amending Rate Schedules EDF-1 (Dark Fiber
Licensing Services) and EDF-2 (Dark Fiber Connection Fees)
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule EDF-1 (Dark Fiber Licensing Services) is hereby amended to read as attached and
incorporated. Utility Rate Schedule EDF-1, as amended, shall become effective July 1, 2018.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule EDF-2 (Dark Fiber Connection Fees) is hereby amended to read as attached and
incorporated. Utility Rate Schedule EDF-2, as amended, shall become effective July 1, 2018.
SECTION 3. The Council finds that the revenue derived from the adoption of this
resolution shall be used only for the purpose set forth in Article VII, Section 2, of the Charter of
the City of Palo Alto.
SECTION 4. The Council finds that the adoption of this resolution increasing dark fiber
rates by the Consumer Price Index to meet operating expenses, purchase supplies and
materials, meet financial reserve needs and obtain funds for capital improvements necessary to
maintain service is not subject to the California Environmental Quality Act (CEQA), pursuant to
California Public Resources Code Sec. 21080(b)(8) and Title 14 of the California Code of
Regulations Sec. 15273(a). After reviewing the staff report and all attachments presented to
/ /
/ /
/ /
/ /
/ /
/ /
Attachment T
* NOT YET APPROVED *
180524 jb 6055044 2
Council, the Council incorporates these documents herein and finds that sufficient
evidence has been presented setting forth with specificity the basis for this claim of CEQA
exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
DARK FIBER LICENSING SERVICES
UTILITY RATE SCHEDULE EDF-1
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No EDF-1-1 Effective 07-01-20187
dated 7-01-20176 Sheet No. EDF-1-1
A. APPLICABILITY:
This rate schedule applies to customer accounts established prior to September 18, 2006, unless the customer elects
to apply the EDF-3 rate to the entire customer account. This rate applies to Fiber Optic services from the City of Palo Alto Utilities (CPAU) pertaining to the City's network (Backbone and associated connections).
B. TERRITORY:
Within the incorporated limits of the City of Palo Alto and land owned or leased by the City.
C. FEES:
1.DARK FIBER BACKBONE LICENSE FEES:
The values or ranges for each of these price components are shown below:
(1) Fiber Price………………………………………………………………. $379.76368.91/FM/month(2) Quantity discount ……………………………………………………… $0 to $59.84/FM/month
(3) Buffer tube discount……………………………………………………….. $0 to $59.84/FM/month(4) Route length discount…………………………………………………….. $0 to $77.80/FM/month
(5) Ring topology discount………………………………………………………$0 to $23.94/FM/month(6) Length of term discount…………………………………………………… $0 to $46.80/FM/month
Minimum Backbone License Fee
$574.37557.95/month
Project Minimum Backbone Fees apply to any project proposal signed after September 18, 2006 in which the project connects with the Backbone.
Description for Discounts:
Quantity discount: based on an array of discounts for quantities of fiber licensed on a specific path. Buffer tube discount: discount for numbers of full buffer tubes licensed on a specific path.
Route length discount: based on the route length licensed on a specific project. Ring topology discount: The ring topology discount for customers contracting for complete rings.
Term discount: based on an array of discounts for contracts greater than one and less than ten years.
2.DARK FIBER LATERAL CONNECTION FEES:
Customer responsibilities and fees for drop and custom cable construction are described in the CPAU Rules
and Regulations, Rate Schedule EDF-2, project proposals and other associated documents. In all cases, theLicensee shall pay an annual Drop/Custom Cable Management Fee based on the follow per foot fees:
(1) Drop Cable Management Fees (for the first 12-Fibers) …………………………… $0.03-$0.07/ft/month
(2) Custom Cable Management Fees (for the first 12-Fibers)……………………….. $0.3736/ft/month(3) Fees for additional Drop or Custom Cable fibers (each additional set of 12-Fibers) $0.07/ft/month
ATTACHMENT U
DARK FIBER LICENSING SERVICES
UTILITY RATE SCHEDULE EDF-1
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No EDF-1-2 Effective 07-01-20187
dated 7-01-20176 Sheet No. EDF-1-2
Minimum Drop or Custom Cable Management Fees ........................................................ $283.81275.69/month
Minimum Drop Cable Management Fees apply to any project proposal signed after September 18, 2006.
