HomeMy WebLinkAbout2017-05-18 Finance Committee Agenda PacketFinance Committee
1
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May 18, 2017
Special Meeting
Council Chambers
2:00 PM
Agenda posted according to PAMC Section 2.04.070. Supporting materials are available in
the Council Chambers on the Thursday 10 days preceding the meeting.
PUBLIC COMMENT
Members of the public may speak to agendized items. If you wish to address the Committee on any issue that is on this agenda, please complete a speaker request card located on the table at the entrance to the Council Chambers/Community Meeting Room, and deliver it to the Clerk prior to discussion of the item. You are not
required to give your name on the speaker card in order to speak to the Committee, but it is very helpful.
Call to Order
Oral Communications
Members of the public may speak to any item NOT on the agenda.
Action Items
1.May 9th Budget Hearing Continuation 2:00-2:30PM
2.Fiscal Year 2018 Proposed Municipal Fee Schedule 2:30-3:30PM
3.General Fund Capital 3:30-5:30PM
a)Buildings and Facilities, Capital Budget (pp. 73-141)
b)Parks and Open Space, Capital Budget (pp. 147-225)
c)Streets and Sidewalks, Capital Budget (pp. 227-249)
d)Traffic and Transportation, Capital Budget (pp. 251-289)
e)Cubberley Infrastructure, Capital Budget (pp. 295-316)
4.Utilities Department 5:30-6:30PM
a)Electric Fund
i. Operating Budget (pp. 411-425)
ii. Capital Budget (pp. 343-427)
b)Fiber Optics Fund
i. Operating Budget (pp. 427-434)
ii. Capital Budget (pp. 429-443)
c)Gas Fund
i. Operating Budget (pp. 435-447)
ii. Capital Budget (pp. 445-479)
d)Wastewater Collection Fund
i. Operating Budget (pp.449-458)
ii. Capital Budget (pp. 495-523)
PROPOSED CAPITAL
PROPOSED OPERATING
MEMO A
MEMO B
2 May 18, 2017
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.
e)Water Fund
i. Operating Budget (pp. 459-472)
ii. Capital Budget (pp. 553-596)
5.Utility Rate Review and Approval 6:30-7:30PM
(Includes Agenda Item Numbers 6-8)
6.Utilities Advisory Commission Recommendation That the City Council
Adopt 1) a Resolution Approving the Fiscal Year 2018 Electric Financial
Plan, and 2) a Resolution Increasing Electric Rates by Amending the
E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU and E-14
Rate Schedules
7.Utilities Advisory Commission Recommendation That the City Council
Adopt a Resolution Approving the Fiscal Year 2018 Gas Utility Financial
Plan with no Changes to Distribution Rates
8.Follow-up Information on Water Utility Rate Comparisons
9. Wrap-Up 7:30-9:30PM
Future Meetings and Agendas
Adjournment
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Finance Committee Items Tentatively Scheduled
Meeting
Date
Line No. Item Title Referral Date
6/6/2017 1 3rd Quarter Financial Status Report
2 Recommendations on Proposed Fiscal Year 2018 Community Development
Block Grant Funding Allocations and the Draft Fiscal Year 2018 Annual Action
Plan (Planning)
12/5/2017 3 Presentation of FY2017 CAFR
MEMO
MEMO
City of Palo Alto
Council & Finance Committee Budget Hearings
Fiscal Year 2018 Budget Process
Meeting Agenda
Mon, 4/17
City Council
6:00PM,
Chambers
City Manager Comments reviewing the upcoming Proposed Operating and Capital Budgets
and Finance Committee schedule for review and discussion
Tues, 5/2
Finance
Committee
6:00 PM,
Chambers
1) FY 2018 Proposed Budget Overview 6:00‐7:00
2) Council Appointed Officials and Council 7:00‐7:30
a) City Attorney, Operating Budget, pp. 127‐135
b) City Auditor, Operating Budget, pp. 137‐146
c) City Clerk, Operating Budget, pp. 147‐156
d) City Council, Operating Budget, pp. 157‐159
e) City Manager, Operating Budget, pp. 161‐173
3) Office of Sustainability, Operating Budget, pp. 305‐313 7:30‐8:00
4) Human Resources Department, Operating Budget 8:00‐9:00
a) General Fund, pp. 248‐256
b) General Liability Fund, Operating Budget, pp. 257‐261
c) Employee Benefit Funds
i) General Benefits Fund, Operating Budget, pp. 481‐484
ii) Workers Compensation Fund, Operating Budget, pp. 262‐268
d) Retiree Benefit Fund, pp. 485‐486
5) Administrative Services Overview 9:00‐9:30
a) General Fund, pp. 180‐187
b) Printing & Mail Fund, 188‐192
6) Non‐Departmental, Operating Budget, pp. 473‐476 9:30‐10:00
Thurs, 5/4
Finance
Committee
Special
Meeting
7:00 PM,
Chambers
1) May 2nd Budget Hearing Continuation 7:00‐7:30
2) Information Technology 7:30‐8:00
a) Operating Budget, pp. 269‐283
b) Capital Budget, 601‐621
3) Library, pp. 285‐294 8:00‐8:30
4) Development Services, pp.213‐228 8:30‐9:00
5) Public Works 9:00‐10:00
a) General Fund, Operating Budget, pp. 348‐359
b) Refuse Fund
i) Operating Budget, pp. 368‐378
ii) Capital Budget, pp. 482‐483
c) Storm Drain Fund
i) Operating Budget, pp. 379‐387
ii) Capital Budget, pp. 486‐493
d) Wastewater Treatment Fund
i) Operating Budget, pp. 395‐402
ii) Capital Budget, pp. 526‐551
e) Airport Fund
i) Operating Budget, pp. 360‐367
ii) Capital Budget, pp. 321‐341
f) Vehicle Replacement and Maintenance Fund
i) Operating Budget, pp. 388‐394
ii) Capital Budget, pp. 625‐647
Tues, 5/9
Finance
Committee
Special
Meeting,
6:00PM,
Chambers
1) May 4th Budget Hearing Continuation 6:00‐6:30
2) Police, Operating Budget, pp. 327‐342 6:30‐7:15
3) Office of Emergency Services, Operating Budget, pp. 295‐303 7:15‐7:30
4) Fire, Operating Budget, pp. 229‐242 7:30‐8:30
5) Community Services, pp. 193‐212 8:30‐9:30
6) Planning and Community Environment, Operating Budget, pp. 315‐326 9:30‐10:30
7) Special Revenue Funds, Operating Budget, pp. 97‐114
10:30‐11:00
a) Parking District, Operating Budget
b) Stanford Development Agreement Fund, Operating Budget
c) Other Special Revenue Funds, Operating Budget
Thurs, 5/18
Finance
Committee
Special
Meeting,
2pm,
Chambers
1) May 9th Budget Hearing Continuation 2:00‐2:30
2) Municipal Fee Schedule (staff report ID #___) 2:30‐3:30
3) General Fund Capital 3:30‐5:30
a) Buildings and Facilities, Capital Budget, pp. 73‐141
b) Parks and Open Space, Capital Budget, pp. 147‐225
c) Streets and Sidewalks, Capital Budget, pp. 227‐249
d) Traffic and Transportation, Capital Budget, pp. 251‐289
e) Cubberley Infrastructure, Capital Budget, pp. 295‐316
4) Utilities Department 5:30‐6:30
a) Electric Fund
i) Operating Budget, pp. 411‐425
ii) Capital Budget, pp. 343‐427
b) Fiber Optics Fund
i) Operating Budget, pp. 427‐434
ii) Capital Budget, pp. 429‐443
c) Gas Fund
i) Operating Budget, pp. 435‐447
ii) Capital Budget, pp. 445‐479
d) Wastewater Collection Fund
i) Operating Budget, pp. 449‐458
ii) Capital Budget, pp. 495‐523
e) Water Fund
i) Operating Budget, pp. 459‐472
ii) Capital Budget, 553‐596
5) Utility Rate Review and Approval 6:30‐7:30
6) HOLD: Wrap‐up 7:30‐9:30
Tues, 5/23
Finance
Committee
Special
Meeting, 6pm
Chambers
1) Continue Budget Wrap‐up 6:00pm
Mon, 6/19
City Council,
6:00PM,
Chambers
Public Hearing ‐ Budget Adoption 6:00pm
Please note that Agenda items may be advanced or delayed based on the number of budget proposals and/or
other discussion items.
5,6,7,8
CITY OF
PALO
ALTO
TO: HONORABLE CITY COUNCIL
FROM: ED SHIKADA, ASSISTANT CITY MANAGER/ UTILITIES GENERAL MANAGER
DATE:
SUBJECT:
MAY 18, 2017
SUPPLEMENTAL INFORMATION FOR AGENDA ITEMS 5, 6, 7, AND 8: OVERVIEW OF
DERIVATIVES POLICIES FOR THE ELECTRIC, GAS, AND WATER UTILITIES
This is an informational addendum to assist with discussion of the May 18, 2017 Council Agenda
Item 5, Utility Rate Review and Approval, which includes the following items:
• Agenda Item 6 with Staff Report 7980 titled Utilities Advisory Commission
Recommendation that the City Council Adopt 1) a Resolution Approving the Fiscal Year
2018 Electric Financial Plan, and 2) a Resolution Increasing Electric Rates by Amending the
E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E·l, E-7-G, E-7 TOU and E-14 Rate Schedules.
• Agenda Item 7 with Staff Report 7979 titled Utilities Advisory Commission
Recommendation that the City Council Adopt a Resolution Approving the Fiscal Year 2018
Gas Utility Financial Plan with no Changes to Distribution Rates
• Agenda Item 8 with Staff Report 8057 titled Follow-up Information on Water Utility Rate
Comparisons
This report is intended to assist with Council deliberations on these items. No additional actions
are recommended in this addendum. It summarizes information related to derivatives1 used to
mitigate rate changes.
Discussion
In response to a suggestion by Councilmember Tanaka at the March 21st Finance Committee
meeting, staff is providing an overview of assessments of the potential for using derivatives as a
hedging mechanism to moderate fluctuations in cost in the purchase of energy commodities. The
1 Derivatives are agreements between two parties to a financial and/or physical transaction at a future date, or an option for one
of the parties to initiate a transaction. They are typically used by businesses for hedging or risk management purposes, but can be
used by Investors for speculative purposes. Prices and quantities may be fixed or may be dependent on the condition of an
underlying market or other objectively measurable condition, such as rainfall. Electricity or gas is a commonly traded physical
product In the electric and gas Industries. Typical products Include futures (e.g. a contract for physical delivery of gas at a fixed price
at a future date, or a contract for a cash settlement at a future date based on the difference between an agreed·upon price and the
market price for gas on that date) or options (e.g. an option for one party to purchase gas from the other at a future date at a fixed
price in exchange for an up-front payment).
6053954
City of Palo Alto established Energy Risk Management Policies in 2001-02, reflecting a philosophy
of risk limitation and control, with financial health as a high priority. These policies established
formal roles among the City Council, Utilities Advisory Commission, staff-level Risk Oversight
Committee and departments, and within this structure derivatives have been used only in limited
ways for hedging.2 If Council is interested in pursuing additional instruments, such as financial
derivatives (like weather derivatives), staff would need to examine the expertise, potential legal
and regulatory implications, and internal controls needed to ensure this is pursued in a prudent
and sustainable manner.
Staff has taken some time to summarize the City's past investigations into the use of derivatives to
manage risk. Generally, the City of Palo Alto has been reticent to use certain types of derivatives to
manage risk due to the potential for high cost and the market risk inherent in such products.
Instead, the City's Council-approved Energy Risk Management Policy3 requires a variety of risk
management tools, including reliance on reserves to "self-insure" against risk, active management
of counterparty credit risk, rates management, and staff adherence to robust internal processes
and procedures. The list of allowed derivatives products is limited.
The City has evaluated a number of derivative products over the years and has each time come to
the conclusion that the risk mitigation achieved by those products is outweighed by the cost.
When establishing the City's hedging program (prior to the California Energy Crisis in 2000-2001)
the City Council and staff preference, now codified in the City's Energy Risk Management Policy,
was for physical as opposed to financial transactions, as reflected in its use of the NAESB (North
American Energy Standards Board) and EEi (Edison Electric Institute) standard contracts and its
decision not to use the ISOA {International Swaps and Derivatives Association) contract, which is
used for purely financial transactions. Numerous cases of municipalities facing significant financial
impacts from using financial derivatives products (generally interest rate swaps) also factored in to
the decision to prohibit use of financial instruments and ISOAs in the City's Energy Risk
Management Policy.
Only products involving physical delivery of energy, capacity, or renewable energy/carbon-related
products are allowed in the City's Energy Risk Management Policy. The most commonly used
products at the City have been fixed price forward gas and electricity purchases and sales to hedge
against market price changes and allow for short term stability in rates. These are still used by the
electric utility, though the utility has only limited market exposure since entering into more long-
term contracts for renewable energy. From 2001 to 2011 the gas utility used fixed price forward
contracts and capped price contracts to hedge against market movements for the City's residential
and small commercial customers. Large commercial customers had a choice of fixed forward rates
or market-based rates, and with few exceptions eventually moved to market-based rates. The
choice to end this program occurred in 2011, and more detail on that decision can be found in
Staff Report 1992, September 20, 2011.
2 The use of derivatives used for speculation is prohibited by Section D( I) of the City's Energy Risk Management
Policy.
3 http:lfwww.cityofpaloalto.org/civicax/lilebank/documents/44069
2 of3
The products permitted by the Energy Risk Management Policy that are most similar to the
derivatives products Councilmember Tanaka referenced are physical call options, capped-price
products, and collars (a combination of purchasing a call option for high prices and selling a put
option for low prices, with the premiums for both products offsetting each other). These products
generally protect against market movements rather than weather risk. Evaluation of these
products has generally shown low benefit for the cost involved, when compared to using reserves
to manage short term market shifts.
Weather derivatives are not currently a permitted product in the City's Energy Risk Management
Policy. However, Staff has evaluated these products in the past to manage risk to the electric
utility of hydroelectric variability, with the most in-depth evaluation in 2005. In general the
premiums have been very high, relative to the frequency and magnitude of the potential payout,
so the City has continued its approved strategy of using reserves to manage hydroelectric risk.
Staff is reviewing these strategies and plans to return to the UAC and Finance Committee this fall.
Staff will include an assessment of the current state of the market for weather derivatives as part
of this review.
Councilmember Tanaka also asked about the use of weather derivatives for revenue protection
due to load losses during a drought. The consumption changes resulting from droughts are
generally long-term, meaning they do not lend themselves to the use of derivatives, and require
long-term rate changes. In past droughts, consumption has generally not recovered to pre-drought
levels. Water utilities generally rely on reservoirs to avoid having to require demand reductions
during droughts. For example, the Sf PUC manages its water supply to require no more than a 20%
reduction in water demand over an eight year serious drought, which was why Palo Alto did not
need to reduce demand as early as some other California cities. Because water utilities use
reservoirs, insurance or derivatives products to protect municipal utilities against revenue loss are
not widely available. This means that buying these products will require working with a seller on a
custom product, which increases risk. When demand reductions are required, staff tries to cushion
the initial impact to the utility's financial position using reserves, but rate increases are eventually
needed because sales tend not return to pre-drought levels. Staff has not investigated using
generic weather derivative products as an alternative to drought rates. However, a one-time
payout from a weather derivative would not eliminate the need to raise rates to account for the
long term sales losses resulting from long term customer consumption changes due to a drought.
~ &dcld1u pi:
Ed Shikada
General Manager I Assistant City Manager
Utilities Department
3 of3
City of Palo Alto (ID # 7980)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/18/2017
City of Palo Alto Page 1
Summary Title: FY 2018 Electric Utility Financial Plan and Rate Proposals
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt 1) a Resolution Approving the Fiscal Year 2018 Electric Financial Plan,
and 2) a Resolution Increasing Electric Rates by Amending the E-1, E-2, E-2-G,
E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU and E-14 Rate Schedules
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission request that the Finance Committee recommend
that Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2018 Electric Financial
Plan (Attachment B); and
2. Adopt a resolution (Attachment C) amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Small Non-Residential Electric Service), E-2-G (Small Non-Residential
Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-
Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-
7-G (Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-
Residential Time of Use Electric Service), and E-14 (Street Lights).
Executive Summary
The FY 2018 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2027. Ongoing costs rose significantly from FY 2016 to FY 2017 and are projected to
remain at or slightly above their FY 2017 levels in the future. Staff is increasing rates over three
years to match revenues to costs, with the first increase taking place July 1, 2016.There are
several reasons for these cost increases. First, costs for electric supply purchases are increasing
as a result of new renewable energy projects coming online, which is responsible for 27% of the
cost increase. Increases in transmission access charges are also projected, another 7% of the
cost increase. Substantial additional capital investment in the electric distribution system is
planned for FY 2018 through FY 2023 (, and operations and maintenance costs are increasing.
City of Palo Alto Page 2
Lastly, sales volumes decreased 5% to 7% in 2016, which has a significant short term impact on
revenue.1
Because of these rising costs and reduced sales, an increase in rates is required to cover
expenses. A 10% to 14% rate increase (depending on customer class and usage) is proposed
effective July 1, 2017 (a nearly 14% overall increase in revenue), and a 7% increase is projected
effective July 1, 2018. However, even with these increases, residential electric rates remain 35%
to 45% below PG&E rates and comparable to or lower than Santa Clara and Roseville, other
publicly-owned utilities that maintain very low bills for customers. The Electric Utility transfer to
the General Fund is estimated at $13.2 million in FY 2018 and using the Council-adopted
methodology rises to $14.2 million in FY 2027.
While staff would normally attempt to spread these rate increases across more than two years
to reduce the single-year ratepayer impact, the electric utility reserves have reached minimum
acceptable levels over the last few years. Due to higher power supply purchase costs as a
result of the drought, operational and other reserves have decreased substantially in the past
couple years, making it infeasible to spread rate increases over multiple years. However, staff
proposes various reserves transfers for FY 2017 and FY 2018 that would limit the rate impact
for most customers as much as is possible, while maintaining the fiscal health of the utility.
While 14% is the overall increase in sales revenues, actual rate increases for each customer
class will differ. Actual rate increases are calculated using the cost of service analysis (COSA)
model created for the City by EES Consulting and first implemented on July 1, 2016.
The Utilities Advisory Commission (UAC) reviewed the Electric Utility Financial Plan and Rate
Proposals at its meeting on April 5, 2017 meeting, and approved them unanimously.
Background
Every year staff presents the Financial Plans for its Electric, Gas, Water, and Wastewater
Collection Utilities and recommends any rate adjustments required to maintain their financial
health. These Financial Plans include a comprehensive overview of the utility’s operations,
both retrospective and prospective, and are intended to be a reference for UAC and Council
members as they review the budget and staff’s rate recommendations. Each Financial Plan also
contains a set of Reserves Management Practices describing the reserves for each utility and
the management practices for those reserves.
The Finance Committee reviewed preliminary financial forecasts at its March 21, 2017 meeting.
Staff has not made any changes to the preliminary projections presented at that meeting.
Discussion
1 Over the long term, decreased consumption allows staff to incorporate new loads, such as electric vehicles,
without as much impact on existing supply and distribution assets. Over the long term this reduces bills for all
consumers, but in the short term rates can increase.
City of Palo Alto Page 3
Summary of Proposed Actions
The two resolutions recommended for Council adoption will accomplish the following:
1. Increase overall electric rates by 14% effective July 1, 2017;
2. Approve various reserves transfers for FY 2017;
3. Approve the FY 2018 Electric Financial Plan.
Proposed and Projected Sales Revenue Requirement, FY 2018 through FY 2022
Table 1 shows the sales revenue increases needed to recover costs of operation over the
forecast period in the FY 2018 Electric Financial Plan.
Table 1: Projected Electric Rate Adjustments, FY 2017 to FY 2023
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
14% 7% 0% 0% 1% 2%
These sales revenue increases are for the utility as a whole, but the rate changes will differ for
individual customer classes. Proposed rate increases for each customer class are discussed
below.
Changes from Prior Financial Forecasts
This projection has changed since the FY 2017 Electric Utility Financial Plan presented last year.
Table 2 compares current rate projections to those projected in the last two year’s Financial
Plans. As shown, the FY 2018 revenue projections are higher than projected the last two years.
Table 2: Projected Electric Rate Trajectory for FY 2018 to FY 2027
Projection FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Current
(FY 2018 Financial Plan) 14% 7% 0% 0% 1% 2% 1%
Last year
(FY 2017 Financial Plan) 10% 2% 0% 1% 0% 0% 0%
Two years ago
(FY 2016 Financial Plan) 6% 1% 1% 0% 0% 2% 2%
The rate increases are related to several factors: increasing transmission access charges and the
cost of renewable projects coming online, substantial additional capital investment in the
electric distribution system is planned through FY 2023, and operations cost increases.
Transmission Access (TAC) charges are levied by the California Independent System Operator
(CAISO) for use of the statewide transmission grid, under rates approved by the Federal Energy
Regulatory Commission (FERC). These charges pay for the costs PG&E and other transmission
owners incur in operating transmission lines. Annually, staff and partner agencies monitor
PG&E’s rate change requests to FERC. This can be a contentious process, and rate increases are
on ongoing issue of concern.
City of Palo Alto Page 4
Even when large rate increases are needed, staff typically attempts to keep increases below
10% per year and increase rates over multiple years. However, due to the impact of the recent
drought on hydroelectric energy generation output, the associated increased energy portfolio
costs, and decreases in customer sales, reserves are lower than forecasted, and cannot be used
for rate stabilization. However, precipitation in early 2017 is likely to lead to higher
hydroelectric output, which may improve reserves and the future financial outlook. The Electric
Utility transfer to the General Fund is calculated at $12.8 million in FY 2018 using the 2009
Council-adopted calculation methodology.
This Financial Plan contains some measures to mitigate the impact on ratepayers. The July 1,
2017 rate increases would have to be substantially higher without proposed transfers from the
Supply Rate Stabilization Reserve, Hydro Rate Stabilization, and Electric Special Projects Reserve
(see below). In addition, this Financial Plan allows the Supply Operations Reserves to be up to
$3.9 million below the minimum Supply Operations Reserve level for FY 2017 through FY 2020.
To keep the Supply and Distribution Operations Reserves above the minimum guideline without
transfers, rate increases over 20% would be required in FY 2018. Staff recommends allowing
Supply Operations Reserves to temporarily go below minimums for two reasons: first, heavy
rains and an above average snowpack indicate both an end to the drought and higher hydro
production, which may result in higher reserves, and second, the presence of the $41 million
Electric Special Projects Reserve means that a relatively small temporary shortfall in the
Operations Reserves should not affect the Electric Utility’s bond ratings. In the event the
drought resurfaces, staff will re-evaluate its projections for FY 2018 and may recommend
additional rate increases or the adoption of a hydroelectric rate adjuster. Note that the
Financial Plan’s Reserves Management Practices allow the Operations Reserve to fall below the
minimum guideline level as long as the plan provides for replenishing the reserve over time.
Staff also recognizes the importance of managing operating costs and maximizing efficiency in
order to minimize rate increases. Staff will continue to regularly review opportunities for cost
savings and efficiency improvements, and implement recommendations where practicable.
Rate Changes by Customer Class
Table 3 shows the rates that will be used to recover sale revenues for each customer class. The
Street Lighting (E-14) class and the E-4 and E-7 Time of Use (TOU) rates are not shown in the
table, but can be seen in the attached rate schedules (Attachment D). These schedules are
omitted for various reasons: the E-14 rate schedule is not easy to summarize, the E-7 TOU rate
is not easy to summarize and is only used by one customer, and the E-4 TOU rate schedule is
both difficult to summarize and not utilized by any customers at this time.
Table 3: Electric Rates (Current and Proposed)
Current Rates
Proposed Rates
(7/1/17)
Change
$ %
City of Palo Alto Page 5
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.11029 0.12159 0.01130 10%
Tier 2 Energy ($/kWh) 0.16901 0.19001 0.02100 12%
Minimum Bill ($/day) 0.3067 0.2938 (0.0129) -4%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.16845 0.18885 0.02040 12%
Winter Energy ($/kWh) 0.11445 0.13267 0.01822 16%
Minimum Bill ($/day) 0.7657 0.7328 (0.0329) -4%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.10229 0.11673 0.01444 14%
Winter Energy ($/kWh) 0.08049 0.08890 0.00841 10%
Summer Demand ($/kW) 19.68 21.05 1.37 7%
Winter Demand ($/kW) 14.04 15.36 1.32 9%
Minimum Bill ($/day) 16.3216 14.8414 (1.4802) -9%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.08749 0.09802 0.01053 12%
Winter Energy ($/kWh) 0.06242 0.07188 0.00946 15%
Summer Demand ($/kW) 18.34 23.84 5.50 30%
Winter Demand ($/kW) 15.65 15.59 (0.06) 0%
Minimum Bill ($/day) 48.5054 42.3648 (6.1406) -13%
Table 4 shows the impact of the proposed July 1, 2017 rate changes on the residential and non-
residential bills for various consumption levels. The overall rate change for the residential class
is roughly 12%.
Table 4: Impact of Proposed Electric Rate Changes on Customer Bills
Rate
Schedule
Usage (kwh/mo)
Bill under
Current Rates
($/mo)
Bill Under Rates
Proposed 7/1/17
($/mo)
Change
$/mo %
E-1 300 33.09 36.48 3.39 10%
(Summer Median) 330 36.40 40.13 3.73 10%
(Winter Median) 453 57.18 63.50 6.31 11%
650 90.48 100.93 10.45 12%
1200 183.43 205.44 22.00 12%
E-2 1,000 141 161 19 14%
E-4 160,000 21,366 23,734 2,368 11%
E-7 500,000 54,473 62,186 7,713 14%
E-7 2,000,000 200,895 229,031 28,136 14%
City of Palo Alto Page 6
Cost of Service Analysis and Rate Study
The rates discussed in the previous section are based on the cost of service methodology
established in “City of Palo Alto Electric Cost of Service and Rate Study”2 drafted by EES
Consulting, Inc. in 2015/16. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates. Additional details are provided in the attached memo (Attachment C).
Reserves Transfers, FY 2017 and FY 2018
The FY 2018 Electric Utility Financial Plan includes several proposed reserves transfers, shown
in Table 5. These reserves transfers have a variety of purposes, but overall they enable the
revenue trajectory projected in the Electric Utility Financial Plan. Without these transfers,
additional rate increases would be required.
Table 5: FY 2017 and FY 2018 Reserves Transfers
Fiscal
Year
Transfer
Amount
Transfer
From
Transfer
To Purpose
FY
2017
Up to $10
million
Special
Projects
Reserve
Distribution
Operations
Reserve
Ensures Distribution Operations Reserve is above
minimum guidelines at the end of FY 2017.
Up to $9
million
Hydroelectric
Stabilization
Reserve
Supply
Operations
Reserve
Funds additional market energy purchases that may be
needed if hydroelectric output associated with spring
2017 precipitation is insufficient to offset below-
average summer and fall 2016 output.
Up to $4.5
million
Supply Rate
Stabilization
Reserve
Distribution
Operations
Reserve
Ensures Distribution Operations Reserve is above
minimum guidelines at the end of FY 2017.
Up to $911
thousand
Supply Rate
Stabilization
Reserve
Supply
Operations
Reserve
Ensures Supply Operations Reserve is above Risk
Assessment level.
FY
2018
Up to
$3.1
million
Supply Rate
Stabilization
Reserve
Supply
Operations
Reserve
To bring Supply Operations Reserve to or above
minimum guidelines at the end of FY 2018.
Up to
$2.4
million
Hydroelectric
Stabilization
Reserve
Supply
Operations
Reserve
To bring Supply Operations Reserve to or above
minimum guidelines at the end of FY 2018.
$500
thousand
Supply Rate
Stabilization
Reserve
Distribution
Operations
Reserve
To bring Distribution Operations Reserve to or above
minimum guidelines at the end of FY 2018.
