HomeMy WebLinkAboutStaff Report 9158
City of Palo Alto (ID # 9158)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/15/2018
City of Palo Alto Page 1
Summary Title: FY 2019 Electric Utility Financial Plan and Rate Proposal
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt: 1) a Resolution Approving the Fiscal Year 2019 Electric Financial Plan,
and 2) a Resolution Increasing Electric Rates by 6% by Amending the E -1, E-2,
E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU and E-14 Rate Schedules
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission (UAC) request that the Finance Committee
recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2019 Electric Financial
Plan (Attachment B), including amendments to the Electric Utility Reserves
Management Practices (Attachment C); and
2. Adopt a resolution (Attachment D) amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Small Non-Residential Electric Service), E-2-G (Small Non-Residential
Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-
Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-
7-G (Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-
Residential Time of Use Electric Service), and E-14 (Street Lights).
Executive Summary
The FY 2019 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2028. Costs are projected to rise substantially for the next several years for seve ral
reasons. First, costs for electric supply purchases are increasing as a result of new renewable
energy projects coming online. Increases in transmission costs are also projected. Substantial
additional capital investment in the electric distribution system is planned for FY 2018 through
FY 2023, and operational costs are increasing.
Because of these rising costs, an increase in sales revenues is required. A 6% rate increase is
proposed for July 1, 2018, and a 3% increase projected for July 1, 2019, wi th (0% to 2%)
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increases projected afterward. While 6% would be the overall increase in sales revenues,
different customer classes will see slightly different increases ranging from 3% to 8%, as shown
in Tables 3 and 4. The proposed rate increases were calculated using the 2016 cost of service
analysis (COSA) model created for the City by EES Consulting, which was implemented on July 1,
2016.
Several reserves transfers were approved in the FY 2018 Electric Financial Plan, but have not
been executed yet. These are summarized below. Due to improved hydroelectric conditions in
FY 2017 and the first half of FY 2018, staff is able to reduce these reserve transfers in the
proposed FY 2019 Electric Financial Plan, particularly the loan from the Electric Special Projects
Reserve. To completely eliminate the loan from the Electric Special Projects Reserve, an 8% rate
increase would be required on July 1, 2018.
Reserve Transfers: Approved, Proposed, and Alternative Transfers
FY 2018 Financial Plan
Approved Transfers
Staff Proposal
(Rate Changes:
6% 2019, 3% 2020)
Alternative
(Rate Changes:
8% 2019, 0% 2020)
Rate Stabilization
Reserve
$9 million $9 million $9 million
Hydroelectric Reserve Up to $11.4 million $1 million (projected) $1 million (projected)
Electric Special
Projects Reserve Loan
$10 million $6 million None
This proposed rate increase is slightly lower than the 8% July 1, 2018 rate increase in staff’s
preliminary rate projections, which was to be followed by a 4% increase on July 1, 2019.
The FY 2019 Electric Financial Plan also includes a change to the reserves policies for the
Hydroelectric Stabilization Reserve, outlining the method used to determine whether the HRA
will be implemented in a given fiscal year, and authorizing staff to transfer f unds between the
Operations and Hydroelectric Stabilization Reserve based on a formula that captures the cost
impact or benefit of hydroelectric generation each year.
Background
Every year staff presents the Finance Committee and UAC with Financial Plans for its Electric,
Gas, Water, and Wastewater Collection Utilities and recommends any rate adjustments
required to maintain their financial health. These Financial Plans include a comprehensive
overview of the utility’s operations, both retrospective and prospective, and are intended to be
a reference for UAC and Council members as they review the budget and staff’s rate
recommendations. Each Financial Plan also contains a set of Reserves Management Practices
describing the reserves for each utility and the management practices for those reserves.
Discussion
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Summary of Proposed Actions
The two resolutions recommended for Council adoption will accomplish the following:
1. Increase overall electric rates by 6% effective July 1, 2018;
2. Approve the FY 2019 Electric Financial Plan, including a change to the reserves policies
for management of the Hydroelectric Stabilization Reserve.
