HomeMy WebLinkAbout2019-05-15 Finance Committee Agenda PacketFinance Committee
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Wednesday, May 15, 2019
Special Meeting
Community Meeting Room
1:00 PM
Agenda posted according to PAMC Section 2.04.070. Supporting materials are available in
the Council Chambers on the Thursday 12 days preceding the meeting.
PUBLIC COMMENT
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Call to Order
Oral Communications
Members of the public may speak to any item NOT on the agenda.
Action Items
Page #s
1:00 – 2:30 PM 1.Fiscal Year (FY 2020) Proposed Budget Overview and
Non-Departmental Section
O: 447
2:30 – 4:00 PM 2.Placemaking and Infrastructure: Utilities Department-
Operating and Capital
a)Electric Fund
i.Utilities Advisory Commission Recommendation
That the City Council Adopt: 1) a Resolution
Approving the Fiscal Year 2020 Electric Financial
Plan, and 2) a Resolution Increasing Electric Rates
by 8 Percent by Amending the E-1, E-2, E-2-G, E-4,
E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU, E-14, E-EEC
and E-NSE Rate Schedule
b)Fiber Optics Fund
c)Gas Fund
i.Utilities Advisory Commission Recommendation
That the City Council Adopt: 1) a Resolution
Approving the Fiscal Year 2020 Gas Utility Financial
Plan; and 2) a Resolution Increasing Gas Rates by
Amending Rate Schedules G-1 (Residential Gas
Service), G-2 (Residential Master-Metered and
Commercial Gas Service), G-3 (Large Commercial
Gas Service), and G-10 (Compressed Natural Gas
Service)
O: 391, C: 337
O: 405, C: 429
O: 413, C: 445
Proposed Capital Budget
Proposed Operating Budget
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2 May 15, 2019
MATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE CITY COUNCIL AFTER DISTRIBUTION OF THE AGENDA
PACKET ARE AVAILABLE FOR PUBLIC INSPECTION IN THE CITY CLERK’S OFFICE AT PALO ALTO CITY HALL, 250 HAMILTON AVE.
DURING NORMAL BUSINESS HOURS.
4:00 – 5:15 PM
5:15 – 6:15 PM
6:15 – 7:15 PM
7:15 – 8:00 PM
d)Wastewater Collection Fund
e)Water Fund
3.Placemaking and Infrastructure: Planning, Development
Services, and Office of Transportation- Operating Budgets
a)Other Special Revenue Funds
Dinner Break
4.Internal Service Departments: Administrative Services,
Human Resources, and Information Technology-
Operating and Capital Budgets
5.City Council Appointed Officials: Attorney, Auditor, City
Clerk, City Manager, and City Council- Operating Budgets
Page #s
O: 425, C: 501
O: 434, C: 557
O: 283, O: 295
O: 173, 227
C: 609
O: 121
Adjournment
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funds. This new policy results in additional costs of $6.2 million in all funds, $3.8 million in the General
Fund. In addition, non-general funds have a budgeted 'catch-up' payment so that their contributions to
the PARS Trust are maintained at a pace consistent with General Fund contributions. The General Fund
contributed $4.0 M in FY 2019 through the actions approved by the City Council in CMR #9925; this
'catch-up' payment represents an equivalent payment from other funds.
Another piece of information contained in the Budget Summary sections of each department and fund
section is the budgeted expenses by division. For most departments, or specific fund within a
department, the 'Administration' division contains the budget for allocated charges. These allocated
charges represent payments to internal service funds, payments to the enterprise funds since the City is
also a rate-payer for utilities, and payments to the General Fund for overhead costs (these only appear
in non-general fund sections). Since these costs are budgeted in the administration division, or
equivalent division such as the Office of the CIO in the IT Fund, the budget can look disproportionate
when compared to operational divisions.
How does the City prioritize CIP projects?
The prioritization of the City's Capital Improvement Program (CIP) is based on several guiding principles,
as well as a holistic review of each department's five-year CIP by a committee comprised of multiple
departments. The main factors that are used in the CIP prioritization process include previous City
Council direction, the City Council's Top Priorities, community input regarding service level and
infrastructure needs, the City's Comprehensive Plan, and the availability of funding and staff resources.
Based on previous Council direction, the first goal in the 2020-2024 CIP is to fund and complete the
Council Approved 2014 Infrastructure Plan (IP) projects. Four of these projects are anticipated to be
completed in FY 2020, including Fire Station #3, Charleston-Arastadero Corridor, Highway 101
Pedestrian Bridge Overpass, and the California Avenue Parking Garage. The second area of focus, which
was brought forward through community input as part of the Infrastructure Blue Ribbon Commission
(IBRC), concentrates on "catch-up" and "keep-up" projects to maintain the City's existing infrastructure.
These two concepts align with the Council's Fiscal Sustainability priority by maintaining funding for high-
priority projects while preserving funding for other capital needs across the City, including unforeseen
issues that come up and need funding immediately.
In order to ensure consistent prioritization and planning of the five-year CIP throughout the City, a
Capital Budget Review Team comprised of the Administrative Services Director, Office of Management
and Budget Capital Budget Manager, and Public Works Director meet with each department's CIP staff
to review and understand the five-year CIP plan. During the development of the 2020-2024 CIP,
departmental staff examined workload capacity, existing resources, and the priorities of each capital
fund to ensure that capital projects already underway or programmed were still priorities. As a result of
these actions, there are relatively few new projects recommended to be added to the 2020-2024 CIP;
several projects were reprioritized and moved into outer years of the five-year period to better align
staff capacity and funding resources. Once each department's CIP was approved by the Capital Budget
Review Team, the City's entire five-year CIP was presented to the City Manager for final review before
the Proposed Capital Budget document was produced. The Proposed Capital Budget was also reviewed
by the Planning and Transportation Commission to ensure the project's compliance with the City's
Comprehensive Plan.
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The 2020-2024 CIP has been prioritized based on the guiding principles outlined above. It should be
noted that the City Council only approves the budget for the first year of any five-year CIP, and the
remaining four years are to be used for forecasting and planning purposes.
How do internal service funds work?
Internal service funds (ISFs) serve as business partners to the organization and charge out the costs of
their operations according to an allocation methodology, which varies by fund. The City currently has
three ISFs: the Printing and Mailing Fund, the Vehicle Replacement and Maintenance Fund, and the
Technology Fund. Each of these funds provide services to other City Departments (internal customers),
and the costs of these services are recovered by the ISFs through charges to these internal customers.
The diagram below provides a visual representation of the funding mechanics of an ISF, and details the
flow of funds from the internal customers to the ISF providing the service. This example reflects the
primary funding mechanism for the Vehicle Replacement & Maintenance Fund ("Vehicle Fund"). The
internal customers contributing to the Vehicle Fund are detailed in blue on the far left. When looking at
the internal customer's budget, these expenses are reported in the expense by category summary table
as an "Allocated Charge." Moving to the right, those charges for example in the Fire Department
General Fund of $1.87 million are accounted for as revenue in the Vehicle Fund (this can be found in
green in the center under "REVENUE"). The revenues in the Vehicle Fund are programed as vehicle
expense activities in orange on the far left under "EXPENSES." This diagram is intended for illustrative
purposes only and reflects the primary source of funds for the Vehicle Fund .
Allocated Charges to Departments for
V h. I R I ent & Maintenance e ice ep1acem
ASD General Fund
$0.07 M (0. 71%)
CSD General Fund
$0.59 M (6.41%)
Fire General Fund
$1.87 M (20.31%)
Library General Fund
$0.01 M (0.08%l
OES General Fund
$0.04 M {0.45%)
OOT General Fund
$0.004 M (0.04%)
PCE General Fund
$0.22 M {2.38%)
PD General Fund
$1.30M(14.15%)
PW General Fund
$1.19 M (12.92%)
IT Internal Service Fund
$0.02 M (0.24%)
PW Enterprise Funds
$0.98 M (10.68%)
UTL Enterprise Funds
$2.91 M (31.64%)
General Fund
$5.29 M (57.44%)
Enterprise
and Other Funds
$3.91 M (42.56%)
}
Vehicle Replacement & Maintenance Fund
REVENUE
Allocated Charges to
Departments for Vehicle
Replacement & Maintenance
$9.20 M
EXPENSES
Allocated Charges $1.26M
Contract Services $0.52M
General Expense $0.07M
Rents & Leases $0.2M
Salary & Benefits $2.2SM
Supplies & Material $1.43M
Vehicle Re lacements $3.47 M
$9.20 M
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What positions are currently vacant throughout the City?
A detailed list of full-time (benefitted) positions that are vacant throughout the City are detailed in
Attachment A. This attachment includes the position title, the vacancy date, and the distribution of the
position by fund. In specific instances, "backfill" is used to cover the duties; positions that are being
backfilled are noted with an italicized job title. Backfill could mean using higher-class pay per the terms
of the appropriate Memorandum of Agreement (MOA), an overstrength position, additional overtime,
or the use of contractual dollars or temporary help to accomplish the workload associated with the
vacant position.
DEPARTMENT HEAD:
CITY MANAGER:
Kiely Nose
Director, Administrative Services/CFO
c~ ___ ..
Ed Shikada
City Manager
ATTACHMENT A: City of Palo Alto Full Time Position Vacancies
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City of Palo Alto Full Time Position Vacancies ATIACHMENTA
(as of April 2019)
DEPARTMENT/JOB TITLE VACANCY DATE GENERAL ENTERPRISE OTHER GRAND
FUND FUNDS FUNDS TOTAL
Administrative Services
Accountant 6/23/2018 1.00 1.00
Accounting Specialist 8/18/2018 -3/16/2019 1.SO 1.50 0.50 3.50
Contracts Administrator 12/29/2018 0.30 0.70 1.00
Director, Office of Management and Budget 5/7/2019 1.00 1.00
Senior Buyer 10/14/2017 1.00 1.00
Senior Management Analyst 7/31/2018 0.90 0.10 1.00
Office of the City Auditor
City Auditor 2/16/2019 1.00 1.00
Office of the City Clerk
Deputy City Clerk 4/13/2019 1.00 1.00
Community Services
Assistant Director, Community Services 1/12/2019 1.00 1.00
Assistant Director, Community Services 5/7/2019 1.00 1.00
Park Maintenance Person 12/01/2018 1.00 1.00
Park Ranger 1/5/2019 1.00 1.00
Fire Department
Battalion Chief EMT Shift 3/17/2018 1.00 1.00
Fire Fighter EMT/Paramedic 1/30/2019 -3/16/2019 2.00 2.00
Fire Chief 1/14/2019 1.00 1.00
Information Technology
Chief Information Officer 12/14/2018 1.00 1.00
Technologist 3/30/2019 1.00 1.00
Library Department
Librarian 1/24/2019 1.00 1.00
Sr Librarian 6/10/2018 -10/2/2018 2.00 2.00
Supervising Librarian 12/29/2018 1.00 1.00
Office of the City Manager
Asst City Manager/Util General Manager 12/29/2018 0.25 0.75 1.00
Chief Sustainability Officer 11/03/2018 1.00 1.00
Deputy City Manager 3/8/2019 1.00 1.00
Planning & Community Environment
Administrative Assistant 11/11/2017 1.00 1.00
Administrative Associate Ill 2/16/2019 1.00 1.00
Associate Planner 8/18/2018 1.00 1.00
Assistant Director, PCE 2/16/2019 1.00 1.00
Building Inspector Specialist 1/5/2019 1.00 1.00
Building/Planning Technician 5/25/2018 -1/21/2019 2.00 2.00
Chief Transportation Official 9/8/2018 0.64 0.36 1.00
Code Enforcement Lead 9/1/2018 1.00 1.00
Code Enforcement Officer 12/29/2018 1.00 1.00
Coordinator, Transportation Systems Mgmt 7/23/2018 0.24 0.26 0.50
Development Center Manager 1/31/2019 1.00 1.00
Development Project Coordinator Ill 4/23/2019 1.00 1.00
Development Services Director 2/10/2018 1.00 1.00
Manager, Planning 5/3/2019 1.00 1.00
Planner 3/3/2018 1.00 1.00
Senior Planner 2/16/2019 -4/13/2019 1.28 0.72 2.00
City of Palo Alto Full Time Position Vacancies ATTACHMENT A
(as of April 2019)
DEPARTMENT/JOB TITLE VACANCY DATE GENERAL ENTERPRISE OTHER GRAND
FUND FUNDS FUNDS TOTAL
Police Department
Police Officer 2/17 /2018 -9/6/2018 12.00 12.00
Public Safety Dispatcher 3/31/2018 -9/26/2018 4.00 4.00
Animal Services Specialist II 5/16/2018 -2/16/2019 2.00 2.00
Animal Services Superintendent 7/9/2016 1.00 1.00
Veterinarian 2/22/2019 1.00 1.00
Veterinarian Technician 11/4/2014 -2/22/2019 2.00 2.00
Human Resources
Senior Human Resources Administrator 11/17/2017 1.00 1.00
Public Works
Administrative Associate I 12/08/2018 0.50 0.50
Associate Engineer 2/16/2019 0.01 0.99 1.00
Assistant Manager, Plant 2/26/2015 1.00 1.00
Engineer 10/13/2018 -4/6/2019 0.20 1.80 2.00
Equipment Operator 12/10/2018 -3/18/2019 1.55 0.45 2.00
Facilities Technician 7 /7 /2018 -3/16/2019 1.80 0.50 0.20 2.50
Fleet Services Coordinator 5/27/2016 1.00 1.00
Heavy Equipment Operator 3/18/2019 0.90 0.10 1.00
Project Manager 4/8/2019 -4/13/2019 1.10 0.35 0.55 2.00
Sr Engineer 3/4/2019 0.11 0.89 1.00
Sr Management Analyst 12/08/2018 0.95 0.05 1.00
Supervisor WQCP Operations 3/30/2019 1.00 1.00
WQC Plant Operator II 3/30/2018 -10/6/2018 2.00 2.00
Utilities Department
Assistant Director Utilities Engineering 10/29/2016 1.00 1.00
Cathodic Protection Technician Asst 3/4/2019 1.00 1.00
Customer Service Specialist -Lead 1/5/2019 1.00 1.00
Chief Operating Officer 5/7/2019 1.00 1.00
Electrician Assistant I 3/19/2018 -4/6/2019 3.00 3.00
Electric Utilities Compliance Technician 12/28/2018 1.00 1.00
Heavy Equipment Operator (HEO) 8/1/2018 -3/26/2019 0.30 1.70 2.00
HEO/lnstal/er Repairer 12/05/2018 1.00 1.00
Lineperson/Cable Specialist -lead 5/18/2017 -12/26/2018 3.00 3.00
Metering Technician 4/2/2018 1.00 1.00
Overhead Underground Troubleman 2/17 /2018 -2/2/2019 2.00 2.00
Power Engineer 3/22/2019 1.00 1.00
Project Engineer 7/31/2018 1.00 1.00
Resource Planner 8/1/2017 -7 /19/2018 1.50 1.50
Sr Engineer -U 11/10/2018 1.00 1.00
Sr Resource Planner 6/23/2018 0.50 0.50
Street Light Traffic Signal & Fiber Tech 4/15/2019 1.00 1.00
Substation Electrician 6/27/2018 1.00 1.00
Utilities Compliance Technician -lead 12/27/2018 1.00 1.00
Utilities Install/Repair 1/14/2019 -3/4/2019 2.00 2.00
Utilities Supervisor 12/28/2018 1.00 1.00
Utilities System Operator 1/16/2014 1.00 1.00
Utilities Field Services Rep 2/18/2019 1.00 1.00
City of Palo Alto (ID # 10217)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/15/2019
City of Palo Alto Page 1
Council Priority: Fiscal Sustainability
Summary Title: FY 2020 Electric Financial Plan and Rates
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt: 1) a Resolution Approving the Fiscal Year 2020 Electric Financial Plan,
and 2) a Resolution Increasing Electric Rates by Amending the E-1, E-2, E-2-G,
E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU, E-14, E-EEC and E-NSE Rate Schedules
From: City Manager
Lead Department: Utilities
Recommendation
Staff requests that the Finance Committee recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2020 Electric Financial
Plan and proposed transfers (Attachment B); and
2. Adopt a resolution (Attachment C) amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Small Non-Residential Electric Service), E-2-G (Small Non-Residential
Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-
Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-
7-G (Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-
Residential Time of Use Electric Service), E-14 (Street Lights), E-NSE (Net Metering Net
Surplus Electricity Compensation), and E-EEC (Export Electricity Compensation).
Executive Summary
The FY 2020 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2024. Costs are projected to rise substantially for the next several years for several
reasons. Costs for electric supply purchases are increasing as a result of increases in
transmission costs. Substantial additional capital investments in the electric distribution system
are planned for FY 2019 through FY 2023, and operational costs are increasing. There has also
been some decrease in the City’s electric load over the past few years. Lastly, revenues are
below costs as of FY 2019.
City of Palo Alto Page 2
Because of these rising costs and other factors, an increase in sales revenues is required to
adequately maintain the Electric Fund. An 8 percent rate increase is proposed for July 1, 2019,
with 4 percent increases in the following years. While 8 percent would be the overall increase
in average rates, different customer classes will see slightly different increases ranging from 6
percent to 8 percent, as shown in Tables 3 and 4. Actual rate increases are calculated using the
2016 cost of service analysis (COSA) model created for the City by EES Consulting, which was
implemented on July 1, 2016.
Background
Every year staff presents the Utility Advisory Commission (UAC) with Financial Plans for its
Electric, Gas, Water, and Wastewater Collection Utilities and recommends any rate adjustments
required to maintain the financial health of these utilities. These Financial Plans include a
comprehensive overview of the utility’s operations, both retrospective and prospective, and are
intended to be a reference for UAC and Council members as they review the budget and staff’s
rate recommendations. Each Financial Plan also contains a set of Reserves Management
Practices describing the reserves for each utility and the management practices for those
reserves.
City of Palo Alto Page 3
Discussion
Summary of Proposed Actions
The two resolutions recommended for Council adoption will accomplish the following:
1) Increase overall electric rates by 8 percent effective July 1, 2019;
2) Approve the FY 2020 Electric Financial Plan, including the following transfers for FY 2019:
a) Approve a transfer of up to $4 million from the Hydro Stabilization Reserve to the
Supply Operations Reserve to maintain reserve adequacy.
b) Transfer all remaining funds ($9.011 million) from the Rate Stabilization reserve to
the Supply Operations Reserve;
c) Transfer up to $2 million from the Supply Operations to the Distribution Operations
reserve to maintain reserve adequacy.
Reserve balance projections for FY 2019 have taken these transfers into account. To effect
these transfers, staff is re-ratifying the following transfer proposals, which were previously
approved in resolution 9692 to take place in FY 2017, but which were not performed: 1)
transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to the Supply
Operations Reserve, 2) transfer up to $9.011 million from the Supply Rate Stabilization Reserve
to the Supply Operations Reserve, and 3) transfer up to $4.5 million from the Supply Operations
Reserve to the Distribution Operations Reserve.
Proposed and Projected Sales Revenue Requirement, FY 2020 through FY 2024
The proposed July 1, 2019 rate increase would be the fourth and last projected increase in a
series of substantial rate increases starting in FY 2017 and continuing into the foreseeable
future. Prior to the first increase on July 1, 2016, rates had not been increased for six
consecutive years since July 1, 2009 because costs had been low over that period. Table 1
shows the sales revenue increases needed to recover costs of operation over the forecast
period in the FY 2020 Electric Financial Plan.
Table 1: Electric Rate Adjustments, FY 2017 to FY 2024
FY 2017
Approved
FY 2018
Approved
FY 2019
Approved
FY 2020
Projected
FY 2021
Projected
FY 2022
Projected
FY 2023
Projected
FY 2024
Projected
11% 14% 6% 8% 4% 4% 4% 3%
These retail rate increases are for the utility as a whole, but the rate changes will differ for
individual customer classes. Proposed rate increases for each customer class are discussed
below.
City of Palo Alto Page 4
Changes from Prior Financial Forecasts
This projection has changed since the FY 2019 Electric Utility Financial Plan presented last year.
Table 2 compares current rate projections to those projected in the last two year’s Financial
Plans.
Table 2: Projected Electric Rate Trajectory for FY 2019 to FY 2025
Projection FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Current
(FY 2020 Financial Plan) 8% 4% 4% 4% 3%
Last year
(FY 2019 Financial Plan) 3% 2% 0% 1% 1%
Two years ago
(FY 2018 Financial Plan) 0% 0% 1% 2% 1%
The rate increases are related to several factors: increasing transmission costs and the cost of
renewable projects coming online, substantial additional capital investment in the electric
distribution system is planned through FY 2023, and operations costs are increasing due to
larger contracting needs. Revenues have also declined as customer usage has decreased,
requiring larger than projected rate increases.
Historically, total electric utility costs (excluding short-term drought impacts) were roughly
$120 million per year, allowing the electric utility to go without a rate increase from July 1, 2009
to July 1, 2016. Over the period from FY 2016 to FY 2018, though, annual costs (net of energy
supply related revenue, like surplus energy sales) increased to roughly $146 million per year
(costs are unusually low in FY 2019 due to some one time savings). Costs are projected to
increase to over $160 million by FY 2024. Figure 1 shows the overall utility’s costs (net of
surplus sales revenues) in FY 2014, FY 2019, and FY 2024. Costs for the supply portfolio
increased by about 3.5 percent per year on average in the past, but are projected to increase at
a slower pace (about 1 percent) in the future. Costs for managing the distribution system (e.g.
maintenance, capital investment, customer service, billing, etc.) have increased as well, growing
by 3.2 percent per year on average in the past, but projected to grow by nearly 4 percent per
year going forward. Overall, costs are projected to increase by 2.2 percent per year over the
forecast horizon
City of Palo Alto Page 5
Figure 1: Electric Utility Costs, FY 2014 Actual vs. FY 2019 and FY 2024 Projections
Figure 2 shows electric distribution costs more specifically. Capital costs increased significantly,
increasing by about 7.5 percent per year on average over the last five years. Increased costs are
related to increased capital investment in the distribution system (e.g. underground district
rebuilds, as well as substation and upgrades). Distribution system operational spending is
projected to increase by about 3 to 4 percent annually. Some of this is due to projected
increases in costs of labor and materials, but also due to the fact that in FY 2014 operational
costs were unusually low due to higher than anticipated staff vacancies and other factors.
Figure 2: Electric Distribution Costs, FY 2014 vs. FY 2019 and FY 2024
City of Palo Alto Page 6
The electric supply portfolio cost increases from FY 2014 to FY 2019 are related primarily to
transmission cost increases and, to a lesser extent, to renewable energy projects coming online,
as shown in Figure 3. In the future, staff forecasts that increased costs will largely be due to
transmission cost increases. These are due to rehabilitation and replacement of the existing
statewide electric transmission system as well as expansion of that system to accommodate
new generation, mostly renewable. Staff works to contain transmission costs through partner
agencies, including the Transmission Agency of Northern California (TANC) and Northern
California Power Agency (NCPA), and through direct partnerships with other local utilities (the
Bay Area Municipal Transmission group, BAMx). All of these groups intervene in transmission
proceedings at the Federal Energy Regulatory Commission (FERC) and the California
Independent System Operator (CAISO) and have achieved some reductions in long-term
transmission costs. Staff is beginning to look at strategies to achieve cost savings in electric
supply, and will discuss these strategies in greater detail through the ongoing Integrated
Resource Planning (IRP) process.
Figure 3: Electric Supply Costs, FY 2014 Actual vs. FY 2019 and FY 2024 Projections
With an 8 percent rate increase, this Financial Plan will prevent any further reductions in
reserves, which are relatively low. The Supply and Distribution Operations Reserves are at their
minimums, the Hydroelectric Stabilization Reserve is at $7.4 million, below the target of $17
million that enables the City to implement its strategy for managing the financial impacts of a
multi-year drought, and the electric utility has already taken a loan of $10 million from its
Electric Special Projects reserve, which is intended to fund projects like smart grid and a second
transmission line. More information on reserve transfers can be found in the FY 2020 Electric
Financial Plan (Attachment B).
City of Palo Alto Page 7
Staff also recognizes the importance of managing operating costs and maximizing efficiency in
order to minimize rate increases. As discussed above, staff is working on cost containment
measures related to transmission and renewable energy costs. Utility consumers also see some
long-term cost savings from City-wide efforts to manage personnel costs. As reflected in the
Utilities Strategic Plan, staff is exploring additional ways to effectively use available resources,
particularly across Divisions.
Rate Changes by Customer Class
Table 3 shows the rates that will be used to recover sale revenues for each customer class. The
Street Lighting (E-14) class and the E-4 and E-7 Time of Use (TOU) rates are not shown in the
table, but can be seen in the attached rate schedules (Attachment E). These schedules are
omitted from Table 3 due to the complexity of these rate schedules and/or these rate
schedules are used by one or none of CPAU’s customers.
City of Palo Alto Page 8
Table 3: Electric Rates (Current and Proposed)
Current
Rates
Proposed
Rates
(7/1/19)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.12871 0.13757 0.00886 6.9%
Tier 2 Energy ($/kWh) 0.19279 0.19367 0.00088 0.5%
Minimum Bill ($/day) 0.3040 0.3283 0.0243 8.0%
E-2 & E-2-G (Small Non-Residential)
Summer Energy
($/kWh)
0.20090 0.20853 0.00763 3.8%
Winter Energy ($/kWh) 0.13861 0.14624 0.00763 5.5%
Minimum Bill ($/day) 0.7740 0.8359 0.0619 8.0%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy
($/kWh)
0.12081 0.12848 0.00767 6.3%
Winter Energy ($/kWh) 0.09297 0.09946 0.00649 7.0%
Summer Demand
($/kW)
24.11 28.91 4.80 19.9%
Winter Demand ($/kW) 18.52 18.97 0.45 2.4%
Minimum Bill ($/day) 15.9946 17.2742 1.2796 8.0%
E-7 & E-7-G (Large Non-Residential)
Summer Energy
($/kWh)
0.10507 0.11432 0.00925 8.8%
Winter Energy ($/kWh) 0.07449 0.07738 0.00289 3.9%
Summer Demand
($/kW)
26.77 30.69 3.92 14.6%
Winter Demand ($/kW) 17.01 17.05 0.04 0.2%
Minimum Bill ($/day) 45.4758 49.1139 3.6381 8.0%
Table 4 shows the impact of the proposed July 1, 2019 rate changes on the residential and non-
residential bills for various consumption levels. The overall rate change for the residential class
is roughly 4 percent.