2 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
City of Palo Alto Page 7
Electric Bill Comparison with Surrounding Cities
Table 6 compares electric bills under current rates as of March 1, 2017 for residential customers
to those in surrounding communities. Under current rates, CPAU’s customer bills are far below
PG&E’s and are lower than others for non-residential customers, but slightly higher than Santa
Clara’s for higher using residential customers.
Table 6: Average Electric Bill Comparison ($/month)
As of March 1, 2017
Customers
Usage
(KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E Santa Clara Roseville
Residential
Customers
300 33.09 36.48 57.04 35.18 55.67
330 (Summer
Median) 36.40 40.13 63.85 38.83 58.64
453 (Winter
Median) 57.18 63.50 97.81 53.78 70.80
650 90.48 100.93 154.12 77.73 97.85
1200 183.43 205.44 374.41 144.59 179.96
Non-
Residential
Customers
1,000 142 161 240 181 146
160,000 21,366 23,734 29,108 20,562 21,009
500,000 54,473 62,186 87,015 62,956 55,955
2,000,000 200,895 229,031 333,041 243,390 214,705
Commission Review and Recommendation
The UAC reviewed this proposal at its April 5, 2017 meeting. Staff noted that the increase
proposal had changed from 12 to 14 percent overall, but that residential rates were projected
to increase by 12 percent.
Commissioner Schwartz noted that, with the recent billing error regarding gas, that staff may
want to do more outreach to customers, especially those with larger current bills. The goal
would be to have those residents understand that the increase was not another error. Staff
agreed with the assessment.
After the presentation, the UAC voted unanimously (5-0. Commissioners Forssell and Trumbull
absent) to approve the proposed rate increase and financial plan. The draft excerpted minutes
from the UAC’s April 5, 2017 meeting are provided as Attachment F.
Timeline
If the Finance Committee recommends approval of the FY 2018 Electric Financial Plan, Council
will consider the recommendations with the FY 2018 budget.
City of Palo Alto Page 8
Resource Impact
The proposed July 1, 2018 rate changes are projected to increase sales revenues by $16.1
million per year over the forecast period.
Policy Implications
The proposed electric rate adjustments were developed using a cost of service study and
methodology, and are consistent with the Council-adopted Reserves Management Practices
that are part of the Financial Plan.
Environmental Review
The Finance Committee’s review and recommendation to Council on the FY 2018 Electric
Financial Plans and rate adjustments does not meet the California Environmental Quality Act’s
definition of a project, pursuant to Public Resources Code Section 21065, thus no
environmental review is required.
Attachments:
Attachment A: Resolution of the Council of the City of Palo Alto Approving the FY 2018
Electric Utility Financial Plan
Attachment B: Proposed FY 2018 Electric Utility Financial Plan
Attachment C: EES 2017 COSA Model and Rate Design Update Memo
Attachment D: Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-
7-G, E-7 TOU, and E-14
Attachment E: Proposed Amendments to Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4
TOU, E-7, E-7-G, E-7 TOU, and E-14
Attachment F: Excerpted UAC Minutes of April 5, 2017
Attachment A
Not Yet Approved
170329 jb 6053933
Resolution No. _____
Resolution of the Council of the City of Palo Alto Approving the
FY 2018 Electric Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes
making long-term projections of market conditions, the physical condition of the system, and
other factors that could affect utility costs, and setting rates adequate to recover these costs. It
does this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2018 Electric Utility Financial Plan.
SECTION 2. The Council hereby approves the transfer of up to $911 thousand from
the Supply Rate Stabilization Reserve to the Supply Operations Reserve in FY 2017, up to $9.0
million from the Hydroelectric Stabilization Reserve to the Supply Operations Reserve in FY
2017, and up to $4.5 million from the Supply Operations Reserve to the Distribution Operations
Reserve in FY 2017, as described in the FY 2018 Electric Utility Financial Plan approved via this
resolution.
/ /
/ /
/ /
/ /
/ /
/ /
Attachment A
Not Yet Approved
170329 jb 6053933
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065, and therefore, no environmental assessment is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Senior Deputy City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2018 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2018 TO FY 2027
ATTACHMENT B
2 | Page
FY 2017 ELECTRIC UTILITY
FINANCIAL PLAN
FY 2018 TO FY 2027
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2018 Rate and Reserves Proposals ....................................................... 7
Section 3A: Rate Design ............................................................................................................... 7
Section 3B: Current and Proposed Rates ..................................................................................... 7
Section 3C: Reserves Management Practices .............................................................................. 8
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................. 10
Section 4A: Electric Utility History ............................................................................................. 11
Section 4B: Customer Base ........................................................................................................ 13
Section 4C: Distribution System ................................................................................................. 13
Section 4D: Cost Structure and Revenue Sources ...................................................................... 14
Section 4E: Reserves Structure ................................................................................................... 15
Section 4F: Competitiveness ...................................................................................................... 16
Section 5: Utility Financial Projections ................................................................................. 17
Section 5A: Load Forecast .......................................................................................................... 17
Section 5B: FY 2012 to FY 2016 Cost and Revenue Trends ........................................................ 19
Section 5C: FY 2016 Results ....................................................................................................... 20
Section 5D: FY 2017 Projections ................................................................................................ 20
Section 5E: FY 2018 – FY 2027 Projections ................................................................................ 21
3 | Page
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 23
Section 5G: Long-Term Outlook ................................................................................................. 27
Section 6: Details and Assumptions ..................................................................................... 30
Section 6A: Electricity Purchases ............................................................................................... 30
Section 6B: Operations .............................................................................................................. 32
Section 6C: Capital Improvement Program (CIP) ....................................................................... 33
Section 6D: Debt Service ............................................................................................................ 33
Section 6E: Equity Transfer ........................................................................................................ 34
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 34
Section 6G: Sales Revenues ....................................................................................................... 35
Section 7: Communications Plan .......................................................................................... 36
Appendices ......................................................................................................................... 38
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 39
Appendix B: Electric Utility Reserves Management Practices ................................................... 43
Appendix C: Description of Electric utility Operational Activities .............................................. 48
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 49
4 | Page
SECTION 1: DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a
section of the distribution system operates. The transmission system operates at
115-500 kV, and this is lowered to 60 kV in the subtransmission section of the
Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution
system, and finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum
electricity demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Sub-transmission System: The section of the Electric Utility’s distribution system that operates
at 60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115
kV or more. The voltage at the intersection of the Electric Utility’s distribution system
and PG&E’s transmission system is 115 kV. The Electric Utility does not own or
operate any transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
5 | Page
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Electric Utility for the next ten fiscal
years. This Financial Plan describes how revenues will cover the costs of operating the utility
safely over that time while adequately investing for the future. It also addresses the financial
risks facing the utility over the short term and long term, and includes measures to mitigate and
manage those risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
The Electric Utility’s costs will increase substantially over the next few years, as shown in Table
1. Most of the increases are related to electric supply costs, which are increasing due to
increased transmission costs and the cost of new renewable energy projects coming online.
There are also inflationary increases in Operations costs, and some additional capital
investment costs.
Table 1: Electric Utility Expenses for FY 2016 to FY 2027
Expenses
($000)
FY 2016
(act.)
FY 2017
(est.)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Power Supply
Purchases 79,115 84,371 87,987 89,066 90,841 90,728 92,221 91,758 92,925 93,904 95,224 96,465
Operations 35,443 54,152 56,307 56,795 58,409 59,238 60,089 61,931 62,507 59,519 60,550 61,610
Capital Projects 21,128 21,490 15,574 15,869 25,150 19,048 17,449 18,354 18,878 19,417 19,972 20,543
TOTAL 135,685 160,013 159,868 161,730 174,400 169,014 169,759 172,042 174,309 172,840 175,746 178,617
To cover these increases in costs, revenues (and therefore rates) need to increase over the next
several years to balance costs and revenues, as shown in Table 2. The table also compares
current rate projections to those projected in last year’s Financial Plan. The rate projections are
higher this year than last year primarily due lower actual and projected sales and increases to
transmission cost projections. In addition, the continued drought has had a greater impact than
expected on hydroelectric supplies. This has affected reserves, making it difficult to phase in
rate increases over multiple years.
Table 2: Projected Electric Rates, FY 2017 to FY 2023
Projection FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
Current 14% 7% 0% 0% 1% 2% 1% 1% 1% 1%
Last Year 10% 3% 0% 1% 0% 2% N/A N/A N/A N/A
Table 3 shows the projected reserve transfers over the forecast period. The Supply Rate
Stabilization Reserve is projected to be drawn down entirely by the end of FY 2018. Funds are
projected to be transferred from the Electric Special Projects (ESP) Reserve to the Operations
Reserve to fund smart grid projects included in the long term CIP budget, but it should be noted
that the smart grid costs included in the forecast are placeholders, as are the transfers from the
ESP Reserve. Any transfers from the ESP Reserve require Council approval.
6 | Page
Staff will request a temporary loan from the ESP reserve of $10 million for the Distribution
Operations reserve, as it is otherwise projected to be critically low. As the intent of the ESP
reserve is to fund projects, not to stabilize rates, this will be a temporary transfer, to be
reversed once distribution rates have increased and stabilized (FY 2020 and 2021) and funds
can be returned to the ESP reserve. Staff is also requesting authority to withdraw funds from
the Hydro Stabilization Reserve in FY 2017 and FY 2018 due to lower than average hydroelectric
generation, though this projection is subject to change with weather conditions. Based on
precipitation to-date, this projection is likely to change, and staff will not perform these
transfers if they become unnecessary.
Table 3: Reserves Transfers for FY 2017 to FY 2027 ($000)
Reserve FY 2017 FY 2018 FY 2019 to FY 2027
Supply Reserves
Electric Special Projects (10,173) 3,000
Hydro Stabilization* (9,000) (2,400) -
Supply Rate Stabilization (5,411) (3,600) -
Supply Operations 10,084 5,500 7,000
Distribution Reserves
Capital Improvement Program
Distribution Operations 14,500 500 (10,000)
* A $9 million transfer from the Supply Rate Stabilization Reserve to the Supply Operations Reserve was
approved by Council when it adopted the FY 2016 Electric Utility Financial Plan
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2017:
1. Complete the proposed FY 2017 reserves transfers described Section 3D: Proposed
Reserve Transfers, as previously requested as part of the FY 2017 Electric Financial Plan
2. Request a new transfer of $10 million from the ESP reserve to the Distribution
Operations Reserve, to be repaid within five years.
Staff proposes the following actions for the Electric Utility in FY 2018:
1. Request the proposed FY 2018 reserves transfers described in Section 3D: Proposed
Reserve Transfers.
2. Increase rates effective July 1, 2017 for a 14% increase in system average rates, and
thereby increase sales revenues by 10% based upon current sales projections.
Note that while the projected rate increases and reserves transfers in this FY 2018 Financial
Plan are adequate to recover costs over the forecast period, the Supply Operations Reserves
are projected to be at or below the minimum Supply Operations Reserve level for FY 2017
through FY 2019, and lower sales have dropped Distribution Operations reserves to very low
levels requiring new transfer requests. While more aggressive increases could be requested,
staff still recommends proceeding with this plan for two reasons: first, recent rains and
7 | Page
favorable snowpack levels may result in favorable hydroelectric production, resulting in higher
reserves, and second, the presence of the Electric Special Projects Reserve with a balance of
$41 million means that a small temporary shortfall in the Operations Reserves should not affect
the Electric Utility’s financial health and bond ratings. In the event drought resurfaces or hydro
fails to materialize, staff will re-evaluate its projections at midyear of FY 2018 and may
recommend additional rate increases or the adoption of a hydroelectric rate adjuster.
SECTION 3: DETAIL OF FY 2018 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The rates discussed in the previous section are based on the cost of service methodology
established in “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2015/16. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates. The COSA is based on design guidelines adopted by Council on September 15,
2015 (Staff Report 6061).
SECTION 3B: CURRENT AND PROPOSED RATES
The current rates were adopted on July 1, 2016, when CPAU increased electric rates by 11%.
Table 4, below, summarizes the current and proposed rates for the four largest customer
classes. The Electric Utility also has specialty rates for smaller groups of customers. These
include variations on its primary rates, such as time of use rates, the PaloAltoGreen rates, and
solar net metering. Staff proposes a 14% overall increase in revenue, requiring 14% increase in
system average rates. Different customer classes may see different percentage changes to their
rates, based upon their usage of the system and cost to serve each group.
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
8 | Page
Table 4: Current and Proposed Electric Rates
Current Rates
Proposed Rates
(7/1/17)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.11029 0.12159 0.01130 10%
Tier 2 Energy ($/kWh) 0.16901 0.19001 0.02100 12%
Minimum Bill ($/day) 0.3067 0.2938 (0.0129) -4%
E-2 & E-2-G(Small Non-Residential)
Summer Energy ($/kWh) 0.16845 0.18885 0.02040 12%
Winter Energy ($/kWh) 0.11445 0.13267 0.01822 16%
Minimum Bill ($/day) 0.7657 0.7328 (0.0329) -4%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.10229 0.11673 0.01444 14%
Winter Energy ($/kWh) 0.08049 0.08890 0.00841 10%
Summer Demand ($/kW) 19.68 21.05 1.37 7%
Winter Demand ($/kW) 14.04 15.36 1.32 9%
Minimum Bill ($/day) 16.3216 14.8414 (1.4802) -9%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.08749 0.09802 0.01053 12%
Winter Energy ($/kWh) 0.06242 0.07188 0.00946 15%
Summer Demand ($/kW) 18.34 23.84 5.50 30%
Winter Demand ($/kW) 15.65 15.59 (0.06) 0%
Minimum Bill ($/day) 48.5054 42.3648 (6.1406) -13%
These proposed rates were prepared in conformance with the “FY 2017 City of Palo Alto Electric
Cost of Service and Rate Study,” performed by EES Consulting (2016).
SECTION 3C: RESERVES MANAGEMENT PRACTICES
No changes to the Electric Utility Reserves Management Practices (See Appendix B: Electric
Utility Reserves Management Practices) are proposed at this time.
SECTION 3D: PROPOSED RESERVE TRANSFERS
In the FY 2017 Electric Financial Plan, Council approved several proposed transfers for FY 2017:
•Transfer up to $1 million from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve. This transfer is to enable the City to spread necessary long term
rate increases over multiple years to reduce the short-term impact on ratepayers.
Current estimates are that the amount will be closer to $911,000.
•Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offset
potential costs associated with low hydroelectric generation. Some or all of this transfer
9 | Page
may be unnecessary if weather conditions change, but current estimates still indicate
the full amount will be needed, since excess generation in the spring of 2017 may not
fully offset below-average generation in the summer and fall of 2016.
•Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution
Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve.
Staff will also request the following for FY 2017:
•Transfer up to $10 million from the ESP Reserve to the Distribution Operations Reserve.
This transfer will be construed as a temporary transfer, to be repaid to the ESP Reserve
within five years.
Proposed transfers for FY 2018 will not be requested by resolution at this time, but will be
requested as part of the FY 2019 Financial Plan, or at FY 2017 year-end should ending reserve
balances require it.
The impact of these transfers on reserves levels can be seen in Figure 8 (for Supply Fund
Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E: FY 2018 – FY 2027
Projections. Table 5 shows the projected balance of each of the Electric Utility reserves for the
period covered by this Financial Plan. The projected balances are also provided in. Appendix A:
Electric Utility Financial Forecast Detail
Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2016 to FY 2027
Ending Reserve
Balance ($000)
FY 2016
(Act.)
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Reappropriations - - - - - - - - - - - -
Commitments 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777
Underground Loan 729 729 729 729 729 729 729 729 729 729 729 729
Public Benefits 1,839 1,331 739 280 95 - - - - - - -
Special Projects 51,838 41,665 41,526 41,192 42,859 46,192 44,665 44,665 44,665 44,665 44,665 44,665
Hydro Stabilization 11,400 2,400 - - - - - - - - - -
Capital - - - - - - - - - - - -
Rate Stabilization 9,011 3,600 - - - - - - - - - -
Operations 21,850 21,570 28,477 31,328 31,984 32,727 36,734 36,600 36,226 38,957 40,471 41,658
Unassigned - - - 916 - - - - - - - -
TOTAL 100,444 75,072 75,248 78,222 79,444 83,425 85,906 85,771 85,397 88,128 89,642 90,830
10 | Page
SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and
11 | Page
Section 6: Details and Assumptions.
SECTION 4A: ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel
engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity
continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E
proved more economical than the diesel engines, and by the late 1920s CPAU was using its own
diesel engines only during peak demand periods. At that time CPAU owned 45 miles of
distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual
consumption. The diesel engines remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did
throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the
sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto,
which doubled the number of customers. Some was related to the proliferation of electric
appliances, as evidenced by the fact that residential customers were using three times more
electricity in 1970 than they had been in 1950. But the most notable factor was the growth of
industry in Palo Alto during that time. By 1970, commercial customers were using 20 times
more electricity per customer than they had been in 1950. These decades also saw several
other notable events, including:
• 1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of
Reclamation to purchase power from the Central Valley Project (CVP), a contract which
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
• 1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
• 1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement
program for its underground system in the early 1990s.
12 | Page
In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and
in 1996 the State legislature passed Assembly Bill 1890, which, among other things, created the
California Independent System Operator (CAISO) to operate the transmission system and the
Power Exchange to facilitate wholesale energy transactions. This restructuring was anticipated
to bring lower costs to consumers, and while CPAU was not required to participate in the
industry restructuring, in 1997 the Council approved a Direct Access Program for the Electric
Utility2 that enabled CPAU to sell electricity outside its service territory and allowed customers
within CPAU’s service territory to choose other providers. The utility unbundled its electric
rates, creating separate supply and distribution components, which would enable customers to
receive only distribution service while purchasing the electricity itself from another provider.
The energy crisis in 2000 to 2001 led to the suspension of direct access by the CPUC in
September 2001 as wholesale energy prices skyrocketed. The Electric Utility was less impacted
than other utilities by the 2000 to 2001 energy crisis thanks to the Calaveras project and its
contract with WAPA for CVP hydropower.
In 2001 CPAU began planning for the impacts associated with the new terms of its contract with
WAPA, set to take effect in 2005. The previous contract had provided 90% of Palo Alto’s power
supply at favorable rates, and PG&E, as a party to the contract, had provided supplemental
power to balance the monthly and annual variability of CVP generation. The new contract
would provide only a third of Palo Alto’s requirement, and the monthly and annual variability in
CVP generation would be passed directly to Palo Alto. As a result, electric supply costs would
increase and CPAU needed to more actively managine its supply portfolio. CPAU began
purchasing power from marketers and also investigated building a power plant in Palo Alto or
partnering in the development of a gas-fired power plant elsewhere. Climate change was also
becoming more of a concern to the community, and gradually CPAU shifted its focus to the
procurement of renewable energy. In 2002 CPAU adopted a goal of achieving 20% of its energy
supply from renewables by 2015. Subsequently CPAU signed its first contract for renewable
power, a contract for energy from a wind generator commencing deliveries in 2005. In 2011 the
renewable energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a
plan to make its electric supply 100% carbon neutral, which it achieves through the
combination of its carbon-free hydroelectric supplies, purchases of long-term renewable energy
supplies, and short-term renewable energy purchases (RECs) to meet the balance of its needs.
2 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
13 | Page
Figure 1: Customer Base (FY 2016)
16%
7%
35%
42%
Residential
Small Comm
Med. Comm
Large Comm
SECTION 4B: CUSTOMER BASE
The City of Palo Alto’s Electric Utility
provides electric service to the
residents, businesses, and other
electric customers in Palo Alto. There
are roughly 29,750 customers
connected to the electric system,
25,700 (86%) of which are residential
and 4,050 (14%) of which are non-
residential. Residential customers
consumed 148 gigawatt-hours (GWh)
in FY 2016, approximately 16% of the
electricity sold, while non-residential
customers consumed 88% or
759 GWh. Residential customers use
electricity primarily for lighting,
refrigeration, electronics, and air conditioning.3 Non-residential customers use the majority of
their electricity for cooling, ventilation, lighting, office equipment (offices), cooking
(restaurants), and refrigeration (grocery stores).4
As shown in Figure 1 large customer loads represent a larger proportion of sales for the Electric
Utility than they do for the City’s other utilities. The largest customers (the 72 customers on the
E-7 rate schedule) account for over 40% of CPAU’s sales. The next largest customer group (the
835 non-residential customers on the E-4 rate schedule) represents another 35% of sales. In
total, that means that about 3% of customers account for nearly three quarters of the electric
load.
SECTION 4C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 470 miles of
distribution lines, of which 223 miles (48%) are overhead lines and 245 miles (52%) are
underground. The Electric Utility also maintains six substations, roughly 2,000 overhead line
transformers, 1,075 underground and substation transformers, and the associated electric
services (which connect the distribution lines to the customers’ homes and businesses). These
lines, substations, transformers, and services, along with their associated poles, meters, and
3 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010 4 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
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Figure 2: Cost Structure (FY 2016)
58%
34%
8%
Commodity Supply
Operations
Capital
Figure 3: Hydroelectric Variability (FY 2018)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 4: Revenue Structure (FY 2016)
87%
13%
Sales of Electricity
Other Revenue
other associated electric equipment, represent the vast majority of the infrastructure used to
deliver electricity in Palo Alto.
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 58% of the Electric Utility’s
costs in FY 2016. Operational costs
represented roughly 34%, and
capital investment was responsible
for the remaining 8%. CPAU’s non-
hydro long-term commodity supply
is heavily dependent on long-term
contracts which have little variability
in price. On average, costs for these
long-term contracts are not
predicted to increase as quickly as operations and CIP costs, and will steadily become a smaller
proportion of the Electric Utility’s costs. Commodity supply costs are projected to be roughly
54% of total costs in FY 2027.
While average year purchase
costs for the electric utility
are predictable due to its
long-term contracts,
variability in hydroelectric
generation can result in
increased or decreased
costs. This is by far the
largest source of variability
the utility faces. Figure 3
shows the difference in costs
under high, projected, and
low hydroelectric generation scenarios for FY 2018. Additional costs associated with a very low
generation scenario can range from $9-11 million per year. For the current hydroelectric risk
assessment see Section 5F: Risk Assessment and Reserves Adequacy.
As shown in Figure 4 the Electric Utility
receives 87% of its revenue from sales of
electricity and the remainder from
connection fees, interest on reserves,
cost recovery transfers from other funds
for shared services provided by the
electric utility, and other sources. Some
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revenue sources are primarily accounting entries that reflect things such as CPAU’s
participation in a pre-funding program associated with its contract with WAPA, as well as
accounting entries associated with occasional sales of surplus hydroelectric energy during wet
years. Without these entries sales revenues represent roughly 91% of total revenues. Appendix
A: Electric Utility Financial Forecast Detail
shows more detail on the utility’s cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 900 largest customers, which provide a similar share of the utility’s revenue stream.
The utility’s retail rate schedules have no fixed charges, although about 24% of the utility’s
revenue comes from peak demand charges on large non-residential customers. Due to
moderate weather and the prevalence of natural gas heating, however, loads (and therefore
revenues) are very stable for this utility, without the large seasonal air conditioning or winter
heating loads seen at some other utilities.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of
contingencies. It also maintains two funds, the Supply Fund and the Distribution Fund, to
manage costs associated with electricity supply and electricity distribution, respectively. This
separation of supply and distribution costs was established as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) back in the late
1990s and early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues
to maintain separate funds to facilitate separation of supply and distribution costs in the rates.
This could be important in case California ever decides to reintroduce Direct Access, and may
also be useful for rate design as the nature of utility services evolves in response to higher
penetrations of distributed generation.
The various reserves are summarized below, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserves for Commitments: Reserves equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserves for Reappropriations: Reserves for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve. This is currently an important
reserve for all utility funds, but changes in budgeting practices will change that in future
years, as described in Section 3C (Reserves Management Practices).
• Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which was accumulated during deregulation of California’s electric system to
fund the stranded costs associated primarily with the Calaveras hydroelectric resource
and the California-Oregon Transmission Project. When that reserve was no longer
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needed for that purpose, the reserve was renamed and the purpose was changed to
fund projects with significant impact that provide demonstrable value to electric
ratepayers.
• Hydroelectric Stabilization Reserve: This contingency reserve is used for managing
additional costs due to below average hydroelectric generation, or to hold surpluses
resulting from above average hydroelectric generation.
• Underground Loan Reserve: This reserve is an accounting tool used to offset receivables
associated with loans made through the underground loan program. It is adjusted
according to principal payments made on those loans.
• Public Benefits Reserve: CPAU’s electric rates include a separate charge called the
“Public Benefits Charge” which generates revenue to be used for energy efficiency,
demand-side renewable energy, research and development, and low-income energy
efficiency services. Any funds not expended in the current year are added to the Public
Benefits Reserve for use in future years.
• Capital Improvement Program (CIP) Reserve: The CIP reserve is used to provide
working capital and contingency funds for the CIP program, as well as to accumulate
funds for major future one-time expenditures. This type of reserve is used in other
utility funds (Electric, Gas, and Wastewater Collection) as well.
• Supply and Distribution Rate Stabilization Reserves: These reserves are intended to be
empty unless one or more large rate increases are anticipated in the forecast period. In
that case, funds can be accumulated to spread the impact of those future rate increases
across multiple years. This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Supply and Distribution Operations Reserves: These are the primary contingency
reserves for the Electric Utility, and are used to manage yearly variances from budget
for operational costs and electric supply costs (aside from variances related to
hydroelectric generation). This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves
are for any financial resources not assigned to the other reserves and are normally
empty.
SECTION 4F: COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2016 was
$551.65 under current CPAU rates, 38% lower than the annual bill for a PG&E customer with
the same consumption and roughly the same as the annual bill for a City of Santa Clara
customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X, which
includes most surrounding comparison communities.
Table 6 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara
(Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown
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below were in effect as of March 1, 2017. PG&E rates were recently increased, and their
residential tiers moved from three to two.
Over the next several years low usage customers in PG&E territory are expected to continue to
see higher percentage rate increases than high usage customers as PG&E compresses its tiers
from the highly exaggerated levels that have been in place since the energy crisis. This is likely
to make the bill for the median Palo Alto consumer look even more favorable compared to
most PG&E customers. Even with the compressed tiers, bills for high usage Palo Alto consumers
are likely to remain substantially lower than the bills for high usage PG&E customers.
The bill calculations show bills under the existing rates, not the proposed July 1, 2017 rates.
However, even with the proposed rate increases, Palo Alto’s residential bills will remain
substantially below PG&E’s current rates, but slightly above Santa Clara’s.
Table 6: Residential Monthly Electric Bill Comparison (Effective 3/1/17, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(March)
300 33.09 57.04 35.18
453 (Median) 57.18 97.81 53.78
650 90.48 154.38 77.73
1200 183.43 374.19 144.59
Summer
(July)
300 33.09 57.04 35.25
(Median) 330 36.40 63.85 38.83
650 90.48 159.66 77.73
1200 183.43 380.43 144.59
Table 7 shows the average monthly electric bill for commercial customers for various usage
levels. Even with the proposed rate increases, Palo Alto’s commercial bills will remain
substantially below PG&E’s, and below Santa Clara’s for some commercial customers.
Table 7: Commercial Monthly Electric Bill Comparison (3/1/17, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 142 240 181
160,000 21,366 29,108 20,562
500,000 54,473 87,015 62,956
2,000,000 200,895 333,041 243,390
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 5 shows a 40-year history of Palo Alto electricity consumption. Average electricity
consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then
electricity consumption has declined slowly as a result of a continuing focus on energy
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efficiency, as well as the adoption of more stringent appliance efficiency standards and energy
standards in building codes.
Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2027. Sales after the July
2016 rate change decreased by 6% from projections. To be conservative, the forecast assumes
that current trends continue and sales through the forecast period decline slightly.
800
850
900
950
1,000
1,050
1,100
1,150
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Figure 6: Forecasted Electricity Consumption
SECTION 5B: FY 2012 TO FY 2016 COST AND REVENUE TRENDS
The annual expenses for the Electric Utility declined between FY 2009 and FY 2012, as shown in
Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail.