Proposed and Projected Sales Revenue Requirement, FY 2019 through FY 2023
The proposed July 1, 2019 rate increase would be the third in a series of rate increases from
FY 2016 through FY 2020. Prior to the first increase on July 1, 2016, rates had not been
increased since July 1, 2009 because costs had been low over that period. Table 1 shows the
proposed and projected rate increases needed to recover costs of operation over the forecast
period in the FY 2019 Electric Financial Plan.
Table 1: Electric Rate Adjustments, FY 2017 to FY 2023
FY 2017
Approved
FY 2018
Approved
FY 2019
Proposed
FY 2020
Projected
FY 2021
Projected
FY 2022
Projected
FY 2023
Projected
11% 14% 6% 3% 2% 0% 1%
These sales revenue increases are for the utility as a whole, but the rate changes will differ for
individual customer classes. Proposed rate increases for each customer class are discussed
below.
Cost drivers and containment
The rate increases are related to several cost factors: increasing transmission costs and new
renewable projects coming online; substantial additional capital investment in the electric
distribution system, and rising operational costs. Historically, total electric utility costs
(excluding short-term drought impacts) were roughly $130 million per year, allowing the
electric utility to go without a rate increase from July 1, 2009 to July 1, 2016. Over the period
from FY 2016 to FY 2019, though, annual costs are increasing to roughly $17 0 million per year,
approximately 25%, and are projected to stay at that level through at least FY 2022. This trend
can be seen in the chart on page 18 of Attachment B (the FY 2019 Electric Utility Financial Plan).
Figure 1 shows the utility’s costs in FY 2016, FY 2019, and FY 2022. Costs for the Supply Portfolio
steadily increase over that time. Costs for Operations increase slightly. Capital Projects costs
increase significantly in FY 2019 due to major one-time capital expenditures, then are projected
to decrease by FY 2022. The drop in capital expense by FY 2022 means that total electric utility
costs in FY 2019 and FY 2022 are projected to be roughly the same.
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Figure 1: Electric Utility Costs, FY 2016 Actual vs. FY 2019 and FY 2022 Projections
As shown in Figure 2, the contribution to cost increases from FY 2016 to FY 2019 is mostly
related to the Supply Portfolio (which includes transmission and renewable projects) as well as
Capital Projects spending, while by FY 2022 the Supply Portfolio is the largest contributor.
Operations spending is projected to increase somewhat compared to FY 2016. Some of this is
due to projected increases in costs of labor and materials, but most of the apparent increase is
due to the fact that not all budgeted funds for Operations were spent in FY 2016, given staff
vacancies and other factors.
Figure 2: Causes of Electric Utility Cost Increases, FY 2016 vs. FY 2019 and FY 2022
The electric Supply Portfolio increases are related primarily to transmission cost increases and
renewable energy projects coming online, as shown in Figure 3. Transmission costs are incurred
to bring electricity from contracted generation sources to Palo Alto. Staff works to contain
transmission costs through partner agencies, including the Transmission Agency of Northern
California (TANC) and Northern California Power Agency (NCPA), and through direct
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partnerships with other local utilities (Bay Area Municipal Transmission group, BAMx). All of
these groups intervene in transmission proceedings at the Federal Energy Regulatory
Commission (FERC) and the California Independent System Operator (CAISO) and have achieved
some reductions in long-term transmission costs. Staff is beginning to explore strategies for
containing renewable energy costs, and will discuss these strategies in greater detail through
the ongoing Integrated Resource Planning (IRP) process.
Staff also continues to work to contain risks and maximize the value of the hydroelectric power
it buys through the Western Area Power Administration (WAPA). WAPA is preparing for new
contracts with its customers after the current contract expires in 2024, and the City is working
in partnership with NCPA and other WAPA customers to ensure the post -2025 contract terms
preserve the value of the resource. All customers are also working to minimize any cost impacts
to the resource from the proposed California Water Fix. Lastly, working through NCPA, efforts
have been made to ensure fair environmental project cost allocations from the Bureau of
Reclamation for power customers, and to pursue repayment of over-collections from previous
years.