DARK FIBER LICENSING SERVICES
UTILITY RATE SCHEDULE EDF-1
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No EDF-1-3 Effective 07-01-20187
dated 7-01-20176 Sheet No. EDF-1-3
3. EARLY TERMINATION FEES:
If the Licensee chooses to terminate for convenience the License Agreement or the term of any project
under the License Agreement, then the Licensee shall pay the applicable termination payment as specified in this schedule or in the License Agreement, as provided below.
Unless otherwise provided in the License Agreement, the Licensee shall pay a termination fee in one of the
following amounts, whichever is less:
• Annual fee of the contract year that the Licensee chooses to terminates in full without term
discounts, or
• Remaining fees of the project term as indicated in the License Agreement.
D. SPECIAL NOTES:
1. All fees must be paid to the City in accordance with the terms of the Dark Fiber License Agreement, the
customer’s project proposals and all the applicable Utilities Rates, Rules, and Regulations.
2. All fees and minimum charges are subject to Consumer Price Index (CPI) adjustments, to be applied annually, except as defined by Section D.3 of this Rate Schedule. Discounts will not be modified by
changes to CPI. 3. The CPI adjustment will be based on the Consumer Price Index for All Urban Consumers (CPI-U) for the San Francisco-Oakland-San Jose MSA, published by the U.S. Department of Labor, Bureau of Labor
Statistics. The adjustment is calculated by dividing the most recent calendar year December CPI by the December CPI in the year rates last changed. In the event that the change between December CPI’s
indicates an adjustment of less than 1% is required, a change to rate schedules may not be made for the upcoming year. Future rate changes will take the last year of change as the new base year for purposes of
calculation.
{End}
DARK FIBER SERVICE CONNECTION FEES
UTILITY RATE SCHEDULE EDF-2
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No EDF-2-1 Effective 7-01-20187
dated 7-01-20176 Sheet No. EDF-2-1
A. APPLICABILITY: This schedule applies to all connections, expansions, and upgrades to the City's Dark Fiber network (Backbone).
B. TERRITORY:
All territory within the incorporated limits of the City and land owned or leased by the City.
C. FEES:
1. ADVANCE ENGINEERING FEES:
Advance engineering (AER) fees must be paid to start the engineering process and are non-refundable. The
fees will be credited against the estimated project cost prior to the collection of the project construction fees.
(1) Commercial/Industrial AER minimum fee ..................................................................... $907881.00
(2) Special conditions (requiring expert assessment) ........................................................... By Estimate
2. ESTIMATED SERVICE CONNECTION AND RECONFIGURATION FEES
All estimated service connection and reconfiguration fees must be paid prior to the scheduling of any construction or reconnections to the City's Dark Fiber network.
(1) Service connection (Interconnection) fee ...................................................... By Estimate
(2) Reconfiguration Fees ..................................................................................... By Estimate
Labor rates are subject to change as stated in the Utility Rate Schedule C-1.
D. NOTES:
1. The Customer is responsible for the installation and maintenance of all ducts and pathways from the facility to the property line in compliance with City of Palo Alto Utilities Rules and Regulations and contract agreements. 2. The City shall not be held liable for delays or interruptions in service, but will make reasonable efforts to provide timely continuous service.
3. All fees are subject to Consumer Price Index (CPI) adjustments, to be applied annually. The CPI adjustment will be based on the Consumer Price Index for All Urban Consumers (CPI-U) for the San Francisco-Oakland-
San Jose MSA, published by the U.S. Department of Labor, Bureau of Labor Statistics. The adjustment is calculated by dividing the most recent calendar year December CPI by the December CPI in the year rates last
changed. In the event that the change between December CPI’s indicates an adjustment of less than 1% is required, a change to rate schedules may not be made for the upcoming year. Future rate changes will take the
last year of change as the new base year for purposes of calculation. {End}
City of Palo Alto | City Clerk's Office | 5/30/2018 2:07 PM
1
Carnahan, David
From:Roberta Ahlquist <roberta.ahlquist@sjsu.edu>
Sent:Tuesday, May 29, 2018 8:18 PM
To:Joyce Beattie; Council, City; Jolinda Decad; Rosalinda Quintanar; Beth Rosenthal; linda
lopez-otero; Gmail:linzjiang; Debbie Mytels
Subject:Re: AS I GET OLDER I REALIZE...