These decreases were partly related to declines in electricity market prices due to the impact of
shale gas and partly due to above average output from hydroelectric resources. These factors
are discussed in more detail in Section 6A: Electricity Purchases. Since FY 2012, total expenses
for the utility have been increasing as renewable resources come online. In FY 2014 through FY
2015 costs were higher due to lower than average output from hydroelectric resources.
Commodity costs are responsible for most of the changes in the utility’s expenses over the last
six years. Operational costs and capital investment increased at less than 1% per year over that
time.
Actual Projection
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2016 and Projections through FY 2027
SECTION 5C: FY 2016 RESULTS
California’s drought, with its corresponding lower hydroelectric energy output, continued to
increase electricity costs in FY 2016. Offsetting this were lower operations and capital program
spending. FY 2016 expenses were $9.2 million lower than in the FY 2017 Financial plan, with
revenues being roughly equal.
SECTION 5D: FY 2017 PROJECTIONS
Last year, staff recommended (and Council approved) an 11% rate change for July 1, 2016, the
start of FY 2017. Based on hydroelectric conditions at the time, staff forecasted a roughly $15.2
million deficit for FY 2017. This deficit was primarily related to low hydroelectric output, and
was to be funded from the Rate Stabilization and Hydroelectric Stabilization reserves. Staff’s
current forecast for FY 2017 is for a deficit of $25.4 million, $10.2 million more than forecast
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last year. This change is mainly due to sales decreasing by 6% after the last rate increase,
cutting projected revenues by $11 million. The onset of wet weather and a forecast for a
reversal in hydro conditions has brought down electric purchase cost projections, but the full
impact of better hydro conditions likely won’t be felt until next fiscal year.
With Operations reserves projected to be below minimum, several transfers, including a
temporary loan from the Electric Special Projects Reserve, proposed. These transfers are
discussed in Section 3D: Proposed Reserve Transfers.
SECTION 5E: FY 2018 – FY 2027 PROJECTIONS
As shown in Figure 7 above, costs for the Electric Utility are projected to increase at a fairly
steady rate through the forecast period. Revenues will have to increase 10% in FY 2018 and
another 7% in FY 2019 to bring revenues in line with expenses. The largest increases are
primarily related to electricity purchase costs, which have been increasing since FY 2013 and
will continue to increase through FY 2018 as new renewable projects come online to fulfill the
City’s environmental goals and as transmission costs increase. Operations costs are expected to
increase at or near the inflation rate (2-4 %/year) through the forecast period. Projected capital
expenses for FY 2018 through FY 2023 are about $4.6 million lower than last year’s forecast as
one large, customer driven project has been put on hold. The project would have been funded
mostly through customer reimbursement. This forecast also assumes that smart grid costs are
funded from the Electric Special Projects Reserves.
Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund
reserves) and Figure 9 (for Distribution Fund reserves), below. The Supply Rate Stabilization
Reserve will be empty by the end of FY 2017. The Distribution Operations reserve will require a
short term transfer of $10 million from the Electric Special Projects reserve to remain adequate
through the forecast period. The $10 million is projected to be transferred back between FY
2020 and FY 2021. The Supply Operations Reserve, however, is forecasted to be below
minimum levels. This is discussed in more detail in Section 5F: Risk Assessment and Reserves
Adequacy. The Hydro Stabilization reserve is projected to be depleted by the end of FY 2017.
Staff will bring plans to Council in spring or summer for a Hydro rate adjustment mechanism to
better utilize, and fund, this particular reserve.
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Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2016 and Projections through FY 2027
Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2016 and Projections through FY 2027
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SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two contingency reserves, the Supply Operations Reserve and
the Distribution Operations Reserve. This Financial Plan maintains reserves in excess of the
reserve minimum for the Distribution Operations Reserve throughout the forecast period.
Reserve levels also exceed the short-term risk assessment level for the Distribution Fund. The
Supply Operations Reserve, however, may end up below minimum levels and below the short-
term risk assessment level.
There are a variety of risks associated with the Supply Fund as are shown in Table 8. Because of
the high range of uncertainty in energy price predictions more than three years in the future,
this risk assessment is only performed for the first two fiscal years of the forecast period. It is
important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 8 is very low.
Table 8: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2018 FY 2019
1.Load Net Revenue 0.9 1.0 Revenue loss from load decreases (net of
reduction in energy purchases)
2.Production from Hydroelectric
Resources: Western & Calaveras 9.3 13.7 Lower than forecasted hydro
3.Renewable Production: Landfill &
Wind 0.5 2.0 Additional cost of renewable output that is
higher than forecasted
4.Carbon Neutral Cost 0.0 0.0 Higher than forecasted market prices for RECs
5.Market Price (Energy)0.7 0.6 Higher than forecasted market prices for
energy
6.Local Capacity 0.6 1.5 Higher than forecasted market prices for local
capacity
7.Transmission/CAISO 3.2 3.3 High-end transmission forecast scenario
8.Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
9.Western Cost 2.4 3.5 Risk of rate adjustments from Western
10.Regulatory and Legal 0.0 0.0 Risks associated with legislative uncertainties
11.Supplier Default 0.2 0.2 Estimate of supplier default risks
Electric Supply Fund Risks $18.8
million
$26.8
million
Projected Supply Operations +
Hydro Stabilization Reserve Levels
$16.0
million
$17.5
million
Of the risks faced by the Electric Utility’s Supply Fund in FY 2018, the risk of a dry year with very
low hydroelectric output is normally the largest, accounting for nearly half the total cost of all
adverse outcomes. Since the utility’s costs for its hydroelectric resources are almost entirely
fixed, costs do not decline when the output of those resources are low, but the utility needs to
buy power to replace the lost output. The converse happens when hydroelectric output is
higher than average.
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Of the remaining risks for FY 2018, $3.2 million is related to the projected costs if transmission
cost increases are higher than staff’s current forecast. Another $2.4 million is related to the
possibility of drought-related changes to Western rates for CVP hydropower.
As shown in Figure 10, the Supply Operations Reserve will drop below the minimum reserve
guidelines by as much as $3.9 million over the course of the forecast period. In addition, as
shown in Figure 11, the combined hydro stabilization and supply operations reserves will drop
below the risk assessment level. It is acceptable under the Electric Utility Reserves Management
Practices to drop below minimum reserve guidelines so long as Council approves the Financial
Plan. Staff recommends proceeding with this plan for two reasons: first, due to larger than
normal rains and snowpack to date, there is a chance of better hydro conditions will result in
higher reserves, and second, the presence of the Electric Special Projects Reserve means that a
small temporary shortfall in the Supply Operations Reserve should not affect the Electric
Utility’s bond ratings. In the event drought re-emerges, staff will re-evaluate its projections for
FY 2019 and may recommend additional rate increases or the adoption of a hydroelectric rate
adjuster.
Figure 10: Electric Supply Operations Reserve Adequacy
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Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 9 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2022. As shown in Figure 12, the Distribution Operations Reserve will stay within the
reserve guidelines over the course of the forecast period. The risk assessment includes the
revenue shortfall that could accrue due to:
1.Lower than forecasted sales revenue; and
2.An increase of 10% of planned system improvement CIP expenditures for the budget year.
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Table 9: Electric Distribution Fund Risk Assessment ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Total non-commodity revenue $46,877 $49,044 $48,931 $48,812 $49,612
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $3,700 $3,871 $3,862 $3,852 $3,916
CIP Budget $15,574 $15,869 $25,150 $19,048 $17,449
CIP Contingency @10% $1,557 $1,587 $2,515 $1,905 $1,745
Total Risk Assessment value $5,257 $5,458 $6,377 $5,757 $5,661
Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, the CIP Reserve is projected to be at or above the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels in later years, CIP Commitments are nearly impossible to project that far out,
and adjustments to the reserve can be made in future years.
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Figure 13: Electric CIP Reserve Adequacy
SECTION 5G: LONG-TERM OUTLOOK
This forecast covers the period from FY 2018 through FY 2027, but various long-term
developments may create new costs for the utility over the next 5 to 35 years. While it is
challenging to accurately forecast the impact these events will have on the utility’s costs, it is
worth noting them as future milestones and keeping them in mind for long-term planning
purposes.
For the supply portfolio, the 2020s will see a number of notable events. The contract with
Western for power from the CVP will expire in 2024. Determining the future relationship with
Western after 2024 will be important in the years leading up to the contract expiration,
especially because this resource represents nearly 40% of the electric portfolio, and is the
utility’s largest source of carbon-free electricity. The utility’s three earliest and lowest cost
renewable contracts will also begin expiring around that time, with the first contract expiring in
2021 and the last in 2028. These three contracts, plus one more expiring in 2030, currently
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provide 17% to 18% of the energy for the utility’s supply portfolio at prices under $65 per
megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those
contracts expire. Although recent prices have been in that range (or even lower), and costs
may decrease in the future, current renewable projects also benefit from a wide range of tax
and other incentives that may or may not be available in the 2020s and beyond. However, staff
is in the process of procuring a replacement for the contract expiring in 2021 at a lower price
than any of the City’s current renewable contracts.
The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs
dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032
(assuming no new debt is issued). The project will only be 40 years old at that time. Calaveras
debt service represents roughly 70% of the annual costs of that project (and nearly 7% of the
utility’s total costs), so when the debt is retired, the project could be a low-cost asset for the
utility, providing carbon-free energy equal to 13% of the Electric Utility’s supply needs in an
average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to 5 million per year in revenue from
allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to
pay for energy efficiency and to purchase renewable energy to support the utility’s Carbon
Neutral Plan. That revenue source is expected to continue through 2020, but provisions for
whether or not these allocations continue past 2020 are still being discussed. If the Electric
Utility no longer received these allowances, it would have to fund these programs from sales
revenues.
Transmission costs are also continuing to rise. If the State continues to increase mandates or
incentives for renewable energy development, integrating these new projects into the
transmission grid will be an ever increasing challenge, some costs of which will be borne by Palo
Alto. The planned expansion of the CAISO to a larger regional grid control area may result in
additional transmission costs that could further increase CPAU’s transmission costs. In addition
to the costs of new transmission lines that will need to be built, flexible resources will be
required to balance rapid changes in wind or solar output throughout the day. Palo Alto will
likely bear some of the costs of these new lines and resources. CPAU is also currently
investigating installing a second transmission interconnection for Palo Alto, which could be
funded by the Electric Special Projects reserve.
Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these
factors may begin to create notable increases in electric consumption and have a variety of
impacts on the distribution system. As housing stock is turned over, however, stricter building
codes may help to counteract load growth, as may increasing numbers of rooftop solar
installations. The utility has already started to take some of these factors into account in its
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long-term planning processes, but will need to continue to incorporate them into its planning
methodologies.
Over the long term, it is conceivable that electricity could replace natural gas and petroleum
almost entirely. Many, if not most, vehicles would use electricity, though hydrogen is another
potential fuel source under development and other technologies might be developed. Initial
analysis of these types of scenarios is being undertaken in the context of the Sustainability and
Climate Action Plan (S/CAP) development process. These types of scenarios require careful
planning for the associated load growth to make sure the distribution system did not end up
overloaded, or conversely, to avoid over investment, and the evaluation of changes to utility
distribution system management to accommodate integration of the various technologies
involved in electrification.
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SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: ELECTRICITY PURCHASES
As shown in Figure 14 the utility gets roughly 50% of its energy from hydroelectric projects in a
normal year (FY 2014 and FY2015 were dry). Contracts with renewable sources made up just
over 30% of the portfolio in FY 2016, and are projected to rise to roughly 50% starting in FY
2017. The remainder comes from unspecified market sources. Under the City’s Carbon Neutral
Plan, CPAU purchases RECs corresponding to the amount of market energy it purchases.
Figure 14: Electricity Supply by Source
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Figure 15 shows the historical and projected costs for the electric supply portfolio,5 as well as
average and actual hydroelectric generation.6 Electric supply costs increased in FY 2013, FY
2014, and FY 2015 due to the drought, which reduced the amount of generation from
hydroelectric resources. Costs decreased slightly in FY 2016 due to better than expected market
purchase costs. Even if hydroelectric generation returns to normal levels, costs will increase in
FY 2017 due to increases in renewable energy costs as various renewable projects come online
to fulfill the City’s carbon neutral and RPS goals. Transmission charges are also projected to
increase as new transmission lines are built throughout California to accommodate new
renewable projects. In total, electric supply costs are projected to increase to $77.8 million by
FY 2020, at which point all currently contracted renewable projects will be online. Supply costs
are only projected to change slightly in subsequent years.
Figure 15: Electric Supply Portfolio Costs, Historical and Projected
5 Costs are shown net of wholesale revenues, and cannot be directly compared with the electric supply purchase
figures shown in Appendix A: Electric Utility Financial Forecast Detail 6 Average hydroelectric generation increased in January of 2015 due to an increase in the utility’s contractual share
of the output of the CVP Federal hydropower project.
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SECTION 6B: OPERATIONS
CPAU’s Electric Utility operations include the following activities:
•Administration, including financial management of charges allocated to the Electric
Utility for administrative services provided by the General Fund and for Utilities
Department administration, as well as debt service and other transfers. Additional detail
on Electric Utility debt service is provided in Section 6D (Debt Service)
•Customer Service
•Engineering work for maintenance activities (as opposed to capital activities)
•Operations and Maintenance of the distribution system; and
•Resource Management
Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 2012 to FY 2015, Operations costs increased by less than 1% per year on average. In
2013 there was a one-time increase in expenses associated with an adjustment to the value of
the City’s investment portfolio. Over the forecast horizon, excluding debt service and transfers,
costs are projected to increase by roughly 2 to 4 % per year.
Figure 16: Historical and Projected Electric Utility Operational Costs
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SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
CIP spending for FY 2018 through FY 2023 is projected to decrease somewhat from last year’s
forecast, primarily due to the removal of some major one-time projects, including service
connection upgrades for a few major customers. Other projects still slated to continue are pole
replacements related to the Fiber to the Home project, and Smart Grid upgrades. Ongoing
capital investment in the electric distribution system is also increasing. This forecast assumes
that smart grid projects are financed from the Electric Special Projects Reserve and with
additional funding from the water and gas funds, but it would also be possible to use bond
financing.
Excluding the one-time projects listed above, the CIP plan for FY 2018 to FY 2022 is primarily
funded by utility rates, but other sources of funds include connection fees (for Customer
Connections), phone and cable companies (primarily for undergrounding), and other funds (for
smart grid). The details of the CIP budget will be available in the Proposed FY 2018 Utilities
Capital Budget. Figure 16 shows the adopted / proposed / projected capital budgets as well as
actual and projected capitalized administrative overhead associated with the program.
Figure 17: Electric Utility CIP Spending
SECTION 6D: DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently
makes payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax
Credit Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction
costs of solar demonstration projects at the Municipal Services Center, Baylands Interpretive
Center, and Cubberley Community Center. The capacity of these projects totaled 250 kW. In
exchange for funding part of the construction costs Electric Utility receives the RECs from these
projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are interest
free (the investors receive a tax credit from the federal government). This bond issuance is
secured by the net revenues of the Electric Utility. Debt service for this bond continues through
2021, and for the financial forecast period is as follows:
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Table 10: Electric Utility Debt Service ($000)
FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
2007 Clean Renewable
Energy Bonds 100 100 100 100 100 -
The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage
ratio of 125% of debt service. The current Financial Plan maintains compliance with these
covenants throughout the forecast period, as shown in Appendix C.
The Electric Utility’s reserves and net revenue are also pledged as security for the bond
issuances listed in Table 11, even though the Electric Utility is not responsible for the debt
service payments. The Electric Utility’s reserves or net revenues would only be called upon if
the responsible utilities are unable to make their debt service payments. Staff does not
currently foresee this occurring.
Table 11: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Electric Utility’s:
Net Revenues Reserves
1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water $1,457 No Yes
*Net of Federal interest subsidy
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.7 Each year it is calculated
according to the 2009 Council-adopted methodology, and does not require additional Council
action.
SECTION 6F: WHOLESALE REVENUES AND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 13% comes
from other sources. Of these other sources, about a third represent wholesale “revenues” that
are included solely for accounting purposes. These revenues have offsetting electric supply
7 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to equity transfer methodology.
35 | Page
purchase costs, and do not normally affect the utility’s net position. Of the remaining revenues,
the largest revenue sources are interest on reserves, connection fees for new or replacement
electric services, and carbon allowance revenues associated with the State’s cap-and-trade
program. In FY 2016 these sources represented roughly 50% of revenue from sources other
than electricity sales. The remaining FY 2016 revenues consisted of a variety of one-time
transfers.
Revenues from connection fees have more than doubled since FY 2009. Revenue from these
sources decreased slightly during the recession, but has increased substantially since then,
peaking in FY 2014. Staff is forecasting slightly lower revenue from this source in subsequent
years.
Carbon allowance revenues are projected to stay stable through the forecast period, as is
interest income. However, both of these revenue sources are subject to some uncertainty. The
State’s cap-and-trade program regulations only describe the program through 2020. This
forecast assumes the program will remain in place with similar program design following 2020,
but that may not be the case. CARB is in the process of establishing post-2020 rules.
The forecast for interest income assumes current interest rates continue and there are no
major reserve reductions aside from what is anticipated in this Financial Plan. If interest rates
rise, interest income could increase, and if reserves decreased (due to drought or a withdrawal
from the ESP reserve for a major project), interest income would decrease.
SECTION 6G: SALES REVENUES
Sales revenue projections are based on the load forecast in Section 5A: Load Forecast and the
projected rate changes shown in Figure 7. As discussed in Section 5A, sales revenues for this
utility stay relatively stable due to the mild climate in Palo Alto, but decreased significantly in
FY 2017. In addition, Palo Alto is a built out City, with incremental growth in population and
relatively stable commercial customer loads.
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SECTION 7: COMMUNICATIONS PLAN
CPAU communication methods include use of the Utilities website, utility bill inserts, messaging
on bills and envelopes, email newsletters, print ads in local publications, videos and
participation in community outreach events. The FY 2018 Electric Utility communications
strategy covers these primary areas: rates, efficiency, renewables, operations, infrastructure,
safety, and changes to utility economic conditions in the wake of the drought.
In FY 2018, CPAU is proposing an 12% increase in electric utility rates. Prior to FY 2017, electric
utility rates had not increased since 2009, as the City has been drawing down reserves from the
Electric Fund. The rate increase was necessary last year and again in FY 2018, as these reserves
are below the minimum reserve level. Communications will focus on the reasons why a rate
increase is necessary, and how this percentage has been impacted due to the drought,
renewable projects, capital improvement and other costs. Palo Alto purchases a significant
portion of its electricity from hydroelectric resources. Severe drought conditions over the past
few years reduced available hydroelectric supplies, requiring the City to purchase more costly
replacement electric supplies. Since the State received a great deal of precipitation in the latter
part of FY 2017, communications staff will now focus messaging on how increased hydroelectric
supplies will impact and potentially change the forecast for electric rates moving forward, at
least in the short-term.
Reliability and safety are primary concerns for CPAU and City Council has placed increasing
emphasis on capital improvement investments for utility infrastructure. In order to maintain
system integrity, continued capital improvement costs are necessary. Deferring such costs to
future years would not be prudent, as deferred investment in maintenance, operations and
capital improvement upgrades could potentially jeopardize the safety and reliability of the
electric utility system. Despite these costs and increasing rates, CPAU’s rates remain lower than
the neighboring community average, including for municipal and investor-owned utilities
(PG&E). Keeping costs low is one of the benefits CPAU offers its customers as a public utility
provider.
CPAU will continue to communicate about the City’s carbon neutral electric supply portfolio.
Outreach includes apprising the public of major renewable energy purchase agreements, which
contribute toward Palo Alto’s long-term energy security and commitment to sustainability.
Recent power purchase agreements have allowed CPAU to procure long-term renewable
electric supplies at low costs. While upfront capital costs to bring these renewable projects
online may initially contribute towards some increase in CPAU’s electric rates, these higher
costs are expected to taper off once the projects begin commercial operations. CPAU will
highlight these environmental attributes and value in our communications.
Throughout the year, communications staff promotes CPAU’s electric efficiency services,
rebates and local renewable energy programs. From January 2015 to December 2016, CPAU
encouragedcommunity participation in the Georgetown University Energy Prize competition, a
friendly, national campaign for energy efficiency. This two-year campaign encouraged the
37 | Page
community to reduce energy use and compete for a $5 million prize. Within the past one to two
years, CPAU launched new programs thatallow customers to better understand and manage
their energy use. These programs include the Home Efficiency Genie; a free utility bill analysis
service with option for a subsidized in-depth home energy assessment; and an online utility
portal for customers to view consumption history, learn about efficiency tips and CPAU
programs they can take advantage of for home energy efficiency.
38 | Page
APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
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APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
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1 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
2
3 ELECTRIC LOAD
4 Purchases (MWh)969,519 976,319 980,894 979,005 977,292 945,703 960,601 940,860 938,688 936,402 934,369 934,369 934,369 934,369 934,369 934,369
5 Sales (MWh)942,562 946,841 950,784 936,773 937,157 906,562 908,459 907,858 905,762 903,556 901,594 901,594 901,594 901,594 901,594 901,594
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1156$ 0.1154$ 0.1164$ 0.1158$ 0.1156$ 0.1233$ 0.1407$ 0.1506$ 0.1506$ 0.1506$ 0.1516$ 0.1553$ 0.1568$ 0.1579$ 0.1589$ 0.1600$
9 Change in System Average Rate -1%0%1%0%0%10%14%7%0%0%1%2%1%1%1%1%
10 Change in Average Residential Bill -1%-4%-1%-5%3%10%11%6%-1%-1%0%2%1%0%0%0%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)343,000 1,886,000 305,000 - - - - - - - - - - - - -
14 Commitments (Non-CIP)1,593,000 2,737,000 3,528,000 3,164,000 3,102,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000
15 Restricted for Debt Service - - - - - - - - - - - - - - - -
16 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - -
17 Central Valley Project Reserve 305,000 314,000 313,000 329,000 - - - - - - - - - - - -
18 Underground Loan Reserve 736,000 742,000 738,000 734,000 730,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000
19 Public Benefits Reserves 3,139,000 1,149,000 2,197,000 2,064,000 2,574,000 1,839,000 1,330,970 739,050 279,587 94,959 - - - - - -
20 Electric Special Projects Reserve 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,838,000 41,665,260 41,525,693 41,192,360 42,859,027 46,192,360 44,665,260 44,665,260 44,665,260 44,665,260 44,665,260
21 Hydro Stabilization Reserve - - - - 17,000,000 11,400,000 2,400,000 - - - - - - - - -
22 Capital Reserves - - - - - - - - - - - - - - - -
23 Rate Stabilization Reserves 66,331,000 74,609,000 69,029,000 70,049,000 14,411,000 9,011,000 3,600,000 - - - - - - - - -
24 Operations Reserves - - - - 22,498,000 21,850,000 21,570,031 28,477,295 31,328,331 31,984,129 32,727,128 36,734,340 36,600,128 36,226,077 38,957,005 40,470,904
25 Unassigned - - - - - - - - 915,938 (0) 0 0 - - - -
26 TOTAL STARTING RESERVES 129,005,000 132,757,000 128,948,000 129,178,000 112,153,000 100,444,000 75,072,262 75,248,039 78,222,216 79,444,115 83,425,489 85,905,601 85,771,388 85,397,337 88,128,265 89,642,164
27
28 REVENUES
29 Net Sales 109,309,318 109,974,337 110,246,264 108,873,377 108,312,917 111,743,300 127,804,839 136,731,078 136,415,457 136,083,191 136,693,648 139,980,910 141,364,099 142,326,185 143,276,966 144,246,140
30 Wholesale Revenues 7,189,218 6,635,790 6,010,409 6,267,000 5,534,000 11,422,865 16,360,219 13,481,291 15,723,490 16,405,058 17,841,074 17,242,448 17,467,779 17,643,588 17,905,633 19,002,541
31 Other Revenues and Transfers In 7,027,230 9,624,213 13,669,185 9,688,480 10,129,274 10,013,826 14,509,829 12,934,637 21,875,693 18,854,966 15,870,577 12,946,907 13,320,702 13,772,401 14,201,802 14,631,713
32 TOTAL REVENUES 123,525,766 126,234,340 129,925,858 124,828,858 123,976,191 133,179,991 158,674,887 163,147,006 174,014,640 171,343,215 170,405,299 170,170,265 172,152,580 173,742,173 175,384,402 177,880,394
33
34 EXPENSES
35 Electric Supply Purchases 58,724,136 61,313,637 68,785,977 80,022,010 79,114,644 84,371,202 87,986,828 89,065,816 90,840,796 90,727,608 92,220,793 91,758,113 92,924,517 93,903,644 95,224,116 96,464,584
36 Operating Expenses
37 Administration
38 Allocated Charges 3,416,423 4,399,674 4,139,837 4,511,222 5,148,470 3,376,852 3,461,365 3,547,989 3,636,783 3,727,743 3,820,946 3,916,481 4,014,404 4,114,776 4,217,658 4,323,112
39 Rent 3,839,201 3,875,836 4,051,044 4,147,742 4,997,101 5,121,102 5,274,735 5,432,977 5,595,966 5,763,845 5,936,761 6,114,864 6,298,310 6,487,259 6,681,877 6,882,333
40 Debt Service 8,902,751 9,265,736 9,020,651 9,037,000 8,985,994 8,889,090 8,868,768 8,471,091 8,480,048 8,444,315 8,453,684 9,299,046 8,893,834 4,898,677 4,896,047 4,894,784
41 Transfers and Other Adjustments 11,603,695 16,797,054 11,329,973 11,003,993 5,920,297 12,078,949 13,226,214 13,275,892 14,159,863 14,163,159 14,166,536 14,169,998 14,173,547 14,177,184 14,180,913 14,184,734
42 Subtotal, Administration 27,762,069 34,338,299 28,541,506 28,699,957 25,051,862 29,465,993 30,831,082 30,727,949 31,872,660 32,099,063 32,377,926 33,500,388 33,380,095 29,677,896 29,976,494 30,284,963
43 Resource Management 2,654,024 3,024,268 3,541,524 2,138,615 2,035,834 3,240,541 3,356,945 3,476,405 3,600,582 3,707,001 3,803,153 3,902,819 4,005,096 4,110,053 4,217,761 4,328,292
44 Demand Side Management 4,541,531 3,529,529 3,187,875 3,491,470 3,723,605 3,690,063 3,773,952 3,639,388 3,357,212 3,297,042 3,255,251 3,339,598 3,384,926 3,431,076 3,478,065 3,525,906
45 Operations and Mtc 9,288,490 9,601,481 9,488,627 10,716,881 11,514,846 13,702,158 14,158,618 14,626,674 15,111,694 15,541,894 15,941,538 16,354,711 16,778,592 17,213,460 17,659,598 18,117,300
46 Engineering (Operating)1,057,783 1,114,945 1,102,008 1,230,160 1,578,022 1,840,073 1,889,674 1,940,499 1,992,737 2,044,182 2,095,630 2,148,473 2,202,649 2,258,191 2,315,133 2,373,512
47 Customer Service 1,908,493 2,007,322 2,032,231 1,548,851 1,538,363 2,212,967 2,297,149 2,383,613 2,473,714 2,549,014 2,615,594 2,684,750 2,755,735 2,828,597 2,903,385 2,980,150
48 Allowance for Unspent Budget - - - - - (1,461,604) (1,508,656) (1,556,914) (1,606,879) (1,651,905) (1,694,232) (1,737,944) (1,782,784) (1,828,782) (1,875,967) (1,924,370)
49 Subtotal, Operating Expenses 47,212,389 53,615,844 47,893,770 47,825,933 45,442,532 52,690,192 54,798,765 55,237,614 56,801,721 57,586,290 58,394,860 60,192,796 60,724,308 57,690,491 58,674,470 59,685,754
50 Capital Program Contribution 13,837,241 15,113,859 13,016,111 14,005,915 11,128,015 21,490,335 15,573,950 15,869,398 25,150,225 19,047,944 17,449,100 18,353,570 18,877,806 19,417,110 19,971,917 20,542,674
51 TOTAL EXPENSES 119,773,766 130,043,340 129,695,858 141,853,858 135,685,191 158,551,729 158,359,542 160,172,828 172,792,742 167,361,841 168,064,753 170,304,478 172,526,631 171,011,245 173,870,503 176,693,012
52 22,058,000.0 26,659,398 15,868,470 16,320,285 16,784,774
53 ENDING RESERVES
54 Reappropriations (Non-CIP)1,886,000 305,000 - - - - - - - - - - - - - -
55 Commitments (Non-CIP)2,737,000 3,528,000 3,164,000 3,102,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000
56 Restricted for Debt Service - - - - - - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - - -
58 Central Valley Project Reserve 314,000 313,000 329,000 - - - - - - - - - - - - -
59 Underground Loan Reserve 742,000 738,000 734,000 730,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000
60 Public Benefits Reserves 1,149,000 2,197,000 2,064,000 2,574,000 1,839,000 1,330,970 739,050 279,587 94,959 - - - - - - -
61 Electric Special Projects Reserve 50,320,000 51,838,000 51,838,000 51,838,000 51,838,000 41,665,260 41,525,693 41,192,360 42,859,027 46,192,360 44,665,260 44,665,260 44,665,260 44,665,260 44,665,260 44,665,260
62 Hydro Stabilization Reserve - - - 17,000,000 11,400,000 2,400,000 - - - - - - - - - -
58 Capital Reserve - - - - - - - - - - - - - - - -
59 Rate Stabilization Reserve 74,609,000 69,029,000 70,049,000 14,411,000 9,011,000 3,600,000 - - - - - - - - - -
60 Operations Reserve - - - 22,498,000 21,850,000 21,570,031 28,477,295 31,328,331 31,984,129 32,727,128 36,734,340 36,600,128 36,226,077 38,957,005 40,470,904 41,658,286
61 Unassigned - - - - - - - 915,938 (0) 0 0 - - - - -
62 TOTAL ENDING RESERVES 132,757,000 128,948,000 129,178,000 112,153,000 100,444,000 75,072,262 75,248,039 78,222,216 79,444,115 83,425,489 85,905,601 85,771,388 85,397,337 88,128,265 89,642,164 90,829,546
63
64 OPERATIONS RESERVE
65 Min (60 days of non-capital expenses)23,548,140 23,951,699 25,106,757 25,973,915 26,332,908 26,857,109 27,090,134 27,593,969 27,942,086 28,353,037 28,150,419 28,667,754 29,179,891
66 Target (90 days of non-capital expenses)33,151,752 33,702,675 35,379,286 36,622,631 37,102,294 37,828,286 38,116,222 38,808,965 39,266,545 39,816,759 39,444,963 40,151,398 40,848,296
67 Max (120 days of non-capital expenses)42,755,364 43,453,651 45,651,816 47,271,347 47,871,681 48,799,463 49,142,310 50,023,961 50,591,003 51,280,480 50,739,507 51,635,042 52,516,702
68 Risk Assessment Value 4,645,297 4,373,014 5,295,861 5,257,153 5,457,746 6,376,895 5,757,260 5,660,508 6,010,401 6,256,453 6,469,660 6,600,181 6,733,749
69
70 DEBT SERVICE COVERAGE RATIO
71 Net Revenues (125% of Debt Service)1090% 1140% 1193% 1315%1286% 1442% 1510% 1603% 1641% 1656% 1682% 1534% 1628% 2995% 3043% 3090%
72 Available Reserves (5x Debt Service)*14.4 13.5 14.0 12.1 10.8 8.0 8.1 8.8 8.9 9.4 9.7 8.8 9.2 17.2 17.5 17.8
*For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants.