Figure 3: Electric Supply Costs, FY 2016 Actual vs. FY 2019 and FY 2022 Projections
This Financial Plan still contains reserves transfers. Last year’s Financial Plan (FY 2018)
authorized the use of the entire Supply Rate Stabilization Reserve (approximately $9 million),
up to $11.4 million from the Hydroelectric Stabilization Reserve, and a $10 million loan from
the Electric Special Projects Reserves to keep the Supply and Distribution Operations Reserves
above the minimum reserve guidelines. If a 6% rate increase is adopted for July 1, 2018, this FY
2019 Financial Plan proposes reducing the Electric Special Projects Reserve loan to $6 million,
and is projecting only roughly $1 million being needed from the Hydroelectric Rate Stabilization
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Reserve. More information on reserve transfers can be found in the FY 2019 E lectric Financial
Plan (Attachment B). Actual expenditures in FY 2017 were lower than budgeted, and cost
savings and revenues from improved hydroelectric generator output also helped mitigate some
of the revenue shortfall that had been projected for FY 2018 in prior Financial Plans.
Staff also recognizes the importance of managing operating costs and maximizing efficiency in
order to minimize rate increases:
As discussed above, staff is working on cost containment measures related to
transmission and renewable energy costs.
City staff looks for opportunities to save money operationally, small opportunities that
add up. For example, the City recently creatively rebid its contract for construction
material supply and spoils hauling to go from using a singl e vendor to multiple vendors
that each specialized in specific materials, realizing nearly $250,000 in savings over
three years.
The current climate of high construction costs results in less capital replacement for
dollars invested. Staff will continue to prioritize near-term projects to address
immediate needs, and potentially defer projects where system reliability will not be
impacted to ensure full value is extracted from existing infrastructure.
A regular review of performance metrics and expenditures.
Consistent with newly approved Utilities Strategic Plan, cost containment is being instituted as
an ongoing priority and annual cycle. This will include the completion of preliminary out -year
rate forecasts in the fall, which will allow for a review b y all Divisions for alignment of multiyear
strategies. This includes ongoing management review of personnel transactions, including
Review/Revisions of position classifications to match evolving needs, Addition/Deletion of
positions to reflect organizational priorities, and Review/Approval to fill individual position
vacancies in conjunction with ASD Budget Office and Human Resources.
Changes from Prior Financial Forecasts
This projection has changed since the FY 2018 Electric Utility Financial Plan presented last year.
Table 2 compares current rate projections to those projected in the last two year’s Financial
Plans. As shown, the FY 2019 rate projections are higher than projected the last two years,
primarily because transmission costs have risen substantially over this period.
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Table 2: Projected Electric Rate Trajectory for FY 2019 to FY 2025
Projection FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Current
(FY 2019 Financial Plan) 6% 3% 2% 0% 1% 1% 1%
Last year
(FY 2018 Financial Plan) 7% 0% 0% 1% 2% 1% 1%
Two years ago
(FY 2017 Financial Plan) 2% 0% 1% 0% 0% 0% 0%
Rate Changes by Customer Class
Table 3 shows the rates that will be used to recover sale revenues for each customer class. The
Street Lighting (E-14) class and the E-4 and E-7 Time of Use (TOU) rates are not shown in the
table, but can be seen in the attached rate schedules (Attachment E). These schedules are
omitted for various reasons: the E-14 rate schedule is not easy to summarize, E-7 TOU rate is
not easy to summarize and is only used by one customer, and the E -4 TOU rate schedule is both
difficult to summarize and not utilized by any customers at this time.
Table 3: Electric Rates (Current and Proposed)
Current Rates
Proposed Rates
(7/1/18)
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%
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Table 4 shows the impact of the proposed July 1, 2018 rate changes on the residential and non -
residential bills for various consumption levels. The overall rate change for the residential class
is roughly 8%.
Table 4: Impact of Proposed Electric Rate Changes on Customer Bills
Rate
Schedule
Usage (kwh/mo)
Bill under
Current Rates
($/mo)
Bill Under Rates
Proposed 7/1/18
($/mo)
Change
$/mo %
E-1 300 36.48 38.61 2.14 5.9%
(Summer Median) 330 40.13 42.47 2.35 5.9%
(Winter Median) 453 63.50 66.19 2.69 4.2%
650 100.93 104.17 3.24 3.2%
1200 205.44 210.20 4.76 2.3%
E-2 1,000 162 171 9.09 5.6%
E-4 160,000 24,071 25,984 1,913 7.9%
E-7 500,000 67,466 72,558 5,096 7.6%
E-7 2,000,000 269,863 290,233 20,384 7.6%
Cost of Service Analysis and Rate Study
The rates discussed in the previous section are based on the cost of service methodology
established in the “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2016. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates.