City of Palo Alto Page 9
Table 4: Impact of Proposed Electric Rate Changes on Customer Bills
Rate
Schedule
Usage (kwh/mo)
Bill under
Current Rates
($/mo)
Bill Under Rates
Proposed 7/1/19
($/mo)
Change
$/mo %
E-1 300 38.61 41.27 2.66 6.9
(Summer Median) 365 49.22 45.40 2.92 6.9
(Winter Median) 453 66.19 69.22 3.03 4.6
650 104.17 107.37 3.21 3.1
1200 210.20 213.89 3.69 1.8
E-2 1,000 170 178 8 4.5
E-4 160,000 26,347 28,661 2,313 8.8
E-7 500,000 75,758 81,337 5,579 7.4
E-7 2,000,000 289,010 325,346 22,316 7.4
Cost of Service Analysis and Rate Study
The rates discussed in the previous section are based on the cost of service methodology
established in the “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2016. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates.
Electric Bill Comparison with Surrounding Cities
Table 5 compares electric bills under current rates as of March 1, 2019 for residential customers
to those in surrounding communities. Under current rates, CPAU’s customer bills are far below
PG&E’s and are lower than others for non-residential customers, but slightly higher than Santa
Clara’s for higher using residential customers. It is unclear at this time what electric rate
changes may be implemented in these communities for FY 2020.
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
City of Palo Alto Page 10
Table 5: Average Electric Bill Comparison ($/month)
As of March 1, 2019
Customers
Usage
(KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E Santa Clara
Residential
Customers
300 $ 38.61 $ 41.27 $ 65.33 $ 35.89
365 (Summer
Median) 49.22 45.40 85.16 43.95
453 (Winter
Median) 66.19 69.22 98.64 54.86
650 104.17 107.37 150.77 79.29
1200 210.20 213.89 301.48 147.48
Non-
Residential
Customers
1,000 170 178 253 184
160,000 25,628 28,661 30,936 21,243
500,000 66,780 81,337 86,341 64,155
2,000,000 289,010 325,346 372,799 261,360
Commission Review
The UAC reviewed this proposal at its April 9, 2019 meeting. The excerpted draft minutes from
the UAC’s April 9, 2019 meeting can be found on the City’s website, located here.
Timeline
If the Finance Committee supports the proposed rate adjustments, the City Council will
consider the proposed Financial Plans and amended rate schedules with the FY 2020 budget.
Resource Impact
The proposed July 1, 2019 rate changes are projected to increase sales revenues by $9 million
per year over the forecast period. The FY 2020 Budget is being developed concurrent with these
rates and depending on final rates, adjustments to the budget may be necessary at a later time.
Policy Implications
The proposed electric rate adjustments were developed using the 2016 cost of service study
and methodology, and are consistent with the Council adopted Reserve Management Practices
that are part of the Financial Plan.
Environmental Review
The Finance Committee’s review and recommendation to Council on the FY 2020 Electric
Financial Plans and rate adjustments does not meet the California Environmental Quality Act’s
definition of a project, pursuant to Public Resources Code Section 21065, thus no
environmental review is required.
Attachments:
City of Palo Alto Page 11
• Attachment A: Resolution Approving FY 2020 Electric Utility Financial Plan Draft
• Attachment B: FY 2020 Electric Utility Financial Plan
• Attachment C: Resolution Adopting FY 2021 Electric Rate Schedules
• Attachment D: Proposed Electric Rate Schedules effective July 1, 2019
Attachment A
* NOT YET APPROVED *
6055193
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2020 Electric Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes
making long-term projections of market conditions, the physical condition of the system, and
other factors that could affect utility costs, and setting rates adequate to recover these costs.
This is done with the goal of providing safe, reliable, and sustainable utility services at
competitive rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2020 Electric Utility Financial Plan.
SECTION 2. The following transfers that were previously approved by resolution 9692
to take place in FY 2017, but which were not performed due to staff error, are hereby
reauthorized in FY 2019: 1) transfer up to $9.0 million from the Hydroelectric Stabilization
Reserve to the Supply Operations Reserve, 2) transfer up to $9.011 million from the Supply Rate
Stabilization Reserve to the Supply Operations Reserve, and 3) transfer up to $4.5 million from
the Supply Operations Reserve to the Distribution Operations Reserve.
//
//
//
//
//
//
//
Attachment A
* NOT YET APPROVED *
6055193
//
//
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental review is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2020 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2020 TO FY 2024
2 | P a g e
FY 2020 ELECTRIC UTILITY
FINANCIAL PLAN
FY 2020 TO FY 2024
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 2020 Rate and Reserves Proposals ....................................................... 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 7
Section 3C: Reserves Management Practices .............................................................................. 8
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................. 10
Section 4A: Electric Utility History ............................................................................................. 10
Section 4B: Customer Base ........................................................................................................ 12
Section 4C: Distribution System ................................................................................................. 12
Section 4D: Cost Structure and Revenue Sources ...................................................................... 13
Section 4E: Reserves Structure ................................................................................................... 14
Section 4F: Competitiveness ...................................................................................................... 15
Section 5: Utility Financial Projections ................................................................................. 16
Section 5A: Load Forecast .......................................................................................................... 16
Section 5B: FY 2014 to FY 2018 Cost and Revenue Trends ........................................................ 18
Section 5C: FY 2018 Results ....................................................................................................... 19
Section 5D: FY 2019 Projections ................................................................................................ 20
Section 5E: FY 2020 – FY 2024 Projections ................................................................................ 20
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 22
3 | P a g e
Section 5G: Long-Term Outlook ................................................................................................. 27
Section 6: Details and Assumptions ..................................................................................... 30
Section 6A: Electricity Purchases ............................................................................................... 30
Section 6B: Operations .............................................................................................................. 32
Section 6C: Capital Improvement Program (CIP) ....................................................................... 33
Section 6D: Debt Service ............................................................................................................ 34
Section 6E: Equity Transfer ........................................................................................................ 35
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 35
Section 6G: Sales Revenues ....................................................................................................... 36
Section 7: Communications Plan .......................................................................................... 37
Appendices ......................................................................................................................... 39
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 40
Appendix B: Electric Utility Reserves Management Practices ................................................... 44
Appendix C: Description of Electric utility Operational Activities .............................................. 49
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 50
4 | P a g e
SECTION 1: DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a
section of the distribution system operates. The transmission system operates at
115-500 kV, and this is lowered to 60 kV in the sub-transmission section of the
Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution
system, and finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum
electricity demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Sub-transmission System: The section of the Electric Utility’s distribution system that operates
at 60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115
kV or more. The voltage at the intersection of the Electric Utility’s distribution
system and PG&E’s transmission system is 115 kV. The Electric Utility does not own
or operate any transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
5 | P a g e
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Electric Utility for the next five fiscal
years. This Financial Plan describes how revenues will cover the costs of operating the utility
safely over that time while adequately investing for the future. It also addresses the financial
risks facing the utility over the short term and long term, and includes measures to mitigate and
manage those risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
The Electric Utility’s costs are projected to increase by about 3% per year on average over the
forecast horizon, as shown in Table 1. The majority of cost is related to electric supply
purchases, which are increasing mainly due increased transmission costs and are projected to
grow at an estimated 2% per year on average. Operations and maintenance costs are about one
third of total costs, and are projected to increase by about 3 to 4% per year on average due to
both inflationary as well as salary and benefits increases. Capital improvement costs are
currently projected to grow by about 6% on average, mainly precipitated by rebuilds of existing
underground districts as well as substation improvements and voltage conversion projects.
Table 1: Electric Utility Expenses for FY 2018 to FY 2024
Expenses
($000)
FY 2018
(act.)
FY 2019
(est.) FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Power Supply
Purchases
94,630 90,625 95,615 95,488 98,895 98,309 98,673
Operations 54,770 52,547 55,087 57,302 60,284 62,265 63,256
Capital Projects 18,803 14,156 15,409 20,148 17,915 19,172 19,268
TOTAL 168,203 157,328 166,112 172,938 177,094 179,746 181,197
To cover these increases in costs, revenues (and therefore rates) need to increase over the next
several years to balance costs and maintain adequate reserves, as shown in Table 2. The table
also compares current rate projections to those projected in last year’s Financial Plan. The rate
projections are slightly higher over the forecast period than last year primarily due to lower
actual and projected sales, increases to transmission cost projections and increases to capital
investment spending.
Table 2: Projected Electric Rates, FY 2020 to FY 2024
Projection FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Current 8% 4% 4% 4% 3%
Last Year 3% 2% 0% 1% 1%
Table 3 shows the projected reserve transfers over the forecast period. The Supply Rate
Stabilization Reserve is projected to be drawn down entirely by the end of FY 2019. Per Council
approval, $10 million was transferred from the Electric Special Projects (ESP) Reserve in FY 2018
to the Operations Reserve. Any transfers from the ESP Reserve require Council approval.
Council also approved using all remaining funds ($11.2 million) from the Hydro Stabilization
6 | P a g e
Reserve, but ending reserves show that only $4 million is warranted at this point. It is staff’s
intention to repay the $10 million loan from ESP reserve and fund the Hydro Stabilization
reserve as is prudent.
Table 3: Reserves Transfers for FY 2019 to FY 2024 ($000)
Reserve FY 2019 FY 2020 FY 2021 to FY 2024
Supply Reserves
Electric Special Projects - - 10,000
Hydro Stabilization (4,000) - 4,000
Supply Rate Stabilization (9,011) - -
Supply Operations 11,011
Distribution Reserves
Capital Improvement Program - - -
Distribution Operations 2,000 - -
*
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2019:
1. Approve a transfer of up to $4 million from the Hydro Stabilization Reserve to the
Supply Operations Reserve to maintain reserve adequacy.
2. Transfer all remaining funds ($9.011 million) from the Rate Stabilization reserve to the
Supply Operations Reserve.
3. Transfer up to $2 million from the Supply Operations to the Distribution Operations
reserve to maintain reserve adequacy.
Staff proposes the following actions for the Electric Utility in FY 2020:
1. Increase rates effective July 1, 2019 for an 8% increase in system average rates.
SECTION 3: DETAIL OF FY 2020 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The rate increase discussed in the previous section is based on the cost of service methodology
established in “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2015/16. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
7 | P a g e
proposed rates. The COSA is based on design guidelines adopted by Council on September 15,
2015 (Staff Report 6061).
SECTION 3B: CURRENT AND PROPOSED RATES
The City adopted the current rates effective July 1, 2018, when CPAU increased electric rates by
6%. Table 4, below, summarizes the current and proposed rates for the four largest customer
classes. The Electric Utility also has specialty rates for smaller groups of customers. These
include variations on its primary rates, such as time of use rates and solar net metering. Staff
proposes an 8% overall increase in average rates. Different customer classes may see different
percentage changes to their rates, based upon their usage of the system and cost to serve each
group.
Table 4: Current and Proposed FY 2020 Electric Rates
Current Rates
Proposed Rates
(7/1/19)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.12871 0.13757 0.00886 6.9%
Tier 2 Energy ($/kWh) 0.19279 0.19367 0.00088 0.5%
Minimum Bill ($/day) 0.3040 0.3283 0.0243 8.0%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.20090 0.20853 0.00763 3.8%
Winter Energy ($/kWh) 0.13861 0.14624 0.00763 5.5%
Minimum Bill ($/day) 0.7740 0.8359 0.0619 8.0%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.12081 0.12848 0.00767 6.3%
Winter Energy ($/kWh) 0.09297 0.09946 0.00649 7.0%
Summer Demand ($/kW) 24.11 28.91 4.80 19.9%
Winter Demand ($/kW) 18.52 18.97 0.45 2.4%
Minimum Bill ($/day) 15.9946 17.2742 1.2796 8.0%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.10507 0.11432 0.00925 8.8%
Winter Energy ($/kWh) 0.07449 0.07738 0.00289 3.9%
Summer Demand ($/kW) 26.77 30.69 3.92 14.6%
Winter Demand ($/kW) 17.01 17.05 0.04 0.2%
Minimum Bill ($/day) 45.4758 49.1139 3.6381 8.0%
These proposed rates were prepared in conformance with the “FY 2017 City of Palo Alto Electric
Cost of Service and Rate Study,” performed by EES Consulting (2016).
8 | P a g e
SECTION 3C: RESERVES MANAGEMENT PRACTICES
This financial plan proposes no changes to the Reserves Management Practices (See Appendix
B: Electric Utility Reserves Management Practices), although staff will continue to review these
policies as required.
SECTION 3D: PROPOSED RESERVE TRANSFERS
As part of the FY 2019 Financial Plan, Staff did not propose and FY 2019 transfers but was
intending on including them as part of the year end BAO process. However, the timing of
reserve reconciliations did not allow for these recommendations to take place. Therefore, staff
will be proposing multiple transfers for FY 2019, requesting that Council approve amounts ‘up
to’ the levels suggested, based upon anticipated ending reserve levels:
• Transfer up to $9.011 million from the Rate Stabilization Reserve to the Supply
Operations Reserve.
• Transfer up to $4.0 million from the Hydroelectric Stabilization Reserve to the Supply
Operations Reserve.
Transfer up to $2 million from the Supply Operations Reserve to the Distribution
Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve.
Reserve balances for FY 2019 have taken these transfers into account. To affect these transfers,
staff is re-ratifying the following transfer proposals, which were previously approved in
resolution 9692 to take place in FY 2017, but were not performed: 1) transfer up to $9 million
from the Hydroelectric Stabilization Reserve to the Supply Operations Reserve, 2) Transfer up to
$9.011 million from the Rate Stabilization Reserve to the Supply Operations Reserve, and 3)
Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution Operations
Reserve.
In FY 2018, Council approved a $10 million loan from the Electric Special Projects (ESP) reserve,
and it is staff’s intention as part of this financial plan to repay the full amount back within the
timeframe of this financial planning horizon. The pace of payback may be moderated based
upon the general financial health of the electric fund.
Figure (for Supply Fund Reserves) and Figure 5 (for Distribution Fund Reserves) in Section 5E: FY
2020 – FY 2024 Projections show the impact of these transfers on reserves levels. Table 5 shows
the projected balance of each of the Electric Utility reserves for the period covered by this
Financial Plan. See also: Appendix A: Electric Utility Financial Forecast Detail
9 | P a g e
Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2017 to FY 2024
Ending Reserve
Balance ($000)
FY 2018
(Act.) FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Re-appropriations 9,063 - - - - - -
Commitments 8,637 3,533 3,533 3,533 3,533 3,533 3,533
Underground Loan 730 730 730 730 730 730 730
Public Benefits 681 - - - - - -
Special Projects 41,838 41,838 41,838 41,838 41,838 46,838 51,838
Hydro Stabilization 11,400 7,400 7,400 7,400 11,400 11,400 11,400
Capital 880 880 880 880 880 880 880
Rate Stabilization 9,011 - - - - - -
Operations 19,900 30,933 30,074 31,260 32,472 36,630 40,603
Unassigned - - - - - - -
TOTAL 102,140 85,314 84,455 85,641 90,853 100,011 108,984
10 | P a g e
SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4A: ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel
engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity
continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E
proved more economical than the diesel engines, and by the late 1920s CPAU was using its own
diesel engines only during peak demand periods. At that time CPAU owned 45 miles of
distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual
consumption. The diesel engines remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did
throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the
sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto,
which doubled the number of customers. Some was related to the proliferation of electric
appliances, as evidenced by the fact that residential customers were using three times more
electricity in 1970 than they had been in 1950. But the most notable factor was the growth of
industry in Palo Alto during that time. By 1970, commercial customers were using 20 times
more electricity per customer than they had been in 1950. These decades also saw several
other notable events, including:
• 1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of
Reclamation to purchase power from the Central Valley Project (CVP), a contract which
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
• 1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
• 1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
11 | P a g e
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement
program for its underground system in the early 1990s.
In the early 1990s the CPUC issued a ruling to deregulate the electric industry in 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
12 | P a g e
Figure 1: Customer Consumption By Class (FY 2018)
16%
6%
36%
42%
Residential
Small Comm.
Med. Comm.
Large Comm.
SECTION 4B: CUSTOMER BASE
The City of Palo Alto’s Electric Utility
provides electric service to the
residents, businesses, and other
electric customers in Palo Alto. There
are roughly 29,600 customers
connected to the electric system,
25,550 (86%) of which are residential
and 4,050 (14%) of which are non-
residential. Residential customers
consumed 148 gigawatt-hours (GWh)
in FY 2018, approximately 16% of the
electricity sold, while non-residential
customers consumed 84% or 752
GWh. Residential customers use
electricity primarily for lighting,
refrigeration, electronics, and air conditioning.3 Non-residential customers use the majority of
their electricity for cooling, ventilation, lighting, office equipment (offices), cooking
(restaurants), and refrigeration (grocery stores).4
As shown in Figure 1 large customer loads represent a large proportion of sales for the Electric
Utility. The proportion of sales to large vs. small customers is greater than for the City’s other
utilities. For example, the largest customers (the 71 customers on the E-7 rate schedule)
account for around 42% of CPAU’s sales. The next largest customer group (the 830 non-
residential customers on the E-4 rate schedule) represents another 36% of sales. In total, that
means that about 3% of customers account for nearly three quarters of the electric load.
SECTION 4C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 472 miles of
distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are
underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line
transformers, around 1,100 underground and substation transformers, and the associated
electric services (which connect the distribution lines to the customers’ homes and businesses).
These lines, substations, transformers, and services, along with their associated poles, meters,
and other associated electric equipment, represent the vast majority of the infrastructure used
to deliver electricity in Palo Alto.
3 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
4 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
13 | P a g e
Figure 2: Cost Structure (FY 2018)
56%
33%
11%
Commodity
Supply
Operations
Capital
Figure 3: Hydroelectric Variability (FY 2019)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 4: Revenue Structure (FY 2018)
80%
20%
Sales of Electricity
Other Revenue
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 56% of the Electric Utility’s
costs in FY 2018. Operational costs
represented roughly 33%, and
capital investment was responsible
for the remaining 11%. CPAU’s non-
hydro long-term commodity supply
is heavily dependent on long-term
contracts which have little variability
in price. On average, costs for these
long-term contracts are not
predicted to increase as quickly as operations and CIP costs, and will steadily become a smaller
proportion of the Electric Utility’s costs. Staff projects commodity supply costs to be
approximately 54% of total costs in FY 2024.
While average year purchase
costs for the electric utility
are predictable due to its
long-term contracts,
variability in hydroelectric
generation can result in
increased or decreased
costs. This is by far the
largest source of variability
the utility faces. Figure
shows the relative difference
in costs under high,
projected, and low hydroelectric
generation scenarios for FY 2019.
Additional costs associated with a very
low generation scenario can range from
$9-11 million per year. For the current
hydroelectric risk assessment see Section
5F: Risk Assessment and Reserves
Adequacy.
As shown in Figure the Electric Utility
receives 80% of its revenue from sales of
electricity and the remainder from
connection fees, interest on reserves, cost recovery transfers from other funds for shared
services provided by the electric utility, and other sources. Some revenue sources are primarily
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accounting entries that reflect things such as CPAU’s participation in a pre-funding program
associated with its contract with WAPA, as well as accounting entries associated with
occasional sales of surplus hydroelectric energy during wet years. Appendix A: Electric Utility
Financial Forecast Detail
shows more detail on the utility’s cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 900 largest customers, which provide a similar share of the utility’s revenue stream.
The utility’s retail rate schedules have no fixed charges, although about 24% of the utility’s
revenue comes from peak demand charges on large non-residential customers. Due to
moderate weather and the prevalence of natural gas heating, however, loads (and therefore
revenues) are very stable for this utility, without the large seasonal air conditioning or winter
heating loads seen at some other utilities.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of
contingencies. It also maintains two funds, the Supply Fund and the Distribution Fund, to
manage costs associated with electricity supply and electricity distribution, respectively. The
City established this separation of supply and distribution costs as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) in the late 1990s and
early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues to
maintain separate funds to facilitate separation of supply and distribution costs in the rates.
This could be important if California ever decides to broadly reintroduce Direct Access, and may
also be useful for rate design as the nature of utility services evolves in response to higher
penetrations of distributed generation.
The summary below describes the various reserves, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserves for Commitments: Reserves equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserves for Reappropriations: Reserves for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve. This is currently an important
reserve for all utility funds, but changes in budgeting practices will change that in future
years, as described in Section 3C (Reserves Management Practices).
• Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which began during deregulation of California’s electric system to fund the
stranded costs associated primarily with the Calaveras hydroelectric resource and the
California-Oregon Transmission Project. When that reserve was no longer needed for
that purpose, the reserve was renamed and the purpose was changed to fund projects
with significant impact that provide demonstrable value to electric ratepayers.
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• Hydroelectric Stabilization Reserve: This contingency reserve is used for managing
additional costs due to below average hydroelectric generation, or to hold surpluses
resulting from above average hydroelectric generation.
• Underground Loan Reserve: This reserve is an accounting tool used to offset receivables
associated with loans made through the underground loan program. It is adjusted
according to principal payments made on those loans.
• Public Benefits Reserve: CPAU’s electric rates include a separate charge called the
“Public Benefits Charge” which generates revenue to be used for energy efficiency,
demand-side renewable energy, research and development, and low-income energy
efficiency services. Any funds not expended in the current year are added to the Public
Benefits Reserve for use in future years.
• Capital Improvement Program (CIP) Reserve: The CIP reserve is used to provide
working capital and contingency funds for the CIP program, as well as to accumulate
funds for major future one-time expenditures. This type of reserve is used in other
utility funds (Electric, Gas, and Wastewater Collection) as well.
• Supply and Distribution Rate Stabilization Reserves: These reserves are intended to be
empty unless one or more large rate increases are anticipated in the forecast period. In
that case, funds can be accumulated to spread the impact of those future rate increases
across multiple years. This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Supply and Distribution Operations Reserves: These are the primary contingency
reserves for the Electric Utility, and are used to manage yearly variances from budget
for operational costs and electric supply costs (aside from variances related to
hydroelectric generation). This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves
are for any financial resources not assigned to the other reserves and are normally
empty.
SECTION 4F: COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2018 was
$676 under current CPAU rates, about 35% lower than the annual bill for a PG&E customer with
the same consumption and approximately 16% higher than the annual bill for a City of Santa
Clara customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X,
which includes most surrounding comparison communities.
Table 6 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara
(Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown
below were in effect as of March 1, 2019.
Over the next several years low usage customers in PG&E territory are expected to continue to
see higher percentage rate increases than high usage customers as PG&E compresses its tiers
from the highly exaggerated levels that have been in place since the energy crisis. This is likely
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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, 2019 rates.
However, even with the proposed rate increases, Palo Alto’s residential bills will remain
substantially below PG&E’s current rates, but slightly above Santa Clara’s.
Table 6: Residential Monthly Electric Bill Comparison (Effective 3/1/19, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(March)
300 38.61 65.33 35.89
453 (Median) 66.19 98.64 54.86
650 104.17 150.77 79.29
1200 210.20 301.48 147.48
Summer
(July)
300 38.61 67.35 35.89
(Median) 365 49.22 85.16 43.95
650 104.17 163.26 79.29
1200 210.20 313.97 147.48
Table 7 shows the average monthly electric bill for commercial customers for various usage
levels. Even with the proposed rate increases, Palo Alto’s commercial bills will remain
substantially below PG&E’s, and below Santa Clara’s for some commercial customers.
Table 7: Commercial Monthly Electric Bill Comparison (3/1/19, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 170 253 184
160,000 25,628 30,936 21,243
500,000 66,780 86,341 64,155
2,000,000 289,010 372,799 261,360
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 3 shows a 34-year history of Palo Alto electricity consumption. Average electricity
consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then
electricity consumption has declined slowly as a result of a continuing focus on energy
efficiency, as well as the adoption of more stringent appliance efficiency standards and energy
standards in building codes. Recently, some larger commercial customers have relocated
operations or shifted to more office type usage. It is unknown how long this trend may
continue.
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Figure 3: Historical Electricity Consumption
Figure 4 shows the forecast of electricity consumption through FY 2028. The forecast assumes
about a 3% demand drop in FY 2019, followed by a generally flattened demand thereafter. This
projection assumes the resumption of an overall declining demand trend, but at a less
steepened pace. These projections will be revised if continuing sales patterns indicate further
declines, or changes in customer mix occur.
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Figure 4: Forecasted Electricity Consumption
SECTION 5B: FY 2014 TO FY 2018 COST AND REVENUE TRENDS
As shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail
, the annual expenses for the Electric Utility remained fairly stable between FY 2014 and FY
2017, but increased in FY 2018. On the capital side, the large Upgrade Downtown CIP project
got underway in FY 2018, which is a much larger project than usual. Electric supply costs
increased as new renewable projects came online, and transmission costs have risen as
improvements are made to the overall California grid.
Section 6A: Electricity Purchases discusses the factors influencing Electric Utility expenses. Since
FY 2012, total expenses for the utility have included the costs of renewable resources coming
online. In FY 2014 through FY 2015 commodity costs were higher due to lower than average
output from hydroelectric resources. Transmission and renewables costs have increased, as
projected in prior financial plans.
Commodity costs have increased, on average, by about 8% per year over this timeframe.
Operations costs have increased by about 5% annually on average. Revenues have increased on
average by about 5% per year over this period, although FY 18 sales revenues were lower than
projected due to declining sales.
Actual Projection
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2018 and Projections through FY 2024
SECTION 5C: FY 2018 RESULTS
FY 2018 saw a continuing decline in sales, and with it lower sales revenues than projected by
about $2 million. In addition, interest income was negligible due to market valuations, and
other revenue sources were lower as well. Total cost of purchasing electricity was higher than
the forecast by approximately $11 million due to dry hydro conditions, but these were offset
somewhat by operations and capital improvement costs being lower than projected. Overall
reserves were impacted by about $11.4 million more than expected.
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Table 8 FY 2018, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues lower than forecast $2,086 Revenue decrease
Interest and other income lower than expected 413 Revenue decrease
Higher purchased electricity costs 11,123 Cost increase
Lower operations expense (2,211) Cost decrease
Net Cost / (Benefit) of Variances $11,411
SECTION 5D: FY 2019 PROJECTIONS
Last year, staff recommended (and Council approved) a 6% rate change for July 1, 2018.
Declining sales led to a revision of revenues, and staff is estimating $8.2 million lower sales.
Other revenues are projected to be about $2.6 million higher, however, and revised expense
estimates bring overall operations costs down by $1.8 million. A revised CIP outlook also
reduces projected expenses by about $8.5 million, as these projects were previously
encumbered and not new funding.
Table 9 FY 2019, Change in Projected Results, 2019 Forecast vs. 2019 Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues revision 8,278 Revenue decrease
Wholesale and other revenues higher than
forecast
(2,614) Revenue increase
Capital improvement costs (8,528) cost decrease
Purchased electricity costs (1,300) cost decrease
Operations costs (460) cost decrease
Net Cost / (Benefit) of Variances ($4,624)
SECTION 5E: FY 2020 – FY 2024 PROJECTIONS
As shown in Figure above, staff projects costs for the Electric Utility to increase at a fairly
steady rate through the forecast period. Revenue increases of 8% in FY 2020 and another 4% in
FY 2021 are projected to bring revenues in line with expenses. Rising electricity purchase costs
are the primary contributor to the increases. Electricity purchase costs have increased
substantially since FY 2013 as new renewable projects have come online to fulfill the City’s
environmental goals, and as transmission costs have increased due to improvements being
made to the California grid. Operations costs are expected to increase at or near the inflation
rate (2-4 %/year) through the forecast period. Projected capital expenses for FY 2018 through
FY 2021 are higher due to work on the Upgrade Downtown project, the rebuilding of existing
underground districts, substation and line voltage upgrades. Once these larger, one-time
project cost increases are completed, annual CIPs may decline somewhat, but staff has included
additional cost assumptions in case further underground district construction is required.