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1 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
2
3 REVENUES
4 Net Sales 88%87%85%87%87%84%81%84%78%79%80%82%82%82%82%81%
5 Other Revenues and Transfers In 12%13%15%13%13%16%19%16%22%21%20%18%18%18%18%19%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 46%46%52%55%54%50%46%47%45%46%46%46%46%47%47%47%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%3%3%3%4%2%2%2%2%2%2%2%2%2%2%2%
13 Rent 3%3%3%3%4%3%3%3%3%3%4%4%4%4%4%4%
14 Debt Service 7%7%7%6%7%6%6%5%5%5%5%5%5%3%3%3%
15 Transfers and Other Adjustments 10%13%9%8%4%8%8%8%8%8%8%8%8%8%8%8%
16 Subtotal, Administration 23%26%22%20%18%19%19%19%18%19%19%20%19%17%17%17%
17 Resource Management 2%2%3%2%2%2%2%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 8%7%7%8%8%9%9%9%9%9%9%10%10%10%10%10%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 2%2%2%1%1%1%1%1%1%2%2%2%2%2%2%2%
21 Allowance for Unspent Budget 0%0%0%0%0%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 36%39%34%31%31%31%32%32%31%32%33%33%33%32%32%32%
23 Capital Program Contribution 12%12%10%10%8%14%10%10%15%11%10%11%11%11%11%12%
24 TOTAL EXPENSES 94%96%97%96%93%94%88%89%90%90%89%90%90%90%90%90%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
28 1. Load Net Revenue 77,428 652,853 1,208,477
29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 3,397,119
30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 539,073
31 4. Carbon Neutral Cost 331,630 303,022 114,983
32 5. Market Price 909,196 775,584 1,138,589
33 6. Local Capacity 475,962 408,388 446,695
34 7. Transmission/CAISO 4,555,915 3,741,647 2,806,120
35 8. Plant Outage 1,000,000 1,000,000 1,000,000
36 9. Western Cost 3,130,000 2,704,738 2,973,619
37 10. Regulatory & Legal - - -
38 11. Supplier Default - - -
39 TOTAL 20,170,708 19,380,490 13,624,674
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 196%172%176%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
44 Distribution Revenue Variance 3,244,706 3,260,213 3,146,827 3,699,758 3,870,807 3,861,873 3,852,466 3,915,598 4,175,044 4,368,672 4,527,949 4,602,989 4,679,481
45 10% CIP Program Contingency 1,400,592 1,112,802 2,149,034 1,557,395 1,586,940 2,515,022 1,904,794 1,744,910 1,835,357 1,887,781 1,941,711 1,997,192 2,054,267
46 Total Risk Asssessment Value 4,645,297 4,373,014 5,295,861 5,257,153 5,457,746 6,376,895 5,757,260 5,660,508 6,010,401 6,256,453 6,469,660 6,600,181 6,733,749
47 Projected Operations Reserve 22,498,000 21,850,000 21,570,031 28,477,295 28,507,266 31,984,129 32,727,129 36,734,340 36,600,128 36,226,077 38,957,005 40,470,904 41,658,286
48 Operations Reserve, % of Risk Value 484%500%407%542%522%502%568%649%609%579%602%613%619%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- - - 15,208,552 15,033,113 16,240,825 16,860,400 17,001,701 17,325,251 17,328,711 17,602,415 17,709,305 17,862,689 17,395,887 17,642,251 17,876,454
46 Target (90 days of non-capital expenses)- - - 22,812,829 22,549,669 24,361,237 25,290,599 25,502,552 25,987,877 25,993,067 26,403,622 26,563,958 26,794,033 26,093,831 26,463,376 26,814,681
47 Max (120 days of non-capital expenses)- - - 30,417,105 30,066,225 32,481,649 33,720,799 34,003,403 34,650,502 34,657,422 35,204,830 35,418,611 35,725,378 34,791,775 35,284,501 35,752,908
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- - - 8,339,587 8,918,586 8,865,932 9,113,516 9,331,206 9,531,858 9,761,423 9,991,554 10,232,781 10,490,348 10,754,532 11,025,503 11,303,437
51 Target (90 days of non-capital expenses)- - - 10,338,923 11,153,006 11,018,050 11,332,032 11,599,742 11,840,409 12,123,155 12,405,343 12,702,586 13,022,725 13,351,132 13,688,022 14,033,616
52 Max (120 days of non-capital expenses)- - - 12,338,259 13,387,426 13,170,167 13,550,548 13,868,279 14,148,960 14,484,888 14,819,131 15,172,392 15,555,102 15,947,732 16,350,541 16,763,794
53 Risk Assessment Value 4,645,297 4,373,014 5,295,861 5,257,153 5,457,746 6,376,895 5,757,260 5,660,508 6,010,401 6,256,453 6,469,660 6,600,181 6,733,749
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1090%1140%1193%1315%1286%1442%1510%1603%1641%1656%1682%1534%1628%2995%3043%3090%
57 Available Reserves (5x Debt Service)*14.4 13.5 14.0 12.1 10.8 8.0 8.1 8.8 8.9 9.4 9.7 8.8 9.2 17.2 17.5 17.8
58 *For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants.
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 43 | Page
APPENDIX B: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
(This section includes the proposed amendments to this section. This section will be finalized
following Council adoption of the final amended version.)
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a)“Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b)“Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c)“Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d)“Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserve for Commitments)
b)For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c)For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d)For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e)For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f)For operating contingencies, as described in Section 12 (Operations Reserves)
g)Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserves for Commitments)
b)For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c)As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d)To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 44 | Page
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 14 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Commitments will be set to an amount equal to the total remaining spending
authority for all contracts in force for the Electric Supply Fund and Electric Distribution
Fund, respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Reappropriations will be set to an amount equal to the amount of all remaining
capital and non-capital budgets that will be reappropriated to the following fiscal year for
each Fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of
Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve
and Adoption of Electric Special Project Reserve Guidelines). These policies and timelines
are included from Resolution 9206 as amended to refer to the reserves structure set forth
in these Reserves Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) The preferred projects to be funded by the ESP Reserve must be identified by end of
FY 2015;
f) Any uncommitted funds remaining at the end of FY 2020 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed; and
g) Funds may be used for analysis and pilot projects which would be the basis for planned
large projects.
Section 7. Hydroelectric Stabilization Reserve
Supply cost savings and surplus energy sales revenue associated with higher than average
generation from hydroelectric resources may be added to the Electric Supply Fund’s
Hydroelectric Stabilization Reserve by action of the City Council and held to offset higher
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 45 | Page
commodity supply costs during years of lower than average generation. Withdrawal of
funds from the Hydroelectric Stabilization Reserve requires action by the City Council.
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a)The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 60 days of budgeted CIP expense
Maximum Level 120 days of budgeted CIP expense
b)Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve
for Commitments as a result of a change in contractual commitments related to CIP
projects. Any other additions to or withdrawals from the CIP reserve require Council
action.
c)Minimum Level:
i)Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ii)If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d)Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 46 | Page
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to d) above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 47 | Page
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e)Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were
funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an
alternative plan that retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 48 | Page
APPENDIX C: DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL ACTIVITIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Electric Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process.
It does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
•monitoring the substations and performing routine maintenance;
•performing preventative maintenance on the system;
•monitoring the system’s status from the UCC using SCADA;
•maintaining the SCADA system;
•investigating outages and other customer complaints and performing emergency
repairs;
•clearing vegetation near overhead power lines; and
•testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX D: SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
570 Kirkland Way, Suite 100
Kirkland, Washington 98033
Telephone: 425 889-700 Facsimile: 425 889-2725
A registered professional engineering corporation with offices in
Kirkland, WA and Portland, OR
March 29, 2017
TO: Jon Abendschein, City of Palo Alto
Eric Keniston, City of Palo Alto
FROM: Anne Falcon, EES Consulting
SUBJECT: 2017 COSA Model and Rate Design Update
Introduction
The City’s COSA and Rate Design models consist of four components: a FERC Account Model
that translates the City’s budget accounts, a Cost of Service (COS) model that allocates the
budgeted costs to customer classes, a Lighting and Traffic Signal COS and Rate Model that
allocates costs to lighting and traffic signal customers, and a Rate Design Model that generates
the rates for all other customer classes. As part of the annual budget process, the FERC Account
Model, Electric COS Model, Lighting and Traffic Signal Model, and Rate Design models were
updated for the FY 2018 budget year. This update included updating financial and load data as
well as reviewing other inputs that impact the City of Palo Alto’s cost of providing electric
service. The underlying methodology of the COSA was not changed. rather EES assisted the City
of Palo Alto with updating the inputs to the existing methodology to reflect FY 2018 sales and
budget projections, and streamline one rate schedule to remove redundancies (e.g. removing
rate schedule E-18).
Summary of Updates
As part of the update, the City staff provided updated budget and load forecasts for the years
FY 2018 through FY 2020. After reviewing the budget data, the revenue requirement and load
forecast in the FERC Account Model and COSA model were updated based on the projected FY
2018 budget. Projected revenues from current rates were forecast for each rate schedule
based on the updated load data staff provided. Rate schedule 18 (Municipal Electric Service)
was removed as customers historically in that rate schedule have been reclassified, as of July
2017to Rate Schedule E-4 (Medium Commercial Electric Service) and E-7 (Large Commercial
Electric Service), to more accurately reflect the costs of serving municipal customers.
ATTACHMENT C
MEMORANDUM TO Jon Abendschein & Eric Keniston
March 29, 2017
Page 2
The Lighting and Traffic Signal Model was updated with FY 2018 transmission and distribution
Operation and Maintenance costs, power supply costs and total overhead costs. This model
determines the total cost of service for the street lighting and traffic lighting rate classes based
on individual bulb type and O&M requirements. This model was then used to determine the
costs associated with providing service to the traffic light rate customers only. The share of
costs associated with traffic lights service will collected as a transfer from the City’s General
Fund to its Electric Utility and is reflected in the Electric COSA model under “Other Revenues”.
The final model update was the rate design model. This model takes the updated COS Model
cost allocation results by rate class and develops rates for each class that meet the allocated
revenue requirement for each rate class. The updates included updated FY 2018 allocated
costs, updated seasonal power cost splits, updated billing data (such as load in each residential
rate tier, Non-Coincident Peaks and energy consumption) and Time of Use (TOU) marginal
costs.
Using the same methodology that was developed in 2016, the following rates were updated:
• E-1: Tier 1 and Tier 2 Energy charges, minimum bill and PBC
• E-1 TOU: TOU energy rates by period and season
• E-2: Energy by season, minimum bill and PBC
• E-4: Energy and demand by season, minimum bill and PBC
• E-4 TOU: TOU energy and demand rates by period and season
• E-7: Energy and demand rates by season, minimum bill and PBC
• E-7 TOU: TOU energy and demand rates by period and season
An updated rate comparison is provided below.
Summary of Results
The following provide the updated rates compared to current rates:
Residential
Energy Rates
Existing
($/kWh)
New
($/kWh) Percent Change
Tier 1 $0.11029 $0.12159 10.2%
Tier 2 $0.16901 $0.19001 12.4%
MEMORANDUM TO Jon Abendschein & Eric Keniston
March 29, 2017
Page 3
Please let me know if you have any questions.
Commercial Existing Rates
Demand ($/kW)Energy ($/kWh)
Summer Winter Summer Winter
E-2 $0.16845 $0.11445
E-4 $19.68 $14.04 $0.10229 $0.08049
E-7 $18.34 $15.65 $0.08749 $0.06242
Commercial New Rates
Demand ($/kW)Energy ($/kWh)
Summer Winter Summer Winter
E-2 $0.18885 $0.13267
E-4 $21.05 $15.36 $0.11673 $0.08890
E-7 $23.84 $15.59 $0.09802 $0.07188
Difference (%)
Demand Energy
Summer Winter Summer Winter
E-2 12.1%15.9%
E-4 7.0%9.4%14.1%10.5%
E-7 30.0%-0.4%12.0%15.1%
Attachment D
Not Yet Approved
170329 jb 6053934 1
Resolution No. ____
Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Small Commercial Electric Service), E-2-G (Small
Commercial Green Power Electric Service), E-4 (Medium Commercial
Electric Service), E-4-G (Medium Commercial Green Power Electric
Service), E-4 TOU (Medium Commercial Time of Use Electric Service),
E 7 (Large Commercial Electric Service), E-7-G (Large Commercial
Green Power Electric Service), E-7 TOU (Large Commercial Time of
Use Electric Service), and E-14 (Street Lights)
R E C I T A L S
A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
The Council of the City of Palo Alto hereby RESOLVES as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2017.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2 (Small Commercial Electric Service) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-2, as amended, shall become effective July 1, 2017.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2-G (Small Commercial Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-2-G, as amended, shall become
effective July 1, 2017.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Commercial Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2017.
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Commercial Green Power Electric Service) is hereby amended to
Attachment D
Not Yet Approved
170329 jb 6053934 2
read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall become
effective July 1, 2017.
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Commercial Time of Use Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended, shall become
effective July 1, 2017.
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Commercial Electric Service) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-7, as amended, shall become effective July 1, 2017.
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Commercial Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become
effective July 1, 2017.
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Commercial Time of Use Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become
effective July 1, 2017.
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated.
Utility Rate Schedule E-14, as amended, shall become effective July 1, 2017.
SECTION 11. The Council makes the following findings:
a. The revenue derived from the adoption of this resolution shall be used only for the
purpose set forth in Article VII, Section 2, of the Charter of the City of Palo Alto.
b. The fees and charges adopted by this resolution are charges imposed for a specific
government service or product provided directly to the payor that are not provided
to those not charged, and do not exceed the reasonable costs to the City of
providing the service or product.
c. The adoption of this resolution changing electric rates to meet operating expenses,
purchase supplies and materials, meet financial reserve needs and obtain funds for
capital improvements necessary to maintain service is not subject to the California
Attachment D
Not Yet Approved
170329 jb 6053934 3
Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec.
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After
reviewing the staff report and all attachments presented to Council, the Council
incorporates these documents herein and finds that sufficient evidence has been
presented setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Senior Deputy City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-1-1 dated 7-1-201609 Sheet No E-1-1
A. APPLICABILITY:
This schedule applies to separately metered single-family residential dwellings receiving retail
energy services from the City of Palo Alto Utilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides electric service.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Tier 1 usage $0.06605883 $0.05164795 $0.0039151 $0.1102912159
Tier 2 usage
Any usage over Tier 1
0.1125309728 0.0682207358 0.0039151 0.169001
Minimum Bill ($/day) 0.30672938
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s billstatement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Calculation of Usage Tiers
Tier 1 electricity usage shall be calculated and billed based upon a level of 11 kWh perday, prorated by meter reading days of service. As an example, for a 30-day bill, the Tier1 level would be 330 kWh. For further discussion of bill calculation and proration, refer
to Rule and Regulation 11.
{End}
ATTACHMENT E
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-1 dated 7-1-201609 Sheet No E-2-1
A. APPLICABILITY: This schedule applies to non-demand metered electric service for small non-residentialcommercial customers and master-metered multi-family facilities.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides electric service. C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period
$0.1059109094 $0.0740007903 $0.0039151 $0.1684518885
Winter Period 0.0641707520 0.0467705356 0.0039151 0.132671445
Minimum Bill ($/day)
0.7328657
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill statement, the bill amount may be broken down into appropriate components as
calculated under Section C. 2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-2 dated 7-1-201609 Sheet No E-2-2
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum demand meter will be installed as promptly as is practicable and thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The maximum demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if in case the Customer’s
load is intermittent or subject to violent fluctuations, the City may use a 5-minute
interval. A thermal-type demand meter which does not reset after a definite time interval
may be used at the City's option. The billing demand to be used in computing charges under this schedule will be the actual maximum demand in kilowatts for the current month. An exception is that the
billing demand for customers with Thermal Energy Storage (TES) will be based upon the
actual maximum demand of such customers between the hours of noon and 6 pm on
weekdays. {End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-1 dated 7-1-201609 Sheet No E-2-1
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-G-1 dated 7-1-20164 Sheet No E-2-G-1
A. APPLICABILITY: This schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities under the Palo Alto Green Program:
1. Small non-residentialcommercial Customers receiving Non-Demand Metered electric service; and
2. Customers with accounts at Master-metered multi-family facilities.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: 1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits
Palo Alto
Green Charge Total
Summer Period
$0.10591090
94
$0.07903400
$0.003915
1 $0.0020
$0.170451
9085
Winter Period 0.075206417 0.053564677 0.0035191 0.0020
$0.116451
3467
Minimum Bill ($/day)
0.7328657
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$0.09094105
91
$0.07903074
00
$0.003915
1
$0.168451
8885
Winter Period
0.0641707520 0.053564677 0.0039151
0.1144513467
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-G-2 dated 7-1-20164 Sheet No E-2-G-2
Minimum Bill ($/day)
0.7328657
Palo Alto Green Charge (per 1000 kWh block) $2.00
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewable sources, and create a transparent and sustainable market that encourages new
development of wind and solar power.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-G-3 dated 7-1-20164 Sheet No E-2-G-3
4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed. The maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that ifin case the Customer-s load is intermittent or subject to violent fluctuations, the City may use a 5-minute
interval. A thermal-type Demand Meter which does not reset after a definite time
interval may be used at the City's option. The billing Demand to be used in computing charges under this schedule will be the
actual maximum Demand in kilowatts for the current month. An exception is that the billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
{End}
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-1 dated 27-51-20136 Sheet No E-4-1
A. APPLICABILITY: This schedule applies to Demand metered secondary Electric Service for customers with a
Maximum Demand below 1,000 kilowatts. This schedule applies to three-phase Electric
Service and may include Service to master-metered multi-family facilities or other facilities
requiring Demand-metered services, as determined by the City.
B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $2.533.38 $17.1467 $19.6821.05
Energy Charge (per kWh)
0.0821809526 0.0166101756 0.0035100391 0.1022911673
Winter Period
Demand Charge (per kW) $1.9355 $12.4913.43 $14.0415.36
Energy Charge (per kWh)
0.0603706743 0.016610176 0.0035100391 0.0804908890
Minimum Bill ($/day) 16.321614.8414 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C.
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-2 dated 27-51-20136 Sheet No E-4-2
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a Maximum Demand meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed. The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if in case the Customer-s
load is intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A thermal-type Demand meter which does not reset after a definite time interval
may be used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such customers between the hours of noon and 6 pm on
weekdays.
4. Power Factor For new or existing customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable
metering to calculate a Power Factor. The City may remove such metering from the
Service of a customer whose Demand has been below 200 kilowatts for four consecutive
months.
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-3 dated 27-51-20136 Sheet No E-4-3
When such metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent (0.25%) for each one percent (1%) that the monthly Power Factor of the customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day metering
is installed, the monthly Power Factor shall be the Power Factor coincident with the customer's Maximum Demand.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any City of Palo Alto full-service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage
profile.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered,allowed provided but the City is not required to supply Service at a particular line
voltage where it has, or will install, ample facilities for supplying at another voltage
equally or better suited to the customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time
after providing reasonable advance notice to any customer receiving a the discount in this
sectionhereunder and affected by such change. The customer then has the option to
change his system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non-
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-4 dated 27-51-20136 Sheet No E-4-4
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-5 dated 27-51-20136 Sheet No E-4-5
{End}
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-1 dated 7-1-20164 Sheet No E-4-G-1
A. APPLICABILITY: This schedule applies to Demand Metered Secondary Electric Service for Customers with a
Maximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green
Program. This schedule applies to three-phase Electric Service and may include Service to
Master-metered multi-family facilities or other facilities requiring Demand-Metered Services, as determined by the City.
B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge (per kW) $2.533.38 $17.6714
$19.6821.05
Energy Charge (per kWh)
0.0821809526 0.01756661 0.0039151 0.0020
0.118730429
Winter Period
Demand Charge (per kW) $1.5593 $12.4913.43
$15.3614.04
Energy Charge (per kWh)
0.0603706743 0.01756661 0.0039151 0.0020
0.090908249
Minimum Bill ($/day) 16.321614.8414
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-2 dated 7-1-20164 Sheet No E-4-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.382.53 $17.6714 $21.0519.68
Energy Charge (per kWh) 0.095268218 0.01756661 0.0039151 0.116730229
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.9355 $12.4913.43 $15.3614.04
Energy Charge (per kWh) 0.06743037 0.01756661 0.0039151 0.08890049
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 14.841416.3216 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-3 dated 7-1-20164 Sheet No E-4-G-3
option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that in case if the Customer’s
load is intermittent or subject to violent fluctuations, the City may use a 5-minute
interval. A thermal-type Demand Meter, which does not reset after a definite time interval, may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with
the Customer's Maximum Demand. 5. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full-service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-4 dated 7-1-20164 Sheet No E-4-G-4
6. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new
development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be offered,allowed provided but the City is not required to supply Service at a particular line
voltage where it has, or will install, ample facilities for supplying at another voltage
equally or better suited to the Customer's electrical requirements, as determined in the
City’s sole discretion. The City retains the right to change its line voltage at any time
after providing reasonable advance notice to any Customer receiving a the discount in this sectionhereunder and affected by such change. The Customer then has the option to
change the system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a
maximum kilovolt-ampere size limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-utility generation source.
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-5 dated 7-1-20164 Sheet No E-4-G-5
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director.
{End}
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-1 dated 27-51-20136 Sheet No E-4-TOU-1
A. APPLICABILITY: This voluntary rate schedule applies to Demand metered secondary Electric Service for
customers with Demand between 500 and 1,000 kilowatts per month and who have sustained
this level of usage for at least three consecutive months during the most recent 12 month period.
This schedule applies to three-phase Electric Service and may include Service to master-metered multi-family facilities or other facilities requiring Demand-metered services, as
determined by the City. In addition, this rate schedule is applicable for customers who did not
pay Power Factor Adjustments during the last 12 months. B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $2.121.52 $6.095.91 $8.217.42
Mid-Peak 0.6654 6.095.91 6.7644
Off-Peak 0.6654 6.095.91 6.7644
Energy Charge (per kWh)
Peak $0.1014408819 $0.01756661 $0.0039151 $0.122910830
Mid-Peak 0.098358367 0.01756661 0.0039151 0.119820378
Off-Peak 0.087487332 0.01756661 0.0039151 0.1089509344
Winter Period
Demand Charge (per kW)
Peak $1.070.87 $7.496.96 $8.567.83
Off-Peak 1.070.87 7.496.96 8.567.83
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-2 dated 27-51-20136 Sheet No E-4-TOU-2
Commodity Distribution Public Benefits Total
Energy Charge (per kWh)
Peak $0.081646566 $0.01756661 $0.0039151 $0.1031108577
Off-Peak 0.057386167 0.01756661 $0.0039151 0.078858178
Minimum Bill ($/day) 16.321614.8414 D. SPECIAL NOTES: 1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C. 2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays) All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Years Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-3 dated 27-51-20136 Sheet No E-4-TOU-3
SEASONAL RATE CHANGES: When the billing period includes use in both the
Summer and the Winter periods, the usage will be prorated based on the number of days
in each seasonal period, and the charges based on the applicable rates therein.. For
further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Demand meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it
may be removed. The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated Time periods as defined under Section D.2.
4. Power Factor Adjustment
Time of Use customers must not have had a Power Factor Adjustment assessed on their Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month, and must not have fallen
below 95% to avoid the Power Factor Adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be subject to Power Factor Adjustments, the Customer will be removed from the E-4-
TOU rate schedule and placed on another applicable rate schedule as is suitable to their
kilowatt Demand and kilowatt-hour usage.
5. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 months, the
Customer may request a rate schedule change to any applicable City of Palo Alto full-
service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 6. Primary Voltage Discount
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-4 dated 27-51-20136 Sheet No E-4-TOU-4
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered,allowed provided but the City is not required to supply Service at a particular line
voltage where it has, or will install, ample facilities for supplying at another voltage
equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time
after providing reasonable advance notice to any Customer receiving a the discount in
this sectionhereunder and affected by such change. The Customer then has the option to
change his system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue meter
are not operating, the Maximum Demand will be reduced by the sum of the
Maximum Generation of those non-utility generators, but in no event shall the
Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-5 dated 27-51-20136 Sheet No E-4-TOU-5
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director. {End}
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-1 dated 27-51-20163 Sheet No E-7-1
A. APPLICABILITY: This schedule applies to Demand metered secondary Service for non-residentialcommercial
Customers with a Maximum Demand of at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months. B. TERRITORY:
This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (kW) $3.492.50 $20.3515.85 $23.8418.34
Energy Charge (kWh) 0.093538311 0.0005887 0.0039151 0.098028749
Winter Period
Demand Charge (kW) $1.9053 $13.6914.11 $15.5965
Energy Charge (kWh) 0.067395804 0.0005887 0.0039151 0.071886242
Minimum Bill ($/day) 42.364848.5054 D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-2 dated 27-51-20163 Sheet No E-7-2
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one account
or one meter if the accounts are on one site. A site shall be defined as one or more utility
accounts serving contiguous parcels of land with no intervening public right-of-ways
(e.g. streets) and have a common billing address.