Electric Bill Comparison with Surrounding Cities
Table 5 compares electric bills under current rates as of March 1, 2018 for residential customers
to those in surrounding communities. Under current rates, CPAU’s customer bills are far below
PG&E’s and are lower than others for non-residential customers, but slightly higher than Santa
Clara’s for higher using residential customers.
Table 5: Average Electric Bill Comparison ($/month)
As of March 1, 2018
Customers
Usage
(KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E Santa Clara
Residential
Customers
300 $ 36.48 $38.61 $ 63.51 $ 35.18
330 (Summer 40.12 42.47 71.70 38.83
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
City of Palo Alto Page 9
Median)
453 (Winter
Median) 63.50 66.19 104.49 53.78
650 100.93 104.17 160.46 77.73
1200 205.45 210.20 314.42 144.59
Non-
Residential
Customers
1,000 161 171 245 181
160,000 23,732 25,984 30,413 20,850
500,000 62,190 72,558 83,820 62,956
2,000,000 268,475 290,233 361,753 256,247
Proposed Change to Reserve Policies
This financial plan proposes a change to Section 7 of the Electric Utility Reserves Management
Practices (see Attachment C), detailing a procedure for calculating the amount of funds staff is
authorized to transfer between the Operations and the Hydroelectric Stabilization Reserves,
based on the extent to which hydroelectric generation deviates from long-term averages. Funds
will be transferred to or from the Hydroelectric Stabilization Reserve on an annual basis based
on the amount of deviation from average hydroelectric generation for each month of the prior
year, multiplied by the average market price for energy for that month.
Commission Review and Recommendation
The UAC reviewed this proposal at its April 12, 2018 meeting . At the meeting staff noted that
the recommendation was a decrease from the earlier increase proposal of 9%. Commissioners
questioned whether it was going to be a dry hydro year in light of the relatively recent wet
weather. Staff commented that while the recent storms had provided some relief, it was still a
relatively dry year. Commissioners also inquired if it was possible to create a ‘smoother’ rate
track, rather than having a 6% increase followed by 3%, etc. Staff responded that the 6% still
required Special Projects Fund and some Hydro Stabilization reserve transfers to keep the
Operations reserve within guideline levels, so the rate track was merited to bring revenues in
line with costs.
Commissioners inquired as to whether supply costs could be contained as they were outside of
the City’s control, and staff responded that the electric portfolio was continually reviewed to
see if selling off higher priced renewables contracts was applicable, and worked with agencies
such as NCPA to help bring down costs. Santa Clara’s lower rates were not ed, and staff
responded that their power portfolio and customer mixes were different than Palo Alto, and
they also have their own generation plant which lowers their transmission costs.
In regards to reserve health, Commissioners inquired as to how much p ower cost could
fluctuate in a drought year. Staff responded that impacts of $8 million or more could be seen,
and the Commission noted that drawing down the Hydro reserve more to help lower rate
increases should not be done at this time. Also, should ther e be another drought, having lower
reserves might mean the newly passed Hydro Rate adjuster could be implemented at the
City of Palo Alto Page 10
largest level, which would amount to a 10% increase.
The UAC voted to recommend that the Council adopt resolutions approving the FY 201 9 Electric
Financial Plan and increasing electric rates by amending Rate Schedules E-1, E-2, E-2-G, E-4, E-4-
G, E-4 TOU, E-7, E-7-G, E-7 TOU, and E-14, all amended to reflect a 6% FY 2019 increase. The
vote was unanimous (5-0, Commissioners Segal and Trumbull absent). Attached is the
excerpted draft minutes from the UAC’s April 12, 2018 special meeting (Attachment F).
Timeline
If the Finance Committee supports the proposed rate adjustments, the City Council will
consider the proposed Financial Plans and amended rate schedules with the FY 2019 budget.
Resource Impact
The proposed July 1, 2018 rate changes are projected to increase sales revenues by $10 million
per year over the forecast period.