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Reserves trends based on these revenue projections are shown in Figure (for Supply Fund
Reserves) and Figure 5 (for Distribution Fund Reserves), below. The Supply Rate Stabilization
Reserve will be empty by the end of FY 2019.
Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2018 and Projections through FY 2024
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Figure 5: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2018 and Projections through FY 2024
SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two primary contingency reserves, the Supply Operations
Reserve and the Distribution Operations Reserve. In the past, the Supply and Distribution funds
had Rate Stabilization Reserves (RSR), but these are being phased out over time. The Supply
RSR currently has $9 million which needs to be transferred to the Supply Operations Reserve. In
addition, the Electric Utility has a Hydro Stabilization reserve and an Electric Special Projects
reserve, both of which can be utilized with prior Council approval.
This Financial Plan maintains reserves above the reserve minimum for the Distribution
Operations Reserve throughout the forecast period. Reserve levels also exceed the short-term
risk assessment level for the Distribution Fund. The Supply Operations Reserve, however, is
currently below minimum levels pending proposed transfers from the Supply Rate Stabilization
Reserve. .
There are a variety of risks associated with the Supply Fund as are shown in Table 10. Because
of the high range of uncertainty in energy price predictions more than three years in the future,
this risk assessment is only performed for the first two fiscal years of the forecast period. It is
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important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 10 is very low.
Table 10: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2020 FY 2021
1. Production from Hydroelectric
Resources: Western & Calaveras 6.8 8.3 Lower than forecasted hydro
2. Nenewable Production: Landfill,
Wind, Solar 2.2 2.0 Lower than forecasted production
3. Market Price (Energy) 0.9 1.0 Higher than forecasted market prices for
energy
4. Load Net Revenue 3.2 3.4 Lower forecast surplus sales
5. Local Capacity 1.1 2.3 Additional local capacity cost
6. Transmission/CAISO 3.6 3.7 High-end transmission forecast scenario
7. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
8. Western Cost 2.3 2.0 Risk of rate adjustments from Western
9. Regulatory and Legal 0.0 0.0 Risks associated with legislative uncertainties
11. Supplier Default 0.2 0.2 Risk of supplier insolvency
Electric Supply Fund Risks $20.8
million
$23.7
million
Projected Supply Operations +
Hydro Stabilization Reserve
Levels
$28.3
million
$28.6
million
Of the risks faced by the Electric Utility’s Supply Fund, the risk of a dry year with very low
hydroelectric output is normally the largest, accounting for nearly one third the total cost of all
adverse outcomes. Since the utility’s costs for its hydroelectric resources are almost entirely
fixed, costs do not decline when the output of those resources are low, but the utility 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 2020, $3.6 million is related to the projected costs if transmission
cost increases are higher than staff’s current forecast. $3.2 million is related to the uncertainty
with surplus energy sales revenues, and uncertainties with regards to renewables production as
well as possible adjustments from Western account for about $2 million each.
As shown in Figure 6, the Supply Operations Reserve was below the minimum reserve
guidelines at the end of FY 2018. However, through reserve transfers and rate increases, staff
projects the Supply Operations Reserve to stay within the reserve guideline levels throughout
the rest pf the forecast period. Figure 11 shows that the combined Hydro Stabilization, Supply
Rate Stabilization and Supply Operations Reserves are projected to be above what is needed for
the risk assessment level.
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Figure 6: Electric Supply Operations Reserve Adequacy
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Figure 7: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 11 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2024. As shown in Figure 12, the Distribution Operations Reserve will stay within the
reserve guidelines over the course of the forecast period. The risk assessment includes the
revenue shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 11: Electric Distribution Fund Risk Assessment ($000)
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Total non-commodity revenue $56,355 $58,968 $61,705 $65,803 $68,207
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $4,448 $4,654 $4,870 $5,193 $5,383
CIP Budget $15,409 $20,148 $17,915 $19,172 $19,268
CIP Contingency @10% $1,541 $2,015 $1,792 $1,917 $1,927
Total Risk Assessment value $5,989 $6,669 $6,662 $7,111 $7,310
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Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, staff projects the CIP Reserve to be above the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels, CIP Commitments are nearly impossible to project that far out, and
adjustments to the reserve can be made in future years.
Figure 13: Electric CIP Reserve Adequacy
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SECTION 5G: LONG-TERM OUTLOOK
This forecast covers the period from FY 2020 through FY 2024, but various long-term
developments may create new costs for the utility over the next 5 to 35 years. While it is
challenging to accurately forecast the impact these events will have on the utility’s costs, it is
worth noting them as future milestones and keeping them in mind for long-term planning
purposes.
For the supply portfolio, the 2020s will see a number of notable events. The contract with
Western for power from the CVP will expire in 2024. Determining the future relationship with
Western after 2024 will be important in the years leading up to the contract expiration,
especially because this resource represents nearly 40% of the electric portfolio, and is the
utility’s largest source of carbon-free electricity. The utility’s three earliest and lowest cost
renewable contracts will also begin expiring around that time, with the first contract expiring in
2021 and the last in 2028. These three contracts, plus one more expiring in 2030, currently
provide 17% to 18% of the energy for the utility’s supply portfolio at prices under $65 per
megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those
contracts expire. Although recent prices have been in that range (or even lower), and costs
may decrease in the future, current renewable projects also benefit from a wide range of tax
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and other incentives that may or may not be available in the 2020s and beyond. However, staff
is in the process of procuring a replacement for the contract expiring in 2021 at a lower price
than any of the City’s current renewable contracts.
The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs
dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032
(assuming the Utility does not issue any new debt). The project will only be 40 years old at that
time. Calaveras debt service represents roughly 70% of the annual costs of that project (and
nearly 7% of the utility’s total costs), so when the debt is retired, the project could be a low-
cost asset for the utility, providing carbon-free energy equal to around 13% of the Electric
Utility’s supply needs in an average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to 5 million per year in revenue from
allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to
pay for energy efficiency programs and to purchase renewable energy to support the utility’s
Carbon Neutral Plan. Staff expects that revenue source to continue through 2020. However,
discussions at the state level are ongoing and will determine whether or not these allocations
continue past 2020, as well as any restrictions CARB may wish to enact on usage of allocation
sales revenues. If the Electric Utility no longer received these allowances or was limited in how
it could spend revenues, it would have to fund these programs from sales revenues.
Transmission costs are also continuing to rise. If the State continues to increase mandates or
incentives for renewable energy development, integrating these new projects into the
transmission grid will be an ever increasing challenge, some costs of which will be borne by Palo
Alto. The planned expansion of the CAISO to a larger regional grid control area may result in
additional transmission costs that could further increase CPAU’s transmission costs. In addition
to the costs of new transmission lines that will need to be built, flexible resources will be
required to balance rapid changes in wind or solar output throughout the day. Palo Alto will
likely bear some of the costs of these new lines and resources. CPAU is also currently
investigating installing a second transmission interconnection for Palo Alto, which could be
funded by the Electric Special Projects Reserve.
Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these
factors may begin to create notable increases in electric consumption and have a variety of
impacts on the distribution system. As housing stock is turned over, however, stricter building
codes may help to counteract load growth, as may increasing numbers of rooftop solar
installations. The utility has already started to take some of these factors into account in its
long-term planning processes, but will need to continue to incorporate them into its planning
methodologies.
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Over the long term, it is conceivable that electricity could replace natural gas and petroleum
almost entirely. Many, if not most, vehicles would use electricity, though hydrogen is another
potential fuel source under development and other technologies might be developed. Staff are
undertaking initial analysis of these types of scenarios in the context of the Sustainability and
Climate Action Plan (S/CAP) development process. These types of scenarios require careful
planning for the associated load growth to make sure the distribution system does not end up
overloaded, or conversely, to avoid over investment, and the evaluation of changes to utility
distribution system management to accommodate integration of the various technologies
involved in electrification.
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SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: ELECTRICITY PURCHASES
As shown in Figure 8 the utility gets roughly 50% of its energy from hydroelectric projects in a
normal year (FY 2014 and FY2015 were dry). Contracts with renewable sources made up just
over 30% of the portfolio in FY 2016, and 50% in FY 2017. Staff expects contracts with
renewable sources to continue at approximately 50% of the portfolio for the forecast period.
The remainder comes from unspecified market sources. Under the City’s Carbon Neutral Plan,
CPAU purchases RECs corresponding to the amount of market energy it purchases.
Figure 8: Electricity Supply by Source
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Figure 9 shows the historical and projected costs for the electric supply portfolio,5 as well as
average and actual hydroelectric generation.6 Electric supply costs increased in FY 2013, FY
2014, and FY 2015 due to the drought, which reduced the amount of generation from
hydroelectric resources. Costs decreased slightly in FY 2016 due to better than expected market
purchase costs, and FY 2017 and FY 2018 had lower hydroelectric costs. Renewable energy
costs assumed a larger portion of cost as various renewable projects came online to fulfill the
City’s carbon neutral and RPS goals, although some of the older, higher priced contracts will
start expiring as early as FY 2022. The current market outlook is that newer renewables projects
should come in at lower costs. Transmission charges are also projected to increase as new
transmission lines are built throughout California to accommodate new renewable projects. In
total, electric supply costs are projected to increase to about $86 million by FY 2022, at which
point all currently contracted renewable projects will be online. Supply costs are only projected
to change slightly in subsequent years.
5 Costs are shown net of wholesale revenues, and cannot be directly compared 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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Figure 9: Electric Supply Portfolio Costs, Historical and Projected
SECTION 6B: OPERATIONS
CPAU’s Electric Utility operations include the following activities:
• Administration, including financial management of charges allocated to the Electric
Utility for administrative services provided by the General Fund and for Utilities
Department administration, as well as debt service and other transfers. Additional detail
on Electric Utility debt service is provided in Section 6D (Debt Service)
• Customer Service
• Engineering work for maintenance activities (as opposed to capital activities)
• Operations and Maintenance of the distribution system; and
• Resource Management
Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 2014 to FY 2018, overall Operations costs have risen annually by about 4.3% on
average. Debt service and transfers costs increase (reflecting transfers to the ESP reserve to
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repay the $10 million loan in FY 2018). However, over the forecast horizon, staff project costs to
increase by roughly 2-3% per year. Starting in FY 2019 and continuing for several years,
Operations and Maintenance costs are increased mainly due to the introduction of a contract
line crew to help while the Utility is understaffed. These costs may be reduced depending on
how much work is needed, and may be phased out as longer-term employees are gained.
Figure 10: Historical and Projected Electric Utility Operational Costs
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
Staff projects CIP spending for FY 2019 through FY 2024 to be consistent with last year’s
forecast, though there is a slight shift in the funding by project category. There will be a
reduction in funding for Undergrounding as current projects are completed; there will be an
increase in funding for Underground Rebuilding and 4/12kV Conversion as improvements are
made to the system in portions of the Crescent Park/Duveneck/St. Francis/Community
Center/Leland Manor/Garland neighborhoods to facilitate rebuild of the Hopkins Substation;
and increase in funding for replacement of distribution system and substation facilities that are
at the end of their useful life. Other significant projects still slated to continue are deteriorated
wood pole replacements, pole relocations to facilitate the Caltrain Railway Electrification
project, Smart Grid upgrades, and ongoing capital investment in the electric distribution system
to maintain/improve reliability. This forecast assumes that the utility finances smart grid
projects from the Electric Special Projects Reserve and with additional funding from the water
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and gas funds, but it would also be possible to use bond financing. That project has tentatively
been moved out to start in FY 2023.
Excluding the one-time projects listed above, the CIP plan for FY 2019 to FY 2024 is primarily
funded by utility rates, but other sources of funds include connection fees (for Customer
Connections), phone and cable companies (primarily for undergrounding), and other funds (for
smart grid). The details of the CIP budget will be available in the Proposed FY 2020 Utilities
Capital Budget. Figure 11 shows the FY 2019 projected budget and the five year CIP spending
plan, although these figures are preliminary pending budget discussions starting in May. The
‘committed’ column represents funds committed to contracts for which work has not yet been
completed or invoices paid.
Figure 11: Electric Utility CIP Spending ($000)
SECTION 6D: DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently
makes payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax
Credit Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction
costs of solar demonstration projects at the Municipal Services Center, Baylands Interpretive
Center, and Cubberley Community Center. The capacity of these projects totaled 250 kW. In
exchange for funding part of the construction costs, the Electric Utility receives the RECs from
these projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are
interest free (the investors receive a tax credit from the federal government). This bond
issuance is secured by the net revenues of the Electric Utility. Debt service for this bond
continues through 2021, and for the financial forecast period is as follows:
Table 11: Electric Utility Debt Service ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2007 Clean Renewable
Energy Bonds 100 100 100 - -
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
One-Time Projects 6,743 (408) 6,335 504 2,075 3,000 3,700 11,700 8,500
System Expansion 150 (4) 146 - - - - - -
Reliability 4,313 (721) 3,592 2,071 1,100 2,750 1,750 600 600
Undergrounding 3,553 (1,506) 2,047 620 50 1,750 50 2,000 -
4/12 Kv Conversion 198 (91) 107 - 1,830 2,000 2,850 1,825 -
Underground Rebuilding 2,259 (7) 2,251 165 2,700 2,650 350 350 350
Ongoing Projects 5,561 (3,183) 2,378 1,069 2,380 2,635 2,415 2,415 2,425
Customer Connections
(Fee Funded)2,830 (1,684) 1,146 411 2,400 2,550 2,700 2,400 2,400
TOTAL 25,607 (7,604) 18,003 4,840 12,535 17,335 13,815 21,290 14,275
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year.
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
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The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage
ratio of 125% of debt service. The current Financial Plan maintains compliance with these
covenants throughout the forecast period, as shown in Appendix C.
The Electric Utility also pledges reserves and net revenue as security for the bond issuances
listed in Table 12, even though the Electric Utility is not responsible for the debt service
payments. The Electric Utility’s reserves or net revenues would only be called upon if the
responsible utilities are unable to make their debt service payments. Staff does not currently
foresee this occurring.
Table 12: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Electric Utility’s:
Net Revenues Reserves
1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water $1,457 No Yes
*Net of Federal interest subsidy
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.7 Each year it is calculated
according to the 2009 Council-adopted methodology, and does not require additional Council
action.
SECTION 6F: WHOLESALE REVENUES AND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 20% comes
from other sources. Of these other sources, about 50 to 60% represents wholesale revenues of
surplus energy sales included solely for accounting purposes. These revenues have offsetting
electric supply purchase costs, and do not normally affect the utility’s net position. Of the
remaining revenues, the largest revenue sources are interest on reserves, connection fees for
new or replacement electric services, and carbon allowance revenues associated with the
State’s cap-and-trade program. In FY 2017 these sources represented roughly 28% of revenue
7 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to equity transfer methodology.
36 | P a g e
from sources other than electricity sales. The remaining FY 2017 revenues consisted of a variety
of one-time transfers.
Revenues from connection fees have increased since FY 2009 varying from year to year.
Revenue from connection fees decreased slightly during the recession, but has increased
substantially since then, peaking in FY 2016 and declining somewhat in FY 2017. Staff forecasts
slightly higher revenue from this source in 2018 through 2021 with revenue leveling out in
subsequent years.
Staff projects carbon allowance and interest income revenues to stay relatively stable through
the forecast period. However, both of these revenue sources are subject to some uncertainty.
The State’s cap-and-trade program regulations only describe the program through 2020. This
forecast assumes the program will remain in place with similar program design following 2020,
but that may not be the case. CARB is in the process of establishing post-2020 rules.
The forecast for interest income assumes current interest rates continue and there are no
major reserve reductions aside from what is anticipated in this Financial Plan. If interest rates
rise, interest income could increase, and if reserves decrease (due to drought or a withdrawal
from the ESP reserve for a major project), interest income would decrease.
SECTION 6G: SALES REVENUES
The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure
provide the basis for sales revenue projections. As discussed in Section 5A, sales revenues for
this utility have been decreasing due to load reduction, but are helped by the mild climate in
Palo Alto. Palo Alto is a built out City, so the opportunities for increased load growth are limited
to the existing footprint of commercial structures and incremental growth in population. As
utilization of existing spaces changes, and energy efficiency measures continue, Palo Alto could
see greater load loss. Increased loads from electric vehicles and the electrification of
households may increase loads somewhat.
37 | P a g e
SECTION 7: COMMUNICATIONS PLAN
The FY 2020 Electric Utility communications strategy covers these primary areas: rates,
efficiency, renewables, operations, infrastructure, safety, and cost containment measures. The
City of Palo Alto Utilities (CPAU) communication methods include use of the Utilities website,
utility bill inserts, messaging on bills and envelopes, email newsletters, print and digital ads in
local publications, videos and participation in community outreach events.
In FY 2020, CPAU is proposing an eight percent increase in electric utility rates. Prior to FY 2017,
electric utility rates had not increased since 2009, as the City had been drawing down reserves
from the Electric Fund. The rate increase is necessary in FY 2019 as operations reserves have
dropped below the reserve target level. Communications will focus on the reasons why a rate
increase is necessary due to cost increases in transmission fees, rising operating and capital
costs, and a reduction in electric sales that have affected the City’s reserves. Perhaps more
important to our customers and other stakeholders is that CPAU is actively working to make
cost containment an ongoing priority and part of an annual cycle, consistent with the newly
approved Utilities Strategic Plan.
Despite these costs and increasing rates, CPAU’s electric utility rates still remain lower than the
neighboring community average, including for municipal and investor-owned utilities (PG&E).
Keeping costs low is one of the benefits CPAU offers its customers as a public utility provider.
CPAU will continue to communicate about the environmental benefits of the City’s carbon
neutral electric supply portfolio. Outreach includes apprising the public of major renewable
energy purchase agreements which contribute toward Palo Alto’s long-term energy security
and commitment to sustainability. Power purchase agreements in recent years have allowed
CPAU to procure long-term renewable electric supplies at low costs. While upfront capital costs
to bring these renewable projects online may have initially contributed towards some increase
in CPAU’s electric rates, these higher costs are tapering off as the projects begin commercial
operations. CPAU will highlight these environmental attributes and value in our
communications.
Throughout the year, communications staff promotes CPAU’s electric efficiency services,
rebates, carbon neutral electric portfolio, and local renewable energy programs. Within the
past few years, CPAU has launched new programs that allow customers to better understand
and manage their energy use. Programs such as the Home Efficiency Genie and commercial
energy efficiency programs help residents and businesses better understand energy usage,
activities and/or upgrades they can implement to improve efficiency and keep utility costs low.
CPAU is exploring opportunities to help customers electrify homes and buildings, as well as
their transportation. Rebates for residential appliances such as heat pump water heaters and
electric vehicle charging stations for multi-family and non-profit facilities are incentivizing more
and more customers to take action. Staff are piloting programs to explore electrification
technologies in other applications as well. These efforts are in line with the City’s Sustainability
and Climate Action Plan goals to reduce greenhouse gas emissions. CPAU will also be launching
an upgraded version of its online utility account services portal this year, which can provide
38 | P a g e
customers with direct access and more information about utility account and consumption
data.
39 | P a g e
APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
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APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
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6053706
1 FISCAL YEAR FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
2
3 ELECTRIC LOAD
4 Purchases (MWh)980,894 979,005 977,292 945,703 925,329 917,891 889,549 890,589 892,967 895,345 889,136
5 Sales (MWh)950,784 936,773 937,157 917,687 899,997 861,466 858,347 859,350 861,645 863,939 857,948
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1164$ 0.1158$ 0.1156$ 0.1249$ 0.1413$ 0.1504$ 0.1614$ 0.1693$ 0.1776$ 0.1865$ 0.1904$
9 Change in System Average Rate 1%0%0%10%13%6%7%5%5%5%2%
10 Change in Average Residential Bill -1%-5%3%11%11%6%7%4%4%4%2%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)305,000 - - - - - - - - - -
14 Commitments (Non-CIP)3,528,000 3,164,000 3,102,055 3,777,205 2,970,955 3,533,348 3,533,348 3,533,348 3,533,348 3,533,348 3,533,348
15 Restricted for Debt Service - - - - - - - - - - -
16 Emergency Plant Replacement 1,000,000 1,000,000 - - - - - - - - -
17 Central Valley Project Reserve 313,000 329,000 - - - - - - - - -
18 Underground Loan Reserve 738,000 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147
19 Public Benefits Reserves 2,197,000 2,064,000 2,574,000 1,839,000 681,330 93,397 - - - - -
20 Electric Special Projects Reserve 51,838,000 51,838,000 51,837,855 51,837,855 51,837,855 41,837,855 41,837,855 41,837,855 41,837,855 41,837,855 46,837,855
21 Hydro Stabilization Reserve - - 17,000,000 11,400,000 11,400,000 11,400,000 7,400,000 7,400,000 7,400,000 11,400,000 11,400,000
22 Capital Reserves - - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964
23 Rate Stabilization Reserves 69,029,000 70,049,000 14,410,840 9,010,840 9,010,840 9,010,840 - - - - -
24 Operations Reserves - - 22,497,607 21,850,187 29,912,981 19,806,460 30,932,608 30,073,923 31,259,973 32,472,062 36,629,491
25 Unassigned - - - - - - - - - - -
26 TOTAL STARTING RESERVES 128,948,000 129,178,000 112,152,357 100,444,086 107,424,072 87,292,010 85,313,921 84,455,237 85,641,287 90,853,375 100,010,805
27
28 REVENUES
29 Net Sales 110,246,264 108,873,377 108,312,917 114,624,726 127,172,308 129,557,477 138,565,429 145,512,954 153,045,336 161,152,446 163,393,133
30 Wholesale Revenues 6,010,409 6,267,000 4,301,366 16,188,920 18,106,327 14,301,333 17,154,668 17,850,725 20,175,945 19,366,208 19,323,362
31 Other Revenues and Transfers In 13,669,185 9,688,480 11,714,494 11,225,911 13,373,312 14,812,806 12,058,254 12,299,750 10,388,889 9,721,745 8,823,213
32 TOTAL REVENUES 129,925,858 124,828,858 124,328,776 142,039,557 158,651,947 158,671,617 167,778,351 175,663,430 183,610,170 190,240,400 191,539,708
33
34 EXPENSES
35 Electric Supply Purchases 68,785,977 80,022,010 75,705,000 80,467,136 94,629,654 90,625,027 95,615,373 95,487,759 98,895,303 98,309,225 98,672,857
36 Operating Expenses
37 Administration
38 Allocated Charges 4,139,837 4,511,222 4,934,195 3,990,822 6,374,241 6,534,109 6,697,993 6,865,675 7,037,365 7,213,364 7,393,764
39 Rent 4,051,044 4,147,742 4,997,101 5,121,102 5,284,977 5,443,527 5,606,832 5,775,037 5,948,288 6,126,737 6,310,539
40 Debt Service 9,020,651 9,037,000 8,885,994 8,953,893 8,867,395 8,464,871 8,473,276 8,439,378 8,447,315 9,280,490 8,914,853
41 Transfers and Other Adjustments 11,329,973 11,004,636 11,798,865 13,052,376 13,449,539 13,131,492 13,291,454 12,643,515 14,241,678 14,395,945 14,770,319
42 Subtotal, Administration 28,541,506 28,700,600 30,616,155 31,118,193 33,976,152 33,573,998 34,069,556 33,723,605 35,674,647 37,016,536 37,389,475
43 Resource Management 3,541,524 2,138,615 2,083,812 1,985,620 1,873,954 2,449,325 2,536,815 2,611,793 2,679,538 2,749,758 2,821,818
44 Demand Side Management 3,187,875 3,491,470 3,643,924 4,271,786 3,889,846 3,487,694 3,201,219 3,136,926 3,091,085 3,171,266 3,215,642
45 Operations and Mtc 9,488,627 10,716,881 11,523,881 11,811,016 11,528,747 15,174,255 15,677,433 16,123,738 16,538,344 16,966,985 17,406,735
46 Engineering (Operating)1,102,008 1,230,160 1,592,024 1,656,522 1,790,942 2,029,395 2,084,026 2,137,827 2,191,632 2,246,896 2,303,554
47 Customer Service 2,032,231 1,548,851 1,540,884 2,190,993 2,291,246 2,475,150 2,568,711 2,646,902 2,716,039 2,787,851 2,861,562
48 Allowance for Unspent Budget - - - - - (3,321,375) (2,525,213) (1,539,384) (1,303,821) (1,337,296) (1,371,632)
49 Subtotal, Operating Expenses 47,893,770 47,826,576 51,000,680 53,034,130 55,350,887 55,868,441 57,612,547 58,841,408 61,587,464 63,601,996 64,627,154
50 Capital Program Contribution 13,016,111 14,005,915 9,331,367 11,558,306 18,803,467 14,156,237 15,409,116 20,148,213 17,915,314 19,171,749 19,268,197
51 TOTAL EXPENSES 129,695,858 141,854,501 136,037,047 145,059,572 168,784,008 160,649,705 168,637,036 174,477,380 178,398,081 181,082,970 182,568,208
52
53 ENDING RESERVES
54 Reappropriations (Non-CIP)- - - - 9,063,000 - - - - - -
55 Commitments (Non-CIP)3,164,000 3,102,055 3,777,205 2,970,955 8,637,000 3,533,348 3,533,348 3,533,348 3,533,348 3,533,348 3,533,348
56 Restricted for Debt Service - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 - - - - - - - - - -
58 Central Valley Project Reserve 329,000 - - - - - - - - - -
59 Underground Loan Reserve 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147
60 Public Benefits Reserves 2,064,000 2,574,000 1,839,000 681,330 681,330 - - - - - -
61 Electric Special Projects Reserve 51,838,000 51,837,855 51,837,855 51,837,855 41,837,855 41,837,855 41,837,855 41,837,855 41,837,855 46,837,855 51,837,855
62 Hydro Stabilization Reserve - 17,000,000 11,400,000 11,400,000 11,400,000 7,400,000 7,400,000 7,400,000 11,400,000 11,400,000 11,400,000
58 Capital Reserve - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964
59 Rate Stabilization Reserve 70,049,000 14,410,840 9,010,840 9,010,840 9,010,840 - - - - - -
60 Operations Reserve - 22,497,607 21,850,187 29,912,981 19,806,460 30,932,608 30,073,923 31,259,973 32,472,062 36,629,491 40,600,991
61 Unassigned - - - - - - - - - - -
62 TOTAL ENDING RESERVES 129,178,000 112,152,357 100,444,086 107,424,072 102,046,595 85,313,921 84,455,237 85,641,287 90,853,375 100,010,805 108,982,305
6053706
1 FISCAL YEAR FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
2
3 REVENUES
4 Net Sales 85%87%87%81%80%82%83%83%83%85%85%
5 Other Revenues and Transfers In 15%13%13%19%20%18%17%17%17%15%15%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 52%55%54%42%50%52%52%48%47%47%46%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%3%4%3%4%4%4%4%4%4%4%
13 Rent 3%3%4%4%3%3%3%3%3%3%3%
14 Debt Service 7%6%7%6%5%5%5%5%5%5%5%
15 Transfers and Other Adjustments 9%8%9%9%8%8%8%7%8%8%8%
16 Subtotal, Administration 22%20%23%21%20%21%20%19%20%20%20%
17 Resource Management 3%2%2%1%1%2%2%1%2%2%2%
18 Operations and Mtc 7%8%8%8%7%9%9%9%9%9%10%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 2%1%1%2%1%2%2%2%2%2%2%
21 Allowance for Unspent Budget 0%0%0%0%0%-2%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 34%31%35%34%30%33%32%32%33%33%34%
23 Capital Program Contribution 10%10%7%8%11%9%9%12%10%11%11%
24 TOTAL EXPENSES 97%96%96%83%91%93%93%92%90%91%91%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
28 1. Load Net Revenue 77,428 652,853 1,208,477
29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 3,397,119
30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 539,073
31 4. Carbon Neutral Cost 331,630 303,022 114,983
32 5. Market Price 909,196 775,584 1,138,589
33 6. Local Capacity 475,962 408,388 446,695
34 7. Transmission/CAISO 4,555,915 3,741,647 2,806,120
35 8. Plant Outage 1,000,000 1,000,000 1,000,000
36 9. Western Cost 3,130,000 2,704,738 2,973,619
37 10. Regulatory & Legal - - -
38 11. Supplier Default - - -
39 TOTAL 20,170,708 19,380,490 13,624,674
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 196% 172% 303%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
44 Distribution Revenue Variance 3,244,706 3,260,213 3,182,718 3,742,109 3,915,276 4,447,787 4,654,039 4,870,078 5,193,448 5,383,251
45 10% CIP Program Contingency 1,400,592 933,137 1,155,831 1,880,347 1,415,624 1,540,912 2,014,821 1,791,531 1,917,175 1,926,820
46 Total Risk Asssessment Value 4,645,297 4,193,350 4,338,548 5,622,455 5,330,899 5,988,699 6,668,861 6,661,609 7,110,623 7,310,071
47 Projected Operations Reserve 22,497,607 21,850,187 29,912,981 19,806,460 30,932,608 30,073,923 31,259,973 32,472,062 36,629,491 40,600,991
48 Operations Reserve, % of Risk Value 484% 521% 689% 352% 580% 502% 469% 487% 515% 555%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- 15,208,552 14,498,215 15,472,236 17,841,143 17,140,924 17,988,389 17,986,039 18,570,934 18,652,144 18,676,588
46 Target (90 days of non-capital expenses)- 22,812,829 21,747,322 23,208,354 26,761,715 25,711,387 26,982,583 26,979,059 27,856,401 27,978,216 28,014,881
47 Max (120 days of non-capital expenses)- 30,417,105 28,996,429 30,944,472 35,682,287 34,281,849 35,976,777 35,972,078 37,141,869 37,304,288 37,353,175
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- 8,339,587 8,513,675 9,755,012 8,008,309 8,273,280 8,594,405 8,974,024 9,229,751 9,452,090 9,690,848
51 Target (90 days of non-capital expenses)- 10,338,923 10,708,963 11,918,803 10,309,464 10,664,077 11,101,838 11,626,400 11,964,099 12,250,561 12,560,474
52 Max (120 days of non-capital expenses)- 12,338,259 12,904,252 14,082,593 12,610,618 13,054,873 13,609,271 14,278,777 14,698,448 15,049,033 15,430,101
53 Risk Assessment Value 4,645,297 4,193,350 4,338,548 5,622,455 5,330,899 5,988,699 6,668,861 6,661,609 7,110,623 7,310,071
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1193% 1315% 1326% 1391% 1591% 1631% 1708% 1729% 1800% 1645% 1732%
57 Available Reserves (5x Debt Service)*14.0 12.1 10.9 11.7 9.5 9.7 9.6 9.7 10.3 10.4 11.8
58 *For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants.