4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of
the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that in case if the Customer’s load is intermittent or subject to violent fluctuations, the City may use a 5-minute
interval. A thermal-type Demand meter which does not reset after a definite time interval
may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-3 dated 27-51-20163 Sheet No E-7-3
5. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option to install applicable
metering to calculate a Power Factor. The City may remove such metering from the
Service of a Customer whose Demand has been below 200 kilowatts for four consecutive months. When such metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25 percent (0.25%) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day metering
is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered,allowed provided but the City is not required to supply Service at a particular line
voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements , as determined in the
City’s sole discretion. The City retains the right to change its line voltage at any time
after providing reasonable advance notice to any Customer receiving a the discount in
this section hereunder and affected by such change. The Customer then has the option to
change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a
maximum kVA size limitation.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-4 dated 27-51-20163 Sheet No E-7-4
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.4) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-5 dated 27-51-20163 Sheet No E-7-5
Section 2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-1 dated 7-1-20164 Sheet No E-7-G-1
A. APPLICABILITY: This schedule applies to Demand Metered Service for large non-residentialcommercial
Customers who choose Service under the Palo Alto Green Program. A Customer may qualify
for this rate schedule if the Customer’s Maximum Demand is at least 1,000KW per month per
site, who have sustained this Demand level at least 3 consecutive months during the last twelve
months B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge ( per kW) $3.492.50 $20.3515.85 $23.8418.34
Energy Charge (per kWh) 0.093538311 0.0005887 0.0039151 0.0020 0.1000208949
Winter Period
Demand Charge (per kW) $1.9053 $13.6914.11 $15.5965
Energy Charge (per kWh) 0.067395804 0.0005887 0.0039151 0.0020 0.073886442
Minimum Bill ($/day) 42.364848.5054
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-2 dated 7-1-20164 Sheet No E-7-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.492.50 $20.3515.85 $23.8418.34
Energy Charge (per kWh) 0.093538311 0.0005887 0.0039151 0.098028749
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.9053 $13.6914.11 $15.5965
Energy Charge (per kWh) 0.067395804 0.0005887 0.0039151 0.071886242
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 42.364848.5054 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C. 2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-3 dated 7-1-20164 Sheet No E-7-G-3
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that in case if the load is
intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Request for Service Qualifying Customers may request Service under this schedule for more than one
Account or one Meter if the Accounts are at one site. A site shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and have a common billing address. 5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-4 dated 7-1-20164 Sheet No E-7-G-4
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile 7. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new
development of wind and solar. Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program. 8. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, butallowed; provided, however, the City is not required to supply Service at a
qualified line voltage where it has, or will install, ample facilities for supplying at another
voltage equally or better suited to the Customer's Electrical requirements , as determined
in the City’s sole discretion. The City retains the right to change its line voltage at any
time after providing reasonable advance notice to any Customer receiving a the discount in this section hereunder and affected by such change. The Customer then has the option
to change the system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a
maximum kilovolt-ampere size limitation.
9. Standby Charge
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-5 dated 7-1-20164 Sheet No E-7-G-5
a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-6 dated 7-1-20164 Sheet No E-7-G-6
{End}
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-1 dated 72-15-20163 Sheet No E-7-TOU-1
A. APPLICABILITY: This voluntary rate schedule applies to Demand metered secondary Service for non-
residentialcommercial customers with a Maximum Demand of at least 1,000KW per month per
site, who have sustained this Demand level at least 3 consecutive months during the last twelve months. In addition, this rate schedule is applicable for customers who did not pay Power Factor Adjustments during the last 12 months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $2.221.48 $6.845.33 $9.066.80
Mid-Peak 0.6451 6.845.33 7.485.84
Off-Peak 0.6451 6.845.33 7.485.84
Energy Charge (per kWh)
Peak $0.1017709267 $0.0005887 $0.0039151 $0.1062609705
Mid-Peak 0.098688792 0.0005887 0.0039151 0.1031609230
Off-Peak 0.087777705 0.0005887 0.0039151 0.092268143
Winter Period
Demand Charge (per kW)
Peak $0.9678 $6.937.15 $7.892
Off-Peak 0.9678 6.937.15 7.892
Energy Charge (per kWh)
Peak $0.080366009 $0.0005887 $0.0039151 $0.084846447
Off-Peak 0.056473 0.0005887 0.0039151 0.0609681
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-2 dated 72-15-20163 Sheet No E-7-TOU-2
Minimum Bill ($/day) 42.364848.5054 D. SPECIAL NOTES:
1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving
Day, and Christmas Day. The dates will be those on which the holidays are legally observed.
SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-3 dated 72-15-20163 Sheet No E-7-TOU-3
3. Request for Service Qualifying customers may request Service under this schedule for more than one account or one
meter if the accounts are on one site. A site shall be defined as one or more utility accounts
serving contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and have a common billing address. 4. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive
months, a Demand meter will be installed as promptly as is practicable and thereafter continued
in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated
Time periods as defined under Section D.2. 5. Power Factor Adjustment Time of Use customers must not have had a Power Factor Adjustment assessed on their Service
for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt-
ampere hours consumed during the month, and must not have fallen below 95% to avoid the
Power Factor Adjustment. Should the City of Palo Alto Utilities Department find that the Customer’s Service should be
subject to Power Factor Adjustments, the Customer will be removed from the E-7-TOU rate
schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand
and kilowatt-hour usage. 6. Changing Rate Schedules Customers electing to be served under E-7 TOU must remain on said schedule for a minimum of
12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a
rate schedule change to any applicable City of Palo Alto full-service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-4 dated 72-15-20163 Sheet No E-7-TOU-4
7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered,
butallowed provided the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to
the Customer's electrical requirements , as determined in the City’s sole discretion. The City
retains the right to change its line voltage at any time after providing reasonable advance notice
to any Customer receiving a the discount in this section hereunder and affected by such change.
The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum
Generation of those non-utility generators, but in no event shall the Customer’s
Maximum Demand be reduced below zero.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-5 dated 72-15-20163 Sheet No E-7-TOU-5
(2) If the non-utility generation source does not operate for an entire billing cycle, the
standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code Section
2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No. E-14-2 dated 7-1-200916 Sheet No. E-14-2
A. APPLICABILITY: This schedule applies to all street and highway lighting installations.
B. TERRITORY: Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City.
C. RATES:
Per Lamp Per Month Class A: Utility supplies energy
and switching service only.
Lamp Rating: High Pressure Sodium Vapor Lamps 100 watts 8.599.66
200 watts 15.8717.83
250 watts 19.5021.92
310 watts 24.1327.12
400 watts 31.0734.92
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No. E-14-2 dated 7-1-200916 Sheet No. E-14-2
Per Lamp Per Month – Class C: Utility supplies energy
and switching service and
maintains entire system,
including lamps and glassware. Lamp Rating:
Mercury-Vapor Lamps
400 watts 32.5834.94
High Pressure Sodium Vapor Lamps
70 watts 28.6130.48
100 watts 30.7932.93
150 watts 34.4337.02
250 watts 41.7045.19 Light Emitting Diode (LED) Lamps
70 watts-equivalent 23.7925.06
100 watts-equivalent 25.4426.91
150 watts-equivalent 26.9628.62 250 watts 31.1233.30
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No. E-14-14 dated 7-1-200916 Sheet No. E-14-14
D. SPECIAL CONDITIONS:
1. Type of Service: This schedule is applicable to series circuit and multiple street lighting
systems to which the Utility will deliver current at secondary voltage. Unless otherwise agreed, multiple current will be delivered at 120/240 volts, three-wire, single-phase. In certain localities the Utility may supply service from 120/208 volt star-connected poly-phase
lines in place of 240-volt service. Single phase service from 480-volt sources will be
available in certain areas at the option of the Utility when this type of service is practical
from the Utility's engineering standpoint. All currents and voltages stated herein are nominal, reasonable variations being permitted. New lights will normally be supplied as multiple systems.
2. Point of Delivery: Delivery will be made to the customer's system at a point or at points
mutually agreed upon. The Utility will furnish the service connection to one point for each group of lamps, provided the customer has arranged his system for the least practicable number of points of delivery. All underground connections will be made by the customer or
at the customer's expense.
3. Switching: Switching will be performed by the Utility (on the Utility's side of points of delivery) and no charge will be made for switching provided there are at least 10 kilowatts of
lamp load on each circuit separately switched, including all lamps on the circuit whether
served under this schedule or not; otherwise, an extra charge of $2.50 per month will be
made for each circuit separately switched unless such switching installation is made for the
Utility's convenience or the customer furnishes the switching facilities and, if installed on the Utility's equipment, reimburses the Utility for installing and maintaining them.
4. Annual Burning Schedule: The above rates apply to lamps which will be turned on and off
once each night in accordance with a regular burning schedule agreeable to the customer but
not exceeding 4,100 hours per year. 5. Maintenance: The rates under Class C include all labor necessary for replacement of
glassware and for inspection and cleaning of the same. Maintenance of glassware by the
Utility is limited to standard glassware such as is commonly used and manufactured in
reasonably large quantities. A suitable charge will be made for maintenance of glassware of a
type entailing unusual expense. Under Class C, the rates include maintenance of circuits between lamp posts and of circuits and equipment in and on the posts, provided these are all
of good standard construction; otherwise, the Utility may decline to grant Class C rates.
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No. E-14-24 dated 7-1-200916 Sheet No. E-14-24
Class C rates applied to any agency other than the City of Palo Alto also include painting of
posts with one coat of good ordinary paint as required to maintain good appearance but do
not include replacement of posts broken by traffic accidents or otherwise.
10. . System Owned In-Part by Utility : Where, at customer's request, the Utility installs, owns,
and maintains any portion of the lighting fixtures, supports, and/or interconnecting circuits,
an extra monthly charge of one and one-fourth percent of the Utility's estimate of additional
investment shall be made.
11. Rates For Lamps Not on Schedule: In the event a customer installs a lamp which is not
presently represented on this schedule, the Utility will prepare an interim rate reflecting the
Utility's estimated costs associated with the specific lamp size. This interim rate will serve as
the effective rate for billing purposes until the new lamp rating is added to Schedule E-14.
{End}
EXCERPTED DRAFT MINUTES OF THE APRIL 5, 2017 UTILITIES ADVISORY COMMISSION
ITEM 4. ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt 1) a Resolution Approving the Fiscal Year 2018 Electric Financial
Plan, and 2) a Resolution Increasing Electric Rates by Amending the E-1, E-2, E-2-G, E-4, E-4-G,
E-4 TOU, E-7, E-7-G, E-7 TOU and E-14 Rate Schedules
Senior Resource Planner Eric Keniston gave an overview of the proposed Financial Plan and rate
changes. The preliminary forecast had changed. Staff was now proposing a 14% overall rate
increase, but he noted the residential increase was only 12%. The proposal included various
reserves transfers to mitigate the overall rate increase and prevent having to increase rates
further this year. This included transfers from the hydro stabilization reserve and a loan from
the Electric Special Projects reserve. These would be used to keep the Supply and Distribution
Reserves within operating guidelines. The Electric Special Projects Reserve would normally not
be used for operational reasons, since it was set aside for special projects, but this plan involved
repaying the loan from that fund by 2020. He gave an overview of the reasons for the rate
changes. Operations costs were increasing as a result of accumulated deferred maintenance
related to difficulty filling positions, and additional capital investment was required due to aging
infrastructure. In addition, new renewable projects were coming online and transmission costs
were increasing. Even with the increases, however, Palo Alto’s electric rates would be
substantially lower than PG&E’s.
Commissioner Schwartz noted there may be increased customer sensitivity to changes on their
bills due to the recent error in gas billing. It would be worthwhile to run a report to identify
people who would see a substantial increase and reach out in advance to let them know that
the bill changes were not due to a billing error. Posting on Nextdoor and other online
information sources would be important.
ACTION: Commissioner Ballantine made a motion to recommend Council approve the staff
recommendation. Vice Chair Danaher seconded the motion. The motion passed unanimously
(5-0, with Chair Cook, Vice Chair Danaher and Commissioners Ballantine, Johnston, and
Schwartz voting yes and Commissioners Forssell and Trumbull absent.)
ATTACHMENT F
City of Palo Alto (ID # 7979)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/18/2017
City of Palo Alto Page 1
Summary Title: FY 2018 Gas Utility Financial Plan and Rate Proposals
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt a Resolution Approving the Fiscal Year 2018 Gas Utility Financial Plan
with no Changes to Distribution Rates
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission request that Finance Committee recommend that
Council adopt a resolution (Attachment A) approving the fiscal year (FY) 2018 Gas Utility
Financial Plan (Attachment B)
Executive Summary
The FY 2018 Gas Utility Financial Plan includes projections of the utility’s costs and revenues for
FY 2018 through FY 2027. In FY 2017, gas rates were increased by 8% effective on July 1, 2016.
In the FY 2017 Financial Plan, staff projected a tentative rate increase of 9% for FY 2018.
However, better than expected ending Operations reserve levels in FY 2016, coupled with a
delay in starting new gas main replacement projects due to staff capacity and to coordinate
planning of downtown projects, as well as recovering post-drought sales, have improved the
near-term financial outlook for the gas fund. Staff proposes utilization of reserves and a series
of lesser rate increases over the next three years to minimize impacts to customers. The
proposed FY 2018 Gas Utility Financial Plan includes no distribution-related gas rate increase
effective on July 1, 2017, however, beginning July 1, 2017, customers may see an estimated
impact of up to 4% on their bills as a result of the Carbon Neutral Gas Plan adopted by Council
in December 2016. Future-year distribution-related rate increases are projected to be 4 to 6
percent over the next four years. In addition, the plan includes proposed transfers to the
Operations Reserve of $1.2 million and $4.8 million from the Rate Stabilization Reserve in FY
2018 and FY 2019, respectively, to ensure that there are appropriate financial reserves for
contingencies. The Rate Stabilization Reserve is projected to be zero balance by the end of FY
2020.
Gas Utility expenses are projected to increase by roughly 3 to 4 percent annually from FY 2017
to FY 2027 due primarily to increased gas supply costs (monthly commodity purchases as well
City of Palo Alto Page 2
as carbon neutral plan and cap and trade allowance purchase costs), as well as higher
operations and maintenance expenses. In the near-term, some of these costs relate to the
cross-bore inspection program and increased capital improvement program (CIP) costs from
higher bids. While existing projects are completed and staffing issues are addressed, new main
replacement projects are not planned until FY 2019. The annual Gas Utility equity transfer to
the General Fund is estimated at $7.0 million in FY 2018 rising to 9.7 million in FY 2027 under
the Council-adopted calculation methodology.
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 started
to recover somewhat, but as with water, it is difficult to determine if changes in behavior will
persist, reducing gas usage long term.
The Utilities Advisory Commission (UAC) reviewed the Gas Utility Financial Plan and Rate
Proposals at its meeting on April 5, 2017 meeting, and unanimously recommended approval of
the proposed financial plan.
Background
Every year staff presents the 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 Finance Committee reviewed preliminary financial forecasts at its March 21, 2017 meeting.
Staff has not made any changes to the preliminary projections for gas presented at that
meeting.
Discussion
Staff’s annual assessment of the financial position of the City’s gas utility is completed to ensure
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.
Proposed Actions for FY 2017
The FY 2017 Gas Utility Financial Plan includes the following proposed action:
1. Reduce the $5.3 million transfer from the Rate Stabilization Reserve to the Operations
Reserve proposed in the FY 2017 Gas Financial Plan to zero.
Proposed Actions for FY 2018
City of Palo Alto Page 3
The FY 2018 Gas Utility Financial Plan also includes the following proposed action:
1. Transfer $1.2 million from the Rate Stabilization Reserve to the Operations Reserve.
The reserve transfers will enable staff to maintain sufficient funds in the Gas Operations
Reserve levels while spreading the required rate increases for the gas utility over several years.
These proposed actions are described in more detail in the FY 2018 Gas Financial Plan
(Attachment B). The annual Gas Utility equity transfer to the General Fund is estimated at $7.0
million in FY 2018, rising to 9.7 million in FY 2027. Each year it is calculated according to the
2009 Council-adopted methodology, and does not require additional Council action.
Staff proposes no adjustments to gas rates in FY 2018 at this time.
FY 2018 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table 1 shows the projected rate adjustments over the next five years and their impact on the
annual median residential gas bill.
Table 1: Projected Rate Adjustments, FY 2017 to FY 2021
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Gas Utility 0% 4% 6% 6% 5%
Estimated Bill Impact ($/mo)* $- $1.79 $2.79 $2.96 $2.61
* estimated impact on median residential gas bill, which is currently $44.72 for CY 2016. This
does not include the bill impacts in FY 2018 associated with the Carbon Neutral Gas Portfolio.
Changes from Preliminary Financial Forecast
After presenting the preliminary financial forecast to the UAC on February 1, 2017, additional
budget information and changes to usage projections have been modified for outer years, but
the FY 2018 proposal of no rate increase remains the same.
Gas Bill Comparison with Surrounding Cities
Table 2 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of May 2016 (to illustrate a summer month bill) and
March 2017 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2016 was $426.72, about 20% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities:
Table 2: Residential Monthly Gas Bill Comparison
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(March
30 34.88 41.57 -16%
(Median) 54 54.53 74.82 -27%
City of Palo Alto Page 4
2016) 80 85.50 120.77 -29%
150 180.51 255.05 -29%
Summer
(Jul 2015)
10 19.93 17.77 12%
(Median) 18 21.94 21.46 2%
30 35.13 41.55 -15%
45 52.91 66.66 -21%
Monthly gas bills for commercial customers for various usage levels for rates in effect as of
March 1, 2016 are shown in Table 3. Bills for CPAU customers at the usage levels shown are
around 10% to 33% higher for commercial customers than for PG&E customers. This is a
substantial improvement over the calendar year 2013 bill comparison, when commercial gas
bills for CPAU customers were 27% to 44% higher than for PG&E customers. This is primarily
attributable to PG&E’s increased distribution rates as the commodity rates for CPAU and PG&E
are very similar, both being based on spot market gas prices.
Table 3: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect Mar. 1, 2017)
Usage
(therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 616 545 13%
5,000 5,459 4,957 10%
10,000 10,840 8,856 22%
50,000 53,788 40,453 33%
Commission Review and Recommendation
The UAC reviewed this proposal at its April 5, 2017 meeting. Staff noted that, while there was
no distribution -related increase, an estimated 4 percent increase is projected when the cost of
purchasing carbon neutral offsets is included as a separate rate component, effective July 1,
2017 when the Carbon Neutral Plan takes effect.
After the presentation, with no discussion, the UAC voted to recommend that the Council adopt
the resolution approving the FY 2018 Gas Utility Financial Plan. The vote was unanimous (5-0),
with Commissioners Forssell and Trumbull absent. The draft excerpted minutes from the UAC’s
April 5, 2017 meeting are provided as Attachment C.
Timeline
The City Council will consider adopting the Financial Plan as part of the FY 2018 budget review
and adoption process.
Resource Impact
See the attached FY 2018 Gas Financial Plan for a more comprehensive overview of projected
cost and revenue changes for the next ten years.
City of Palo Alto Page 5
Policy Implications
The proposed Gas Financial Plan is consistent with Council-adopted Reserve Management
Practices.
Environmental Review
The Finance Committee’s review and recommendation to Council on the FY 2018 Gas Financial
Plans does not meet the California Environmental Quality Act’s definition of a project, pursuant
to Public Resources Code Section 21065, thus no environmental review is required.
Attachments:
Attachment A: Resolution of the Council of the City of Palo Alto Approving the FY 2018
Gas Utility Financial Plan
Attachment B: Proposed FY 2018 Gas Utility Financial Plan
Attachment C: Excerpted UAC Meeting Minutes of April 5, 2017
Attachment A
* NOT YET APPROVED *
170320 jb 6053929
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2018 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 2018 Gas Utility Financial Plan.
SECTION 2. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
/ /
/ /
/ /
/ /
/ /
/ /
Attachment A
* NOT YET APPROVED *
170320 jb 6053929
Code Section 21065, and therefore, no environmental assessment is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Senior Deputy City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2018 GAS
UTILITY
FINANCIAL PLAN
FY 2018 TO FY 2027
ATTACHMENT B
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 2 | Page
GAS UTILITY FINANCIAL PLAN
FY 2018 TO FY 2027
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2018 Rate and Reserve Proposals ........................................................ 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................... 8
Section 4A: Gas Utility History ..................................................................................................... 8
Section 4B: Customer Base ........................................................................................................ 10
Section 4C: Distribution System ................................................................................................. 11
Section 4D: Cost Structure and Revenue Sources ...................................................................... 12
Section 4E: Reserves Structure ................................................................................................... 12
Section 4F: Competitiveness ...................................................................................................... 13
Section 4G: Gas Supply Rates .................................................................................................... 14
Section 5: Utility Financial Projections ................................................................................. 15
Section 5A: Load Forecast .......................................................................................................... 15
Section 5A: FY 2012 to FY 2016 Cost and Revenue Trends ........................................................ 16
Section 5B: FY 2016 Results ....................................................................................................... 17
Section 5C: FY 2017 Projections ................................................................................................. 18
Section 5D: FY 2018-FY 2027 Projections .................................................................................. 18
Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 19
Section 5G: Long-Term Outlook ................................................................................................. 21
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 3 | Page
Section 6: Details and Assumptions ..................................................................................... 22
Section 6A: Gas Purchase Costs ................................................................................................. 22
Section 6B: Operations .............................................................................................................. 23
Section 6C: Capital Improvement Program (CIP) ....................................................................... 24
Section 6D: Debt Service ............................................................................................................ 26
Section 6E: Equity Transfer ........................................................................................................ 27
Section 6F: Revenues ................................................................................................................. 27
Section 6G: Communications Plan ............................................................................................. 28
Appendices ......................................................................................................................... 30
Appendix A: Gas Financial Forecast Detail ................................................................................ 31
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 32
Appendix C: Gas Utility Reserves Management Practices ......................................................... 34
Appendix D: Description of Gas Utility Cost Categories ............................................................ 38
Appendix E: Gas Utility Communications Samples .................................................................... 39
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 4 | Page
SECTION 1: DEFINITIONS AND ABBREVIATIONS
ABS: Acrylonitirile butydene styrene, a plastic gas main material
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
April 1 2 , 2016 5 | Page
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Gas Utility for the next ten years. This
Financial Plan provides revenues to cover the costs of operating the utility safely over that time
while adequately investing for the future. It also addresses the financial risks facing the utility
over the short term and long term, and includes measures to mitigate and manage those risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
From FY 2018 through FY 2027, non-commodity costs are projected to increase at 3% to 4% per
year. In the short term, some of these costs are related to the cross-bore inspection program,
as well as cap-and-trade and carbon neutral allowance purchase costs. Capital improvement
program (CIP) costs have increased as the economy has improved, and while CPAU plans a new
gas main replacement project every year, recent larger than expected bids have required
resizing and redesign of some existing plan projects. Because of this, the next new main
replacement project will take place in FY 2019. As a result, CIP costs for FY 2017 and 2018 will
be lower than normal by around $3.7 million. The Gas Utility expenses over the period of this
financial plan are shown in Table 1 below.
Table 1: Gas Utility Expenses for FY 2016 to FY 2027 (Thousand $’s)
Expenses
($000)
FY
2016
(act.)
FY
2017
(est.)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Commodity costs 8,127 13,042 15,437 14,931 15,304 15,584 16,021 16,569 17,227 17,909 18,679 19,235
Operations 17,239 21,687 22,587 22,901 22,559 23,022 24,403 25,292 26,221 27,195 28,222 27,982
Capital Projects 5,017 2,214 2,074 5,725 5,960 6,145 6,335 6,525 6,721 6,923 7,130 7,344
TOTAL 30,384 36,943 40,098 43,557 43,823 44,751 46,759 48,386 50,169 52,027 54,032 54,561
To ensure that revenues cover projected rising costs, the financial plan includes the rate
trajectory shown in Table 2. No increase is projected for FY 2018.
Table 2: Projected Gas Rate Trajectory for FY 2018 to FY 2027
Projection FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Current Financial Plan 0% 4% 6% 6% 5% 3% 3% 2% 1% 0%
FY 2017 Financial Plan 9% 7% 4% 1% 1% 1% 1% 1% 1% N/A
FY 2016 Financial Plan 4% 4% 4% 3% 3% N/A N/A N/A N/A N/A
The Gas Rate Stabilization Reserve is 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 CIP
Reserve can be used to offset one-time unanticipated capital costs. Table 3 shows the projected
reserve transfers over the forecast period.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 6 | Page
Table 3: Transfers To/(From) Reserves for FY 2017 to FY 2027 ($000)
Reserve FY 2017 FY 2018 FY 2019 to FY 2027
Rate Stabilization 0 (1,208) (4,810)
Operations 0 1,208 4,810
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Gas Utility in FY 2017:
1. Amend the proposed $5.3 million transfer from the Rate Stabilization Reserve to the
Operations Reserve, as proposed in the FY 2017 Gas Financial Plan, to no transfer, based
on projected ending Operations Reserve levels.
Staff proposes the following actions for the Gas Utility in FY 2018:
2. No distribution rate increase for FY 2018. See Section 3B: Current and Proposed Rates
for more details.
3. Transfer $1.2 million from the Rate Stabilization Reserve to the Operations Reserve. See
Section 3C: Proposed Reserve Transfers for more details.
SECTION 3: DETAIL OF FY 2018 RATE AND RESERVE PROPOSALS
SECTION 3A: RATE DESIGN
The Gas Utility’s rates are evaluated and implemented in compliance with cost of service
requirements. The Gas Utility’s current rates are based on the methodology from the April 2012
Gas Utility Cost of Service Study completed by Utility Financial Solutions1. In preparation for an
update to the study, staff discussed a proposed scope with the Utilities Advisory Commission in
October 2016, and the Council in November 20162. The updated study is projected to be
completed by the end of FY 2017, and will provide guidance for the next proposed rate action,
currently slated for FY 2019.
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, monthly service charges were increased 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 program4. This component will change 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
1 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395 2 Staff Report 7416 11/14/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54576 3 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395 4 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 7 | Page
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 $0.10
per therm.
CPAU has four rate schedules: one for separately metered residential customers (G-1), one for
small commercial and master-metered multi-family residential customers (G-2), one for
customers using over 250,000 therms per year (G-3) and a specific schedule for the Compressed
Natural Gas station (G-10). All customers pay a monthly service charge, which represents meter
reading, billing, and other customer service costs, as well as a portion of operations and
maintenance cost. All customers are also charged for each therm of gas used. Separately
metered residential customers are charged on a tiered basis, differentiated by season. During
the winter months, the first 2 therms per day (60 therms for a 30 day billing period) are charged
a base price per CCF, and all additional units charged a higher price per therm. During the
summer months, the first tier level is 0.667 therms per day, or 20 therms for a 30 day billing
period. Commercial customers pay a uniform price for each therm used.
Table 4 shows the current monthly service charges for all rate schedules. Table 7 shows the
consumption charges related to distribution charges. As mentioned earlier, commodity charges
change monthly, and transportation charges are tied to the PG&E G-WSL rate schedule. Three
years’ worth of volumetric rate history can be found on Palo Alto’s website.7 Some recent
commodity price history is discussed in Section 6A: Gas Purchase Costs.