Policy Implications
The proposed electric rate adjustments were developed using the 2016 cost of service study
and methodology, and are consistent with the Council adopted Reserve Management Practices
that are part of the Financial Plan.
Environmental Review
The Finance Committee and UAC’s review and recommendation to Council on the FY 2019
Electric Financial Plans and rate adjustments does not meet the California Environmental
Quality Act’s definition of a project, pursuant to Public Resources Code Section 21065, thus no
environmental review is required.
Attachments:
Attachment A: Resolution Approving FY 2020 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: Excerpted Draft UAC Minutes of April 12, 2018 Special Meeting
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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F Y 201 9 ELECTRIC UTILITY
F INANCIAL PLAN
FY 2019 TO FY 202 8
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 ABBR EVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a
section of the distribution system operates. The transmission system operates at
115-500 kV, and this is lowered to 60 kV in the sub-transmission section of the
Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution
system, and finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum
electricity demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Sub-transmission System: The section of the Electric Utility’s distribution system that operates
at 60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115
kV or more. The voltage at the intersection of the Electric Utility’s distribution system
and PG&E’s transmission system is 115 kV. The Electric Utility does not own or
operate any transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
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SECTION 2 : EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Electric Utility for the next 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 2 A : OVERVIEW OF FINANC IAL 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 2 B : 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 201 9 RATE AND RESERVES PR OPOSALS
SECTION 3 A : 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 3 B : 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 3 C : 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.
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SECTION 3 D : PROPOSED RESERVE TRA NSFERS
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
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SECTION 4 : UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4 A : ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel
engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity
continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E
proved more economical than the diesel engines, and by the late 1920s CPAU was using its own
diesel engines only during peak demand periods. At that time CPAU owned 45 miles of
distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual
consumption. The diesel engines remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did
throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the
sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto,
which doubled the number of customers. Some was related to the proliferation of electric
appliances, as evidenced by the fact that residential customers were using three times more
electricity in 1970 than they had been in 1950. But the most notable factor was the growth of
industry in Palo Alto during that time. By 1970, commercial customers were using 20 times
more electricity per customer than they had been in 1950. These decades also saw several
other notable events, including:
• 1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of
Reclamation to purchase power from the Central Valley Project (CVP), a contract which
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
• 1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
• 1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
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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
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Figure 1: Customer Consumption By Class (FY 2017)
16%
6%
36%
42%
Residential
Small Comm.
Med. Comm.
Large Comm.
SECTION 4 B : CUSTOMER BASE
The City of Palo Alto’s Electric Utility
provides electric service to the
residents, businesses, and other
electric customers in Palo Alto. There
are roughly 29,600 customers
connected to the electric system,
25,550 (86%) of which are residential
and 4,050 (14%) of which are non-
residential. Residential customers
consumed 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 4 C : DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 472 miles of
distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are
underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line
transformers, around 1,100 underground and substation transformers, and the associated
electric services (which connect the distribution lines to the customers’ homes and businesses).
These lines, substations, transformers, and services, along with their associated poles, meters,
3 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
4 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
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Figure 2: Cost Structure (FY 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 4 D : 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 4 E : RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of
contingencies. It also maintains two funds, the Supply Fund and the Distribution Fund, to
manage costs associated with electricity supply and electricity distribution, respectively. The
City established this separation of supply and distribution costs as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) in the late 1990s and
early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues to
maintain separate funds to facilitate separation of supply and distribution costs in the rates.
This could be important if California ever decides to broadly reintroduce Direct Access, and may
also be useful for rate design as the nature of utility services evolves in response to higher
penetrations of distributed generation.
The summary below describes the various reserves, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserves for Commitments: Reserves equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserves for Reappropriations: Reserves for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve. This is currently an important
reserve for all utility funds, but changes in budgeting practices will change that in future
years, as described in Section 3C (Reserves Management Practices).
• Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which 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
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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 4 F : 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.
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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 5 A : 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.
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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.
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Figure 6: Forecasted Electricity Consumption
SECTION 5 B : FY 201 3 TO FY 2017 COST AND REVENUE TRE NDS
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
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2017 and Projections through FY 2028
SECTION 5 C : 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.
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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 5 D : 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 5 E : 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
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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 5 F : RISK ASSESSMENT AND RESERVES ADEQUAC Y
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.