ELECTRIC UTILITY FINANCIAL PLAN
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APPENDIX B: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c) For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f) For operating contingencies, as described in Section 12 (Operations Reserves)
g) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserves for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c) As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d) To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
ELECTRIC UTILITY FINANCIAL PLAN
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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.
ELECTRIC UTILITY FINANCIAL PLAN
J u n e 2 0 1 8 47 | 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 48 | 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.
ELECTRIC UTILITY FINANCIAL PLAN
J u n e 2 0 1 8 49 | P a g e
APPENDIX C: DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL ACTIVITIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Electric Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process.
It does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
• monitoring the substations and performing routine maintenance;
• performing preventative maintenance on the system;
• monitoring the system’s status from the UCC using SCADA;
• maintaining the SCADA system;
• investigating outages and other customer complaints and performing emergency
repairs;
• clearing vegetation near overhead power lines; and
• testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX D: SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
Attachment C
* NOT YET APPROVED *
6055196 1
Resolution No. _________
Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Residential Master-Metered and Small Non-Residential
Electric Service), E-2-G (Residential Master-Metered and Small Non-
Residential Green Power Electric Service), E-4 (Medium Non-
Residential Electric Service), E-4-G (Medium Non-Residential Green
Power Electric Service), E-4 TOU (Medium Non-Residential Time of
Use Electric Service), E 7 (Large Non-Residential Electric Service), E-7-
G (Large Non-Residential Green Power Electric Service), E-7 TOU
(Large Non-Residential Time of Use Electric Service), E-14 (Street
Lights), E-NSE (Net Metering Net Surplus Electricity Compensation),
and E-EEC (Export Electricity Compensation).
R E C I T A L S
A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2019.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2 (Residential Master-Metered and Small Non-Residential Electric Service) is
hereby amended to read as attached and incorporated. Utility Rate Schedule E-2, as amended,
shall become effective July 1, 2019.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule
E-2-G, as amended, shall become effective July 1, 2019.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2019.
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Non-Residential Green Power Electric Service) is hereby
Attachment C
* NOT YET APPROVED *
6055196 2
amended to read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall
become effective July 1, 2019.
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Non-Residential Time of Use Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended,
shall become effective July 1, 2019.
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective
July 1, 2019.
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become
effective July 1, 2019.
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Non-Residential Time of Use Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become
effective July 1, 2019.
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated.
Utility Rate Schedule E-14, as amended, shall become effective July 1, 2019.
SECTION 11. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-NSE (Net Metering Net Surplus Electricity Compensation) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-NSE, as amended, shall become
effective July 1, 2019.
SECTION 12. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-EEC (Export Electricity Compensation) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-EEC, as amended, shall become effective July 1, 2019.
SECTION 13. The Council makes the following findings:
a. The revenue derived from the adoption of this resolution shall be used only for the
purpose set forth in Article VII, Section 2, of the Charter of the City of Palo Alto.
b. The fees and charges adopted by this resolution are charges imposed for a specific
government service or product provided directly to the payor that are not provided
Attachment C
* NOT YET APPROVED *
6055196 3
to those not charged, and do not exceed the reasonable costs to the City of
providing the service or product.
c. The adoption of this resolution changing electric rates to meet operating expenses,
purchase supplies and materials, meet financial reserve needs and obtain funds for
capital improvements necessary to maintain service is not subject to the California
Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec.
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After
reviewing the staff report and all attachments presented to Council, the Council
incorporates these documents herein and finds that sufficient evidence has been
presented setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-1-1 Sheet No E-1-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This schedule applies to separately metered single-family residential dwellings receiving Electric
Service from the City of Palo Alto Utilities.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Tier 1 usage $0.0833907214
$0.0497105240 $0.0044700417 $0.1375712871
Tier 2 usage
Any usage over Tier 1
0.1156911347
0.0735107515
0.0044700417
0.1936719279
Minimum Bill ($/day)
0.32833040
D. SPECIAL NOTES: 1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Calculation of Usage Tiers Tier 1 Electricity usage shall be calculated and billed based upon a level of 11 kWh per day, prorated by Meter reading days of Service. As an example, for a 30-day bill, the Tier 1 level would be 330 kWh. For further discussion of bill calculation and proration,
refer to Rule and Regulation 11.
{End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-1 Sheet No E-2-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This schedule applies to the following Customers receiving Electric Service from the City of Palo Alto Utilities:
1. Small non-residential Customers receiving Non-Demand Metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period
$0.1185511205 $0.0855108468 $0.0044700417 $0.2085320090
Winter Period 0.0850207678 0.0567505766 0.0044700417 0.1462413861
Minimum Bill ($/day) 0.83597740 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C. 2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-2 Sheet No E-2-2
dated 7-1-2018 Effective 7-1-2019
seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option. The billing Demand to be used in computing charges under this schedule will be the actual maximum Demand in kilowatts for the current month. An exception is that the
billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays. {End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No E-2-G-1 Sheet No E-2-G-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities under the Palo Alto Green Program:
1. Small non-residential Customers receiving Non-Demand Metered Electric Service; and 2. Customers with Accounts at Master-Metered multi-family facilities.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Palo Alto
Green
Charge Total
Summer Period
$0.11855112
05
$0.08551084
68
$0.004470
0417 $0.0020
$0.210532
0290
Winter Period
0.0850207678
0.0567505766
0.0044700417 0.0020
$0.1482414061
Minimum Bill ($/day)
0.83597740
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$0.11855112
05
$0.08551084
68
$0.004470
0417
$0.208532
0090
Winter Period
0.0850207678
0.0567505766
0.0044700417
0.1462413861
Minimum Bill ($/day)
0.83597740
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No E-2-G-2 Sheet No E-2-G-2
dated 7-1-2018 Effective 7-1-2019
Palo Alto Green Charge (per 1000 kWh block) $2.00
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewable
sources, and create a transparent and sustainable market that encourages new
development of wind and solar power. Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No E-2-G-3 Sheet No E-2-G-3
dated 7-1-2018 Effective 7-1-2019
4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer-s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option. The billing Demand to be used in computing charges under this schedule will be the
actual maximum Demand in kilowatts for the current month. An exception is that the
billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on weekdays.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-1 Sheet No E-4-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This schedule applies to Demand metered Secondary Electric Service for Customers with a
maximum Demand below 1,000 kilowatts. This schedule applies to three-phase Electric
Service and may include Service to master-metered multi-family facilities or other facilities
requiring Demand-metered Service, as determined by the City.
B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $4.412.98 $24.5021.13 $28.9124.11
Energy Charge (per kWh)
0.1053609893 0.0186501771 0.0044700417 0.1284812081
Winter Period
Demand Charge (per kW) $2.751.87 $16.2216.65 $18.9718.52
Energy Charge (per kWh)
0.0763407109 0.0177101865 0.0044700417 0.0994609297
Minimum Bill ($/day) 17.274215.9946 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-2 Sheet No E-4-2
dated 7-1-2018 Effective 7-1-2019
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a Maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed. The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has been below 200 kilowatts for four consecutive
months.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-3 Sheet No E-4-3
dated 7-1-2018 Effective 7-1-2019
When such metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent (0.25%) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any City of Palo Alto full-service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage
profile.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non-
utility generation source.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-4 Sheet No E-4-4
dated 7-1-2018 Effective 7-1-2019
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No E-4-G-1 Sheet No E-4-G-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This schedule applies to Demand metered Secondary Electric Service for Customers with a
maximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green
Program. This schedule applies to three-phase Electric Service and may include Service to
Master-metered multi-family facilities or other facilities requiring Demand metered Service, as determined by the City.
B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge (per kW) $4.412.98 $24.5021.13
$28.9124.11
Energy Charge (per kWh)
0.1053609893
0..0186501771
0.0044700417 0.0020
0.1304812281
Winter Period
Demand Charge (per kW) $2.751.87 $16.2216.65
$18.9718.52
Energy Charge (per kWh)
0.0763407109
0.0186501771
0.0044700417 0.0020
0.1014609497
Minimum Bill ($/day) 17.274215.9946
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No E-4-G-2 Sheet No E-4-G-2
dated 7-1-2018 Effective 7-1-2019
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $4.412.98 $24.5021.13 $28.9124.11
Energy Charge (per kWh) 0.1053609893 0.0186501771 0.0044700417
0. .1284812081
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $2.751.87 $16.2216.65 $18.9718.52
Energy Charge (per kWh) 0.0763407109 0.0186501771 0.0044700417 0..0994609497
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 17.274215.9946 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No E-4-G-3 Sheet No E-4-G-3
dated 7-1-2018 Effective 7-1-2019
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the
option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter, which does not reset after a definite time interval, may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand.
5. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full-service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No E-4-G-4 Sheet No E-4-G-4
dated 7-1-2018 Effective 7-1-2019
6. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change the system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-utility generation source.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Supersedes Sheet No E-4-G-5 Sheet No E-4-G-5
dated 7-1-2018 Effective 7-1-2019
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-1 Sheet No E-4-TOU-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This voluntary rate schedule applies to Demand metered Secondary Electric Service for
Customers with Demand between 500 and 1,000 kilowatts per month and who have sustained
this level of usage for at least three consecutive months during the most recent 12 month period.
This schedule applies to three-phase Electric Service and may include Service to Master-Metered multi-family facilities or other facilities requiring Demand-metered Service, as
determined by the City. In addition, this rate schedule is applicable for Customers who did not
pay power factor adjustments during the last 12 months. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $2.611.76 $8.447.28 $11.059.04
Mid-Peak 0.9564 8.447.28 9.397.92
Off-Peak 0.9564 8.447.28 9.397.92
Energy Charge (per kWh)
Peak $0.0964209248 $0.0186401771 $0.0044700417 $0.1195411436
Mid-Peak 0..1214211645 0.0186401771 0.0044700417 0.1445313833
Off-Peak 0.0745107146 0.0186401771 0.0044700417 0.0976309334
Winter Period
Demand Charge (per kW)
Peak $1.531.04 $9.049.28 $10.5710.32
Off-Peak 1.531.04 9.049.28 10.5710.32
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-2 Sheet No E-4-TOU-2
dated 7-1-2018 Effective 7-1-2019
Commodity Distribution Public Benefits Total
Energy Charge (per kWh)
Peak $0.1178108187 $0.0186401771 $0.0044700417 $0.1409210375
Off-Peak 0.1011307028 0.0186401771 $0.0044700417 0.1242509216
Minimum Bill ($/day) 17.274215.9946 D. SPECIAL NOTES: 1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C. 2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays) All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-3 Sheet No E-4-TOU-3
dated 7-1-2018 Effective 7-1-2019
SEASONAL RATE CHANGES: When the billing period includes use in both the
Summer and the Winter periods, the usage will be prorated based on the number of days
in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it
may be removed. The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time periods as defined under Section D.2.
4. Power Factor Adjustment
Time of Use Customers must not have had a power factor adjustment assessed on their Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month, and must not have fallen
below 95% to avoid the power factor adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be subject to power factor adjustments, the Customer will be removed from the E-4-TOU
rate schedule and placed on another applicable rate schedule as is suitable to their
kilowatt Demand and kilowatt-hour usage.
5. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 months, the
Customer may request a rate schedule change to any applicable City of Palo Alto full-
service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 6. Primary Voltage Discount
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-4 Sheet No E-4-TOU-4
dated 7-1-2018 Effective 7-1-2019
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more
of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the
Maximum Generation of those non-utility generators, but in no event shall the
Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-5 Sheet No E-4-TOU-5
dated 7-1-2018 Effective 7-1-2019
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-1 Sheet No E-7-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This schedule applies to Demand Metered Service for large non-residential Customers with a
Maximum Demand of at least 1,000KW per month per site, who have sustained this Demand
level at least 3 consecutive months during the last twelve months. B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (kW) $5.033.14 $25.6623.63 $30.6926.77
Energy Charge (kWh) 0.1093210037 0.00053 0.0044700417 0.1143210507
Winter Period
Demand Charge (kW) $2.891.84 $14.1615.17 $17.0517.01
Energy Charge (kWh) 0.072386979 0.00053 0.0044700417 0.0773807449
Minimum Bill ($/day) 49.113945.4758 D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-2 Sheet No E-7-2
dated 7-1-2018 Effective 7-1-2019
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one
Account or one Meter if the Accounts are on one site. A site shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and have a common billing address.
4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of
the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the
City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-3 Sheet No E-7-3
dated 7-1-2018 Effective 7-1-2019
5. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option to install applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has been below 200 kilowatts for four consecutive months. When such metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The power factor adjustment is applied
by increasing the total energy and Demand charges for any month by 0.25 percent (0.25%) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kVA size limitation.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-4 Sheet No E-7-4
dated 7-1-2018 Effective 7-1-2019
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.4) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4) , as amended.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-5 Sheet No E-7-5
dated 7-1-2018 Effective 7-1-2019
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-1 Sheet No E-7-G-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This schedule applies to Demand metered Service for large non-residential Customers who
choose Service under the Palo Alto Green Program. A Customer may qualify for this rate
schedule if the Customer’s Maximum Demand is at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge ( per kW) $5.033.14 $25.6623.63 $30.6926.77
Energy Charge (per kWh) 0.1093210037 0.00053 0.0044700417 0.0020 0.1163210707
Winter Period
Demand Charge (per kW) $2.891.84 $14.1615.17 $17.0517.01
Energy Charge (per kWh) 0..0723806979 0.00053 0.0044700417 0.0020 0.0793807649
Minimum Bill ($/day) 49.113945.4758
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-2 Sheet No E-7-G-2
dated 7-1-2018 Effective 7-1-2019
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $5.033.14 $25.6623.63 $30.6926.77
Energy Charge (per kWh) 0.1093210037 0.00053 0.0044700417 0.1143210507
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $2.891.84 $14.1515.167 $17.0517.01
Energy Charge (per kWh) 0.0723806979 0.00053 0.0044700417 0.0773807449
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 49.113945.4758 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C. 2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-3 Sheet No E-7-G-3
dated 7-1-2018 Effective 7-1-2019
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Request for Service Qualifying Customers may request Service under this schedule for more than one
Account or one Meter if the Accounts are at one site. A site shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and have a common billing address. 5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to the computation of any primary voltage discount. The power factor adjustment is applied
by increasing the total energy and Demand charges for any month by 0.25 percent or
(1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load
was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-4 Sheet No E-7-G-4
dated 7-1-2018 Effective 7-1-2019
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile 7. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new
development of wind and solar. Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program. 8. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a qualified line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's Electrical requirements, as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change the system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
9. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e), applies to Customers that have a non-utility generation source
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-5 Sheet No E-7-G-5
dated 7-1-2018 Effective 7-1-2019
interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-1 Sheet No E-7-TOU-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This voluntary rate schedule applies to Demand Metered Service for non-residential Customers
with a Maximum Demand of at least 1,000KW per month per site, who have sustained this
Demand level at least 3 consecutive months during the last twelve months. In addition, this rate schedule is applicable for Customers who did not pay power factor adjustments during the last
12 months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $3.111.92 $8.627.94 $11.739.86
Mid-Peak 0.9762 8.627.94 8.569.60
Off-Peak 0.9762 8.627.94 8.569.60
Energy Charge (per kWh)
Peak $0.1135610149 $0.00053 $0.0044700417 $0.1185610619
Mid-Peak 0.1429912779 0.00053 0.0044700417 0.1479913249
Off-Peak 0.0877607842 0.00053 0.0044700417 0.0927608312
Winter Period
Demand Charge (per kW)
Peak $0.931.47 $7.687.17 $8.618.63
Off-Peak 0.931.47 7.687.17 8.618.63
Energy Charge (per kWh)
Peak $0.0761907150 $0.00053 $0.0044700417 $0.0811907620
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-2 Sheet No E-7-TOU-2
dated 7-1-2018 Effective 7-1-2019
Off-Peak 0.0654006138 0.00053 0.0044700417 0.0704006608
Minimum Bill ($/day) 49.113945.4758 D. SPECIAL NOTES:
1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving
Day, and Christmas Day. The dates will be those on which the holidays are legally observed.
SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-3 Sheet No E-7-TOU-3
dated 7-1-2018 Effective 7-1-2019
period, and the charges based on the applicable rates therein. For further discussion of bill
calculation and proration, refer to Rule and Regulation 11.
3. Request for Service Qualifying Customers may request Service under this schedule for more than one Account or one Meter if the Accounts are on one site. A site shall be defined as one or more utility Accounts
serving contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and
have a common billing address. 4. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Demand Meter will be installed as promptly as is practicable and thereafter continued
in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve
consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time periods as defined under Section D.2. 5. Power Factor Adjustment
Time of Use Customers must not have had a power factor adjustment assessed on their Service
for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt-ampere hours consumed during the month, and must not have fallen below 95% to avoid the power factor adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be
subject to power factor adjustments, the Customer will be removed from the E-7-TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage.
6. Changing Rate Schedules Customers electing to be served under E-7 TOU must remain on said schedule for a minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a rate schedule change to any applicable City of Palo Alto full-service rate schedule as is suitable
to their kilowatt Demand and kilowatt-hour usage.
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-4 Sheet No E-7-TOU-4
dated 7-1-2018 Effective 7-1-2019
7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered,
but the City is not required to supply Service at a particular line voltage where it has, or will
install, ample facilities for supplying at another voltage equally or better suited to the Customer's
electrical requirements, as determined in the City’s sole discretion. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change his system so
as to receive Service at the new line voltage or to accept Service (without voltage discount)
through transformers to be supplied by the City subject to a maximum kilovolt-ampere size
limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue Meter are not
operating, the Maximum Demand will be reduced by the sum of the Maximum
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-5 Sheet No E-7-TOU-5
dated 7-1-2018 Effective 7-1-2019
Generation of those non-utility generators, but in no event shall the Customer’s
Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section
2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-14-1 Sheet No. E-14-1
dated 7-1-2018 Effective 7-1-2019
A. APPLICABILITY: This schedule applies to all street and highway lighting installations.
B. TERRITORY: Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City.
C. RATES:
Per Lamp Per Month Class A: Utility supplies energy
and switching service only.
Lamp Rating: High Pressure Sodium Vapor Lamps
100 watts 8.285.91
200 watts 15.2910.91
250 watts 18.7913.41
310 watts 23.2516.59 400 watts 29.9421.36
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-14-2 Sheet No. E-14-2
dated 7-1-2018 Effective 7-1-2019
Per Lamp Per Month – Class C: Utility supplies energy
and switching service and
maintains entire system, including lamps and glassware.
Lamp Rating:
Mercury-Vapor Lamps
400 watts 32.5834.12
High Pressure Sodium Vapor Lamps
70 watts 25.7231.40
100 watts 27.8232.90
150 watts 33.3235.40 250 watts 38.3340.40
Light Emitting Diode (LED) Lamps
70 watts-equivalent 21.0728.08
100 watts-equivalent 22.6629.22 150 watts-equivalent 24.1330.26
250 watts 28.1433.12
D. SPECIAL CONDITIONS:
1. Type of Service: This schedule is applicable to series circuit and multiple street lighting
systems to which the Utility will deliver current at secondary voltage. Unless otherwise
agreed, multiple current will be delivered at 120/240 volts, three-wire, single-phase. In certain localities the Utility may supply service from 120/208 volt star-connected poly-phase
lines in place of 240-volt service. Single phase service from 480-volt sources will be
available in certain areas at the option of the Utility when this type of service is practical
from the Utility's engineering standpoint. All currents and voltages stated herein are
nominal, reasonable variations being permitted. New lights will normally be supplied as multiple systems.
2. Point of Delivery: Delivery will be made to the customer's system at a point or at points
mutually agreed upon. The Utility will furnish the service connection to one point for each
group of lamps, provided the customer has arranged his system for the least practicable number of points of delivery. All underground connections will be made by the customer or
at the customer's expense.
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-14-3 Sheet No. E-14-3
dated 7-1-2018 Effective 7-1-2019
3. Switching: Switching will be performed by the Utility (on the Utility's side of points of
delivery) and no charge will be made for switching provided there are at least 10 kilowatts of
lamp load on each circuit separately switched, including all lamps on the circuit whether served under this schedule or not; otherwise, an extra charge of $2.50 per month will be made for each circuit separately switched unless such switching installation is made for the
Utility's convenience or the customer furnishes the switching facilities and, if installed on the
Utility's equipment, reimburses the Utility for installing and maintaining them.
4. Annual Burning Schedule: The above rates apply to lamps which will be turned on and off
once each night in accordance with a regular burning schedule agreeable to the customer but
not exceeding 4,100 hours per year. 5. Maintenance: The rates under Class C include all labor necessary for replacement of
glassware and for inspection and cleaning of the same. Maintenance of glassware by the Utility is limited to standard glassware such as is commonly used and manufactured in
reasonably large quantities. A suitable charge will be made for maintenance of glassware of a
type entailing unusual expense. Under Class C, the rates include maintenance of circuits
between lamp posts and of circuits and equipment in and on the posts, provided these are all
of good standard construction; otherwise, the Utility may decline to grant Class C rates. Class C rates applied to any agency other than the City of Palo Alto also include painting of
posts with one coat of good ordinary paint as required to maintain good appearance but do
not include replacement of posts broken by traffic accidents or otherwise.
10. . System Owned In-Part by Utility : Where, at customer's request, the Utility installs, owns, and maintains any portion of the lighting fixtures, supports, and/or interconnecting circuits,
an extra monthly charge of one and one-fourth percent of the Utility's estimate of additional
investment shall be made.
11. Rates For Lamps Not on Schedule: In the event a customer installs a lamp which is not presently represented on this schedule, the Utility will prepare an interim rate reflecting the
Utility's estimated costs associated with the specific lamp size. This interim rate will serve as
the effective rate for billing purposes until the new lamp rating is added to Schedule E-14.