Table 4: Current Monthly Service Charges
Rate Schedule Monthly Service Charge ($/month)
Current ( as of 7/1/16)
G-1 (Residential) $10.32
G-2 (Small Commercial) $78.23
G-3 (Large Commercial) $377.43
G-10 (CNG) $52.93
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
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 8 | Page
Table 5: Current Gas Distribution Charges
Current ( as of 11/1/16)
G-1 (Residential)
Tier 1 Rates 0.3933
Tier 2 Rates 0.9319
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.5767
G-3 (Large Commercial)
Uniform Rate 0.5687
G-10 (Compressed Natural Gas)
Uniform Rate 0.0093
No changes to distribution rates are proposed for FY 2018.
SECTION 3C: PROPOSED RESERVE TRANSFERS
In the FY 2017 Financial Plan, $5.3 million was proposed to be transferred from the Rate
Stabilization Reserve into the Operations Reserve.
Lower actual expenses in FY 2016 as well as projected lower expenses in FY 2017 are expected
to result in higher ending reserve balances than initially projected, so staff recommends not
transferring funds at this time. A tentative transfer of $1.2 million in FY 2018, followed by $4.3
million in FY 2019, is included in the financial projections in this Financial Plan. These will enable
CPAU to maintain adequate Operations Reserve levels while moderating the pace of increase in
gas rates. The impact of these transfers on reserves levels can be seen in Appendix A: Gas Utility
Financial Forecast Detail.
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 comprised
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 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 Public Utilities Commission) to increase rates
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by nearly 72.5%. Despite these initial hurdles, Palo Alto’s system grew tremendously, and by
1924 revenues had exceeded those of the electric utility. Sales were such that the annual
reports of the time noted gas usage “appears to be greater than that of any other city in the
state, showing that gas is a very popular form of fuel in Palo Alto.” Just prior to the acquisition
of the neighboring town of Mayfield’s gas system (centered around today’s California Avenue)
in 1929, the miles of main in service and customers connections had doubled.
Notable changes to the gas supply itself came in 1930, when PG&E ceased supplying purely
manufactured (or coal) gas from its Potrero Hill facility in San Francisco and instead switched to
natural gas. In 1935, a supplementary butane injection system (later retired) was purchased
from Standard Oil to mitigate large wintertime peaks. Gas sales were at 248,658 million cubic
feet (MCF) with 4,849 active services.
Early gas mains in Palo Alto were made of steel, but in the 1950s, like many other utilities, CPAU
switched to ABS plastic. CPAU switched to PVC plastic in the early 1970s, but around 100 miles
of ABS mains had already been installed. A 1990 evaluation of the system found a steadily
increasing rate of gas leaks associated with those mains, something that other gas utilities had
also been experiencing. To reduce leaks, CPAU accelerated its main replacement program from
7,000 feet (1.3 miles) of replacements per year to 20,000 feet (3.8 miles) per year. This would
enable the utility to replace all of its ABS and its most vulnerable steel and PVC mains with
polyethylene (PE) mains over the course of the following 36 years.8 As of 2015 the Gas Utility
had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic
protection was not effective. Current main replacement projects will target the last ~800 feet of
remaining ABS main as well as tackling PVC replacement. A PVC risk analysis to determine the
appropriate footage of annual PVC replacement for future CIP projects is currently being
conducted. This is an example of how local control of its Gas Utility has provided Palo Alto
residents with substantial benefits. During the 1990s and 2000s, while CPAU was increasing its
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.
8 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990 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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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 23,400 customers are connected to the natural gas system,
approximately 21,700 (93%) of which are residential and 1,700 (7%) of which are non-
residential. Residential customers consume about 10 to 12 million therms of gas per year,
roughly 45% of the gas sold, while non-residential customers consume 55% (about 14 to 15
million therms). Residential customers use gas primarily for space heating (46% of gas
consumed) and water heating (42%), with the remainder consumed for other purposes such as
cooking, clothes drying, and heating pools and spas.11 Non-residential customers use gas for
space and water heating (73% of gas consumed), cooking (20%), and industrial processes
(6%).12
The Gas Utility receives gas at the four receiving stations within Palo Alto where CPAU’s
distribution system connects with Pacific Gas and Electric’s (PG&E’s) system. These receiving
stations are jointly operated by CPAU and PG&E. CPAU purchases gas from various natural gas
marketers, with PG&E providing only local transportation service (transportation from the
PG&E City Gate gas delivery hub to Palo Alto). CPAU also has transmission rights on PG&E’s
transmission pipeline from Malin, Oregon to PG&E City Gate, allowing it to purchase lower
priced gas at that location. CPAU does not produce or store any natural gas, and purchases gas
in the monthly and daily spot markets. The cost of the purchased gas is passed through directly
to customers through a rate adjuster that varies monthly with market prices. In a similar
fashion, the cost for local transportation has now been tied to PG&E’s G-WSL rate schedule,
and varies when and if PG&E changes their rate schedule. The cost of purchased gas and PG&E
local transportation service usually account for roughly one third of the utility’s expenditures.
11 http://energyalmanac.ca.gov/naturalgas/overview.html 12 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Statistics shown are
for end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located.
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SECTION 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 23,400 gas services (which
connect the gas mains to the customers’ gas lines). These mains and services, along with their
associated valves, regulators, and meters, represent the vast majority of the infrastructure used
to deliver gas in Palo Alto. CPAU has an ongoing CIP to repair and replace its infrastructure over
time, the expense of which normally accounts for around 15 to 20% of the utility’s
expenditures. Costs for main replacements have been going up in recent years.
In addition to the CIP, the Gas Utility performs a variety of maintenance activities related to the
system, such as monitoring the system for leaks, testing and replacing meters, monitoring the
condition of steel pipe, and building and replacing gas services for buildings being built or
redeveloped throughout the city. The utility also shares the costs of other system-wide
operational activities (such as customer service, billing, meter reading, supply planning, energy
efficiency, equipment maintenance, and street restoration) with the City’s other utilities. These
maintenance and operations expenses, as well as associated administration, debt service, rent,
and other costs, make up roughly half of the utility’s expenses. In addition to these ongoing
activities, CPAU has conducted a program to find and replace cross-bores over the last several
years. Currently, $1 million is budgeted per year for the cross-bore program through FY 2019.
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.
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Figure 2: Cost Structure (FY 2016)
57%27%
16%
Operations
Gas Purchases
Capital
Figure 1: Revenue Structure (FY 2016)
93%
7%
Sales of Gas
Other Revenue
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 1, the Gas
Utility receives 93% 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 2016,
gas purchase costs accounted for
roughly 27% of the Gas Utility’s
costs. This percentage can vary
widely from year to year, as this
cost is based upon market
purchases, but now also includes
costs related to cap and trade. In
FY 2016, Palo Alto received a
large transportation rate
settlement from PG&E, which
lowered costs substantially. This
stemmed from the CPUC’s
findings related to the San Bruno
pipeline explosion. Operational
costs represented roughly 57%, and capital investment was responsible for the remaining 16%.
CIP is normally about 20% of expenses, but this may be lower in times when projects are
deferred, as will happen in FY 2017 and FY 2018.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains six reserves for its Gas Utility to manage various types of contingencies. These
are summarized below, but see Appendix C: Gas Utility Reserves Management Practices for
more detailed definitions and guidelines for reserve management:
• Reserve for Commitments: A reserve equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserve for Reappropriations: A reserve for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve.
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• Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to
accumulate funds for future expenditure on CIP projects and is anticipated to be empty
unless a major one-time CIP expenditure is expected in future years. This CIP can also
act as a contingency reserve for the CIP. This type of reserve is used in other utility funds
(Electric, 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 6 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of May 2016 (to illustrate a summer month bill) and
March 2017 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2016 was $426.72, about 20% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 6: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(March 2017)
30 34.88 41.57 -16%
(Median) 54 54.53 74.82 -27%
80 85.50 120.77 -29%
150 180.51 255.05 -29%
Summer
(May 2016)
10 19.93 17.77 12%
(Median) 18 21.94 21.46 2%
30 35.13 41.55 -15%
45 52.91 66.66 -21%
Table 7 shows the monthly gas bills for commercial customers for various usage levels for rates
in effect as of March, 2017. Bills for CPAU customers at the usage levels shown are around 10%
to 33% 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
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customers were 27% to 44% 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 March, 2017)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 616 545 13%
5,000 5,459 4,957 10%
10,000 10,840 8,856 22%
50,000 53,788 40,453 33%
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. The actual commodity prices are shown in Figure 3. As shown,
commodity prices have fluctuated by around $0.20 over the last two years, but have generally
been lower than prices seen in 2013 and 2014.
Figure 3: Gas Commodity Rates from July 2012 through March 2017
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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, as the drought has eased and a relatively normal winter has
progressed, gas usage has started to increase again.
Figure 4: Historic Gas Consumption
Gas consumption, as denoted by the dotted line in Figure 5, is projected to recover somewhat
and stay stable over the forecast period, although changes such as replacement of gas
appliances with electric appliances or customer behavior may result in lower long run usage. As
with prior drought/gas usage declines in the past, it is likely that consumption will not come
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back to pre-conservation levels. It is too early to tell, however, where the new ‘normal’ level of
consumption will be.
Figure 5: Forecast Gas Consumption
SECTION 5A: FY 2012 TO FY 2016 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 they are projected to change over the next decade.
The annual expenses for the gas utility decreased substantially between 2012 and 2016 due to
lower gas sales. Market prices for gas supplies are shown in Figure 3 above. FY 2014 and 2015
were notable due to the fact that no new funding was added for main replacement projects, to
permit the completion of a backlog of projects which had previously been funded. This allowed
for backlogged gas main replacement projects to be started, and used existing capital reserves.
Starting in FY 2012, additional funding for gas cross-bore inspections increased Operations
costs.
Revenues have generally matched expenses in most years. As shown in Figure 6 below,
revenues were below cost in FY 2011 and FY 2013 and nearly at cost in FY 2016. The absence of
funding for main replacement projects in FY 2014 and FY 2015, 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 distributionrates was in July 2016 when rates
were increased by 8%. In FY 2012, commodity rates were changed to a market-based, monthly
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pass-through cost—and commodity rates (and usage) fell, so revenues actually declined in FY
2013 after the rate increase.
Figure 6: Gas Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2016 and Projections through FY 2027
SECTION 5B: FY 2016 RESULTS
Sources of funds for FY 2016 were in line with projections, but expenses related to Purchases
and Capital spending came in well below expected budget. Total FY 2016 expenses were $30.4
million compared to projections of $35.9 million in the FY 2017 Financial Plan. Table 8
summarizes the variances from forecast.
Table 8: FY 2016, Actual Results vs. Financial Plan Forecast
Net Cost/(Benefit) Type of change
Purchase costs lower than forecast (1,132,000) Cost savings
Operations cost savings and reclass (2,498,000) Cost savings
Capital Improvement cost spending (1,872,000) Cost savings
Operations cost savings (31,000) Cost savings
Net Cost / (Benefit) of Variances $(5,465,000)
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SECTION 5C: FY 2017 PROJECTIONS
Current projections indicate that sales revenues will be slightly higher than last year’s forecast.
However, a main replacement projected budgeted for this year will not be started until FY
2019. Table 9 summarizes the current and projected variances from FY 2017 Financial Plan.
Table 9: FY 2017 Projected Results vs. Financial Plan Forecast
Net Cost/ (Benefit) Type of change
Sales revenues higher than forecast (984,000) Revenue increase
Other revenues and interest higher than forecast (742,000) Revenue increase
Operations & maintenance, Customer service and
purchase cost increases
617,000 Cost increase
Main replacement projects delayed (4,091,000) Cost savings
Net Cost / (Benefit) of Variances ($5,200,000)
SECTION 5D: FY 2018-FY 2027 PROJECTIONS
As can be seen in Figure 6 above, costs for the Gas Utility are projected to rise in FY 2017, then
are projected to increase at around 3% per year through FY 2026. In Operations, this is due to
an additional continuing $1 million for cross-bore inspections (this expense is projected to
continue for at least three years), as well as general inflationary increases of around 2.6% per
year. Salaries and benefits expenses are projected to rise at nearly 4% per year, per the City’s
Long Range Financial Plan. New CIP main replacement programs are projected to be put on
hold until FY 2019. At that point, CIP spending is projected to return to normal levels (around $6
million), then grow at around 2% per year thereafter. Gas commodity costs are the most
variable component. At the time the budget was developed in December 2016, gas supply
prices were projected to increase by around 3 to 4% per year. Since this is a pass-through cost
to customers, the risk of these costs being higher or lower than expected has a minimal impact
on reserves.
As shown in Figure 7, the Rate Stabilization Reserves are projected to be depleted by FY 2020.
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Figure 7: Gas Utility Reserves
Actual Reserve Levels for FY 2016 and Projections through FY 2027
SECTION 5E: RISK ASSESSMENT AND RESERVES ADEQUACY
The Gas Utility’s primary contingency reserve, the Operations Reserve, is projected 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 recovering to the target level by
FY 2027 with the projected rate trajectory.
Figure 8: Operations Reserve Adequacy
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Forecasted Operations Reserve levels also exceed the short-term risk assessment for the Utility.
Table 10 summarizes the risk assessment calculation for the Gas Utility through FY 2022. The
same methodology is used for FY 2023 through FY 2027 as well. The risk assessment includes
the revenue shortfall that could accrue due to:
1. Lower than forecasted distribution sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget
year.
Table 10: Gas Risk Assessment ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Total non-commodity revenue $20,465 $21,676 $23,503 $25,557 $27,559
Max. revenue variance, previous ten years 16% 16% 16% 16% 16%
Risk of revenue loss $3,282 $3,476 $3,769 $4,098 $4,419
CIP Budget $809 $4,421 $4,617 $4,762 $4,911
CIP Contingency @10% $81 $442 $462 $476 $491
Total Risk Assessment value $3,363 $3,918 $4,231 $4,575 $4,910
Finally, the CIP Reserve was created 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.
At the end of FY 2016, the sum of the CIP Reserve and existing Commitments was a bit over $10
million, as shown in Figure 7. Based upon FY 2017’s adjusted CIP budget, this is well above the
maximum reserve level of $1.97 million. However, the next two years are anomalous in that a
main replacement project is not scheduled. As a normal year maximum would be between $9
to $11 million, staff does not recommend reducing the CIP reserve at this time, especially in
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light of the fact that CIP project costs have been increasing. Staff will continue to review this
reserve and the appropriateness of the current minimum and maximum guideline levels.
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 or an increase in manufacturing in the U.S. might drive up
natural gas prices, but other factors, such as generally more mild winters, might drive gas
demand lower. It is also difficult to predict the magnitude of the additional cost impacts
associated with the State’s cap-and-trade program over the long term. In the face of this
uncertainty, CPAU is able to protect the financial position of the Gas Utility by continuing its
current strategy of passing these costs directly to its customers via month-varying rate
adjustment mechanisms. The City has recently opted to pursue 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 some amount of electrification of gas-
using appliances is likely to be 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 fUpdate, 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 City Gate, even including the costs of transmission from Malin to
City Gate. Gas is purchased 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, but prices for the last year
have risen somewhat. High levels of natural gas in storage, along with warmer than normal
weather on the West coast has kept prices low, as shown in Figure 9.
Figure 9: Gas Market Prices at PG&E Citygate
Gas commodity costs are expected to increase steadily over the next several years. Figure 10
shows the projected gas prices used to generate this forecast. Projections for transmission costs
associated with transporting gas over PG&E’s Redwood transmission pipeline (from Malin,
Oregon to the PG&E Citygate) are based on rates adopted in the most recent update to the Gas
Accord.
Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary
adder to PG&E’s local transportation rate,14 but in December 2014 PG&E applied to the CPUC
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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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 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 2017 to FY 2019 include funding for the cross-bore program. In the
1970s CPAU, like many other utilities, adopted horizontal drilling as an alternative to trenching
when installing new gas services. This created the possibility of cross-bores, which can happen
when a gas service is bored through a sewer lateral. Though cross-bores are very rare, they can
create a dangerous situation when a contractor attempts to clear a blocked sewer line, because
if the cross-bored gas service is damaged during the line clearing it can result in a gas leak.
CPAU has been inspecting new gas services since 2001, and in 2011 began video inspections of
the sewer laterals at the location of horizontally-drilled gas services installed before 2001. This
inspection program has cost roughly $1 million per year since FY 2012. While a majority of
sewer laterals have been inspected, staff has come across several services which are not able to
be scoped, either due to infiltration by roots or broken/collapsed pipe segments. Staff has
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included $3 million in additional funding between FY 2017 and FY 2019 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
• Customer Connections, which covers the cost when the Gas Utility installs new services
or upgrades existing services at a customer’s request in response to development or
redevelopment. The Gas Utility charges a fee to these customers to cover the cost of
these projects.
• Ongoing Projects, which covers the cost of routine meter, regulator, and service
replacement, minor projects to improve reliability or increase capacity, and other
general improvements.
• Tools and Equipment, which covers the cost of capitalized equipment, such as
directional boring equipment.
• One-time Projects, which represents occasional large projects that do not fall into any
other category.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 25 | Page
Table 11 shows the current status of these project categories and future projected spending.
Table 11: Budgeted Gas CIP Spending
The Gas Main Replacement (GMR) Program is in the process of reaching a major milestone, the
replacement of the last gas mains made from ABS plastic. The program to replace ABS and
other low-performing materials in the system started in the 1990s (see Section 4A: Gas Utility
History for more detail). CPAU temporarily slowed down its new CIP appropriations in this
category in FY 2014 and 2015 in order to finish the last major ABS main replacement project
and to catch up on a backlog of projects that has accumulated due to staffing issues. With the
replacement of all ABS mains with PE plastic, the material most at risk for failure is removed
leaving only PVC plastic, steel (wrapped, with cathodic protection), and PE mains. The next
focus of the GMR program will be PVC mains. CPAU is considering updating the Gas System
Master Plan to determine which areas of the system to prioritize. The plan will help CPAU
determine whether the pace of main replacement (approximately three miles of main each
year, or 1.5% of the system) needs to be increased, decreased, or whether it needs to remain
the same.
The current budgets for gas main replacement might not fully take into account the recent rise
in costs for main replacement, which have increased from the levels seen during the recent
recession. Several factors may be contributing to this. Economic recovery in the Bay Area, as
well as a greater focus on infrastructure improvement by many municipal agencies and utilities
could be creating high demand for contractors in these fields. Newer, more leak resistant pipe
materials may have ongoing greater costs. CPAU has seen the replacement cost per linear foot
increase by 25 to 50% over the last couple of years. Currently CPAU plans to complete as much
main replacement as possible within its current budget, provided there are no safety concerns.
However, if this trend of higher cost continues, the Gas Utility may require larger CIP budgets,
and as a result, larger rate increases.
These increases in cost are a partial reason for the two year delay in projects. The most recent
project, when put out for bid, resulted in very few contractors competing, and project bids
larger than budgeted. Staff will redesign this and future projects into smaller segments to keep
budgets lower, while not compromising on overall system integrity. The other reason for delay
is the University Avenue Business District project, and getting coordination amongst all
departments is taking more time than expected. Finally, there has been an ongoing issue with
keeping and maintaining qualified staff to design and work on projects.
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
One Time Projects 425 (2) 423 109 - - - - -
Gas Main Replacement 4,878 (187) 4,691 - - 3,588 3,759 3,878 4,000
Tools And Equipment 146 - 146 20 - 640 - - -
Ongoing Projects 254 (140) 114 88 809 833 858 884 911
Customer Connections 232 (660) (428) 159 1,265 1,303 1,342 1,383 1,424
TOTAL 5,935 (988) 4,946 375 2,074 6,365 5,960 6,145 6,335
*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).
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 26 | Page
Ongoing Projects, Tools and Equipment, and Customer Connections are projected to cost
approximately $0.8 million in FY 2018 and increase by 3% per year through the end of the
forecast period. In practice, these projects can fluctuate dramatically depending on system
conditions and the pace of development and redevelopment in the city. It is worth noting that
the Customer Connections program is paid for through fee revenue, so when costs go up, so
does fee revenue.
Aside from customer connections and some transfers from other funds, the CIP plan for
FY 2018 to FY 2022 is funded by utility rates. The details of the plan are shown in Appendix B:
Gas Utility Capital Improvement Program (CIP) Detail.
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. Debt service for this bond for the financial
forecast period is shown in Table 12. Debt service on this bond will continue through 2026.
Table 12: Gas Utility Debt Service
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
2011 Utility Revenue
Refunding Bonds, Series A 803 802 800 800 802 804 805 803 800 803
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 13 and
Table 14.
Table 13: Debt Service Coverage Ratio ($000)
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
Revenues 36,643 38,225 39,175 41,695 44,306 46,879 49,025 50,992 52,835 54,530
Expenses
(Excluding CIP and
Debt Service)
(33,926) (37,223) (37,033) (37,063) (37,804) (39,621) (41,057) (42,646) (44,305) (46,100)
Net Revenues 2,717 1,002 2,142 4,632 6,502 7,258 7,968 8,346 8,530 8,430
Debt Service 803 802 800 800 802 804 805 803 800 803
Coverage Ratio 338% 125% 268% 579% 811% 903% 990% 1039% 1039% 1039%
15 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 27 | Page
Table 14: Debt Service Minimum Reserves ($000)
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
Gas Utilitya 19711 17838 13456 11328 10883 11003 11642 12465 13273 14588
Debt Serviceb 803 804 803 802 801 801 802 803 800 803
Reserves Ratioc 25x 22x 17x 14x 14x 14x 15x 16x 16x 16x
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 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 15, even though the Gas Utility is not responsible for the debt service payments.
The Gas Utility’s reserves or net revenues would only be called upon if the responsible utilities
are unable to make their debt service payments. Staff does not currently foresee this occurring.
Table 15: 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 since16. 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 service connection and capacity fees, followed closely
by sales of allowances related to California’s cap-and-trade program. Another revenue item
related to the cap-and-trade program is collected in customers’ bills. While the State provides
CPAU with a certain number of free allowances each year, the Gas Utility is required to sell a
portion of those in accordance with the regulations. In order to have enough allowances to
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.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 28 | Page
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.
Sales revenue projections are based 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. Forecasts are continually evaluated to see when new
trends emerge.
SECTION 6G: COMMUNICATIONS PLAN
The FY 2018 communications strategy covers four primary areas: operations, infrastructure,
safety, efficiency, renewables and rates. Since moving to market pricing for commodity rates,
changes to the commodity rates are posted monthly on the City’s website. Gas use efficiency
incentives are promoted year-round, but most heavily during winter months to impact heating
activities. Promotional methods include community outreach events, print ads in local
publications, utility bill inserts, messaging on the bills and envelopes, website pages, email
blasts, videos for the web and local Comcast channels, Home Energy Reports and the use of
social media.
To keep customers apprised of the status and accomplishments of capital improvement
projects, a network of project web pages are maintained. Traffic is driven to the website via
print and digital ads, social media and email blasts. Safety topics are emphasized year-round.
CPAU is engaging in several campaigns and programs in FY 2018 to promote gas utility
efficiency and renewable energy. The Georgetown University Energy Prize competition is a
friendly, national campaign to encourage communities to reduce energy use. Energy savings
from reduced gas and electric consumption qualify to help Palo Alto compete for a $5 million
prize at the end of a two-year campaign. Since adoption of a carbon neutral electric supply
portfolio, CPAU launched a new voluntary renewable natural gas carbon offsets program,
PaloAltoGreen Gas. Much of our programmatic promotional activity will center around
customer education and encouragement to sign up for participation in PaloAltoGreen Gas.
Other new programs include home efficiency services and online tools to help customers
manage their energy use.
Stepping up efforts to promote gas safety education, staff is focusing outreach around youth,
the importance of calling USA (811) before digging for anyone who may excavate in and around
Palo Alto, such as plumbers and contractors, potential sewer and gas line cross-bores, keeping
fats, oils and greases out of drains, and ensuring clear access to meters. For younger
“customers-to-be,” CPAU created a Home Safety Detective campaign that includes special tool
kits to help them identify home safety problems. Staff provides safety kits to youth and adults
at school presentations, neighborhood safety and emergency preparedness fairs and other
community outreach events. Meter access awareness is highlighted through use of materials
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 29 | Page
featuring photos of some unusual ways people obstruct access to their meters, including using
them as bike racks and building storage sheds around them.
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 which is mailed to all customers in Palo
Alto, as well as plumbers, contractors and excavators that may work in and around the area.
Staff talks with business customers at special facilities meetings, attends neighborhood safety
and emergency preparedness fairs and offers presentations to school and community groups.