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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
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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
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Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, staff projects the CIP Reserve to be above the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels, CIP Commitments are nearly impossible to project that far out, and
adjustments to the reserve can be made in future years.
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Figure 13: Electric CIP Reserve Adequacy
SECTION 5 G : 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 | P a g e
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
SECTIO N 6 A : ELECTRICITY PURCHASE S
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 6 B : OPERATIONS
CPAU’s Electric Utility operations include the following activities:
• Administration, including financial management of charges allocated to the Electric
Utility for administrative services provided by the General Fund and for Utilities
Department administration, as well as debt service and other transfers. Additional detail
on Electric Utility debt service is provided in Section 6D (Debt Service)
• Customer Service
• Engineering work for maintenance activities (as opposed to capital activities)
• Operations and Maintenance of the distribution system; and
• Resource Management
Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 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 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
Staff projects CIP spending for FY 2019 through FY 2024 to be consistent with last year’s
forecast, though there is a slight shift in the funding by project category. There will be a
reduction in 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 6 D : DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently
makes payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax
Credit Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction
costs of solar demonstration projects at the Municipal Services Center, Baylands Interpretive
Center, and Cubberley Community Center. The capacity of these projects totaled 250 kW. In
exchange for funding part of the construction costs, the Electric Utility receives the RECs from
these projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are
interest free (the investors receive a tax credit from the federal government). This bond
issuance is secured by the net revenues of the 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 6 E : EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.7 Each year it is calculated
according to the 2009 Council-adopted methodology, and does not require additional Council
action.
SECTION 6 F : WHOLESALE REVENUES A ND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 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 6 G : S ALES 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 D ETAIL
6053706
(page intentionally left blank)
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 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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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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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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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.
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APPENDIX C : DESCRIPTION OF ELE CTRIC UTILITY OPERAT IONAL ACTIVITIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Electric Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process.
It does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
• monitoring the substations and performing routine maintenance;
• performing preventative maintenance on the system;
• monitoring the system’s status from the UCC using SCADA;
• maintaining the SCADA system;
• investigating outages and other customer complaints and performing emergency
repairs;
• clearing vegetation near overhead power lines; and
• testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX D : SAMPLES OF RECENT EL ECTRIC UTILITY OUTRE ACH COMMUNICATIONS
ELECTRIC UTILITY FINANCIAL PLAN
J u n e 2 0 1 8 1 | P a g e
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
J u n e 2 0 1 8 2 | P a g e
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
J u n e 2 0 1 8 3 | P a g e
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
J u n e 2 0 1 8 4 | P a g e
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
J u n e 2 0 1 8 5 | P a g e
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
$0.0721466
05
$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 as
calculated 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, the
Tier 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
$0.112051059
1
$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
0.075200767
8
0.053560576
6
0.0041739
1 0.0020
$0.134671
4061
Minimum Bill ($/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
$0.188852
0090
Winter Period
0.075200767
8
0.053560576
6
0.0041739
1
0.1346713
861
Minimum Bill ($/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}
EXCERPTED DRAFT MINUTES OF THE APRIL 12, 2018 SPECIAL MEETING
UTILITIES ADVISORY COMMISSION
ITEM 1: ACTION: Staff recommendation that the Utilities Advisory Commission recommend the City
Council adopt 1) a Resolution approving the Fiscal Year 2019 Electric Financial Plan, and 2) a Resolution
increasing Electric Rates by 9% by amending the E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU,
and E-14 Rate Schedules.
Ed Shikada, Utilities General Manager, noted a revision in the proposed rate increase. Staff originally
recommended a 9% rate increase but is now proposing a 6% rate increase.
Erik Keniston, Senior Resource Planner, reported that the recommended rate increase for the Electric
Utility is 6% in fiscal year 2019 followed by a 3% increase in fiscal year 2020 and a 2% increase in fiscal
year 2021. With the recommended rate increase, revenue projections should match cost projections. Last
year, staff projected a 7% rate increase. In the short term, staff is projecting a slight increase in Capital
Improvement Program (CIP) expenditures related to one-time projects, but then costs decrease after
2021. Some of the capital investments are related to Smart Grid improvements. In current models, staff
assumes funding for Smart Grid improvements will come from the Electric Special Projects Reserve Fund.