{End}
EXPORT ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-EEC-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-EEC-1 Sheet No.E-EEC-1
dated 7-1-2016 Effective 7-1-2019
A. APPLICABILITY: This schedule applies in conjunction with the otherwise applicable rate schedules for each customer class. This schedule may not apply in conjunction with any time-of-use rate schedule. This schedule applies to Customer-Generators as defined in Rule and Regulation 2 who are either not eligible for Net Energy Metering or who are eligible for Net Energy metering but elect to take service under this rate schedule. B. TERRITORY: Applies to locations within the service area of the City of Palo Alto. C. RATE: The following buyback rate shall apply to all energy exported to the grid. Per kWh Export electricity compensation rate $0.100907485 D. SPECIAL CONDITIONS 1. Metering equipment: Electricity delivered by CPAU to the Customer-Generator or received by CPAU from the Customer-Generator shall be measured using a meter capable of registering the flow of electricity in two directions (aka “bidirectional meter”). The electrical power measurements will be used for billing the Customer-Generator. CPAU shall furnish, install and own the appropriate meter. 2. Billing: a. CPAU shall measure during the billing period, in kilowatt-hours, the energy delivered and received after the Customer-Generator serves its own instantaneous load. b. CPAU shall bill the Customer-Generator consumption charges for the energy delivered by CPAU to the Customer-Generator based on the Customer-Generator’s applicable rate schedule. c. In the event the energy generated exceeds the energy consumed and therefore is received by CPAU, the Customer will receive a credit for all energy received by CPAU at the buyback rate designated in section C above. 3. Generation facilities shall adhere to Rule and Regulation 27: Generating Facility Interconnections.
{End}
NET METERING NET SURPLUS ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-NSE-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-NSE-1 Sheet No.E-NSE-1
dated 1-1-2011707-01-2016 Effective 7-1-2019
A. APPLICABILITY: This schedule applies to eligible residential and small commercial Net Energy Metering Customers who, at the end of an annual settlement period, as described in Rule 29, are Net Surplus Customer-Generators of electricity who elect to receive monetary compensation as such preference is indicated on the net surplus electricity election form. This schedule only applies to Customers who participate in Net Energy Metering, and does not apply to Customers that take service under the City’s Net Energy Metering Successor Rate, as each of these terms are defined in Rule and Regulation 2. B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides electric service. C. RATES: Per kWh Net Surplus Electricity Compensation rate $0.08771721 D. SPECIAL CONDITIONS 1. Net Surplus Electricity Compensation Rate eligibility shall be determined as specified in Rule 29. Net surplus electricity, as specified in Rule 29, if applicable, will be multiplied by the above compensation rate to determine the Customer’s annual net surplus electricity compensation stated in dollars. 2. Additional terms, conditions and definitions govern Net Energy Metering Service and Interconnection, as described in Rule 29.
{End}
City of Palo Alto (ID # 10255)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/15/2019
City of Palo Alto Page 1
Council Priority: Fiscal Sustainability
Summary Title: FY 2020 Gas Financial Plan and Rates
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt: 1) a Resolution Approving the Fiscal Year 2020 Gas Utility Financial
Plan; and 2) a Resolution Increasing Gas Rates by Amending Rate Schedules
G-1 (Residential Gas Service), G-2 (Residential Master-Metered and
Commercial Gas Service), G-3 (Large Commercial Gas Service), and G-10
(Compressed Natural Gas Service)
From: City Manager
Lead Department: Utilities
RECOMMENDATION
Staff requests that the Finance Committee recommend that the City Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2020 Gas Utility
Financial Plan (Attachment B) and reserve transfers; and
2. Adopt a resolution (Attachment C) increasing gas rates by amending Rate Schedules G-1
(Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas
Service), G-3 (Large Commercial Gas Service), and G-10 (Compressed Natural Gas
Service) (Attachment D).
EXECUTIVE SUMMARY
The FY 2020 Gas Utility Financial Plan includes projections of the utility’s costs and revenues for
FY 2020 through FY 2024. Gas utility costs are made up of supply-related costs (35 percent of
costs) and distribution-related costs (65 percent of costs). Supply-related costs (and customer
rates) vary monthly with the gas markets, but customer rates for gas distribution are evaluated
annually and set by Council action like other utility rates. Gas rates related to distribution costs
were last increased by 6 percent on July 1, 2018. The proposed FY 2020 Gas Utility Financial
Plan includes an 8 percent increase in distribution rates on July 1, 2019. Because distribution
accounts for only 65 percent of the average customer’s bill, this is projected to increase system
rate revenues (and billings) by approximately 5 percent overall. Further distribution increases of
City of Palo Alto Page 2
5 percent to 12 percent are projected over the following four years (with a 4 percent to 8
percent increase in overall gas rates).
In addition, the plan proposes transfers to the Operations Reserve of $6.3 million from the Rate
Stabilization Reserve, and up to $6 million to the CIP Reserve from the Operations Reserve, to
ensure that there are appropriate financial reserves for contingencies. The Rate Stabilization
Reserve is projected to be at zero balance by the end of FY 2020.
In their analysis and development of the 2019 Natural Gas Cost of Service and Rates Study, staff
and the consultants have identified a realignment in cost allocations required for the gas
customer rate classes. While the distribution rate increase across all customer classes is
proposed to be 8 percent, the residential (G1) class will see a larger increase of 13.25 percent,
while the commercial classes (G2 and G3) will see between a 2.87 and 5.07 percent increase,
respectively, as detailed below. These correspond to an overall rate increase (including supply)
of8.1 percent for residential and of 3.0 and 1.5 percent for the two commercial classes These
cost shifts between customer classes are a result of increased fixed costs, declining customer
usage and shifts to how customers use the gas system.
Figure 1 below shows the primary drivers for the proposed rate change: first, Capital
Improvement (CIP) cost are increasing, followed by increases in Operations expenses, and
finally, a portion of the increase can also be attributed to an anticipated decrease in usage,
which is consistent with long term trends. These increases will be discussed in greater depth
below:
Figure 1: Allocation of Distribution Rate increase
Supply-related costs (the cost of the natural gas itself, gas transmission, and gas environmental
charges) are the most volatile component of the Gas Utility’s expenses, and recent gas market
spikes and proposed transmission rate hikes have led staff to project supply cost increases of
around 4 percent annually for the forecast horizon. Market prices, however, are monitored
from month to month and automatically incorporated into monthly supply rate adjustments.
City of Palo Alto Page 3
Therefore, it is not possible to exactly predict what supply rates will be during the planning
horizon. However, if staff’s forecast held, it would result in a 1 percent to 2 percent increase to
customer bills. Where overall rate increases (supply plus distribution) are referenced in this
report, the figures do not attempt to predict or include any supply rate increase that will occur
as a result of the monthly supply rate adjustments.
BACKGROUND
Every year staff presents the Utilities Advisory Commission and Finance Committee with
Financial Plans for its Electric, Water, Gas, and Wastewater Collection Utilities and recommends
any rate adjustments required to maintain their financial health. These Financial Plans include a
comprehensive overview of the utility’s operations, both retrospective and prospective, and are
intended to be a reference for UAC and Council members as they review the budget and staff’s
rate recommendations. Each Financial Plan also contains a set of Reserves Management
Practices describing the reserves for each utility and the management practices for those
reserves.
The City’s gas is purchased from a variety of marketers who source gas from throughout the
Western United States. The City then pays Pacific Gas and Electric (PG&E) to transmit that gas
across its gas transmission system to Palo Alto, and the gas is then delivered to customers
through the system of gas mains and services that make up the City’s gas distribution system.
The Gas Utility’s costs can be divided into two main categories: gas supply costs (which includes
the cost of the gas itself, the cost of transmitting the gas to Palo Alto, and environmental costs1)
and the costs of running the business and operating the distribution system. As noted above,
gas supply costs vary with the market, and the costs are passed through to customers through a
gas supply rate component that varies monthly.
The UAC reviewed preliminary financial forecasts at its February 6, 2019 meeting and final
forecasts at its May 1, 2019 meeting. The Finance Committee reviewed preliminary gas
forecasts at its April 2, 2019 meeting. At that meeting, a Committee member requested an
overview of the gas hedging program and that it is available in Attachment E.
1 This is primarily the cost of complying with the State’s Cap and Trade system and procuring offsets under the
City’s Carbon Neutral Gas program.
City of Palo Alto Page 4
DISCUSSION
Staff’s annual assessment of the financial position of the City’s gas utility is completed to ensure
adequate revenue to fund operations and to document that the City’s rates do not exceed the
level permitted under California Constitution (Proposition 26). The assessment includes making
long-term projections of market conditions, of costs associated with the physical condition of
infrastructure, and of other factors that could affect utility costs. Rates are then proposed that
will be adequate to recover projected costs.
Proposed Actions for FY 2020
The FY 2020 Gas Utility Financial Plan includes the following proposed actions:
1. Amend gas rate schedules (see Attachment D) to increase distribution rates by
approximately 8 percent (a 5 percent increase on overall rates).
2. Transfer up to $6.3 million from the Rate Stabilization Reserve (RSR) to the Operations
Reserve, and up to $6 million from the Operations Reserve to the CIP Reserve.
The reserve transfers will enable staff to both maintain sufficient funds in the Gas Operations
Reserve while providing funds for CIP projects which will be occurring every other year, as
discussed below. These proposed actions are described in more detail in the FY 2020 Gas
Financial Plan (Attachment B).
Proposed Gas Rates and Cost of Service Update
The Gas Utility’s rates are evaluated and implemented in compliance with cost of service
requirements. The Gas Utility’s proposed rates are based on the methodology from the draft
April 2019 Natural Gas Cost of Service and Rates Study, the final version to be presented to
Council in June. The methodology used was similar to the prior study performed in April 2012
by Utility Financial Solutions2, utilizing the average and excess method for allocating costs, and
updated to reflect current infrastructure asset values, annual utility costs, and some changes in
consumption patterns between customer classes seen in the post drought era. Because the
majority of gas costs are fixed, the consultant recommended (and staff accepted) shifting a
share of costs currently included in the volumetric (per therm) rate over to the base (per
account per month) rates. This increase in base rates by 22 percent (for G1), 26.6 percent (for
G2) and 72.6 percent (for G3), while creating savings in the volumetric rates. The study was
performed in conformance with the scope previously discussed with the Utilities Advisory
Commission in October 2016, and the Council in November 20163.
The COSA estimates a net distribution revenue requirement of $24,098,000 for FY 2020. It
further estimates that the existing rates would generate $22,313,072 in distribution revenues
for FY 2020. An 8 percent increase in distribution rates is necessary to recover this deficiency.
2 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
3 Staff Report 7416 11/14/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54576
City of Palo Alto Page 5
Figure 2: Cost of Service Summary
Figure 2 above outlines how these revenue requirements and distribution charges are allocated
amongst the three gas customer classes.
The updated COSA allocates $10,111,795 of the net distribution revenue requirement to the
Residential (G1) customer class. This is 42 percent of the total net distribution revenue
requirement; a similar percentage to that found in the 2012 COSA. Under the current rate
structure, however, G1 customers would provide only about 40 percent of overall distribution
rate revenue. This is because energy consumption per G1 customer has decreased by roughly
10 percent since the 2012 COSA, while fixed costs allocated to the customer class have not
decreased at the same rate. Resetting G1 distribution revenues to comprise 42 percent of
system-wide distribution revenues requires that G1 distribution revenues be increased by 13.25
percent.
For Small Commercial (G2) customers, per customer usage has also decreased by roughly 10
percent, but because of the higher usage of G2 customers their fixed costs are a smaller share
of total costs, and the increase in the per-unit cost for the class is smaller than for the
Residential class. The Large Commercial (G3) group has seen a growth in the relative number of
customers from the prior study, has both the highest use per customer and the highest load
factor, resulting in a lower average cost than the G1 and G2 groups.
The growth in the costs has also had an impact to the cost of service by class. Compared to the
2012 COSA, costs related to Customer Service, Accounts and Sales have increased by about 30
percent, compared with 36 percent for O&M and under 30 percent for other cost components.
An increase in Customer Service related costs shifts more costs to the residential class because
it has a higher number of customers. It also leads to higher customer charges for all three of
the classes.
Staff proposes to adjust gas rates as shown in Table 1 and Table 2 below, effective July 1, 2019.
These changes are projected to increase the system average gas rate (total of supply and
City of Palo Alto Page 6
distribution) by roughly 5 percent and residential rates by 8 percent. These rate changes are
included in the proposed amended rate schedules in Attachment D.
Table 1: Current and Proposed Monthly Service Charges
Rate Schedule
Monthly Service Charge
($/month)
Change
Current (as of
7/1/18)
Proposed for
FY 2020
($) (%)
G-1 (Residential) $10.94 $13.35 $2.41 22.0%
G-2 (Small Commercial) 82.92 104.95 22.03 26.6%
G-3 (Large Commercial) 400.08 690.45 290.37 72.6%
G-10 (CNG) 56.11 70.98 14.87 26.5%
Table 2: Current and Proposed Gas Distribution Charges
Change
Current (as of
7/1/18)
Proposed
for FY 2020
($) (%)
G-1 (Residential)
Tier 1 Rates $0.4239 $0.4835 $0.0596 14.1%
Tier 2 Rates 0.9948 1.0426 0.0478 4.8%
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.6183 0.6102 (0.0081) (1.3%)
G-3 (Large Commercial)
Uniform Rate 0.6098 0.6056 (0.0420) (0.7%)
Bill Impact of Proposed Rate Changes
Table 3 shows the impact of the proposed July 1, 2019 rate changes on various levels of
residential bills. The average increase for the residential class is roughly 8 percent based on last
year’s commodity prices, but some customers may see slightly higher or lower increases due to
slight changes in the composition of the utility’s costs, as well as prevailing market prices in the
months displayed.
City of Palo Alto Page 7
Table 3: Impact of Proposed Gas Rate Changes on Residential Bills
Usage
(Therms/month)
Bill under
Current Rates
Bill under
Proposed Rates
Change
$/mo. %
Winter (Using December 2018 commodity prices)
30 $ 48.38 $ 52.58 $ 4.20 8.7%
54 (median) 78.33 83.96 5.63 7.2%
80 122.19 129.14 6.94 5.7%
150 249.51 259.80 10.29 4.1%
Summer (Using July 2018 commodity prices)
10 $ 20.04 $ 23.05 $ 3.01 15.0%
18 (median) 27.32 30.81 3.48 12.7%
30 43.96 48.04 4.08 9.3%
45 66.17 70.97 4.80 7.2%
Table 4 shows the impact of the proposed July 1, 2019 rate changes on various representative
commercial customer bills.
Table 4: Impact of Proposed Gas Rate Changes on Commercial Bills
(Using December 2018 commodity prices)
Usage
(Therms/month)
Bill under Current
Rates
Bill under
Proposed Rates
Change
%
500 804 822 2.2%
5,000 7,295 7,276 (0.3%)
10,000 14,506 14,447 (0.4%)
50,000 72,092 72,172 0.1%
FY 2020 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table shows the projected rate adjustments over the next five years and their impact on the
annual median residential gas bill.
Table 5: Projected Rate Adjustments, FY 2020 to FY 2024
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Gas Utility 8% 8% 8% 6% 4%
Estimated Bill Impact ($/mo)* $4.38 $3.72 $4.02 $3.25 $2.30
* estimated impact on median residential gas bill, which is currently $42.12 for CY 2018.
One of the main drivers for the increase in the Gas Utility’s short term costs (and therefore
rates) over the next several years are increases in capital improvement costs to maintain a safe
and reliable system. In FY 2014, FY 2015 and FY 2017, costs for the gas utility were unusually
City of Palo Alto Page 8
low as new main replacements were not planned. The gas, water and wastewater utilities
generally try to perform a main replacement annually in each utility, but in the gas utility
beginning new projects was not feasible in those years. In FY 2014 and FY 2015, this was due to
the fact that staff was completing a prior major gas main replacement project, the largest in
utility history, which completed replacement of all ABS gas mains in Palo Alto. Then, FY 2017
included replacements of gas mains on University Avenue, a project that has evolved into the
Upgrade Downtown project involving a coordinated replacement of several different types of
infrastructure to avoid multiple disruptions to the business district. This has been a multi-year
planning effort that did not allow for design of other new projects. This allowed the Gas Utility
to temporarily keep rates lower than they would typically have been needed to be to fund
future operations and capital replacement. These future capital replacement costs will be
higher, as well. As the emphasis on infrastructure improvement has taken hold both regionally
and nationally, contractor bids for new projects have risen greatly from where they were during
the last recession.
This current financial plan works to address these challenges in a way that will allow City of Palo
Alto Utilities (CPAU) to meet its gas main replacement (GMR) needs. The next focus of the
GMR program will be the replacement of all Polyvinyl Chloride (PVC) mains with Polyethylene
(PE) mains. CPAU installed PVC pipes from the early 1970s to mid-1980s. Some of the City’s PVC
pipe is approaching 50 years of service, and according to industry data, PVC pipes have a much
higher leakage rate than PE mains after 20 years of service due to potential disbondment of
fittings and joints. This financial plan includes approximately $11 million every other year for
main replacement construction instead of $6.5 million annually, starting in FY 2021. This shift
to larger main replacement construction projects every other year will slightly lengthen the
amount of time needed to replace all PVC pipes in the system but will attract more contractors
and better pricing to bid on the larger projects. Additionally, this main replacement project
schedule for gas will be staggered with water and wastewater (water and wastewater
construction every even year and gas construction every odd year), which will ease scheduling
difficulties for inspection coverage due to shared inspection staff across water, wastewater,
gas, and large development services projects. This arrangement is likely to be a short-term
solution (3-5 years) until project capacity can be increased and upward pressure on utility rates
has eased.
Because of this staggered CIP approach, and from a budgeting standpoint, there will be a
pattern of revenues being higher than cost one year and lower the next. To avoid a ‘sawtooth’
pattern in reserves because of this, the funds which would otherwise have gone to pay for CIP
expenditures in the even year will be placed in the CIP reserve, to be used in the following year
when the CIP expense occurs. Therefore, staff is requesting a $6 million transfer from the
Operations Reserve to the CIP reserve in FY 2020.
Over the longer term, gas commodity costs are the most variable factor in customer gas bills,
being subject to market forces, and are currently projected to grow by about 4 percent per
year. Increases to Operations costs are projected to be 3 to 4 percent annually, although there
City of Palo Alto Page 9
is a near term increase in cost to pay for phase two of a cross-bore safety verification program.
During trenchless installation, a natural gas pipeline can cross through a segment of lateral via
boring. The project will be to video inspect, determine and repair any unintended conflicts
between natural gas service pipelines and sanitary sewer laterals. Phase two of this program is
estimated to require $1 million per year for the next three years.
Figures 1 below illustrates the projected long run changes in the Gas Utility’s costs. Cost
increases over the FY 2016 to FY 2024 time period are mainly from Commodity costs, followed
by Operations and Capital.
Figure 1: FY 2016, FY 2019 and FY 2024 costs
* Note that FY 2024 Capital Investment cost is displayed as an average of two years’
cost, as FY 2023 has an $11 million main replacement project while FY 2024 does not.
Gas usage was trending downward over the last several years, most likely due to relatively
warm winter heating seasons, as well as lower hot water usage during the drought, but a cooler
winter and the end of drought restrictions has brought increased usage. Gas usage has nearly
recovered to levels seen back in 2013, but as with water, it is difficult to determine whether or
when long run usage will resume the declining trend seen over the last few decades.
Changes from Preliminary Financial Forecast
After presenting the preliminary financial forecast to the UAC on February 6, 2019, staff
updated its CIP plan as described above, based upon both projected system needs and current
staffing capacity. The impact on rates was that the preliminary projection of a 15 percent
City of Palo Alto Page 10
distribution rate increase for FY 2020 (10 percent overall bill impact) was reduced to 8 percent
(5 percent overall bill impact).
Gas Bill Comparison with Surrounding Cities
Table 6 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of July 2018 (to illustrate a summer month bill) and
February 2019 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2018 was $469.94, about 14 percent lower than the annual bill for a
PG&E customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 6: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(February 2019)
30 39.55 46.31 -14.6%
(Median) 54 62,43 83.49 -25.2%
80 100.93 139.13 -27.5%
150 207.64 288.94 -28.1%
Summer
(July 2018)
10 $ 20.04 12.48 63.4%
(Median) 18 27.32 24.56 13.8%
30 43.96 46.26 -3.6%
45 66.17 73.38 -8.3%
Table 7 shows the monthly gas bills for commercial customers for various usage levels for rates
in effect as of February 2019. Bills for CPAU customers at the usage levels shown are around 3
percent lower to 12 percent higher for commercial customers than for PG&E customers. This is
a substantial improvement over the calendar year 2013 bill comparison, when commercial gas
bills for CPAU customers were 27 percent to 44 percent higher than for PG&E customers. This is
primarily attributable to PG&E’s increased distribution rates as the commodity rates for CPAU
and PG&E are very similar, both being based on spot market gas prices.
Table 7: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect February 2018)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 657 681 -3%
5,000 5,823 6,257 -1%
10,000 11,563 11,139 4%
50,000 57,374 51,414 12%
City of Palo Alto Page 11
Commission Review
The UAC reviewed this proposal at its May 1, 2019 meeting. Staff presented the UAC with the
updated proposal showing an 8% distribution increase (a 5% overall impact), a slight reduction
from the initial 9% projection in the preliminary projections. Commissioners commented that
the impacts were larger for smaller users, being as the increases were larger for customer
charges. Staff responded that efforts were ongoing to try and keep costs from rising, but that
the size of the changes, while large on a percentage basis, were not large on a dollar basis.
The UAC recommended and unanimously approved staff’s proposal. The excerpted draft
minutes from the UAC’s May 1, 2019 meeting can be found on the City’s website, located here.
Timeline
If the Finance Committee supports the proposed rate adjustments, the City Council will
consider adopting the Financial Plan and rate amendments as part of the FY 2020 budget
review and adoption process. If Council approves the proposed rate changes, they will become
effective July 1, 2019.
RESOURCE IMPACT
Normal year sales revenues for the Gas Utility are projected to increase by roughly 4 percent
($1.2 million) as a result of the proposed rate increases, not including fluctuations in
commodity revenue/cost. The FY 2020 Budget is being developed concurrent with these rates
and, depending on the final rates, adjustments to the budget may be necessary at a later time.
See the attached FY 2020 Gas Financial Plan for a more comprehensive overview of projected
cost and revenue changes for the next five years.
POLICY IMPLICATIONS
The proposed gas rate adjustments are consistent with Council-adopted Reserve Management
Practices that are part of the Financial Plan, and were developed using a cost of service study
and methodology consistent with industry-accepted cost of service principles.
ENVIRONMENTAL REVIEW
The Finance Committee’s review and recommendation to Council on the FY 2020 Gas Financial
Plan 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: Draft RESO FY 2020 Gas Financial Plan Adoption
• Attachment B: FY 2020 Gas Financial Plan
• Attachment C: Resolution Amending Gas Rate Schedules G1, G2, G3 and G10 for FY 2020
• Attachment E: Info Item Regarding Hedging
Attachment A
* NOT YET APPROVED *
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2020 Gas Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes
making long-term projections of market conditions, the physical condition of the system, and
other factors that could affect utility costs, and setting rates adequate to recover these costs. It
does this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby adopts the FY 2020 Gas Utility Financial Plan.
SECTION 2. The Council hereby approves the transfer of up to $300,000 Thousand
from the Rate Stabilization Reserve to the Operations Reserve, and up to $6 Million from the
Rate Stabilization Reserve to the CIP Reserve, as described in the FY 2020 Gas Utility Financial
Plan approved via this resolution.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental assessment is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
Attachment A
* NOT YET APPROVED *
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2020 GAS
UTILITY
FINANCIAL PLAN
FY 2020 TO FY 2024
GAS UTILITY FINANCIAL PLAN
M a r c h 2019 2 | P a g e
GAS UTILITY FINANCIAL PLAN
FY 2020 TO FY 2024
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 Reserve Proposals ........................................................ 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 8
Section 3C: Bill impact of Proposed Rate Changes ...................................................................... 9
Section 3D: Proposed Reserve Transfers ................................................................................... 10
Section 4: Utility Overview .................................................................................................. 11
Section 4A: Gas Utility History ................................................................................................... 11
Section 4B: Customer Base ........................................................................................................ 12
Section 4C: Distribution System ................................................................................................. 13
Section 4D: Cost Structure and Revenue Sources ...................................................................... 14
Section 4E: Reserves Structure ................................................................................................... 14
Section 4F: Competitiveness ...................................................................................................... 15
Section 4G: Gas Supply Rates .................................................................................................... 16
Section 5: Utility Financial Projections ................................................................................. 17
Section 5A: Load Forecast .......................................................................................................... 17
Section 5A: FY 2014 to FY 2018 Cost and Revenue Trends ........................................................ 18
Section 5B: FY 2018 Results ....................................................................................................... 19
Section 5C: FY 2019 Projections ................................................................................................. 20
Section 5D: FY 2020-FY 2024 Projections .................................................................................. 20
Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 21
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M a r c h 2019 3 | P a g e
Section 5F: Long-Term Outlook ................................................................................................. 23
Section 6: Details and Assumptions ..................................................................................... 24
Section 6A: Gas Purchase Costs ................................................................................................. 24
Section 6B: Operations .............................................................................................................. 25
Section 6C: Capital Improvement Program (CIP) ....................................................................... 26
Section 6D: Debt Service ............................................................................................................ 28
Section 6E: Equity Transfer ........................................................................................................ 30
Section 6F: Revenues ................................................................................................................. 30
Section 6G: Communications Plan ............................................................................................. 31
Appendices ......................................................................................................................... 33
Appendix A: Gas Financial Forecast Detail ................................................................................ 34
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 35
Appendix C: Gas Utility Reserves Management Practices ......................................................... 37
Appendix D: Description of Gas Utility Cost Categories ............................................................ 41
Appendix E: Gas Utility Communications Samples .................................................................... 42
GAS UTILITY FINANCIAL PLAN
M a r c h 2019 4 | P a g e
SECTION 1: DEFINITIONS AND ABBREVIATIONS
ABS: Acrylonitirile butydene styrene, a plastic gas main material
AMI: Advanced Metering Infrastructure
CARB: California Air Resources Board
CIP: Capital Improvement Program
CNG: Compressed Natural Gas
CPAU: City of Palo Alto Utilities Department
CPUC: California Public Utilities Commission
Cross-bore: A cross-bore exists when one utility line has been drilled or “bored” through a
portion of another line. Gas cross-bores can occur in sewer lines as a result of “horizontal
boring” construction practices.
Distribution: transportation of gas to customers.
GMR Program: Gas Main Replacement Program
Local Transportation: transportation of gas to Palo Alto across PG&E’s distribution system from
PG&E City Gate.
Malin: a delivery hub referred to in gas purchase contracts and located in Malin, Oregon, where
the northern end of PG&E’s Redwood Transmission Pipeline is located.
MMBtu: Millions of British thermal units, a unit of gas measurement equal to ten therms.
Commonly used for high volume gas measurement. Wholesale purchases of gas from suppliers
are typically measured in MMBtu.
O&M: Operations and Maintenance
PE or HDPE: Polyethylene, a gas main material (more specifically, High-Density Polyethylene)
PG&E: Pacific Gas and Electric
PG&E Citygate, or Citygate: a delivery hub referred to in gas purchase contracts. Any gas
delivered to PG&E’s distribution system (such as gas delivered at the southern end of PG&E’s
Redwood Transmission Pipeline) is said to have been delivered at PG&E Citygate.