Joyce, Loved this! thanks much.
Friends,
When you have a moment, write the city council and tell them not to raise the water rates. We've had too many utility rate increases and if enough people object, it might not happen.
city.council@cityofpaloalto.org
On Tue, May 29, 2018 at 4:39 PM, Joyce Beattie <jycbyt@gmail.com> wrote:
AS I GET OLDER I REALIZE:
#1 - I talk to myself, because there are times I need expert advice.
#2 - I consider "In Style" to be the clothes that still fit.
#3 - I don't need anger management I need people to stop pissing me off.
#4 - My people skills are just fine. It's my tolerance for idiots that needs work.
#5 - The biggest lie I tell myself is, "I don't need to write that down. I'll remember
it."
ATTACHMENT V
City of Palo Alto | City Clerk's Office | 5/30/2018 2:07 PM
2
#6 - I have days when my life is just a tent away from a circus.
#7 - These days, "on time" is when I get there.
#8 - Even duct tape can't fix stupid - but it sure does muffle the sound.
#9 - Wouldn't it be wonderful if we could put ourselves in the dryer for ten minutes,
then come out wrinkle-free and three sizes smaller?
#10 - Lately, I've noticed people my age are so much older than me.
#11 - "Getting lucky" means walking into a room and remembering why I'm there.
#12 - When I was a child, I thought nap time was punishment. Now it feels like a
mini vacation.
#13 - Some days I have no idea what I'm doing out of bed.
#14 - I thought growing old would take longer.
#15 - Aging sure has slowed me down, but it hasn't shut me up.
#16 - I still haven't learned to act my age.
City of Palo Alto | City Clerk's Office | 5/29/2018 1:51 PM
1
Carnahan, David
From:Roberta Ahlquist <roberta.ahlquist@sjsu.edu>
Sent:Tuesday, May 29, 2018 1:41 PM
To:Council, City
Subject:How to keep up with your problematic actions?
Dear Council Members and City Manager:
1. Why are you 'giving away' Avenidas $$? They advocated, against many residents, for this redevelopment. Let them pay for it. Further-more, they are NOT really very non-profit, look at the costs for classes, look at the
administrative salaries of these folks! Make them pay the going rate. Think of how much we could make for a
low-income housing if they were charged anywhere near the going rate. Get them fund-raising and use the $$
for city sponsored low-income housing.
2. You want to help keep the existing low-income housing stock? Then don't let Stanford demolish vacant rental
houses that could be easily repaired and used for low-income Stanford workers, not demolished and replaced
with high income housing for faculty. Commit to acting on your 'talk' of supporting BMR housing.
3. You've PRIVATIZED the Rinconada City PUBLIC Pool! It used to have many kids, parents, in both pools on Sundays. It was a festive, active place, full of kids learning to swim. This Sunday the kids pool was off
limits, (I think this is their regular schedule) and only a few swimmers were there at first (1pm), in lap lanes
only. When I left at 2:30 there were no more than 30 folks there, mostly adult lap swimmers, and only 1 life
guard on at 1pm, 2 later. Prices higher! Prices for lessons higher! What happened to our community pool??
Take it back. High school life-guards cost less, were very helpful, prices were not so high. Do a survey!
4. Once again, we are being asked to pay increased prices for our water! Every year or two we get increases for
either one utility or another. Stop it. You can't run a city off of the utilities, which although 'public', seem to be
not very economical. I oppose these increases. Nickel and dimeing the residents is not my idea of good
economics. Cut the $$ for the Council Chambers upgrade. It's way out of line.There are many ways to provide services for this community. Get creative and economical.
Sincerely,
Roberta Ahlquist