The majority of the change in expenses between fiscal year 2016 and fiscal year 2022 is driven by the
supply portfolio. Between fiscal year 2019 and fiscal year 2022, costs will be about the same overall.
Supply reserves remain relatively healthy. At this time, staff projects a withdrawal from the Hydroelectric
Stabilization Reserve Fund of approximately $1 million. If drought or a dry hydroelectric year occurs,
having more money in the Reserve Fund will be critical to the financial health of the Electric Utility.
In response to Chair Danaher's query asking whether the utility was receiving less hydroelectric power
than expected, Jonathan Abendschein, Assistant Director of Resource Management, explained that March
storms helped alleviate the dry year through February. The City will receive less than average hydroelectric
generation, but it is not extremely low.
Keniston continued his presentation. The Distribution Operations Reserve Fund was below the minimum
guideline level in 2017, but staff will transfer funds so that the balance falls within guideline levels. The
Supply Operations Reserve Fund should meet the target level during the forecast period. The Distribution
Operations Reserve Fund is expected to remain at the target level.
In answer to Chair Danaher's question about reasons for the Supply Operations Reserve Fund rising and
falling in 2018, 2019, and 2020, Keniston indicated it was a result of staff's proposed transfers of funds
between supply and distribution reserve funds.
In reply to Commissioner Johnston's inquiry regarding a way to spread the proposed rate increases over
five years, Keniston advised that the 6% rate increase was needed to keep fund balances within guideline
ranges given the cost projections. Even with the increase, staff planned to withdraw funds from the
ATTACHMENT F
Electric Special Projects Reserve Fund as a temporary loan. Abendschein clarified that the Utility has only
limited control over supply costs because they are influenced long term rather than year-to-year, so it was
difficult to make short-term adjustments to reduce the rate increases. Costs could be controlled over the
long term. For example, the Utility works with partner agencies to intervene in transmission cases, which
can achieve significant savings. One short-term cost containment measure is Northern California Power
Agency's (NCPA) recent refinancing of debt on the Calaveras resource. Palo Alto's share of that savings
will be a few hundred thousand dollars. Noting the Commissioners comment on Silicon Valley Power
having lower rates, he said that Silicon Valley Power, which is the City of Santa Clara's utility, has lower
rates than Palo Alto because it ended its final coal contract in December, has an in-town gas plant on
which there is little debt, and seeks data center and manufacturing customers. Shikada added that the
location of the gas plant allows Santa Clara to avoid the transmission access charge.
Chair Danaher proposed staff include reasons for the rate increase in the staff report to the Council. In
response to his question regarding the cost of a bad drought year to the Utility, Keniston indicated the
Utility could easily exhaust all funds in the Hydroelectric Stabilization Reserve Fund. Abendschein stated
the estimated cost of a drought year is $8-$10 million. Chair Danaher did not believe the Utility has
sufficient reserve fund balances to delay a rate increase.
In reply to Commissioner Forssell's question about whether the hydroelectric rate adjuster would help
the Utility in drought years, Abendschein reported the adjuster will be helpful. When reserve fund
balances are low and the year is dry, the effective percentage increase for the rate adjuster is in the
ballpark of 8%-10% on the bill. If the Council chooses to reduce reserve funds in order to spread rate
increases over future years, the risk of going from no rate adjuster to a full rate adjuster in one year
increases. Higher reserve balances would allow the rate adjuster to be implemented at a lower level
(about 5% bill impact) in the first year and perhaps 10% in the second year.
In response to Vice Chair Ballantine's question about the impact of the Cost of Service Study on the use
of tiered rates, Keniston advised that one tier of rates was eliminated due to the Cost of Service Study.
The existing tier structure will not change.
ACTION: Vice Chair Ballantine moved to recommend the City Council adopt 1) a Resolution approving the
Fiscal Year 2019 Electric Financial Plan, and 2) a Resolution increasing Electric Rates by 6% by amending
the E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU, and E-14 Rate Schedules. Commissioner
Johnston seconded the motion. The motion carried 5-0 with Chair Danaher, Vice Chair Ballantine,
Commissioners Forssell, Johnston, and Schwartz voting yes.