PVC: Polyvinyl chloride, a plastic gas main material
Summer: April 1 to October 31
Therms: The standard unit of measurement for natural gas sales to customers, equal to 100,000
British thermal units. Therms measure the heating value of the gas, rather than its volume.
Transmission: transportation of gas between major gas delivery hubs via a gas transmission
pipeline, such as PG&E’s Redwood pipeline.
UAC: Utilities Advisory Commission, an appointed body that advises the City Council on CPAU
issues.
Winter: November 1 to March 31
GAS UTILITY FINANCIAL PLAN
M a r c h 2019 5 | P a g e
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Gas Utility for the next five years. This
Financial Plan provides revenues to cover the costs of operating the utility safely over that time
while adequately investing for the future. It also addresses the financial risks facing the utility
over the short term and long term, and includes measures to mitigate and manage those risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
This financial plan projects non-commodity costs to increase from FY 2019 through FY 2024 at
about 3.6% per year on average. In the short term, some of these cost increases are related to
the cross-bore inspection program, but capital improvement program (CIP) costs have also
increased as the economy has improved. The national and regional focus on infrastructure
improvement has created more demand, and the pool of skilled construction labor has not
grown at the same pace. While CPAU generally has planned a new gas main replacement
project every year, recent larger than expected bids have required resizing and redesign of
some existing planned projects. The size, scope and complexity of the University Avenue
Business District project, which is nearing completion, resulted in no new CIP work being
budgeted for FY 2019. Staff is currently budgeting for a new, larger main replacement project
every other year. This revised main replacement schedule will allow CPAU to reasonably meet
its main replacement needs while addressing challenges in the current construction market and
optimizing current staffing resources. However, if it is found that PVC pipe replacement should
be replaced sooner, then the pace and size of main replacements may need to increase. Table 1
shows the Gas Utility expenses over the period of this financial plan.
Table 1: Gas Utility Expenses for FY 2018 to FY 2024 (Thousand $’s)
Expenses
($000)
FY 2018
(act.)
FY 2019
(est.) FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Commodity costs 12,921 13,022 14,362 14,729 15,174 15,576 16,122
Operations 19,571 21,468 22,494 22,868 22,497 23,054 23,576
Capital Projects 7,804 5,567 2,350 13,402 2,436 13,490 2,551
TOTAL 40,297 40,057 39,206 50,999 40,108 52,120 42,249
To ensure that revenues cover projected rising costs, the financial plan includes the rate
trajectory shown in Table 2.
Table 2: Projected Gas Rate Trajectory for FY 2020 to FY 2024
Projection FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
Current Financial Plan 5% 8% 8% 6% 4%
FY 2019 Financial Plan 8% 7% 7% 4% 4%
FY 2018 Financial Plan 6% 6% 5% 3% 3%
The Gas Utility has Rate Stabilization Reserves in both the Supply and Distribution funds, which
can be used to smooth rate increases over several years. This Financial Plan projects that these
reserves will be exhausted by the end of FY 2020. The Gas Utility also has a CIP Reserve to help
GAS UTILITY FINANCIAL PLAN
M a r c h 2019 6 | P a g e
offset spikes in CIP spending which do not merit separate bond financing. Going forward, this
reserve will be used to offset the annual fluctuations in main replacement costs. Table 3 shows
the projected reserve transfers over the forecast period.
Table 3: Transfers To/(From) Reserves for FY 2019 to FY 2024 ($000)
Reserve FY 2019 FY 2020 FY 2021 to FY 2024
Rate Stabilization (17) (6,363) -
CIP - 6,000 (720)
Operations 17 363 720
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Gas Utility in FY 2019:
1. Transfer any remaining funds in the Supply Rate Stabilization Reserve to the Operations
Reserve (currently estimated at $17,000).
Staff proposes the following actions for the Gas Utility in FY 2020:
2. Increase distribution rates by 8% (a 5% overall increase) for FY 2020, primarily reflecting
increases to capital expenditures and also increased operations costs. See Section 3B:
Current and Proposed Rates for more details.
3. Propose a transfer of up to $6.363 million from the Distribution Rate Stabilization
Reserve to the Operations Reserve, to keep the ending balance of the Operations
Reserve above the adopted guideline level and below the maximum guideline level.
4. Amend the Gas Utility Reserves Management Practices to clarify the purpose, funding
of, and transfers to and from the CIP Reserve.
SECTION 3: DETAIL OF FY 2019 RATE AND RESERVE PROPOSALS
SECTION 3A: RATE DESIGN
The Gas Utility’s rates are evaluated and implemented in compliance with cost of service
requirements. The Gas Utility’s proposed rates are based on the methodology from the March
2019 Natural Gas Cost of Service and Rates Study, included here as Attachment E. The
methodology used was similar to the prior study performed in April 2012 by Utility Financial
Solutions1, and updated to reflect current costs as well as changes in consumption patterns
between customer classes. The study was performed in conformance with the scope previously
discussed with the Utilities Advisory Commission in October 2016, and the Council in November
20162.
For the Residential (G1) customers, energy consumption per customer has decreased by
roughly 10 percent when compared to the 2012 COSA. This means that the fixed costs
1 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
2 Staff Report 7416 11/14/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54576
GAS UTILITY FINANCIAL PLAN
M a r c h 2019 7 | P a g e
associated with the Residential class are spread among a smaller amount of therms consumed,
increasing the per unit cost for the class. For Small Commercial (G2) customers, per customer
usage has also decreased by roughly 10 percent, but as both the use per customer and load
factor are higher than for the Residential class, Small Commercial customers have a lower
average cost than for the Residential class. The Large Commercial (G3) group has seen a growth
in the relative number of customers from the prior study, and while per customer usage has
dropped by nearly 40%, this class still has both the highest use per customer and the highest
load factor, resulting in a lower average cost than the G1 and G2 groups.
The growth in the costs has also had an impact to the cost of service by class. Compared to the
2012 COSA, costs related to Customer Service, Accounts and Sales have increased by 78%
compared to an increase of 36% for O&M and under 30% for other cost components. This
shifts more costs to the residential class because it has a higher number of customers. It also
leads to higher customer charges for all three of the classes.
After reviewing current and proposed operating costs, changes to the utilities infrastructure
mix, and developing patterns of usage between Palo Alto’s customers (with commercial
consumption declining at a greater rate relative to residential consumption), it was determined
that residential customers would require about a 5% increase to achieve cost of service (COSA)
parity between classes, while small and large commercial customers would require
corresponding decreases, as outlined in Table 4 below:
Table 4: Cost of Service (COSA) results by Customer Class
After these class shifts were determined, the 8% distribution rate increase was applied to rates,
as outlined in Section 3B: Current and Proposed Rates. As much of the distribution cost relates
to relatively constant and recurring operations costs within the system, which occur or are
required regardless of how much gas flows through the system, or are related to pipeline
replacements which serve to benefit all customers better safety and reliability, it is reasonable
to allocate more of the cost and relative increases within monthly service charges and less to
volume related sales.
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M a r c h 2019 8 | P a g e
SECTION 3B: CURRENT AND PROPOSED RATES
On July 1, 2012 CPAU restructured its rates so that the commodity component varied monthly
to match changes in gas market prices.3 In addition, CPAU increased monthly service charges to
recover the cost of providing gas service to customers. In January 2015, the Council adopted a
new rate component to collect the costs of purchasing allowances for the purpose of
compliance with the State’s cap-and-trade program.4 This component changes depending on
the cost of allowances and gas demand. In October 2016, the Council adopted a resolution
changing the Local Transportation rate (which had been collapsed into the Distribution rate in
2015 to streamline bill presentation), to be a pass-through of PG&E’s Gas Transportation Rate to
Wholesale/Resale Customers (G-WSL) charge to Palo Alto.5 This went into effect November 1,
2016. In December 2016, Council approved a carbon neutral gas plan, with a goal of achieving a
carbon neutral gas portfolio by FY 2018.6 The plan is for costs associated with the plan to be a
passed through directly to customers as well, although the rate impact is not to exceed $0.10
per therm. Three years’ worth of volumetric rate history can be found on Palo Alto’s website.7
CPAU has four rate schedules: one for separately metered residential customers (G-1), one for
small commercial and master-metered multi-family residential customers (G-2), one for
customers using over 250,000 therms per year (G-3) and a specific schedule for the Compressed
Natural Gas station (G-10). All customers pay a monthly service charge, which represents meter
reading, billing, and other customer service costs, as well as a portion of operations and
maintenance cost. All customers are also charged for each therm of gas used. Separately
metered residential customers are charged on a tiered basis, differentiated by season. During
the winter months, the first 2 therms per day (60 therms for a 30 day billing period) are charged
a base price per CCF, and all additional units charged a higher price per therm. During the
summer months, the first tier level is 0.667 therms per day, or 20 therms for a 30 day billing
period. Commercial customers pay a uniform price for each therm used.
Table 5 shows the current monthly service charges for all rate schedules. Table 106 shows the
consumption charges related to distribution charges. As mentioned earlier, commodity charges
change monthly, and transportation charges are tied to the PG&E G-WSL rate schedule. Some
recent commodity price history is discussed in Section 6A: Gas Purchase Costs.
3 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
4 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537
5 Staff Report 7260 10/17/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54165
6 Staff Report 7533 12/05/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54882
7 Monthly Gas Commodity & Volumetric Rates http://www.cityofpaloalto.org/civicax/filebank/documents/30399
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Table 5: Current and Proposed Monthly Service Charges
Rate Schedule
Monthly Service Charge
($/month)
Change
Current (as of
7/1/18)
Proposed for
FY 2020
($) (%)
G-1 (Residential) $10.94 $13.35 $2.41 22.0%
G-2 (Small Commercial) 82.92 104.95 22.03 26.6%
G-3 (Large Commercial) 400.08 690.45 290.37 72.6%
G-10 (CNG) 56.11 70.98 14.87 26.5%
Table 6: Current and Proposed Gas Distribution Charges
Change
Current (as of
7/1/18)
Proposed
for FY 2020
($) (%)
G-1 (Residential)
Tier 1 Rates $0.4239 $0.4835 $0.0596 14.1%
Tier 2 Rates 0.9948 1.0426 0.0478 4.8%
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.6183 0.6102 (0.0081) (1.3%)
G-3 (Large Commercial)
Uniform Rate 0.6098 0.6056 (0.0420) (0.7%)
G-10 (Compressed Natural Gas)
Uniform Rate 0.0100 0.0100 0.0000 -
SECTION 3C: BILL IMPACT OF PROPOSED RATE CHANGES
Table 7 shows the impact of the proposed July 1, 2019 rate changes on the median residential
bill. The average increase is roughly 8% based on prices in December 2018, but some customers
may see slightly higher or lower increases due to slight changes in the composition of the
utility’s costs, as well as prevailing market prices.
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Table 7: Impact of Proposed Gas Rate Changes on Residential Bills
Usage
(Therms/month)
Bill under
Current Rates
Bill under
Proposed Rates
Change
$/mo. %
Winter (Using December 2018 commodity prices)
30 $ 48.38 $ 52.58 $ 4.20 8.7%
54 (median) 78.33 83.96 5.63 7.2%
80 122.19 129.14 6.94 5.7%
150 249.51 259.80 10.29 4.1%
Summer (Using July 2018 commodity prices)
10 $ 20.04 $ 23.05 $ 3.01 15.0%
18 (median) 27.32 30.81 3.48 12.7%
30 43.96 48.04 4.08 9.3%
45 66.17 70.97 4.80 7.2%
Table 8 shows the impact of the proposed July 1, 2019 rate changes on various representative
commercial customer bills.
Table 8: Impact of Proposed Gas Rate Changes on Commercial Bills
(Using December 2018 commodity prices)
Usage
(Therms/month)
Bill under Current
Rates
Bill under
Proposed Rates
Change
%
500 804 822 2.2%
5,000 7,295 7,276 (0.3%)
10,000 14,506 14,447 (0.4%)
50,000 72,092 72,172 0.1%
SECTION 3D: PROPOSED RESERVE TRANSFERS
The FY 2019 Financial Plan proposed a $2 million transfer from the Rate Stabilization Reserve
into the Operations Reserve in FY 2019. Actual expenses in FY 2018 resulted in higher ending
reserve balances than initially projected. The Supply Rate Stabilization reserve is projected to
end the year at $19,000, and staff recommends that this amount be transferred to the
Operations Reserve and the Rate Stabilization reserve drawn to zero. Further gains or losses to
this fund should come from the Operations Reserve. A tentative transfer of $6.363 million from
the Distribution Rate Stabilization reserve in FY 2020 is included in the financial projections in
this Financial Plan. The intent for several years has been to utilize these funds to mitigate rate
increases and otherwise bring the Rate Stabilization reserves to zero.
In addition, there is $3.8 million in the CIP Reserve. These funds can be used to help mitigate
additional, one-time costs, but with the current plan to stagger main replacement projects
every other year, this fund can also be used to hold funds collected from rate revenues that
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should be used to fund CIP projects. In a year with no project budgeted, rate revenues will likely
exceed expenses, but conversely, in years with a main replacement project, rates are not
anticipated to cover total cost. The reasonable approach is to transfer excess funds from the
Operations Reserve to the CIP Reserve in non-main replacement years, then utilize those funds
in years with replacements. The net effect will be more evenly funded Operations Reserve and
a CIP reserve that better reflects available funds for projects. The impact of these transfers on
reserves levels can be seen in Appendix A: Gas Utility Financial Forecast Detail.
SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information and to help readers better understand the forecasts in Section 5:
Utility Financial Projections and Section 6: Details and Assumptions.
SECTION 4A: GAS UTILITY HISTORY
On September 22, 1917, the City of Palo Alto issued a bond to purchase the property of Palo
Alto Gas Company and continue it as a municipal enterprise. At the time, the system was
comprised of 21 miles of mains, 1,900 meters, and was valued at $65,500. PG&E supplied the
gas, which was synthesized from coal at its Potrero gasification facility. Almost immediately the
City faced challenges. Losses were at nearly 25% according to PG&E’s master meter, and PG&E
had filed with the Railroad Commission (the forerunner to today’s CPUC) to increase rates by
nearly 72.5%. Despite these initial hurdles, Palo Alto’s system grew tremendously, and by 1924
revenues had exceeded those of the electric utility. Sales were such that the annual reports of
the time noted gas usage “appears to be greater than that of any other city in the state,
showing that gas is a very popular form of fuel in Palo Alto.” Just prior to the acquisition of the
neighboring town of Mayfield’s gas system (centered around today’s California Avenue) in
1929, the miles of main in service and customers connections had doubled.
Notable changes to the gas supply itself came in 1930, when PG&E ceased supplying purely
manufactured (or coal) gas from its Potrero Hill facility in San Francisco and instead switched to
natural gas. In 1935, a supplementary butane injection system (later retired) was purchased
from Standard Oil to mitigate large wintertime peaks. Gas sales were at 248,658 million cubic
feet (MCF) with 4,849 active services.
Early gas mains in Palo Alto were made of steel, but in the 1950s, like many other utilities, CPAU
switched to ABS plastic. CPAU switched to PVC plastic in the early 1970s, but around 100 miles
of ABS mains had already been installed. A 1990 evaluation of the system found a steadily
increasing rate of gas leaks associated with those mains, something that other gas utilities had
also been experiencing. To reduce leaks, CPAU accelerated its main replacement program from
7,000 feet (1.3 miles) of replacements per year to 20,000 feet (3.8 miles) per year. This would
enable the utility to replace all of its ABS and its most vulnerable steel and PVC mains with
polyethylene (PE) mains over the course of the following 36 years.8 As of 2015 the Gas Utility
had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic
8 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990
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protection was not effective. Current main replacement projects will target the last ~800 feet of
remaining ABS main as well as tackling PVC replacement. A PVC risk analysis to determine the
appropriate footage of annual PVC replacement for future CIP projects is currently being
conducted. This is an example of how local control of its Gas Utility has provided Palo Alto
residents with substantial benefits. During the 1990s and 2000s, while CPAU was increasing its
main replacement rate to ensure a robust gas distribution system, PG&E was underspending on
safety-related infrastructure, according to a past audit.9
In the 1990s, while grappling with the issues surrounding its distribution system, CPAU was also
participating in major changes to the structure of the gas industry in California. Until 1988 CPAU
had a formal policy of setting its rates equal to PG&E’s rates and successfully did so with the
exception of one year in the mid-1970s. At times this led to inadequate revenue (1974 to 1981)
as PG&E, the City’s only gas supplier, regularly filed requests with the CPUC to increase the
wholesale gas supply rates charged to the Gas Utility. In the 1990s, as the CPUC began
deregulating the natural gas industry in California, the Gas Utility began purchasing gas from
suppliers other than PG&E. In 1997 the CPUC adopted the “Gas Accord,”10 which enabled the
Gas Utility (along with other local transportation-only customers) to obtain transmission rights
on PG&E’s Redwood transmission pipeline running from Malin, Oregon into California.
In 2000/2001 the California energy crisis occurred, causing major disruptions to the Gas Utility’s
supply costs. Wholesale gas prices rose over 500% between January 2000 and January 2001.
The Council approved drawing down reserves to provide ratepayer relief and, for two years
following the crisis, CPAU rates were above PG&E’s as reserves were replenished. In April 2001
the Council approved a hedging practice of buying fixed price gas one to three years into the
future. After reaching a low point in October 2001, prices continued to rise, and as a result the
CPAU hedging strategy frequently resulted in a wholesale supply cost advantage compared to
PG&E until prices began to decline steeply in mid-2008. At that point the Gas Utility’s wholesale
supply costs became higher than market gas prices due to fixed price contracts entered into
prior to 2008. As a result the Gas Utility’s wholesale supply costs were higher than PG&E’s for
several years. In 2012 Council approved a plan to formally cease the hedging strategy and
purchase all gas on the short-term (“spot”) markets. As of July 1, 2012, the commodity portion
of the gas rates changes every month based on the spot market gas price.
SECTION 4B: CUSTOMER BASE
CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas
customers in Palo Alto. Close to 23,600 customers are connected to the natural gas system,
approximately 22,000 (93%) of which are residential and 1,600 (7%) of which are non-
residential. Residential customers consume about 11 to 13 million therms of gas per year,
roughly 45% of the gas sold, while non-residential customers consume 55% (about 14 to 16
million therms). Residential customers use gas primarily for space heating (46% of gas
consumed) and water heating (42%), with the remainder consumed for other purposes such as
9 Focused Financial Audit of The Pacific Gas & Electric Company’s Gas Distribution Operations, Overland Consulting,
made available through a CPUC Administrative Law Judge’s ruling on A12-11-009/I13-03-007 on 5/31/2013
10 CPUC decision 97-08-055. Since then, the Gas Accord has been amended four times, with the most recent being
Gas Accord V, application A.09-09-013
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cooking, clothes drying, and heating pools and spas.11 Non-residential customers use gas for
space and water heating (73% of gas consumed), cooking (20%), and industrial processes
(6%).12
The Gas Utility receives gas at the four receiving stations within Palo Alto where CPAU’s
distribution system connects with Pacific Gas and Electric’s (PG&E’s) system. These receiving
stations are jointly operated by CPAU and PG&E. CPAU purchases gas from various natural gas
marketers, with PG&E providing only local transportation service (transportation from the
PG&E City Gate gas delivery hub to Palo Alto). CPAU also has transmission rights on PG&E’s
transmission pipeline from Malin, Oregon to PG&E City Gate, allowing it to purchase lower
priced gas at that location. CPAU does not produce or store any natural gas, and purchases gas
in the monthly and daily spot markets. The cost of the purchased gas is passed through directly
to customers through a rate adjuster that varies monthly with market (bidweek) prices. In a
similar fashion, the cost for local transportation is now tied to PG&E’s G-WSL rate schedule, and
varies when and if PG&E changes its rate schedule. The cost of purchased gas and PG&E local
transportation service usually account for roughly one third of the utility’s expenditures.
SECTION 4C: DISTRIBUTION SYSTEM
To deliver gas from the receiving stations to its customers, the utility owns 210 miles of gas
mains (which transport the gas to various parts of the city) and close to 23,600 gas services
(which connect the gas mains to the customers’ gas lines). These mains and services, along with
their associated valves, regulators, and meters, represent the vast majority of the infrastructure
used to deliver gas in Palo Alto. CPAU has an ongoing CIP to repair and replace its infrastructure
over time, the expense of which normally accounts for around 15 to 20% on average of the
utility’s expenditures. Costs for main replacements have been going up in recent years.
In addition to the CIP, the Gas Utility performs a variety of maintenance activities related to the
system, such as monitoring the system for leaks, testing and replacing meters, monitoring the
condition of steel pipe, and building and replacing gas services for buildings being built or
redeveloped throughout the city. The utility also shares the costs of other system-wide
operational activities (such as customer service, billing, meter reading, supply planning, energy
efficiency, equipment maintenance, and street restoration) with the City’s other utilities. These
maintenance and operations expenses, as well as associated administration, debt service, rent,
and other costs, make up roughly half of the utility’s expenses.
In addition to these ongoing activities, CPAU has conducted a program to find and replace
cross-bores over the last several years. Currently, $1 million is budgeted per year for the cross-
bore program through FY 2021. However, the ongoing cross-bore investigation may require
additional funding, or extend for longer into the future, as the remaining sewer lines are more
difficult to examine than the majority of the wastewater collection system that has been
examined to date.
11 http://energyalmanac.ca.gov/naturalgas/overview.html
12 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Statistics shown are
for end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located.
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Figure 2: Cost Structure (FY 2018)
48%
33%
19%
Operations
Gas Purchases
Capital
Figure 1: Revenue Structure (FY 2018)
92%
8%
Sales of Gas
Other Revenue
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 1, the Gas
Utility receives about 92% of its
revenue from sales of gas and the
remainder from capacity and
connection fees, interest on
reserves, and other sources.
Appendix A: Gas Utility Financial
Forecast Detail shows more detail
on the utility’s cost and revenue
structures.
As shown in Figure 2, in FY 2018,
gas purchase costs accounted for
roughly one third of the Gas
Utility’s costs. This percentage
can vary widely from year to year,
as this cost is based upon market
purchases, and now also includes
costs related to cap and trade.
Operational costs in FY 2018
represented roughly half of
expenses and capital investment
was responsible for the remaining
19%. CIP is normally about 20% of
expenses, but this may be lower
in times when spending for new
projects is deferred, as happened in FY 2017.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains six reserves for its Gas Utility to manage various types of contingencies. The
summary below describes each of these briefly. See Appendix C: Gas Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserve for Commitments: A reserve equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserve for Re-appropriations: A reserve for funds dedicated to projects re-
appropriated by the City Council, nearly all of which are capital projects. Most City
funds, including the General Fund, have a Re-appropriations Reserve.
• Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to
accumulate funds for future expenditure on CIP projects. This CIP can also act as a
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contingency reserve for the CIP. This type of reserve is used in other utility funds
(Electric, Water, and Wastewater Collection) as well.
• Rate Stabilization Reserve: This reserve is intended to be empty unless one or more
large rate increases are anticipated in the forecast period. In that case, funds can be
accumulated to spread the impact of those future rate increases across multiple years.
This type of reserve is used in other utility funds (Electric, Water, and Wastewater
Collection) as well.
• Operations Reserve: This is the primary contingency reserve for the Gas Utility, and is
used to manage yearly variances from budget for operational gas costs. This type of
reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as
well.
• Unassigned Reserve: This reserve is for any funds not assigned to the other reserves
and is normally empty.
SECTION 4F: COMPETITIVENESS
Table 9 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of July 2018 (to illustrate a summer month bill) and
February 2019 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for fiscal year 2018 was $469.94, about 14% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 9: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(February 2019)
30 39.55 46.31 -14.6%
(Median) 54 62,43 83.49 -25.2%
80 100.93 139.13 -27.5%
150 207.64 288.94 -28.1%
Summer
(July 2018)
10 20.38 12.48 63.4%
(Median) 18 27.94 24.56 13.8%
30 44.59 46.26 -3.6%
45 67.32 73.38 -8.3%
Table 1010 shows the monthly gas bills for commercial customers for various usage levels for
rates in effect as of February 2019. Bills for CPAU customers at the usage levels shown can vary
between 3% lower to 12% higher for commercial customers than for PG&E customers. This is a
substantial improvement over the calendar year 2013 bill comparison, when commercial gas
bills for CPAU customers were 27% to 44% higher than for PG&E customers. This is primarily
attributable to PG&E’s higher distribution rates as the commodity rates for CPAU and PG&E are
very similar, both being based on spot market gas prices.
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Table 10: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect February 2019)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 657 681 -3%
5,000 5,823 6,257 -1%
10,000 11,563 11,139 4%
50,000 57,374 51,414 12%
SECTION 4G: GAS SUPPLY RATES
Starting in July 2012, CPAU replaced a “laddering” hedging strategy for purchasing gas supplies
with a strategy to buy gas on the short-term, or “spot” markets and pass the commodity cost to
customers on a monthly basis. Figure 3 shows the actual commodity prices charged. For the
last two and a half years, prior to December 2018, commodity prices had generally fluctuated in
a fairly narrow band, with prices averaging around $0.32/therm. However, in December 2018, a
variety of factors combined that led to a one time market spike: Regional temperatures were
cooler than normal, but in addition, gas supplies stored in underground facilities were lower
than normal, as well as constrained due to problems with the Aliso Canyon facility in southern
California. Also, there were pipeline constraints at both the northern and southern borders.
While there was not an actual constriction on supply, the confluence of all these factors drove
up the bidweek prices for all California delivery points. Once it was seen that these factors were
not causing gas supply shortages, prices returned to levels more commonly seen.
Figure 3: Gas Commodity Rates from July 2012 through February 2019
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SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Gas usage in Palo Alto is volatile, varying with both economic and weather conditions. As shown
in Figure 4, in the early 1970’s, gas purchases reached over 45 million therms per year. Usage
dropped dramatically in the 1976/1977 drought when customers saved significant amounts of
(hot) water by upgrading to efficient showerheads. During the 1980s and 90s average gas usage
was around 36 million therms per year. Usage dropped again in the early 2000’s. In FY 2001, gas
prices escalated during the California energy crisis and Palo Alto’s rates increased by nearly
200%. From 2003 to 2011, usage decreased by 2.3% mainly as a result of continued customer
investments in energy efficiency.
In 2014 and 2015, unusually warm winters, as well as ongoing drought, caused gas usage to
tumble to historic lows. In FY 2017 and FY 2018, as the drought has eased, gas usage increased
again, but has appeared to have stabilized.
Figure 4: Historic Gas Consumption
Gas consumption, as denoted by the dotted line in Figure 5, is projected to resume the long run
trend of decreasing usage over the forecast period, although changes such as replacement of
gas appliances with electric appliances or customer behavior may result in lower long run
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usage. As with prior drought/gas usage declines in the past, it is likely that consumption will not
come back to pre-conservation levels. It is too early to tell, however, where a new ‘normal’
level of consumption will be.