While print materials and website pages still feature prominently, CPAU is turning the outreach
emphasis to direct mail, newspaper inserts, social media, online videos and cable TV. Copies of
all outreach materials and logs of activities are saved in the Gas Safety Public Awareness Plan
that is reviewed at least once per year by the Department of Transportation.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 30 | Page
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
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 31 | Page
APPENDIX A: GAS FINANCIAL FORECAST DETAIL
($'000)
Actual Actual Actual Actual Actual
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
1 RATE CHANGE (%)*0%12%0%0%0%8%0%4%6%6%5%3%3%2%1%0%
2 SALES IN THOUSAND THERMS 30,447 28,901 28,117 28,881 26,719 27,829 27,434 27,463 27,623 27,546 27,482 27,432 27,394 27,450 27,510 27,541
3
4 Utilities Retail Sales 41,034 33,759 34,843 29,515 28,065 33,243 33,852 34,339 36,422 38,683 40,918 42,694 44,275 45,736 46,948 47,566
5 Service Connection & Capacity Fees 592 731 654 602 961 1,017 1,048 1,079 1,111 1,145 1,179 1,179 1,179 1,179 1,179 1,179
6 Other Revenues & Transfers In 103 830 313 415 873 1,857 2,965 3,395 3,906 4,251 4,573 4,916 5,266 5,623 6,081 6,043
7 Interest plus Gain or Loss on Investment 1,119 (239)706 450 730 526 361 362 256 227 209 237 272 297 322 338
8 Total Sources of Funds 42,847 35,081 36,517 30,982 30,629 36,643 38,225 39,175 41,695 44,306 46,879 49,025 50,992 52,835 54,530 55,126
9
10 Purchases of Utilities:
11 Supply Commodity 15,356 12,461 12,992 9,537 9,178 10,098 12,106 11,487 11,805 12,097 12,495 13,001 13,616 14,254 14,980 15,468
12 Supply Transportation 879 994 1,333 982 (1,051)2,944 3,331 3,444 3,499 3,487 3,526 3,568 3,611 3,655 3,699 3,767
13 Total Purchases 16,235 13,455 14,325 10,519 8,127 13,042 15,437 14,931 15,304 15,584 16,021 16,569 17,227 17,909 18,679 19,235
14
15 Administration (CIP + Operating)3,473 4,273 3,988 4,007 3,337 3,064 3,147 3,232 3,319 3,408 3,500 3,594 3,691 3,790 3,892 3,997
16 Customer Service 1,270 1,358 1,338 1,195 1,097 1,584 1,644 1,705 1,767 1,830 1,896 1,964 2,034 2,107 2,183 2,261
17 Demand Side Management 614 630 438 632 566 1,471 1,512 1,554 1,597 1,641 1,686 1,732 1,780 1,828 1,879 1,930
18 Engineering (Operating)333 340 352 369 426 529 547 565 584 604 623 644 665 687 710 733
19 Operations and Maintenance 5,032 4,940 4,119 4,403 4,153 5,980 6,189 6,398 5,613 5,807 6,007 6,215 6,429 6,652 6,882 7,120
20 Resource Management 729 506 516 556 472 724 748 772 798 823 850 877 905 934 965 996
21 Debt Service Payments 406 296 805 804 249 803 802 800 800 802 803 804 802 799 802 -
22 Rent 230 219 419 431 443 455 467 480 492 505 519 532 546 561 574 587
23 Transfers to General Fund 6,006 5,971 5,811 5,730 6,194 6,594 7,035 6,888 7,069 7,069 7,974 8,370 8,794 9,248 9,734 9,739
24 Other Transfers Out 170 207 606 151 303 484 496 508 520 533 546 560 573 587 602 617
25 Capital Improvement Programs 7,821 7,620 1,026 1,832 5,017 2,214 2,074 5,725 5,960 6,145 6,335 6,525 6,721 6,923 7,130 7,344
26 Total Uses of Funds 42,320 39,814 33,743 30,629 30,384 36,943 40,098 43,557 43,823 44,751 46,759 48,386 50,169 52,027 54,032 54,561
27
28 Into/ (Out of) Reserves 528 (4,733)2,773 353 245 (300)(1,874)(4,382)(2,127)(446)120 639 823 808 499 565
29
30 Reappropriations + Commitments 19,211 19,363 11,305 6,491 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255
31 Plant Replacement 1,000 1,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0
32 CIP Reserve 0 0 0 1,591 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820
33 Rate Stabilization 15,992 11,318 15,981 7,215 6,018 6,018 4,810 524 0 0 0 0 0 0 0 0
34 Operations Reserve 0 0 0 10,847 10,296 9,873 9,208 9,112 7,508 7,063 7,183 7,822 8,645 9,453 10,768 11,333
35 Unassigned 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1
36 Total Reserves 36,203 31,681 27,286 26,144 26,389 25,966 24,093 19,711 17,583 17,138 17,258 17,897 18,720 19,528 20,843 21,409
37 (1,142)245 (423)(1,874)(4,382)(2,127)(446)120 639 823 808 1,315 566
38 Short Term Risk Assessment Value 1,226 3,753 3,560 3,363 3,918 4,231 4,575 4,910 5,144 5,340 5,510 5,635 5,659
39
40 Operations Reserve Guidelines
41 Min (60 Days Commodity + O&M) 5,620 5,000 5,821 6,139 6,074 6,039 6,136 6,412 6,622 6,856 7,100 7,357 7,425
42 Target (90 Days Commodity + O&M) 8,429 7,500 8,731 9,208 9,112 9,058 9,204 9,618 9,933 10,284 10,650 11,036 11,137
43 Max (120 Days Commodity + O&M) 11,239 10,000 11,641 12,277 12,149 12,077 12,272 12,824 13,244 13,712 14,201 14,715 14,849
44
City of Palo Alto
Gas Utility
Fiscal Year
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 32 | Page
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 2018 FY 2019 FY 2020 FY 2021 FY 2022
ONE TIME PROJECTS
GS-10000 Gas Station 3 Rebuild - - - - - - - - - - -
GS-15001 Security at Receiving Stations 275,000 - 150,000 (1,563) 423,437 109,174 - - - - -
Subtotal, One-time Projects 275,000 - 150,000 (1,563) 423,437 109,174 - - - - -
GAS MAIN REPLACEMENT (GMR) PROGRAM
GS-09002 GMR - Project 19 - - - - - - - - - - -
GS-10001 GMR - Project 20 - - - - - - - - - - -
GS-11000 GMR - Project 21 100,000 - (100,000) - - - - - - - -
GS-12001 GMR - Project 22 3,571,560 - 3,000 (144,495) 3,430,065 - - - - - -
GS-13001 GMR - Project 23 620,650 3,010,000 (2,967,500) (42,500) 620,650 - - 3,588,150 - - -
GS-14003 GMR - Project 24 - 640,000 - - 640,000 - - - 3,100,000 - -
GS-15000 GMR - Project 25 - - - - - - - - 659,000 3,200,000 -
GS-16000 GMR - Project 26 - - - - - - - - - 678,200 3,300,000
GS-20000 GMR - Project 27 - - - - - - - - - - 700,000
GS-20001 GMR - Project 28 - - - - - - - - - - -
Subtotal, Gas Main Replacement Program 4,292,210 3,650,000 (3,064,500) (186,995) 4,690,715 - - 3,588,150 3,759,000 3,878,200 4,000,000
TOOLS AND EQUIPMENT
GS-13002 General Shop Equipment/Tools 70,106 100,000 (170,106) - - - - - - - -
GS-01019 Global Positioning System - - - - - - - - - - -
GS-03008 Polyethylene Fusion Equip.- - - - - - - - - - -
GS-14004 Gas Distribution System Model 126,365 - 19,574 - 145,939 19,574 - 640,000 - - -
Subtotal, Tools and Equipment 196,471 100,000 (150,532) - 145,939 19,574 - 640,000 - - -
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 33 | Page
Gas Utility Capital Improvement Program (CIP) Detail (continued)
Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
ONGOING PROJECTS
GS-11002 Gas System Improvements 202,373 231,913 (173,254) (77,393) 183,639 87,771 238,870 246,036 253,417 261,020 268,851
GS-03009 System Ext. - Unreimbursed 128,690 198,500 (334,679) (62,123) (69,612) - 204,455 210,590 216,908 223,415 230,117
GS-80019 Gas Meters and Regulators 304,927 355,030 (659,957) - - - 365,681 376,652 387,952 399,591 411,579
Subtotal, Ongoing Projects 635,990 785,443 (1,167,890) (139,516) 114,027 87,771 809,006 833,278 858,277 884,026 910,547
CUSTOMER CONNECTIONS (FEE FUNDED)
GS-80017 Gas System Extensions 213,712 1,228,500 (1,209,764) (660,368) (427,920) 158,819 1,265,355 1,303,315 1,342,415 1,382,688 1,424,169
Subtotal, Customer Connections 213,712 1,228,500 (1,209,764) (660,368) (427,920) 158,819 1,265,355 1,303,315 1,342,415 1,382,688 1,424,169
GRAND TOTAL 5,613,383 5,763,943 (5,442,686) (988,442) 4,946,198 375,338 2,074,361 6,364,743 5,959,692 6,144,914 6,334,716
Funding Sources
Connection Fees 1,017,000 (1,209,764) 1,047,510 1,078,935 1,111,303 1,144,642 1,178,981
Utility Rates 4,746,943 (4,232,922) 1,026,851 5,285,808 4,848,389 5,000,272 5,155,735
CIP-RELATED RESERVES DETAIL
6/30/2016
(Actual)
6/30/2017
(Unaudited)
Reappropriations 5,345,914 4,570,860
Commitments 267,469 375,338
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 34 | Page
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
April 1 2 , 2016 35 | Page
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
April 1 2 , 2016 36 | Page
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
April 1 2 , 2016 37 | Page
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
April 1 2 , 2016 38 | Page
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
EXCERPTED DRAFT MINUTES OF THE APRIL 5, 2017 UTILITIES ADVISORY COMMISSION
ITEM 3: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt a Resolution Approving the Fiscal Year 2018 Gas Utility Financial
Plan With no Changes to Gas Distribution Rates
Senior Resource Planner Eric Keniston gave an overview of the Gas Utility financial forecast. No
gas distribution rate change was proposed, but customers would see a bill increase as a result
of the Carbon Neutral Gas Plan approved by Council in November 2016. A charge of up to ten
cents per therm had been approved to buy offsets for all gas delivered within Palo Alto. Staff
projected this would cost $1.3 million dollars in FY 2017, resulting in a projected 4% increase.
This had not been highlighted in the projections presented at the March 2017 UAC meeting.
However, aside from noting this impact, staff had no changes from the proposal presented at
the March meeting.
ACTION: Vice Chair Danaher made a motion to recommend Council approval of the staff
recommendation. Commissioner Ballantine seconded the motion. The motion passed
unanimously (5-0, with Chair Cook, Vice Chair Danaher and Commissioners Ballantine,
Johnston, and Schwartz voting yes and Commissioners Forssell and Trumbull absent)
ATTACHMENT C
City of Palo Alto (ID # 8057)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/18/2017
City of Palo Alto Page 1
Summary Title: Follow-up Information on Water Utility Rate Comparisons
Title: Follow-up Information on Water Utility Rate Comparisons
From: City Manager
Lead Department: Utilities
Recommendation
This is a discussion item and no action is required.
Background
At its April 4, 2017 meeting, the Finance Committee requested more information on why water
bills for Palo Alto’s residential customers were higher than those of surrounding agencies. This
report provides background on water utility benchmarking efforts undertaken since 2010. In
addition, preliminary insights from a 2014 staff benchmarking effort are discussed.
Discussion
Staff has attached an April 15, 2014 Finance Committee staff report (Staff Report ID 4480,
Discussion of Water Utility Benchmarking Studies and Future Work Plan) summarizing the
results of past efforts in 2010 and 2013 (Attachment A). To supplement that report, Attachment
B provides an informal 2014 staff analysis comparing CPAU water utility rates with several
nearby agencies.
The findings of the 2010, 2013 and 2014 benchmarking studies are largely consistent. Some of
the key insights are:
1. As indicated by these analyses, it has long been recognized that water utility rates in Palo
Alto are higher than some nearby agencies. It should be noted that CPAU’s relatively low
electric and gas utility rates typically result in lower total utility bills for customers;
however, water rates are relatively high and have been regularly reviewed over the past
several years.
2. Comparison among agencies can be difficult due to varying system sizes, and benchmarking
is complicated by factors unique to each agency such as geography, residential/commercial
customer mix, and capital improvement practices.
3. Single family residential customer usage in Palo Alto is relatively high among the
City of Palo Alto Page 2
comparison agencies, 25-35% above median, contributing to higher monthly bills.
4. Single family residential customers represent 41% of overall CPAU consumption, contrasting
with 24% and 27% in Mountain View and Santa Clara, respectively. That means that a
greater share of the water utility’s fixed costs are allocated to single-family customers than
in other service territories since Palo Alto’s single-family customers use a greater share of
system capacity than other agencies’ customers do.
5. Debt service currently constitutes roughly 7% of CPAU rates, primarily related to the El
Camino Reservoir and related emergency storage projects. Many other systems have no
debt service.
6. Operating costs are relatively high per square mile of urban service area. Salary and
benefit costs are relatively high due to a greater number of employees than any comparison
agencies. In part, the greater number of employees had to do with the greater number of
miles of water main per customer, due to the less dense nature of Palo Alto’s urban core.
Even with the Foothills areas omitted, Palo Alto has a lower population and customer
density than other cities. Employee counts are much more comparable between Palo Alto
and other cities when compared on the basis of number of employees per mile of water
main.
7. Capital spending for distribution and water supply (excluding recycled water) was found to
be substantially higher on an absolute (rather than normalized) dollar basis in Palo Alto,
even though Palo Alto was the smallest of the five agencies in the study. That included both
cash investments in capital spending and debt service costs (see Attachment B).
Benchmarking is a complex exercise due to the different physical layouts of different systems,
different consumption characteristics of the populations, and different methods of accounting,
making it hard to discern clear, simple reasons for cost differences. Even choosing a basis for
cost comparison can be challenging. For example, differences in consumption patterns can
heavily skew comparison on a cost per CCF basis. Differences in the ratio of commercial to
residential customers can skew a comparison on a cost per customer basis. A cost per mile of
main comparison basis can be helpful for some types of costs, but hides differences in density
of the service territories that affect customer bills, since customers in a less dense service
territory require a greater length of water main to serve each customer, leading to higher bills
for each customer in a less dense territory. These differences are addressed in the 2014
benchmarking study.
Benchmarking is an ongoing effort, as is cost-effectiveness review and implementation of
operational changes. Staff is continuing to review opportunities for improving efficiency and
minimizing customer rates, and will report to the Committee and Council as this effort
proceeds.
Timeline
Staff plans to schedule further discussions of this topic in the fall of 2017.
Resource Impact
City of Palo Alto Page 3
These discussions will be accomplished with existing staff. No additional resources are required.
Policy Implications
There are no policy implications associated with a discussion of water utility operating costs
and rates.
Environmental Review
Discussion of water utility operating costs and rates 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: Staff Report ID 4480, Water Utilities Benchmarking Review and Future
Work Plan
Attachment B: Comparison of Capital Spending by Water Utility
Attachment C: Final Excerpted Minutes of the April 15, 2014 Finance Committee
Meeting
City of Palo Alto (ID # 4480)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 4/15/2014
City of Palo Alto Page 1
Summary Title: Water Utility Benchmarking Review and Future Work Plan
Title: Discussion of Water Utility Benchmarking Studies and Future Work
Plan
From: City Manager
Lead Department: Utilities
Recommendation
This report presents two benchmarking studies previously done of the City’s Water Utility, and
presents some possible future areas for analysis. No action is required, but staff requests input
on its work plan regarding future benchmarking for the Water Utility.
Executive Summary
The Water Utility’s rates have been rising over the last several years, primarily due to seismic
upgrades to the Hetch Hetchy system that are leading to steeply increasing wholesale water
costs, a large investment in the utility’s emergency water supply and storage system, and the
levels of investment required to maintain and replace Palo Alto’s aging distribution mains. The
rising water rates have led to increased interest in the difference between Palo Alto’s rates and
the rates of those neighboring agencies who also receive water from the Hetch Hetchy system.
Two benchmarking studies of the Water Utility have been performed in the last several years.
The first, completed in 2010 and based on Fiscal Year (FY) 2009, focused only on the Water
Utility. The second was done as part of an organizational assessment done by SAIC for the City
and delivered on March 18, 2014. The common theme in these studies is that Palo Alto has
older water infrastructure than other agencies and has higher levels of capital investment and
operations and maintenance expense as a result.
Staff is planning to complete a deeper analysis of some of these questions in 2014, and has
listed some topics for further investigation later in this report. Staff would like the Finance
Committee’s comments on its work plan.
ATTACHMENT A
City of Palo Alto Page 2
Background
This report is offered in response to a recommendation by the Finance Committee during the
FY 2014 budget process in May of 2013. The Finance Committee asked staff to return at a later
date for a review of the City’s water costs. This topic has been discussed in depth once before,
in 2010, and a recent analysis by SAIC also addressed some of these issues. In addition, staff did
some of its own preliminary analysis in late 2013 in an attempt to delve more deeply into some
of the issues raised by these two studies. Staff presented some of this preliminary analysis to
the Utilities Advisory Commission (UAC) at its January 8, 2014 meeting, and the UAC
recommended completing more in-depth analysis before proceeding to the Finance
Committee. Staff concurs, and is providing this report as background for the Finance
Committee on the results of previous benchmarking efforts, and to provide an opportunity for
the Committee to communicate any specific questions it would like to have addressed.
Discussion
The City has completed two benchmarking studies in the last several years related to the City’s
Water Utility.
2010 Benchmarking Study
In 2010 the City hired HF&H Consultants to perform a benchmarking study that focused solely
on the Water Utility. This study sought to answer the following questions:
1. Why are the City of Palo Alto Utilities’ (CPAU’s) water rates higher than neighboring
utilities?
2. How does the Water Utility budget compare with other neighboring utilities?
3. What qualitative and quantitative information explains the differences in major cost
categories, such as water purchase costs, operations costs, staff costs, and capital costs?
4. How do the neighboring utilities compare with respect to the state of their respective
utility infrastructures, emergency preparedness, and reliability?
5. What are CPAU customers getting for the extra money collected for water utility
services?
HF&H compared the Water Utility with Redwood City, Mountain View, Milpitas, Hayward, Santa
Clara, and California Water Service Company’s Bear Gulch District. The consultant found that
CPAU’s rates were higher than average for several reasons:
City of Palo Alto Page 3
1. The Water Utility puts more staff resources and capital into maintaining and replacing
its older facilities.
2. Economies of scale are greater for the comparison cities.
3. Palo Alto’s service area is more broadly spread, with more pumping zones, all of which
makes it more expensive to serve.
4. Palo Alto experiences more seasonal variation in its demand, which requires a higher
level of operating capability.
5. Palo Alto provides a higher quality of service, with a lower number of complaints
received and a lower number of system outages.
6. Palo Alto’s cost of water supplies is higher than some of the agencies that purchase
some water from Santa Clara Valley Water District and/or pump groundwater.
HF&H’s Water Utility Benchmarking Study was presented to the Finance Committee on
November 2, 2010 (CMR: 393:10). That report is provided as Attachment A.
2014 SAIC Organizational Assessment
On March 18, 2014, the Finance Committee received a report from SAIC Energy, Environment &
Infrastructure, LLC describing an organizational assessment of CPAU as a whole. The report
found that CPAU was a “well-run, reliable, and innovative organization,” and that its water
utility was “performing well,” though it should continue its efforts to manage O&M costs and
water supply costs. To form these conclusions SAIC benchmarked the Water Utility against a
number of other water utilities across California and in other parts of the country. The results
are shown in the table below that was taken from the SAIC study.
City of Palo Alto Page 4
Benchmarking Results from SAIC Study
CPAU Results (CY 2011)
Measure
Better
than
Average
At or
Near
Average
Worse
Than
Average
Water
Revenue per Million Gallons Delivered (Fig. 3-17) √
Net Income per Revenue Dollar (Fig. 3-18) √
Retail Water Customers per FTE (Fig. 3-19) √
O&M Expense per Million Gallons (Fig. 3-20) √
O&M Expense per Water Retail Customer (Fig. 3-21) √
O&M Expense per Mile of Water Main (Fig. 3-22) √
A&G Expense per Retail Water Customer (Fig. 3-23) √
A&G Expense per Million Gallons Processed (Fig. 3-24) √
Million Gallons per Day Delivered per FTE (Fig. 3-25) √
Average Monthly Residential Water Bill (Fig. 3-26) √
SAIC noted that CPAU was worse than average on Operation and Maintenance (O&M) expense
per mile of water main and in water delivered per Full-Time Equivalent (FTE). The consultant
attributed higher O&M expense to the higher attention paid to its older water infrastructure,
noting that CPAU, unlike most other utilities, is currently implementing an aggressive water
distribution system infrastructure replacement program. The consultant also urged caution in
interpreting the water delivery numbers, since Palo Alto appears to directly allocate
administrative and customer service FTEs to its utility in contrast to other utilities that do an
indirect allocation of overhead costs. This artificially deflates CPAU’s water delivery per FTE.
Future Staff Work Plan
Staff has done some preliminary analysis of the Water Utility’s typical comparison agencies, and
has come to similar initial conclusions as HF&H and SAIC. Palo Alto was developed earlier than
the comparison cities and has maintained lower growth rates than its neighbors, which is likely
responsible for its substantially older infrastructure. This older infrastructure requires higher
levels of Capital Improvement Program (CIP) and O&M investment. Palo Alto has been aware
of this need for a long time. In 1990 an in-depth assessment of infrastructure costs was
performed that found that CPAU’s aging water infrastructure required an increased level of
investment to maintain the health of the system. As the accelerated main replacement
program ramped up, CPAU’s rates went from being comparable to its neighboring agencies to
City of Palo Alto Page 5
being above them. By 2000, CPAU’s average residential bill was as high relative to other
agencies as it is today. This suggests that infrastructure, both for SFPUC’s regional water
system and CPAU’s local distribution system, is the main driver of CPAU’s high water rates
relative to other agencies.
Staff has also found some other avenues that are worth investigating, including the following:
1. CPAU bills are not necessarily the highest for all customer classes and usage levels. This
is because allocations of system costs between residential and non-residential
customers appear to differ from utility to utility. Presumably these differences in
allocations are due to different service territory characteristics, since most utilities use
similar cost allocation methodologies.
2. Different agencies have different ratios of units of water delivered per mile of water
main, which affects rates. The lower cost comparison agencies tended to deliver more
water per mile of main, meaning that the maintenance costs for each mile of main were
spread over more sales units, leading to lower rates. This is reflective of the fact that
Palo Alto is more spread out than its neighboring cities, as noted in the 2010
Benchmarking Study, meaning that more mains are required to deliver water to the
same number of customers.
Staff plans to extend its preliminary analysis over the course of 2014 to answer a variety of
other questions, if possible. Since the data required to answer these questions is not easily
found in a comparable format in public documents, it will require the cooperation of other
agencies. The extent to which staff can answer these questions depends on the extent to which
these agencies are willing to take the time to extract the data and answer clarifying questions
about it. Some of the questions staff will seek to answer are:
1. Taking into account the physical differences between service territories, how do CPAU’s
O&M costs compare to those for other BAWSCA agencies?
2. How do CPAU’s administration, allocated overhead, and customer service costs
compare to other BAWSCA agencies?
3. How do CPAU’s salaries and benefits compare to other BAWSCA agencies?
4. How are costs allocated between residential and non-residential customer classes for
comparable BAWSCA agencies, and what drives those allocations?
5. How would costs need to change for rates to become competitive?
Staff welcomes comments on these questions and suggestions for additional avenues of inquiry
to be incorporated into the study.
City of Palo Alto Page 6
Timeline
Staff plans to complete its review by December 2014 and will return to the UAC and Finance
Committee with its conclusions.
Resource Impact
Staff estimates it will require approximately 0.1 FTE in 2014 to complete this analysis. This will
be absorbed with existing staff.
Environmental Review
The Finance Committee’s discussion of these benchmarking studies does not meet the
definition of a project, pursuant to Section 21065 of the California Environmental Quality Act,
thus no environmental review is required.
Attachments:
Attachment A: CMR 393:10 Water Utility Benchmark Study (PDF)
TO: HONORABLE CITY COUNCIL
FROM: CITY MANAGER DEPARTMENT: UTILITIES ATTENTION: FINANCE COMMITTEE
DATE: NOVEMBER 2, 2010 CMR: 393:10
SUBJECT: Water Utility Benchmark Study
This report is informational only and no action is required.
EXECUTIVE SUMMARY Staff has received comments in various forums that the City’s water rates have been among the highest in the region. The water utility benchmarking study was conducted by an outside
consultant to obtain an independent assessment of the factors that could explain this difference.
This study compared the City’s water utility with six nearby water suppliers.
The study revealed that the City does have higher water purchase cost than average as it gets all of its water supplies from San Francisco, which is more expensive than groundwater or other
supplies from the Santa Clara Valley Water District. In addition, due to its size, Palo Alto does
not benefit from the economies of scale available to larger agencies. Palo Alto’s water system is
more expensive than average to operate since the City is spread out and includes sparser development in hillier terrain. Palo Alto’s main distribution pipelines are also the oldest within
the group, and older infrastructure is more expensive to maintain and replace.
Another objective of the benchmarking study was to identify benefits that Palo Alto rate payers
may receive from the higher rates they pay. The study indicates that Palo Alto provides a higher quality of service based on the lower number of complaints received and fewer system outages.
BACKGROUND
During its review of the Utilities long-term financial projections and the review of the Fiscal
Year (FY) 2011 budget in the Spring of 2010, the Utilities Advisory Commission (UAC) and the Finance Committee recommended that a benchmark study for the Water Utility be prepared.
Staff engaged a consultant (HF&H Consultants, LLC) to complete the benchmarking study. This
report summarizes the findings of the study, which staff presented to the UAC at its October 6,
2010 meeting.
CMR: 393:10 Page 1 of 6
Current Rates and Bills For further background information the following two figures compare monthly bills using
current water rates. Several cities implemented water rate increases in FY 2011 while Palo Alto
has not increased water rates since July 1, 2009. These later water rate increases were not
incorporated in the bill comparisons provided in the consultant report. The figure below represents monthly bills for single-family residential customers using current water rates. Hayward is shown twice in the following two figures, outer city rates (Hayward-O) and inner
city rates (I).
Palo Alto
Redwood City
Mountain View
Milpitas
Hayward ‐I
Hayward ‐O
Santa Clara
Bear Gulch ‐MP
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
0 5 10 15 20 25 30 35 40 45 50 55 60 65 70
Mo
n
t
h
l
y
Bi
l
l
($
)
Usage Per Monthly Bill (CCF)
Single Family Residential Monthly Bills
Benchmark City Comparisons
5/8" meter
Water bills for non-residential customers are shown in the chart below for different usage levels.
Note that although bills in Palo Alto are higher than average, they are not the highest in the
group of comparator cities.
CMR: 393:10 Page 2 of 6
Palo Alto Redwood City
Mountain View
Milpitas
Hayward ‐I
Hayward ‐O
Santa Clara
Bear Gulch ‐MP
$0
$2,000
$4,000
$6,000
$8,000
$10,000
$12,000
$14,000
0 250 500 750 1000 1250 1500 1750 2000
Mo
n
t
h
l
y
Bi
l
l
($
)
Usage Per Monthly Bill (CCF)
Commercial Monthly Bills
Benchmark City Comparisons
5/8" meter
DISCUSSION
Study Objectives and Approach
Given the concerns expressed by the UAC and the Council Finance Committee about Palo Alto’s
water rates, staff initiated a benchmark study for the Water Utility in May 2010. The objective of the study was to develop benchmarks to provide insight into key questions such as:
o Why are Palo Alto water rates higher than neighboring cities?
o How does Palo Alto’s water utility budget compare with others?
o What qualitative and quantitative factors explain the differences?
o How does Palo Alto’s infrastructure, emergency preparedness and reliability compare with its neighbors?
o What benefits do Palo Alto rate payers receive from higher rates?
Six neighboring cities with comparable size and location were selected for the benchmark comparisons. The scope of the study was defined to capture information from readily available documents on the benchmarks identified in the first phase and then, as a potential second phase,
to conduct further evaluation of the most informative benchmarks. HF&H Consultants, LLC
completed the first phase of the study and then staff followed up with further surveying and
CMR: 393:10 Page 3 of 6
compiling additional information from the benchmark cities. The Water Utility Benchmark Study is provided as Attachment A. The study focused on areas such as:
o Rate structures and related charges
o Service area and customer characteristics
o Operating and capital budgets
o Infrastructure condition
o Staffing and operational requirements
o Quality of service
Study Conclusions 1. Service Area and Infrastructure Benchmarks
The benchmark cities selected have the overall characteristics shown in the following table:
City Population Service Area
(square miles)
Water Deliveries
(million gallons per day)
Palo Alto 63,400 26.0 12.3
Hayward 150,878 62.5 18.6
Milpitas 70,817 13.6 11.2
Mountain View 74,762 12.0 11.4
Redwood City 83,895 35.0 10.4
Santa Clara 117,242 19.3 22.2
California Water Company’s Bear
Gulch District (serves parts of Menlo
Park, Atherton and Woodside)
57,108 45.3 13.1
The study concluded that Palo Alto’s population is smaller than average and, therefore, does not benefit from economies of scale, suggesting higher costs to serve its customers. In addition, Palo
Alto is less densely populated which may imply higher cost per capita for service. Palo Alto has
larger single family home lot sizes suggesting higher water use for irrigation. This results in a
higher ratio of peak to average usage translating to costlier service requirements. 2. Water Use Benchmarks
Palo Alto’s overall average water usage per account is about the same as the average for the
group. Comparing single family water use per account with the average for the group yields a
similar result. However, Palo Alto’s single-family residential customers water use per account is actually the second highest after Bear Gulch, which has very different characteristics (much larger average lot size). This provides one reason for higher average residential water bills.
Palo Alto’s fraction of “lost and unaccounted for” water (total sales volumes divided by total
purchase volumes) is in line with the industry average of 8-9%. Santa Clara’s fraction of lost and unaccounted for water was extremely low and could partly explain their low water rates. Staff examined Santa Clara’s policy regarding minimizing their water losses. Staff will further
investigate whether similar emphasis on reducing water losses could have a significant impact on
Palo Alto’s costs.
CMR: 393:10 Page 4 of 6
3. Operations and Maintenance (O&M) Benchmarks O&M benchmarks can be used to determine how efficient water distribution operations are. The
study found that Palo Alto mains are the oldest average age in the benchmark cities. This
suggests that the City’s infrastructure is more expensive to maintain. In addition, Palo Alto has a
higher variation between peak and minimum month flows, which would suggest the need for greater infrastructure needs (and cost) to meet peak flow requirements, and greater operational cost to serve a wider range of flows.
Palo Alto has a greater number of employees per gallon delivered and per account. However,
other cities use staff from other departments for services such as meter reading and billing and pay for these services in the form of an allocation, rather than directly in employee costs. In addition, Palo Alto does its own engineering design in-house while other entities contract out for
these services.
Overall, Palo Alto’s operations costs are somewhat higher than average, which is consistent with the higher level of service provided and Palo Alto’s lower economy of scale.
4. Quality of Service Benchmarks
Palo Alto receives below average complaints for taste, odor, turbidity, and high or low pressure
problems. These factors indicate that customer satisfaction is higher than average in Palo Alto. In addition, Palo Alto has fewer outages per gallon of water delivered and per mile of main suggesting better system maintenance and operations.