Figure 5: Forecast Gas Consumption
SECTION 5A: FY 2014 TO FY 2018 COST AND REVENUE TRENDS
Figure 6 and Appendix A: Gas Utility Financial Forecast Detail show how costs have changed
during the last five years as well as how staff project costs to change over the next decade.
The annual expenses for the gas utility generally decreased between 2014 and 2017. Lower gas
sales in conjunction with the drought, as well as lower gas market prices in FY 2015 and FY 2016
(as shown in Figure 3 above) resulted in lower overall commodity expenses. FY 2014, FY 2015
and FY 2017 were notable due to the fact that no new funding was added for main replacement
projects. In FY 2014 and FY 2015, this was due to the fact that staff was completing a prior
major gas main replacement project, the largest in utility history, which completed replacement
of ABS gas mains in Palo Alto. The FY 2018 project included replacements of gas mains on
University Avenue, a project that has evolved into the Upgrade Downtown project involving a
coordinated replacement of several different types of infrastructure to avoid multiple
disruptions to the business district. This has been a multi-year planning effort that did not allow
for design of other new projects. This allowed the Gas Utility to temporarily keep rates lower
than they will need to be to fund future operations and capital replacement.
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Revenues have generally matched expenses in most years and were higher than expenses in FY
2017. The absence of new budget funding for main replacement projects for several years, as
well as the availability of relatively large reserves, forestalled the need for rate increases until
now.
As shown in Figure 6, the last adjustment to gas distribution rates was in July 2018 when CPAU
increased rates by 4%. In FY 2012, commodity rates were changed to a market-based, monthly
pass-through cost—and commodity rates (and usage) fell, so revenues (and gas supply costs)
actually declined in FY 2013 after the rate increase. Figure 6 assumes no change in gas supply
costs over the forecast period to illustrate the impact of proposed distribution rate changes on
the overall customer bill. In reality, gas supply costs are uncertain and are passed through to
customers as they change month to month.
Figure 6: Gas Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2018 and Projections through FY 2024
SECTION 5B: FY 2018 RESULTS
Sources of funds for FY 2018 were lower than projections by $214,000, but operational
expenses came in well below the expected budget. Total FY 2018 expenses were $40.3 million
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compared to projections of $42.2 million in the FY 2019 Financial Plan. Table 11 summarizes the
variances from forecast.
Table 11: FY 2018, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Purchase costs lower than forecast (408) Cost savings
Operations cost savings (1,538) Cost savings
Decreased interest income and other
non-sales revenues 257
Revenue decrease
Increased sales revenues (44) Revenue increase
Net Cost / (Benefit) of Variances (1,733)
SECTION 5C: FY 2019 PROJECTIONS
Current projections indicate that sales revenues will be slightly higher than last year’s forecast
due to higher than expected market prices. While gas purchase costs are also projected to
increase appreciably during the forecast period, the current financial plan also anticipates
higher operations and CIP costs than projected in the prior financial plan. Table 12 summarizes
the current and projected variances from the FY 2019 Financial Plan.
Table 12: FY 2019 Projected Results vs. Current Financial Plan Forecast ($000)
Net Cost/ (Benefit) Type of change
Sales revenues higher than forecast (452) Revenue increase
Other revenues and interest higher than forecast (159) Revenue decrease
Purchase cost increase 928 Cost increase
Operations & maintenance, customer service, and
capital improvement cost increases
401 Cost increase
Net Cost / (Benefit) of Variances 717
SECTION 5D: FY 2020-FY 2024 PROJECTIONS
Figure 6 above shows staff projections that overall costs for the Gas Utility will stay relatively
flat into FY 2020. This is largely in part due to a modified CIP schedule starting in FY 2020. For FY
2020 through 2024, staff anticipates annual capital expenditures will fluctuate due to planning
for larger main replacement construction projects every other year instead of smaller projects
annually. This revised main replacement schedule will allow CPAU to meet its main
replacement needs while addressing challenges in the current construction market and
optimizing current staffing resources. Averaging the cost of CIP over these two year cycles,
costs are expected to increase by around 3.6% on average annually through FY 2024. In
Operations, there is a short run addition of $1 million, starting in FY 2019, for cross-bore
inspections (this expense is projected to continue for at least three years), as well as general
inflationary increases of around 2 to 4% per year. Salaries and benefits expenses are projected
to rise at 3 to 4% per year, per the City’s Long Range Financial Plan. Construction costs continue
to increase, which resulted in increased costs in FY 2018 and FY 2019 for the University Avenue
Business District project, which is nearing completion. The next new main replacement project
after the University Avenue project will take place in FY 2021, and ongoing main replacement is
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expected to be more expensive. Gas commodity costs are the most variable component and are
currently projected to increase by around 4.4% annually. Since this is a pass-through cost to
customers, the risk of these costs being higher or lower than expected has a lower impact on
reserves.
As shown in Figure 7, this financial plan projects the Rate Stabilization Reserves to be depleted
by FY 2020. In addition, in years where revenues are higher than expenses due to those being
CIP planning years, funds will be moved into the CIP reserve to help counter the following
year’s higher CIP related costs.
Figure 7: Gas Utility Reserves
Actual Reserve Levels for FY 2018 and Projections through FY 2024
SECTION 5E: RISK ASSESSMENT AND RESERVES ADEQUACY
This financial plan projects the Gas Utility’s primary contingency reserve, the Operations
Reserve, to be within guideline levels throughout the forecast period, barring either short-run
budget savings and/or larger future increases. Figure 8 shows the Operations Reserve within
the guideline levels.
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Figure 8: Operations Reserve Adequacy
Forecasted Operations Reserve levels also exceed the short-term risk assessment for the Utility.
Table 13 summarizes the risk assessment calculation for the Gas Utility through FY 2024. The
risk assessment includes the revenue shortfall that could accrue due to:
1. Lower than forecasted distribution sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget
year.
Table 13: Gas Risk Assessment ($000)
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Total non-commodity revenue $23,518 $26,174 $29,159 $31,355 $32,773
Max. revenue variance, previous ten years 16% 16% 16% 16% 16%
Risk of revenue loss $3,771 $4,197 $4,676 $5,028 $5,255
CIP Budget $1,008 $12,019 $1,012 $12,023 $1,040
CIP Contingency @10% $101 $1,202 $101 $1,202 $104
Total Risk Assessment value $3,872 $5,399 $4,777 $6,230 $5,359
Finally, the City created the CIP Reserve at the end of FY 2015 to act as a contingency reserve
for capital improvement projects. Current guidelines state that the balance of this reserve
should fall between 12 and 24 months of budgeted CIP expense, but staff will continue to
review this reserve and the appropriateness of the current minimum and maximum guideline
levels in light of the new alternating year CIP plan. In general, the current financial plan projects
continual average growth of the CIP reserve over time.
At the end of FY 2018, the sum of the CIP Reserve and existing Commitments was $8 million, as
shown in Figure 7.
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SECTION 5F: LONG-TERM OUTLOOK
In the longer term (5 to 35 years out) it is very difficult to predict the Gas Utility’s commodity
costs. A variety of long-term trends could affect commodity costs either positively or negatively.
Continuing improvement in gas extraction technology, such as fracking, could continue to
create generous supplies of gas, but these technologies are also under greater scrutiny with
respect to their environmental impacts. On the demand side, a continued shift from coal to
natural gas for electricity generation, an expansion of export capabilities, or an increase in
manufacturing in the U.S. might drive up natural gas prices, but other factors, such as generally
more mild winters or an increased drive towards electrification, might drive gas demand lower.
It is also difficult to predict the magnitude of the additional cost impacts associated with the
State’s cap-and-trade program over the long term. In the face of this uncertainty, CPAU is able
to protect the financial position of the Gas Utility by continuing its current strategy of passing
these costs directly to its customers via month-varying rate adjustment mechanisms. The City
pursues a policy of purchasing offsets to make gas usage in Palo Alto carbon neutral. The cost is
not to exceed $0.10/therm.
Future CIP investment needs for the Gas Utility may be lower than in the past, although costs
per foot for main replacement have been increasing substantially. The Gas Utility has replaced
nearly all of its ABS gas mains and its most problematic steel and PVC mains as well. The PE pipe
being used now is expected to have at least a fifty-year lifetime, and there is growing evidence
that it may last much longer than that. This would result in lower CIP investment over the long
term. CPAU is considering performing a study in the near future to develop its future main
replacements priorities and strategy.
Long-term state or local climate goals could also have a major impact on the Gas Utility. The
Global Warming Solutions Act, Assembly Bill 32 (AB32), set a goal of reducing greenhouse gas
(GHG) emissions to 1990 levels by 2020. In its December 2007 Climate Protection Plan, the City
set a goal of lowering emissions to 15% below 2005 levels by 2020. As a community Palo Alto
achieved these goals in 2012 even with continued use of natural gas for heating, cooking, and
industrial processes. However, to achieve the recently adopted Sustainability and Climate
Action Plan (S/CAP) goal of an 80% reduction in carbon emissions by 2030, or the State’s
adopted goal of an 80% reduction in emissions by 2050, extensive electrification of gas-using
appliances is necessary. If significant amounts of electrification occurred, stranded investment
and higher rates could be required as the costs of the distribution system are recovered over a
lower sales base. It is instructional that, in the recent discussion draft of its scoping plan update,
CARB says, to meet those goals, natural gas use would have to be “mostly phased out.”13 Staff
intends to begin evaluating how to manage potential impacts of these trends over the next few
years.
13 Climate Change Scoping Plan, First Update, Discussion Draft for Public Review and Comment, California Air
Resources Board, October 2013, pg 88.
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SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: GAS PURCHASE COSTS
The Gas Utility purchases much of its gas for delivery at Malin, Oregon which is almost always
cheaper than delivery at PG&E Citygate, even including the costs of transmission from Malin to
Citygate. The Gas Utility purchases gas on a month-ahead and day-ahead basis in the spot
market. The last few years have seen gas prices in a relatively narrow but low band. In FY 2019,
however, lower levels of natural gas in storage , along with colder than normal weather and
pipeline constraints on both the northern and southern borders of California has created some
short term price spikes, as shown in Figure 9.
Figure 9: Gas Market Prices at PG&E Citygate
On September 15, 2014, Council adopted Resolution #9451 authorizing the City’s participation
in a natural gas purchase from Municipal Gas Acquisition and Supply Corporation (MuniGas) for
the City’s entire retail gas load for a period of at least 10 years. The MuniGas transaction
includes a mechanism for municipal utilities to utilize their tax exempt status to achieve a
discount on the market price of gas. As of November 1, 2018, gas began flowing under this
program, reducing the City’s gas commodity cost by about $1 Million per year and saving gas
customers approximately $0.03 per therm on the commodity portion of their bills.
Gas commodity costs are expected to increase slowly but steadily over the next several years.
Figure 10 shows the projected gas prices used to generate this forecast. Projections for
transmission costs associated with transporting gas over PG&E’s Redwood transmission
pipeline (from Malin, Oregon to the PG&E Citygate) are based on rates adopted in the most
recent update to the Gas Accord.
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Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary
adder to PG&E’s local transportation rate,14 but in December 2014 PG&E applied to the CPUC to
more than double local transportation costs. The application was not settled until late 2016. As
these charges are dictated by PG&E and are outside of Palo Alto’s control, staff proposed
making these costs pass-through charge, similar to the commodity charge, and this became
effective in November 2016.
Figure 10: Wholesale Gas Price Projections
SECTION 6B: OPERATIONS
Operations costs include the Customer Service, Demand Side Management, Operations and
Maintenance (including Engineering), Resource Management, and Administration categories in
Figure 11, below. Debt service, rent, and transfers are also included in Operations costs
(excluding the General Fund equity transfer). Appendix D: Description of Gas Utility Cost
Categories includes detailed descriptions of the activities associated with these cost categories.
Operations costs are generally projected to increase by 2 to 4% per year. Salary and benefits,
inflation, and other assumptions match those used in the City’s long-range financial forecast.
Operations costs for FY 2019 to FY 2021 include funding for the cross-bore program. In the
1970s CPAU, like many other utilities, adopted horizontal drilling as an alternative to trenching
when installing new gas services. This created the possibility of cross-bores, which can happen
when a gas service is bored through a sewer lateral. Though cross-bores are very rare, they can
create a dangerous situation when a contractor attempts to clear a blocked sewer line, because
if the cross-bored gas service is damaged during the line, clearing it can result in a gas leak.
14 California Public Utilities Commission Advice Letter 3430-G, effective January 1, 2014. Also see CPUC Decision
12-12-30 regarding the Pipeline Safety Enhancement Plan Adder.
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CPAU has been inspecting new gas services since 2001, and in 2011 began video inspections of
the sewer laterals at the location of horizontally-drilled gas services installed before 2001. This
inspection program has cost roughly $1 million per year since FY 2012. While a majority of
sewer laterals have been inspected, staff has come across several services which are not able to
be scoped, either due to infiltration by roots or broken/collapsed pipe segments. Staff has
included $3 million in additional funding between FY 2019 and FY 2021 for this program, but
the program will likely require additional funding in future years to complete.
Figure 11: Historical and Projected Operational Costs
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
The Gas Utility’s CIP program consists of the following programs and budgets:
• The Gas Main Replacement Program, under which the Gas Utility replaces aging gas
mains ranked to have the highest threat scores within the system.
• Customer Connections, which covers the cost when the Gas Utility installs new services
or upgrades existing services at a customer’s request in response to development or
redevelopment. The Gas Utility charges a fee to these customers to cover the cost of
these projects.
• Ongoing Projects, which covers the cost of routine meter, regulator, and service
replacement, minor projects to improve reliability or increase capacity, and other
general improvements.
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• Tools and Equipment, which covers the cost of capitalized equipment, such as
directional boring, gas pipeline maintenance and emergency equipment.
• One-time Projects, which represents occasional large projects that do not fall into any
other category.
Table 14 shows the current status of these project categories and future projected spending.
Table 14: Budgeted Gas CIP Spending ($000)
The Gas Main Replacement (GMR) Program is in the final stages of completing a major
milestone with the replacement of gas mains made from Acrylonitrile-Butadiene-Styrene (ABS)
plastic. The program to replace ABS and other low-performing materials within the gas system
started in the 1990s (see Section 4A: Gas Utility History for more detail). CPAU temporarily
slowed down its FY 2014 and 2015 CIP appropriations in this category in order to finalize the
last major ABS main replacement project and to catch up on projects that had accumulated due
to staffing issues. With the replacement of all ABS mains with Polyethylene (PE) plastic near
completion, the material most at risk for failure is the remaining Polyvinyl chloride (PVC) plastic
and steel (wrapped, with cathodic protection). The next focus of the GMR program will be the
replacement of all PVC mains with PE mains. CPAU is considering updating the Gas System
Master Plan to determine which sections of pipeline to prioritize and assist in determining the
pace of main replacement (approximately three miles of main each year, or 1.5% of the
system).
The current budget for the gas main replacement program takes into account the recent rise in
construction costs. Several factors are contributing to the increase in construction costs and
include economic recovery in the Bay Area, a greater focus on infrastructure improvement by
many municipal agencies, and the higher demand for utility contractors within these fields.
CPAU has seen the replacement cost per linear foot increase by 25% to 50% over the last
couple of years. The Gas Utility posted the most recent project for competitive bid (the
Upgrade Downtown Project) and this resulted in very few contractor bids and an eventual
contract price that was much higher than estimated (staff has requested $6.7 million additional
funding in FY 2018 related to this project) . Staff is beginning to include the higher construction
cost in future project estimates in order to maximize the amount of pipe replaced, as well as
insuring the overall integrity of the gas system. Currently, CPAU plans to replace as many aging
mains as possible within its current budget. However, if this trend of higher construction cost
continues, the Gas Utility may require larger CIP budgets and as a result, an increase in rates.
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
One Time Projects 42 (31) 10 - - - - - -
Gas Main Replacement 11,584 (6,714) 4,870 4,237 - 11,000 - 11,000 -
Tools And Equipment 379 (69) 311 48 120 120 100 100 103
Ongoing Projects 1,101 (52) 1,049 8 888 900 912 924 937
Customer Connections 1,344 (547) 797 71 1,342 1,383 1,424 1,467 1,511
TOTAL 14,450 (7,413) 7,037 4,364 2,350 13,402 2,436 13,491 2,551
*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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This financial plan addresses these challenges in a way that will allow CPAU to meet its main
replacement needs. This financial plan includes approximately $11 million every other year for
main replacement construction instead of $6.5 million annually. This shift to larger main
replacement construction projects every other year will lengthen the amount of time needed to
replace all PVC pipes in the system, but will attract more contractors to bid on the larger
projects. Additionally, this main replacement project schedule for gas will be staggered with
water and wastewater (water and wastewater construction every even year and gas
construction every odd year), which will ease scheduling difficulties for inspection coverage due
to shared inspection staff across water, wastewater, gas, and large development services
projects. However, if staff sees a greater rate of failure of existing pipe materials, CIP projects
may resume a more frequent schedule and may require additional rate funding needs.
There is no new main replacement budgeted in FY 2020. However, work will continue on
ongoing main replacement projects in FY 2020 and FY 2021. This staggered schedule for gas
main replacement will allow staff to focus on current priorities such as the Upgrade Downtown
project. As the staff vacancies become filled and construction costs stabilize, staff can re-
evaluate the need to return to an annual replacement program.
Staff projects ongoing projects, tools and equipment, and customer connections to cost
approximately $2.4 million in FY 2020 and remain relatively flat through the end of the forecast
period. In practice, these projects can fluctuate dramatically depending on prices of material,
system conditions and the pace of development and redevelopment in the city. It is worth
noting that fee revenue pays for the Customer Connections program, so when costs go up fees
will be adjusted as well.
Aside from customer connections and transfers from other funds, the CIP plan for FY 2020 to FY
2024 is funded by utility rates. Appendix B: Gas Utility Capital Improvement Program (CIP)
Detail shows the details of the plan.
SECTION 6D: DEBT SERVICE
The Gas Utility currently makes debt service payments on one bond issuance, the 2011 Series A
Utility Revenue Refunding Bonds. This bond issuance was to refinance the $18 million principal
remaining on the Utility Revenue Bonds, 2002 Series A issued for the Gas and Water Utilities to
finance various improvements to the distribution systems. $9.4 million of this issuance was
secured by the net revenues of the Gas Utility. Table 15 shows debt service for this bond for the
financial forecast period. Debt service on this bond will continue through 2026.
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Table 15: Gas Utility Debt Service
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
2011 Utility Revenue
Refunding Bonds, Series A
800 800 802 803 804 802
The 2011 bonds include two covenants stating that 1) the Gas Utility will maintain a debt
coverage ratio of 125% of debt service, and 2) that the City will maintain “Available Reserves”15
equal to five times the annual debt service. The current financial plan complies with these
covenants throughout the forecast period, as shown in Table 16 and Table 17.
Table 16: Debt Service Coverage Ratio ($000)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
Revenues 36,972 39,381 42,322 45,585 48,539 50,564
Expenses
(Excluding CIP and
Debt Service)
(26,265) (28,111) (28,851) (28,653) (29,400) (30,301)
Net Revenues 10,707 11,270 13,471 16,932 19,139 20,263
Debt Service 800 800 802 803 804 802
Coverage Ratio 1339% 1409% 1679% 2108% 2379% 2526%
Table 17: Debt Service Minimum Reserves ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Gas Utilitya 20,672 20,847 12,170 17,647 14,066 22,381
Debt Serviceb 800 800 802 803 804 802
Reserves Ratioc 26x 26x 15x 22x 17x 28x
a) CIP, Rate Stabilization, Operations, and Unassigned Reserves
b) Gas Utility’s share of the debt service on the 2011 bonds.
c) Calculated using only Gas Utility reserves. The actual reserves ratio for the 2011 bonds is calculated based on the
combined Electric, Gas, and Water Utility reserves and total debt service and is higher than shown here.
The Gas Utility’s reserves and net revenue are also pledged as security for the bond issuances
listed in Table 18, even though the Gas Utility is not responsible for the debt service payments.
The Gas Utility’s reserves or net revenues would only be called upon if the responsible utilities
are unable to make their debt service payments. Staff does not currently foresee this occurring.
15 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities
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Table 18: Other Issuances Secured by Gas Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Gas Utility’s:
Net Revenues Reserves
1995 Series A Utility
Revenue Bonds Storm Drain $680 Yes No
1999 Utility Revenue
Bonds, Series A
Wastewater Collection
Wastewater Treatment
Storm Drain
$1,207 No Yes
2009 Water Revenue
Bonds (Build America
Bonds)
Water $1,977* No Yes
*Net of Federal interest subsidy
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Gas Utility based on a methodology adopted by
Council in 2009 that has remained unchanged since.16 Each year it is calculated according to the
2009 Council-adopted methodology, and does not require additional Council action.
SECTION 6F: REVENUES
The Gas Fund receives most of its revenues from sales of gas, but about 8% comes from other
sources. The largest of these comes from sales of allowances related to California’s cap-and-
trade program followed closely by service connection and capacity fees. Another revenue item
related to the cap-and-trade program is collected in customers’ bills. While the State provides
CPAU with a certain number of free allowances each year, the Gas Utility is required to sell a
portion of those in accordance with the regulations. In order to have enough allowances to
cover customers’ natural gas emissions, CPAU must buy allowances at market, and
subsequently passes through the cost of those allowances to customers. The regulations do not
allow the revenue derived from the sale of the free allowances to offset allowance purchases,
thus the pass-through rate component.
This financial plan bases sales revenue projections on the load forecast in Section 5A: Load
Forecast. Except where stated otherwise, these load forecasts are based on normal weather.
Weather can vary substantially, however, and this can affect revenues substantially. Also,
changes in customer behavior, as well as changes to more efficient gas appliances, or switching
to electric appliances, will modify these forecasts. Staff continually evaluates forecasts to see
when new trends emerge.
16 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to equity transfer methodology.
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SECTION 6G: COMMUNICATIONS PLAN
The FY 2020 Gas Utility communications strategy covers these primary areas: operations,
infrastructure, safety, efficiency, renewables, rates, and cost containment measures. The City of
Palo Alto Utilities (CPAU) communication methods include use of the Utilities website, utility bill
inserts, messaging on bills and envelopes, email newsletters, print and digital ads in local
publications, videos and participation in community outreach events. Since moving to market
pricing for commodity rates, the City of Palo Alto Utilities (CPAU) commodity rates can change
monthly. Staff post these updates to the Utilities rates webpages. Consistent with the newly
approved Utilities Strategic Plan, CPAU is instituting cost containment as an ongoing priority
that is part of our annual cycle.
In FY 2020, CPAU is proposing a 5 percent overall rate increase for the gas utility. However, we
anticipate that gas distribution rates will need to increase about 11% in FY 2020 due to a
resumption in capital improvement projects and an increase in commodity charges. Such
maintenance and operations projects are important to maintain a safe and reliable gas
distribution system. To keep customers apprised of the status and accomplishments of capital
improvement projects, the City maintains a network of project web pages. Print and digital ads,
social media and email blasts drive traffic to the website.
CPAU promotes gas use efficiency incentives year-round, but most heavily during winter
months to impact heating activities. CPAU continues to look for more ways to promote gas use
efficiency and awareness of the City’s carbon neutral natural gas utility. Programs such as the
Home Efficiency Genie and commercial energy efficiency programs help residents and
businesses better understand energy usage, activities and/or upgrades they can implement to
improve efficiency and keep utility costs low. CPAU will be launching an upgraded version of its
online utility account services portal this year, which can provide customers with direct access
and more information about utility account and consumption data.
CPAU emphasizes safety for all utility services year-round. Stepping up efforts to promote gas
safety education, staff is focusing outreach among stakeholders to increase awareness of the
need to call USA (811) before digging for anyone who may excavate in and around Palo Alto,
such as plumbers and contractors. Staff is also focusing outreach on the importance of
contacting CPAU to check for potential sewer and gas line cross-bores prior to clearing a sewer
line. Additional outreach messaging includes keeping fats, oils and greases out of drains, and
ensuring clear access to meters. CPAU has developed a number of safety outreach materials to
distribute to customers at community outreach events, emergency preparedness fairs, school
and business meetings.
CPAU will continue to promote safety, infrastructure, operations, efficiency and rate
adjustment messages through a variety of marketing and media channels. Every year, CPAU
publishes an updated gas safety awareness brochure and mails it to all customers in Palo Alto,
as well as to emergency responders, public officials, plumbers, contractors and excavators that
may work in and around the area. Staff talk with business customers at special facilities
meetings, attend neighborhood safety and emergency preparedness fairs and offer
presentations to school and community groups. While print materials and website pages still
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feature prominently, CPAU is increasing emphasis on outreach through email newsletters,
direct mail, newspaper inserts, social media and online videos. The Gas Safety Public Awareness
Plan contains saved copies of all outreach materials and logs of activities; the Department of
Transportation typically reviews this Plan at least once per year.
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APPENDICES
Appendix A: Gas Financial Forecast Detail
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
Appendix C: Gas Utility Reserves Management Practices
Appendix D: Description of Gas Utility Cost Categories
Appendix E: Gas Utility Communications Samples
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APPENDIX A: GAS FINANCIAL FORECAST DETAIL
Actual Actual
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
1 RATE CHANGE (%)*0%0%0%8%0%4%5%8%8%6%4%
2 SALES IN THOUSAND THERMS 28,117 28,881 26,719 28,146 28,314 27,921 27,725 27,531 27,339 27,147 26,957
3
4 Utilities Retail Sales 34,843 29,515 28,065 34,110 34,056 33,548 35,480 37,946 40,956 43,271 44,892
5 Service Connection & Capacity Fees 654 748 961 940 1,078 1,079 1,111 1,145 1,179 1,179 1,179
6 Other Revenues & Transfers In 313 414 2,346 694 1,739 1,871 2,404 2,806 3,233 3,683 4,154
7 Interest plus Gain or Loss on Investment 706 450 730 13 26 474 386 425 217 406 339
8 Total Sources of Funds 36,517 31,127 32,102 35,758 36,899 36,972 39,381 42,322 45,585 48,539 50,564
9
10 Purchases of Utilities:
11 Supply Commodity & Cap and Trade 12,992 9,537 9,178 9,720 9,698 9,514 10,009 10,279 10,550 10,871 11,404
12 Supply Transportation 1,333 982 (1,051)2,843 3,223 3,507 4,354 4,450 4,625 4,705 4,719
13 Total Purchases 14,325 10,519 8,127 12,563 12,921 13,022 14,362 14,729 15,174 15,576 16,122
14
15 Administration (CIP + Operating)3,988 3,764 2,881 2,553 3,598 3,682 3,790 3,880 3,967 4,057 4,149
16 Customer Service 1,338 1,421 1,364 1,441 1,508 1,551 1,632 1,684 1,732 1,782 1,833
17 Demand Side Management 438 632 566 855 826 845 870 890 910 931 952
18 Engineering (Operating)352 369 426 355 351 360 373 383 393 403 413
19 Operations and Maintenance 4,119 4,403 4,153 4,321 4,620 5,747 5,988 6,157 5,318 5,462 5,611
20 Resource Management 516 556 472 566 357 441 463 477 491 505 519
21 Debt Service Payments 805 803 248 226 203 800 800 802 803 804 802
22 Rent 419 431 443 455 602 618 634 651 668 685 704
23 Transfers to General Fund 5,811 5,730 6,194 6,726 6,699 6,601 7,106 7,088 7,343 7,536 7,688
24 Other Transfers Out 606 151 303 510 808 824 840 856 872 889 906
25 Capital Improvement Programs 1,026 1,832 6,889 2,214 7,804 5,567 2,350 13,402 2,436 13,490 2,551
26 Total Uses of Funds 33,743 30,611 32,066 32,785 40,297 40,057 39,206 50,999 40,108 52,120 42,249
27
28 Into/ (Out of) Reserves 2,773 516 36 2,972 (3,397)(3,084)175 (8,677)5,477 (3,581)8,315
29
30 Reappropriations + Commitments 11,305 6,491 6,255 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209
31 Plant Replacement 0 0 0 0 0 0 0 0 0 0 0
Debt Service Reserve 826 826 816 813 795 795 795 795 795 795 795
32 CIP Reserve 0 1,591 3,820 3,820 3,820 3,820 9,820 600 5,100 1,100 9,100
33 Rate Stabilization 15,981 7,215 6,018 6,539 7,090 6,363 0 0 0 0 0
34 Operations Reserve 0 10,847 10,296 13,549 8,638 6,281 6,818 7,361 8,338 8,757 9,072
35 Unassigned 0 0 0 0 0 0 0 0 0 0 0
36 Total Reserves 28,112 26,970 27,205 28,930 24,551 21,466 21,641 12,964 18,441 14,860 23,175
37 (1,142)236 1,725 (4,379)(3,084)175 (8,677)5,477 (3,581)8,315
38 Short Term Risk Assessment Value 1,226 3,753 3,516 4,051 3,941 3,872 5,399 4,777 6,230 5,359
39
40 Operations Reserve Guidelines
41 Min (60 Days Commodity + O&M) 5,616 5,000 5,585 5,171 5,718 6,062 6,150 6,124 6,240 6,372
42 Target (90 Days Commodity + O&M) 8,424 7,500 8,377 7,756 8,577 9,093 9,225 9,186 9,360 9,557
43 Max (120 Days Commodity + O&M) 11,233 10,000 11,169 10,341 11,437 12,124 12,300 12,248 12,481 12,743
44
City of Palo Alto
Gas Utility
Fiscal Year
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APPENDIX B: GAS UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
ONE TIME PROJECTS
GS-15001 Security at Receiving Stations 41,534 - - (31,134) 10,400 - - - - - -
Subtotal, One-time Projects 41,534 - - (31,134) 10,400 - - - - - -
GAS MAIN REPLACEMENT (GMR) PROGRAM
GS-11000 GMR - Project 21 100,000 - - - 100,000 - - - - - -
GS-12001 GMR - Project 22 8,633,799 800,000 - (6,651,737) 2,782,062 2,737,035 - - - - -
GS-13001 GMR - Project 23 - 550,000 - (61,950) 488,050 - - 10,000,000 - - -
GS-14003 GMR - Project 24 - - - - - - - 1,000,000 - 10,000,000 -
GS-15000 GMR - Project 25 - - - - - - - - - 1,000,000 -
GS-18000 Gas ABS/Tenite Replacement - 1,500,000 - - 1,500,000 1,500,000 - - - - -
Subtotal, Gas Main Replacement Program 8,733,799 2,850,000 - (6,713,687) 4,870,112 4,237,035 - 11,000,000 - 11,000,000 -
TOOLS AND EQUIPMENT
GS-13002 General Shop Equipment/Tools - 350,000 - (66,642) 283,358 40,613 100,000 100,000 100,000 100,000 103,000
GS-14004 Gas Distribution System Model 9,357 20,000 - (2,157) 27,200 7,200 20,000 20,000 - - -
Subtotal, Tools and Equipment 9,357 370,000 - (68,799) 310,558 47,813 120,000 120,000 100,000 100,000 103,000
Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
ONGOING PROJECTS
GS-11002 Gas System Improvements 7,979 246,036 - - 254,015 7,979 500,000 500,000 500,000 500,000 500,000
GS-03009 System Ext. - Unreimbursed - 421,180 - (24,814) 396,366 - - - - - -
GS-80019 Gas Meters and Regulators 48,804 376,652 - (26,972) 398,484 - 387,952 399,591 411,579 423,926 436,644
Subtotal, Ongoing Projects 56,783 1,043,868 - (51,786) 1,048,865 7,979 887,952 899,591 911,579 923,926 936,644
CUSTOMER CONNECTIONS (FEE FUNDED)
GS-80017 Gas System Extensions 40,991 1,303,315 - (547,144) 797,162 71,093 1,342,415 1,382,688 1,424,169 1,466,894 1,510,901
Subtotal, Customer Connections 40,991 1,303,315 - (547,144) 797,162 71,093 1,342,415 1,382,688 1,424,169 1,466,894 1,510,901
GRAND TOTAL 8,882,464 5,567,183 - (7,412,550) 7,037,097 4,363,920 2,350,367 13,402,279 2,435,748 13,490,820 2,550,545
Funding Sources
Connection Fees 1,017,000 - 1,047,510 1,078,935 1,111,303 1,144,642 1,178,981
Utility Rates 4,550,183 - 1,302,857 12,323,344 1,324,445 12,346,178 1,371,564
CIP-RELATED RESERVES DETAIL
6/30/2018
(Actual)
6/30/2019
(Unaudited)
Reappropriations 808,464 2,673,177
Commitments 8,074,000 4,363,920
GAS UTILITY FINANCIAL PLAN
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APPENDIX C: GAS UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Gas Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY
2015 to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Gas Utility’s Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
Section 3. Distribution Fund Reserves
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Gas Utility’s Capital
Improvement Program (CIP), as described in Section 6 (CIP Reserve)
d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 8 (Operations Reserve)
f) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 9 (Unassigned Reserves)
Section 4. Reserve for Commitments
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Commitments will be set to an amount equal to the total remaining spending authority for
all contracts in force for the Wastewater Collection Utility at that time.
Section 5. Reserve for Reappropriations
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Reappropriations will be set to an amount equal to the amount of all remaining capital and
GAS UTILITY FINANCIAL PLAN
M a r c h 2019 38 | P a g e
non-capital budgets, if any, that will be re-appropriated to the following fiscal year for each
fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 12 months of budgeted CIP expense
Maximum Level 24 months of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve
for Commitments as a result of a change in contractual commitments related to CIP
projects. Any other additions to or withdrawals from the CIP reserve require Council
action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek Council approval to
hold funds in this reserve in excess of the maximum level, if they are held for a specific
future purpose related to the CIP.
Section 7. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and held
to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate
Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization
Reserve at the end of any fiscal year, any subsequent Gas Utility Financial Plan must result
in the withdrawal of all funds from this Reserve by the end of the Financial Planning Period.
GAS UTILITY FINANCIAL PLAN
M a r c h 2019 39 | P a g e
Section 8. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves
described in Section 4-Section 7 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for
that year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months
of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Gas Utility’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
9, below.
Section 9. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas
Utility’s Fund Balance will be held in the Unassigned Reserve. If there are any funds in the
Unassigned Reserve at the end of any fiscal year, the next Financial Plan presented to the
City Council must include a plan to assign them to a specific purpose or return them to the
Gas Utility ratepayers by the end of the first fiscal year of the next Financial Planning Period.
For example, if there were funds in the Unassigned Reserves at the end of FY 2015, and the
next Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a
plan to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff
may present an alternative plan that retains these funds or returns them over a longer
period of time.
GAS UTILITY FINANCIAL PLAN
M a r c h 2019 40 | P a g e
Section 10. Intra-Utility Transfers Between Supply and Distribution Funds
The Gas Utility records costs in two separate funds: the Gas Supply Fund and the Gas
Distribution Fund. At the end of each fiscal year staff is authorized to transfer an amount
equal to the difference between Gas Supply Fund costs and Gas Supply Fund Revenues from
the Gas Distribution Fund Operations Reserve to the Gas Supply Fund, or vice versa. Such
transfers shall be included in the ordinance closing the budget for the fiscal year.
GAS UTILITY FINANCIAL PLAN
M a r c h 2019 41 | P a g e
APPENDIX D: DESCRIPTION OF GAS UTILITY COST CATEGORIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Gas Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process. It
does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their gas services.
Resource Management: This category includes gas procurement, contract management, rate
setting, and tracking of legislation and regulation related to the gas industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
• surveying the gas system (50% of the system each year) and repairing any leaks found;
• investigating reports of damaged mains or services and perform emergency repairs;
• building and replacing gas services for new or redeveloped buildings; and
• testing and replacing meters to ensure accurate sales metering.
This category also includes a variety of functions the utility shares with other City utilities,
including:
• the Field Services team (which does field research of various customer service issues);
• the Cathodic Protection team (which monitors and maintains the systems that prevent
corrosion in metal pipes and reservoirs); and
• the General Services team (which manages and maintains equipment, paves and
restores streets after gas, water, or sewer main replacements, and provides welding
services, including certified gas line welding services)
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services and Utilities
Department administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering gas efficiency programs and the
direct cost of rebates paid.
Engineering (Operating): The Gas Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX E: GAS UTILITY COMMUNICATIONS SAMPLES
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Attachment C
* NOT YET APPROVED *
Resolution No. _________
Resolution of the Council of the City of Palo Alto Increasing Gas
Rates by Amending Rate Schedules G-1 (Residential Gas Service),
G-2 (Residential Master-Metered and Commercial Gas Service), G-3
(Large Commercial Gas Service), and G-10 (Compressed Natural Gas
Service Service)
R E C I T A L S
A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
B. On ____, 2019, the City Council heard and approved the proposed rate increase
at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-1 (Residential Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-1, as amended, shall become effective July 1, 2019.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-2 (Residential Master-Metered and Commercial Gas Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule G-2, as amended, shall
become effective July 1, 2019.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-3 (Large Commercial Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-3, as amended, shall become effective July 1, 2019.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-10 (Compressed Natural Gas Service Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule G-10, as amended, shall become effective
July 1, 2019.
SECTION 5. The City Council finds as follows:
a. Revenues derived from the gas rates approved by this resolution do not exceed the
funds required to provide gas service.
b. Revenues derived from the gas rates approved by this resolution shall not be used
for any purpose other than providing gas service, and the purposes set forth in
Article VII, Section 2, of the Charter of the City of Palo Alto.
Attachment C
* NOT YET APPROVED *
SECTION 6. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
SECTION 7. The Council finds that the adoption of this resolution changing gas rates
to meet operating expenses, purchase supplies and materials, meet financial reserve needs and
obtain funds for capital improvements necessary to maintain service is not subject to the
California Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec.
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After reviewing
the staff report and all attachments presented to Council, the Council incorporates these
documents herein and finds that sufficient evidence has been presented setting forth with
specificity the basis for this claim of CEQA exemption.
Attachment C
* NOT YET APPROVED *
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
Overview of Gas Utility Hedging Program
Natural gas commodity prices depend on market supply and demand balances and can be unpredictable
and volatile. Gas market price increases during the energy crisis drained approximately $8 million from
the Gas Supply Rate Stabilization Reserve and required four large rate increases in fiscal year 2001. As a
result, the City of Palo Alto initiated a rate stabilization program whereby a portion of gas needs were
purchased at fixed and capped prices over a rolling 36-month time horizon. That hedging strategy was
implemented for about 10 years until shale production shifted the supply/demand balance, market
prices decreased, and City Council became concerned that Palo Alto’s gas rates were higher than rates in
neighboring communities served by PG&E.
In 2011, Council approved a monthly pass-through market-based gas commodity rate. The revised policy
was driven by several factors:
1. Over the long term, the cost of Palo Alto’s gas portfolio will be equal to the gas market
regardless of the hedging strategy;
2. A monthly pass-through rate maintains parity with PG&E;
3. Gas bills vary dramatically by season due to usage patterns much more than they vary due to
commodity rate changes;
4. Market-based rates are more likely to reflect the state of the overall economy thus giving
customers a break during downturns;
5. The need for financial reserves is reduced; and
6. Simplifying the portfolio saves staff time.
Staff Report #21061 is the Finance Committee recommendation to Council to abandon the hedging
program and move to pass-through rates. The report includes more historical context, a robust analysis
of market price volatility, and the impact to customer bills.
The resulting revisions to the Gas Utility Long-term Plan are described in Staff Report #2552.2
1 https://www.cityofpaloalto.org/civicax/filebank/documents/42836
2 https://www.cityofpaloalto.org/civicax/filebank/documents/41656
• CITY OF
PALO
ALTO
TO:
FROM:
CITY OF PALO AL TO
MEMORANDUM
FINANCE MEETING ~
5/15/2019 3
0 Received Before Meeting
HONORABLE CITY COUNCIL, FINANCE COMMITTEE
City Manager DEPARTMENT: Planning & Community
Environment
AGENDA DATE: May 15, 2019
SUBJECT: FY 2020 Proposed Operating Budget -Planning & Community
Environment Department Reorganization
The FY 2020 Proposed Operating Budget reflects recommended changes in departmental
structures including establishing the Office of Transportation and the merging of the
former Development Services Department _with the Planning & Community Environment
Department. The FY 2020 Proposed Operating Budget, released April 22, 2019, reflects
these organizational changes at a macro level; however, refinements to staffing
complements remain necessary to ensure a successful and sustainable allocation of
resources. Below are the recommended further transactions in order to complete the
merger of the former Development Services Department with the Planning & Community
Environment (PCE) Department. This memorandum should be reviewed as a supplement,
or amendment to the FY 2020 Proposed Operating Budget pages 295-312.
This reorganization will assist in merging the functions, while maintaining the
Development Center "one stop shop" and fostering a structure that encourages recruiting
and retaining staff through succession planning, as previously initiated in the Planning
Division in FY 2019. The Planning Division has struggled to recruit and retain key staffing,
this proposed structure is intended to allow new managers to develop their skills as
Principal Planners before rising higher in the leadership team. The chart below looks at
the recommended changes to staffing levels:
Proposed Changes to the FY 2020 PCE Staffing
Position Deletions Position Additions ------Job Classification FTE Job Classification FTE
Business Analyst -1.00 Manager Planning 2.00
Development Services Director -1.00 Principal Planner 1.00
Manager Development Center -1.00 Program Assistant 1.00
Planning Division Manager -1.00 Senior Business Analyst 1.00
Principal Management Analyst* 1.00
Changes in Full Time Staffing -4.00 6.00
Clerical Assistant (PT) -0.20
Management Specialist (PT) -0.30
Staff Specialist (PT) -0.96
Changes in Part-time Staffing -l.46
Total Net Position Change -5.46 6.00
* Limited term ending June 30, 2020.
A net addition of 2.0 full time positions are recommended to be added in FY 2020;
however, only 1.0 of those positions is ongoing. A limited ferm Principal Management
Analyst, to be funded 50% by development services fees and 50% by the General Fund, is
recommended to assist the department during this transition period. This position will
assist with settling all administrative financial structures as well as a potential for a new
fee study to assess the cost of services under this new model.
Overall, this model brings balance to the merger under the direction of one Department
Director and one Assistant Director. Redundancies in administrative staffing were already
allocated to the establishment of the Office of Transportation (1.0 Management Analyst,
and 1.0 Administrative Assistant) in the FY 2020 Proposed Operating Budget. The actions
recommended in this reorganization take account of this change in business staffing
through the elimination of part-time staffing and higher-level management positions to
allocate resources back to direct services such as program assistance and planning
assistance. For example, instead of various part-time staffing positions, it is
recommended that these be eliminated and consolidated into a full time Program
Assistant. The higher-level management positions, such as the Development Services
Director and recently added Planning Division Manager (which was never filled), will be
eliminated to realign staffing under the two existing division manager positions in PCE,
the "Chief Planning Official" and "Chief Building Official," and rely more on lower level
staffing such as the Planning Manager and Principal Planner classifications. This will allow
staff to be more program centered and assist in services that may include, but are not
limited to, urban design expertise, currently primarily performed by consultants on an ad
hoc basis.
Overall, this reorganization is anticipated to increase costs in FY 2020 by $200,000 in all
funds, approximately $300,000 in the General Fund. Of the General Fund costs, $50,000
will be offset by fees for services related to the Development Center resulting in a net
cost of $250,000 in the General Fund in FY 2020. Once the limited term Principal
Management Analyst position sunsets, this staffing realignment is forecasted to be
neutral across all funds expense estimates. In the General Fund, ongoing additional costs
of $41,000 are expected. However, in order to align resources allocated to fees for
services related to the Development Center, a loss of $85,000 in revenues is expected as
well resulting in a net impact of $125,000 to the General Fund beginning in FY 2021. These
estimates presume that development related services remain at a 100% cost recovery
levels.
With the Office of Transportation now separate, this reorganization eliminates all prior
allocations of resources to transportation related funding sources including resources
allocated to various Parking Funds, a cost reduction of $28,000, and all resources
allocated to the General Capital Improvement Fund, a cost reduction of $63,000.
Should these changes be approved, staff will recalculate the financial changes by
department, by fund, by budget group, as per the appropriation limits in the municipal
code, for inclusion in the budget wrap-up memorandum for final review by the Finance
Committee on May 28, 2019.
Kiely Nose
Director/CFO, Administrative Services
Ed Shikada
City Manager
• CITY OF
PALO
ALTO
TO:
FROM:
CITY OF PALO AL TO
MEMORANDUM
HONORABLE CITY COUNCIL, FINANCE COMMITIEE
FINANCE MEETING ~
5/15/2019 3
0 Received Before Meeting
City Manager DEPARTMENT: Office of Transportation
AGENDA DATE: May 15, 2019
SUBJECT: FY 2020 Proposed Operating Budget -Office of Transportation,
Transportation Management Association (TMA) Funding Request
On April 16, 2019 the Finance Committee reviewed a request by the Transportation
Management Association (TMA) for additional funding (up to $720,000 annually). The
request can be found in the CMR# 10198 (link below), and the presentation provided by
the TMA is attached to this memorandum, Attachment A.
CMR #10198: https://www.cityofoaloalto.org/civicax/filebank/documents/70194
The Finance Committee requested that staff provide analysis outlining the implications of
providing additional funding to the TMA on parking rates, assuming the additional funding
would be fully funded by additional new revenues. Currently, the Palo Alto TMA is
receiving annual support from the City in the a~mount of $480,000 which is funded
through the University Avenue Parking Fund through parking permit revenues. The
analysis below provides a few options for the Finance Committee review including the
current parking permit pricing to accommodate this additional funding request. These
are not intended to be absolute options, but rather provide different scenarios for the
Finance Committee to consider.
Scenario A: no change in employee parking permit rates, use fund balance in the
University Avenue Parking Fund which is currently at $3.1 million as of June 30, 2018.
Scenario B: Increase employee parking permit rates approximately 5%, providing the
TMA additional funding of $120,000, a total of $600,000 annually.
Scenario C: Increase employee parking permit rates approximately 7.5%, providing the
TMA additional funding of up to $180,000, a total of $660,000 annually. (The majority
of City fees are recommended to increase 7.5% in FY 2020, this just models a similar
assumption for comparison and context).
Scenario D: Increase employee parking permit rates approximately 10%, providing the
TMA additional funding of approximately $240,000, a total of $720,000 annually.
In alignment with the current practice and the Finance Committee, the scenarios above
assume that the fee increase to accommodate the TMA max request would be funded
solely from the University Avenue Parking fund. However, in order to not incentivize
employee permit holders to park in residential areas, past practice has held employee
permit prices consistent between the garage and surface lot permits and the Residential
Preferential Parking (RPP) permits. This chart below assumes this practice would continue
and models the employee parking permit rates for the scenarios above.
I ·1-Parking Area Scenario A: Scenario B: l Scenario C: Scenario D: j
Current Permit +5% increase +7.5% increase +10% Increase
Downtown Core $750/yr $788/yr $806/yr $825/yr I ---·-$825/yr I Downtown RPP $750/yr $788/yr $806/yr
California Avenue $375/yr $394/yr $403/yr $412/yr I
I ~
Evergreen Park/Mayfield RPP $375/yr $394/yr $403/yr $412/yr
Southgate RPP $375/yr $394/yr $403/yr $412/yr
This analysis assumes no changes in other permits such as the daily permit fee and that
approximately 3,300 employee permits will be issued annually in the downtown core. The
data integrity of the parking permits continues to be a challenge as many processes are
currently manual. Staff anticipates that this information will become more readily
available with the implementation of a more efficient and comprehensive parking permit
system in the future.
Other considerations for this funding request may include:
Expanding funding beyond the University Avenue Parking Fund and providing both
funding and services to the California Avenue area.
Increasing the cost will require an increase in City costs, as approximately
$354,000 is contributed for City employee permits annually.
If past practice continues and employee· parking rates increase to remain
consistent across garage, surface lot, and RPP permits, any increased revenues in
other programs, such as the RPP program, would first be allocated to those funds
to assist in offsetting operating losses in those operations.
This memorandum should be reviewed as a supplement to the FY 2020 Proposed
Operating Budget pages 93-107.
Kiely Nose
Director/CFO, Administrative Services
ATTACHMENT A: TMA Funding Presentation
Ed Shikada
City Manager
~lfoTMA
o FY 2020 Budget Request to City
o From $480K {flat} to $720K (503 growth}
o Cal Ave Pilot is walled off from downtown
o Provide ROI info to inform decision making
o Parking structs, va1et parking, etc
Sub-type I 2015 sov 300~ Target
reduction sov
Service workers 74% -22% 52%
Govt worker 59% -18% 41 %
Light office 69% -21% 48%
Tech worker 33% -10% 23%
source: bit.ly/PATMA2018report, appendix E
o Goal: 303 downtown commute reduction
o Transit passes, after-hours Lyft, Scoop, Waze
o US TDM social equity leader
o Jan 14 Council: create an employer pgm
2018 sov
56%
53%
67%
28%
Formation & funding
Emeryville TMA $4.2M 82% $3.4M Business Improvement District (BID)
Mission Bay TMA $1.7M 91% $1.SM property assessments
MtnViewTMA $1.4M 65% Employers: transit service agreement funds
San Leandro TMO $1.3M 77% $780K BID
Berkeley Gateway TMA $296K 91% Bayer HealthCare & Wareham Devt fund it
West Alameda TMA $224K 60% Property assessments fund
TMASF $799K SF TOM reqt => 82 bldgs formed & fund.
Contra Costa Centre (estimate) $309K 31% 14 property owners formed. TDM District.
Moffett Park Biz Group $168K Formed by employers. Member dues fund.
Alameda (Point) TMA $98K Property assessment funds
source: ALTRANS review of Bay Area TMAs
o TMAs form for buses or large bldgs/parcels
o 7 govt-imposed funding, 3 self-fund
o Except PATMA. Non-resident SOY (U. Ave pkng fund)
$480 ,000 (non-residents)
$720,000 ~~::..~ ...... """'
$1.2M
$1.74M
o $120,000 overhead
o $1,800 per car
o public policy can lower
o Proven 439 cars·
o 366 dntn, 73 Cal Ave
o Will pursue grant funding
PATMA
200cars ~ ~ ~~
333cars ~
600 cars A~ ~ ~ ~~~
900cars ~ ~ ~ ~~~
o 375 Hamilton Garage
o $139,000/space + $8,252/space/year
o Lot R valet: $2,263/space/year, Lot S: $783
o TMA: $1,800/car removed/year(+ climate/traffic benefits)
Feb March Apr May June July Aug
#passes 45 73 80 80 80 80
o Funders (Facebook/Palantir) require separate project
o Separate accounting, staff, etc
o To prove transit pass program scales
o The City can help prioritize where to remove cars in PA
o Downtown, Cal Ave, T&C, PAUSD, JCC, child care, dentists
o Will pursue external funding -no guarantee
o No additional budget request to City
o Employers with commute programs have 213 lower SOV (SMC}
o Modes: Transit, bike, e-bike/scooter/skateboard, Scoop, Waze
o Employers w I 20 to 2,000 employees are persuaded to join
o Hotel Parmani required to participate! (policy beats persuasion)
o Annual fee per employee plus a la carte
o Commuters earn vouchers for PA merchants (recycle incentive$}
o $100 meal during "commuter acquisition"
o Lower "maintenance" incentives
o Replace current Scoop/Waze direct subsidy expenditure
o Automated reporting of each green trip
o Verification of conversion away from SOV.
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o Negotiated 333 Scoop cost reduction
o $95/hour PATMA Exec Dir is a bargain
o Compared to $225/hour at some TMAs
o 433 staffing cost reduction is underway
o Entrepreneurial stage of lifecycle
o No peer TMAs
o Increased our staff hours to grow
o Throttling expenses back down thru July 1
o Otherwise, we run out of money
CY2018 Expense, Revenue, Transit passes
-Expenses -Revenue • Transit passes
$80,000 ------250
200 $60,000 --/----'AL._ ____ _
150
$40,000 / ~~~--·~~~~~~~~~~~~~~ •
100
$20,000 50
$0 0
Jan Feb March April May June July August Sept Oct Nov Dec
o Lower-cost staff hours. Fewer Exec Dir hours
o $9 5/hr TMA Exec Dir vs $225 for Emeryville
o $55K Feb programs o higher than revenue
o Transit pass attrition (no new passes)
o Can re-grow in future
o Keep Waze & Scoop
o Averse reaction when you cut
o For 2019, replace $39K commute web survey
PATMAstaff
Low-income transit passes
Scoop rideharing
Waze Carpool
After-hours low-income Lyft
Rent
Total Expenses
Monthly revenue
Net/Total
Cash balance
o with $0 front door intercepts (validate web survey)
Feb'19
$17,879
$37,010
$11,544
$4,500
$1,595
$1,000
$73,527
$45,000
-$28,527
$100,613
Cars cut July '19 Cars cut
$10,360
245 $20,963 135
71 $11,544 71
43 $4,500 43
7 cut 0
$1,000
$48,367
$45,000
366 -$3,367 249
$31,846
o Cut Scoop, Waze & Lyft in April
o Stabilize transit at financial break-even level
o Result: 200 cars off road {via transit passes)
720K/yr funding $60K mo I Cars cut
PATMAstaff $10,360
transit passes $32,843 I 223
Scoop $1 1,544 I 71
Waz.e Carpool $4 ,500 43
Lyft cut 0
Rent $1 ,000
o 337 cars removed Tot Expense $60,247
Mo. revenue $60,000
Net/Total I -$247 I 337