5. Utility Infrastructures, Emergency Preparedness, and Reliability
Palo Alto plans to replace its water utility infrastructure within the average service lives of the facilities, which is a more aggressive replacement plan than other utilities. Palo Alto’s incidence of main breaks, leaks, and outages is below average, which is further evidence of higher/better
reliability. Although Palo Alto has less storage capacity than average, and, therefore, could be
viewed as less reliable, the City is in the process of constructing additional storage.
6. Other Conclusions
Water purchase costs
Palo Alto currently pays more for water than the average benchmark comparator since some of
the agencies use less expensive groundwater or treated water from the Santa Clara Valley Water
District. In addition, other agencies supplement their supplies with recycled water, the full cost of which may not be included in their water utility budgets. Palo Alto is currently entirely reliant
on the San Francisco Public Utilities Commission (SFPUC) for its drinking water supply. The
cost of SFPUC’s water will increase steeply in the next few years before leveling off. In
anticipation of these cost increases, Palo Alto has set its rates to generate reserves to smooth out
the increased cost.
Capital costs (past, present and projected)
Since Palo Alto’s main distribution lines are the oldest within the group, Palo Alto has
aggressively invested in facilities to improve system reliability and in programs to improve its
water use efficiency. Palo Alto’s Capital Improvement Plan (CIP) expenditure levels are
CMR: 393:10 Page 5 of 6
generally higher than other benchmark cities. Some of the benchmark cities also receive
significant revenues from connection fees that are used to fund capital improvements.
Rent
Palo Alto's Water Utility pays rent to the City's General Fund for its use of land. Palo Alto's
costs in this category are generally higher than other cities.
ATTACHMENTS
A. Water Utility Benchmark Study
B. Draft minutes from the UAC October 6,2010 meeting
PREPARED BY:
REVIEWED BY:
DEPARTMENT APPROVAL:
CITY MANAGER APPROVAL:
CMR: 393:10
IPEKCONNOLLY -'C-
Senior Resource Planner 1':11
SHIV A SWAMINATHAN "'(;ib
Senior Resource Planner
DEBBIE LLOYD J) L
Acting Assistant Director, Resource Management
~Pclt-~
JAMES KEENE
City Manager
Page 6 of6
HF&H CONSULTANTS, LLC
Managing Tomorrow’s Resources Today
201 North Civic Drive, Suite 230 Robert D. Hilton, CMC Walnut Creek, California 94596 John W. Farnkopf, PE Tel: (925) 977-6950 Laith B. Ezzet, CMC Fax: (925) 977-6955 Richard J. Simonson, CMC hfh-consultants.com Marva M. Sheehan, CPA
TECHNICAL MEMORANDUM
To: Ipek Connolly, City of Palo Alto
Jane Ratchye, City of Palo Alto
From: John Farnkopf, HF&H Consultants, LLC
Sima Mostafaei, HF&H Consultants, LLC
Greg Trueblood, HF&H Consultants, LLC
Date: September 21, 2010
Subject: Water Utility Benchmarking Study
This technical memorandum summarizes the results of our benchmarking study
performed for the City of Palo Alto Utilities (CPAU) to assist in its rate-setting process
and potentially other purposes such as operational performance evaluation. This study
evaluated benchmarks at a reconnaissance level based on readily available data within the
project schedule and contract budget. This technical memorandum contains the
following sections:
I. Introduction
II. Service Area Benchmarks
III. Water Use Benchmarks
IV. O&M Benchmarks
V. Quality of Service Benchmarks
VI. Expense and Revenue Benchmarks
VII. Rate Benchmarks
VIII. Customer Bill Benchmarks
IX. Findings
X. Concluding Remarks and Possible Next Steps
Additional detail is included in the appendix.
I. Introduction
As part of its process of continuous self-assessment, the CPAU compares its utility rates
with similar neighboring cities. It has been observed and reported that the City’s water
rates have been among the highest in the region. The need for a benchmarking study
stemmed from the desire by the CPAU to obtain an independent assessment of the
City of Palo Alto Water Utility Benchmarking Study
HF&H Consultants, LLC September 21, 2010 2
factors that explain this difference. The purpose of the study is to provide answers to
the following questions:
1) Why are CPAU water rates higher than other neighboring utilities?
2) How does the CPAU water utility budget compare with other neighboring
utilities?
3) What qualitative and quantitative information explains the differences in major
cost categories (e.g., water purchase costs, operations costs, staff costs, capital
costs (past, present, and projected), transfers out).
4) How do the neighboring utilities compare with respect to the state of their
respective utility infrastructures, emergency preparedness and reliability?
5) What are CPAU customers getting for the extra money collected for water utility
services?
In this study, the City of Palo Alto’ water utility was compared with six other water
suppliers: the Cities of Redwood City, Mountain View, Milpitas, Hayward, and Santa
Clara and California Water Service Company’s Bear Gulch District.1
Within this group,
there is considerable variation in size, as shown below.
As can be seen, there are some disproportionate relationships. For example, Palo Alto’s
and Cal Water’s surface areas are large given their populations; Santa Clara’s surface
area for its population is comparatively small. Such examples illustrate the difficulty in
making statistical comparisons with a sample size of seven in which there may be
outliers that can skew the statistics and when data were not always available for all
seven agencies.
In the text of this report, Palo Alto is compared against the mean for the group and the
highest and lowest individual values. This comparison is intended to simplify
understanding each benchmark. Readers are urged, however, to also review the
appendix, which shows the values for each agency. In this way, the affects of
disproportionate relationships, outlier values, and missing data can aid in drawing
conclusions.
Documents from readily available sources were used in preparing this study. For most
but not all of the seven agencies, the following documents were reviewed:
• Budgets
• Comprehensive Annual Financial Reports
1 Cal Water is unusual among the agencies studied. It is the only member of the group that is a regulated water company; all the others are cities. It serves a disproportionately high single-family residential population in affluent
portions of Menlo Park, Atherton, and Woodside whose customers have large lots.
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HF&H Consultants, LLC September 21, 2010 3
• Capital improvement programs
• Urban Water Management Plans
• Drinking Water Reports
• Master fee schedules
• Official statements
• General Plans
• Service Efforts and Accomplishments Report and other reports specific to Palo
Alto only
• Written responses provided by cities to the survey conducted by CPAU staff
Over 60 published source documents exceeding 5,000 pages were relied upon. In a few
cases, telephonic interviews were also conducted. In addition to HF&H’s research,
CPAU staff conducted additional targeted surveys and interviews to supplement in
areas of the greatest interest such as the condition of infrastructure, past and projected
capital improvement programs, funding sources, areas of staff deployment, and capital
improvement plan implementation. In view of the large volume of data and limited resources
available for research and analysis, this study should be regarded as a reconnaissance level study,
as was intended within the scope of services for this project.
The data extracted from these documents represents a recent timeframe, but not the
same timeframe for each benchmark or for each agency. As such, the report represents
conditions typically ranging from the last few years up to the current year, depending
on the benchmark. Whereas benchmarks concerning historical trends can extend into
prior decades, benchmarks concerning rates reflect rates that are either currently in
effect or adopted but not yet effective.
II. Service Area and Infrastructure Benchmarks
Service area benchmarks compare general differences in the service areas that could
lead to differences in providing service. Infrastructure benchmarks combined with
service area benchmarks allow for additional definition of the physical differences
among the agencies. Figure 1 summarizes the key benchmarks that were evaluated.
Palo Alto’s population ranks it smaller in the sample and, as a result, Palo Alto does not
benefit from the economies of scale available to larger agencies. Palo Alto also appears
to be less densely developed compared to the mean for the group based on the number
of residents and accounts per square mile and the miles of main per square mile. In
effect, Palo Alto’s water utility infrastructure may be spread over a larger area. It is
likely that Palo Alto may have significant undeveloped open space compared to the
other agencies.2
2 This could be verified by reviewing land use data.
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Figure 1. Service Area and Infrastructure Benchmarks
Benchmark Palo Alto Mean
Palo
Alto vs.
Mean High Low Significance of Benchmark
Service area characteristics
Population 63,400 88,300 -28%150,878 57,108 Size affects economies of scale.
Population growth over last ten years 8.6%8.2%4%17.9%-1.7%Growth affects need to expand.
Accounts 19,443 21,777 -11%32,382 16,463 Size affects economies of scale.
Surface area (square miles) 26.0 30.5 -15%62.5 12.0 Size affects economies of scale.
Residents per square mile 2,438 3,717 -34%6,230 1,261 Population density; larger is denser.
Accounts per square mile 748 900 -17%1,436 405 Development density; larger is denser.
Average Temperature (deg F)58.0 57.0 2%59.2 48.6 Irrigation needs; lower is cooler.
Average annual precipitation (in) 15.37 16.35 -6%19.81 14.03 Irrigation needs; lower is drier.
Infrastructure
Miles of distribution mains 219 262 -16%350 175
Accounts per mile of main 89 84 5%98 57 Infrastructure density; larger is denser.
Miles of main per square mile 8.42 10.51 -20%15.28 5.60 Infrastructure density; larger is denser.
Average age of distribution mains (years)61 45 34%61 33 Age affects need for O&M and R&R
Capital Assets (net book value)
Capital assets per account $3,288 $3,085 7%$5,087 $1,541 Investment
Capital assets per hcf $10.65 $10.14 5%$19.73 $5.51
Capital assets per square mile $2,458,500 $2,553,050 -4%$3,528,231 $798,273 Infrastructure concentration
Palo Alto’s average temperature is slightly above average and its precipitation is
slightly below average, the combined effect of which is a slightly higher irrigation
requirement for similar landscapes. Land use is also a significant influence in irrigation
water use.3
Larger lots in hotter, drier climates can lead to higher irrigation water use.
The values reported by the agencies indicated that Palo Alto’s distribution mains are
the oldest within the group. Older infrastructure is more expensive to maintain and
replace. The value of Palo Alto’s capital assets per account and per unit of water
delivered is slightly higher than the mean. Because of Palo Alto’s sparser development,
the value of its capital assets per square mile is slightly less than the mean.
III. Water Use Benchmarks
Water use benchmarks can indicate relative water use efficiency. More efficient water
use is presumed to be less expensive to supply per account. Palo Alto’s single-family
residential water use is near average for the group. Palo Alto’s multi-family use is much
less than average because it has fewer, smaller multi-family accounts. Palo Alto’s
commercial, institutional, and industrial (CII) use is somewhat above average. Overall,
for all its classes, Palo Alto’s average use per account is near the average.
3 A review of land use data could indicate differences in average lot size, which would assist in understanding
differences in irrigation among the agencies.
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Figure 2. Water Use Benchmarks
Losses are an indicator of a number of broad conditions. Systems with low losses can
have better maintained distribution mains with pressures held within recommended
limits so that leaks and breaks are minimized. Systems with low losses can also indicate
better controlled reservoirs with fewer spills and more accurate and better maintained
meters.
Based on published sources,4 Palo Alto’s water losses are below average.5
City staff
partially attributes the low losses to inaccurate SFPUC master meters, which under-
record deliveries to the City; other factors are also pending further review. Other
agencies in the group reported low losses due to under-recording SFPUC meters. As a
result of the lack of accurate data on losses, it is not possible to make meaningful
comparisons about losses. However, based on Palo Alto’s internal water loss reports,
Palo Alto’s losses are within industry norms.
IV. O&M Benchmarks
Operations and Maintenance (O&M) benchmarks indicate how service area and water
use characteristics affect O&M. Palo Alto’s O&M benchmarks suggest areas that could
lead to higher operating costs. For example, the employee data indicate that Palo Alto
uses more employees per millions of gallons delivered than the average for the group
and has fewer accounts per employee.
Benchmarks relying on the number of employees are problematic because of the
differences among the agencies in how they account for staff. For example, the CPAU
includes its meter reading staff as part of its water utility; other cities provide these staff
from other departments, which may result in undercounting their water utility staff. In
other cases, attributions of public works or other non-water utility staff to an agency’s
water utility may use approximate formulae rather than direct attribution from time
4 Bay Area Water Supply and Conservation Agency Annual Survey, FY 2008-09.
5 Palo Alto has subsequently verified that the water losses are in the 8% to 9% range, in line with industry average.
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HF&H Consultants, LLC September 21, 2010 6
sheets. Palo Alto also provides its own design staff, whereas some of the other agencies
contract design work to consultants.
Figure 3. O&M Benchmarks
Benchmark Palo Alto Mean
Palo
Alto vs.
Mean High Low Significance of Benchmark
Operations and maintenance
Mgd per employee 0.28 0.36 -22%0.49 0.28 Efficiency; larger is more efficient.
Accounts per employee 445 576 -23%745 445 Efficiency; larger is more efficient.
Miles of main per O&M employee 8.4 12.7 -34%17.7 8.4 Efficiency; larger is more efficient.
Mgd per O&M employee 0.47 0.72 -35%1.07 0.47 Efficiency; larger is more efficient.
O&M employees as a percent of total employees 59%52%15%64%40%
Load factors
Peak month to average monthly demand 1.50 1.45 4%1.70 1.25 Design conditions; smaller is better.
Peak month to minimum monthly demand 3.21 2.52 28%4.26 1.57 Operational extremes; smaller is better.
Mgd per booster pump station 2.05 1.64 25%2.65 0.22 Pumping cost; larger is more expensive.
Square miles per pressure zone 3.25 4.28 -24%10.42 1.22 Pumping cost; smaller is more expensive.
Square miles per booster pump 4.33 4.05 7%8.93 0.77 Pumping cost; smaller is more expensive.
Days of Storage 0.85 1.35 -37%2.04 0.84 Emergency preparedness; larger is better.
Gallons of potable storage per account 540 854 -37%1,071 540 Emergency preparedness; larger is better.
Load factors indicate a higher variation of flow between peak and minimum month
flows. Higher load factors can require greater operational skill, instrumentation, etc. in
serving a wider range of flows. Higher load factors will also lead to designing larger,
more expensive facilities to meet peak flows. In Palo Alto’s case, its hillier and more
extended service area calls for higher pumping rates with the associated increase in
power cost.
Palo Alto’s distribution system storage is below average compared with the group.
Further evaluation of this metric is needed to confirm that the data are comparable
(some of the other agencies in the sample have raw water storage that may have been
included with their treated water storage). We note that the City is currently
constructing additional storage that is not included in this report.
V. Quality of Service Benchmarks
O&M practices are ultimately reflected in the quality of service, which reflects customer
complaints and outages. Based on recent Drinking Water Reports submitted to the
Department of Public Health, Palo Alto’s complaints are overall below average,
specifically in taste and odor, turbidity, and high or low pressure. Palo Alto also has
fewer outages per million gallons per day (mgd) and per mile of main.
City of Palo Alto Water Utility Benchmarking Study
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Figure 4. Quality of Service Benchmarks
VI. Expense and Revenue Benchmarks
Palo Alto’s service area characteristics (specifically population size and distribution and
infrastructure age) contribute toward more costly operations. In meeting its operational
challenges, Palo Alto provides a comparatively high level of service. This level of
service comes at a cost, however, as indicated by the financial benchmarks in Figure 5.
Figure 5. Financial Benchmarks
Benchmark Palo Alto Mean
Palo
Alto vs.
Mean High Low Significance of Benchmark
Expenses
Total expenses (excl non-oper revenue)$25,903,000 $21,548,215 20%$27,088,382 $17,006,605 Magnitude of expenditures
Budgeted expenses per account $1,332 $1,013 32%$1,332 $837 Cost of providing service; lower is cheaper.
Operations
O&M cost per account $338 $288 17%$444 $150 Cost of operations.
Salary and benefits per employee $123,822 $119,191 4%$143,833 $96,667 Salary cost.
Average cost of purchased water ($/hcf)$0.17 $0.15 12%$0.17 $0.12 Supply cost.
Cost of purchased water as % of total budget 40%49%-18%58%34%Cost of supply (SFPUC and SCVWD).Recent Annual CIP (within last 10 years)$4,100,000 $2,925,000 40%$4,400,000 $750,000 Magnitude of expenditures
Current Annual Capital Improvements
Annual CIP expense $6,298,750 $4,432,725 42%$6,298,750 $2,125,000 Magnitude of expenditures
Annual CIP expense per account $324 $218 48%$370 $66
Annual CIP expense per hcf $1.05 $0.69 52%$1.11 $0.23
Annual CIP expense per employee $144,136 $101,568 42%$144,136 $41,262
Annual CIP expense per mile of main $28,761 $19,160 50%$29,975 $6,071
Annual CIP expense compared to depreciation 538%337%60%558%108%Funding depreciation
Debt service as a percent of total budget 14%7%100%14%3%Indebtedness.
Debt service, per account $184 $83 122%$184 $28 Indebtedness.
Rent as a percent of expenses 7%3%148%8%0%Revenues
Total annual revenue per account $1,489 $1,108 34%$1,489 $859 Customer cost; larger is more expensive.
Connection fee revenue as a percent of rate rev 2.4%2%42%8%0%Cost recovery from growthConnection fees per 3/4" connection $3,600 $3,825 -6%$5,726 $1,787 Contributes toward funding capital projects.
Palo Alto’s overall budgeted operating and capital expenses per account are 32% higher
than the mean. Although O&M costs per account are 17% higher, salary costs are close
to average per employee. Palo Alto’s cost of water is slightly above average because its
sole source of supply is the SFPUC and less expensive alternatives such as groundwater
are not currently being used. Palo Alto’s cost of purchased water as a percent of the
total budget is not as high because Palo Alto has other expenses (e.g., debt service, rent
paid on land for water infrastructure) that are not present to such a degree in the other
agencies’ budgets.
City of Palo Alto Water Utility Benchmarking Study
HF&H Consultants, LLC September 21, 2010 8
Palo Alto’s annual capital expenditures are higher for all of the benchmarks. The
amount by which Palo Alto’s average annual CIP currently exceeds depreciation
indicates that Palo Alto’s CIP more than keeps up with depreciation and is much higher
than the average for the group.
Palo Alto’ Water Fund pays rent to the General Fund. Other agencies have a similar
charge (although they may not characterize it as rent). Palo Alto’s charge is higher than
the mean.
Palo Alto’s annual revenues per account need to cover its higher expenses. We note
that Palo Alto’s connection fees, which produce revenue from growth to offset capital
expenses, are near average; the associated revenue is dependent on growth rates that
vary among the agencies. Revenue from connection fees can fund significant portions
of capital improvement programs, thereby taking some of the pressure off rates.
VII. Rate Benchmarks
Rate benchmarks aid in understanding the impact of costs on rates and the question of
whether rates are commensurate with costs and the level of service. For this
benchmark, there are two components: quantity charges and service charges, the sum of
which comprises the bill. A customer’s quantity charge will depend on its water use,
and the service charge depends on the size of the service. The combined structure of
these two rate components must be designed to meet the agency’s rate-making
objectives, among which are typically revenue sufficiency and water conservation.
Figure 6 graphically compares the current adopted residential quantity charges for each
of the members of the group, some of which rates have not increased recently (e.g., Palo
Alto) and some of which have increased significantly. All of the members have tiered
rates.6
Palo Alto’ rates are initially higher than the other agencies in the group but not
for demand beyond 25 hcf, at which point Mountain View’s and Redwood City’s rates
are higher. Hence, claims that “Palo Alto’s rates are the highest” are over simplify the
case.
Figure 7 provides benchmarks related to rate design, which are useful in understanding
the relationship between each member’s costs and the rate structure designed to
generate revenue to recover its costs. Palo Alto’s residential quantity charges have
fewer tiers than the average. Palo Alto’s residential tiers step up quickly, which
provides a strong price signal but the ratio of the top tier to lowest tier is not as great as
the average.
Palo Alto’s quantity charges are generally higher, but that is consistent with also having
lower service charges for the majority of its customers. For an average residential
6 Santa Clara’s minimum charge structure effectively provides the first 3 hcf at no cost; hence, the quantity charge for
its first tier is $0.00/hcf.
City of Palo Alto Water Utility Benchmarking Study
HF&H Consultants, LLC September 21, 2010 9
customer, only 6% of the bill comes from the service charge, which is well within the
California Urban Water Conservation Council’s guidelines.
Figure 7 also shows benchmarks for the service charges, which are graduated in
proportion to the size of the service. Palo Alto’s service charges are all much lower than
average (i.e., again, Palo Alto’s rates are not always the highest). Lower service charges
provide stronger price signals to encourage water use efficiency because more of the
revenue must be recovered from the quantity charge. The California Urban Water
Conservation Council guidelines call for generating at least 70% of rate revenue from
quantity charges. At 94%, Palo Alto is the highest in the group, which evidences a very
potent conservation orientation.
Figure 6. Comparison of Residential Quantity Charges
$0
$1
$2
$3
$4
$5
$6
$7
$8
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69
Qu
a
n
t
i
t
y
C
h
a
r
g
e
(
$
/
H
C
F
)
HCF Per Monthly Bill
Mountain View
Palo Alto
CWS Bear Gulch
Milpitas
Hayward
Santa Clara
Redwood City
City of Palo Alto Water Utility Benchmarking Study
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Figure 7. Rate Benchmarks
Benchmark Palo Alto Mean
Palo
Alto vs.
Mean High Low Significance of BenchmarkRates Structures - -
Quantity charge price signal - residential - -
Number of tiers 2.00 2.71 -26%4.00 1.00 Component of variable price signal.
Slope of tiers from lowest to highest ($/hcf)$0.239 $0.098 143%$0.239 $0.000 Higher slope produces stronger price signal
Ratio of top tier to lowest tier 1.42 2.06 -31%4.09 1.00 Higher ratio produces stronger price signal.
Quantity charge price signal - non-residential
Number of tiers 1.00 1.57 -36%3.00 1.00 Component of price signal.
Slope of tiers from lowest to highest ($/hcf)$0.000 $0.021 -100%$0.129 $0.000 Higher slope produces stronger price signal
Ratio of top tier to lowest tier 1.00 1.22 -18%1.99 0.90 Higher ratio produces stronger price signal.
Service charges
For 5/8 inch meter $5.00 $11.55 -57%$22.41 $5.00
For 3/4 inch meter $5.00 $14.39 -65%$27.03 $5.00
For 1 inch meter $6.50 $21.81 -70%$45.05 $6.50
For 1 1/2 inch meter $12.27 $37.68 -67%$90.10 $12.27
For 2 inch meter $19.37 $58.96 -67%$144.15 $19.37
For 3 inch meter $77.65 $135.56 -43%$270.29 $58.70
For 4 inch meter $130.60 $222.53 -41%$450.49 $92.25
For 6 inch meter $260.43 $411.49 -37%$900.97 $184.70
For 8 inch meter $383.67 $604.00 -36%$996.05 $294.05
Average monthly bills
Single-family residential - average
Monthly consumption (hcf)14 13 4%26 9 Average water use per residence.
Monthly quantity charge $72.64 $46.29 57%$105.96 $21.24 Customer cost for water.
Service: 3/4"$5.00 $14.39 -65%$27.03 $5.00 Lower charge recovers less fixed cost.
Total $77.64 $60.69 28%$124.65 $34.41 Lower is less expensive.
Quantity charge portion 94%73%28%94%47%Conservation signal; CUWCC prefers > 70%
Annual SFR bills as percent of MHI 0.74%0.67%10%0.83%0.47%Affordability; EPA threshold = 2%.
VIII. Customer Bill Benchmarks
The combination of the quantity and service charge structures yields bills for customers
that depend on their monthly water use and service connection size. Figures 8 and 9
graph bills for ranges of consumption for residential customers (assuming a 3/4”
service and monthly consumption up to 70 hcf per month7
) and non-residential
customers (assuming a 3” service and monthly consumption up to 1,000 hcf per month).
Palo Alto’s residential bills are not the highest for use below 12 hcf per month; at some
point to the right of Figure 9, Mountain View’s and Redwood City’s rates will produce
higher bills than Palo Alto’s rates.
7 In calculating residential bills, the average monthly flow per single-family residence was used for each agency.
Hence, the bills reflect both the differences in rate structure as well as the differences in average use per account.
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Figure 8. Residential Customer Bills
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70
Mo
n
t
h
l
y
B
i
l
l
(
$
)
Usage Per Monthly Bill (HCF)
Palo Alto
CW Bear Gulch
Milpitas
Hayward
Santa Clara
Redwood City
M
Mountain
View
Figure 9 shows that Palo Alto’s non-residential bills are never the highest in large part
because Palo Alto’s service charges for larger services are well below average. However,
Palo Alto’s non-residential bills are higher than the mean.
Figure 10 presents a comparison of average single-family residential water bills in
relation to the population of the agency’s service area. This graph also shows a trend
line for the group. By plotting bills versus population, it is possible to see how the size
of the agency affects its costs. As the smallest agencies in the group, Cal Water and Palo
Alto will not benefit from the economies of scale that the larger agencies receive. Palo
Alto is not the only member of the group above the trend line. The agencies below the
trend line may also benefit from other advantages, such as later development with
correspondingly younger infrastructure, which would not require as much capital
investment to maintain. It is also possible that regardless of the age of their
infrastructure, the agencies below the trend line are simply not making the investment
that is being made by those above the trend line.
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Figure 9. Non-Residential Customer Bills
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
Mo
n
t
h
l
y
B
i
l
l
(
$
)
Usage on Monthly BIll (HCF)
Mountain View
Palo Alto
Redwood City
Hayward
MilpitasCW Bear Gulch
Santa Clara
Figure 10. Population versus Average Single-Family Residential Water Bill
Palo Alto
Redwood City
Mountain View
Milpitas HaywardSanta Clara
CWS -Bear Gulch
$-
$20
$40
$60
$80
$100
$120
$140
50,000 70,000 90,000 110,000 130,000 150,000
Mo
n
t
h
l
y
B
i
l
l
Population
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IX. Findings
The purpose of this benchmarking study was to provide answers to the following
questions:
Why are CPAU water rates higher than other neighboring utilities? As a precursor to
answering this question, it is important to distinguish between the components of the
rates, some of which are not higher in Palo Alto when compared to the members in the
group. Palo Alto’s highest residential and non-residential volume charges are lower
than Mountain View’s and Redwood City’s. Moreover, all of Palo Alto’s service
charges are lower than the average.
It is also important to distinguish between rates and bills. The City’s residential volume
rates are generally higher; however, based on assumptions about the size of the
connection and average monthly water consumption at each agency, customer bills
vary. Water bills for low-use residential customers compared to the average are only
slightly higher. Water bills for high-use residential customers are lower in Palo Alto
than in Mountain View and Redwood City, but higher than the other agencies. For the
average residential customer, it is true that Palo Alto’s bills are higher than the average
for the group. Part of the reason is due to Palo Alto’s rates and part is due to Palo Alto’s
average water use.
The following benchmarks help explain why Palo Alto’s rates are generally higher than
average:
1) Palo Alto puts more staff resources and capital into maintaining and replacing its
older facilities.
2) Palo Alto’s population and water sales are below average. Economies of scale
are greater for other members of the group.
3) Palo Alto’s service area is more broadly spread with more pumping zones.
Sparser development in hillier terrain is more expensive to serve because of the
cost of constructing the infrastructure and the cost of O&M, particularly
pumping.
4) Palo Alto experiences more seasonal variation in its demand, which requires a
higher level of operating capability, particularly in operating pumping, storage,
SCADA, and water quality monitoring equipment.
5) Palo Alto provides a higher quality of service based on the lower number of
complaints received and system outages.
6) Palo Alto’s cost of water supplies is higher compared to some of the agencies that
purchase water from SCVWD, pump groundwater, and use recycled water.
7) Palo Alto’s utility pays rent for land occupied by water facilities. Some other
cities have similar, lower charges.
How does the CPAU water utility budget compare with other neighboring utilities?
The CPAU budget for FY 2009 is 20% above average in total dollars and 32% above
average when measured in terms of dollars per account. O&M and debt service are a
City of Palo Alto Water Utility Benchmarking Study
HF&H Consultants, LLC September 21, 2010 14
greater percentage of Palo Alto’s budget than average but its cost of purchased water is
smaller portion of the budget than average.
What qualitative and quantitative information explains the differences in major cost
categories (e.g., water purchase costs, operations costs, staff costs, capital costs (past,
present, and projected), transfers out)?
This question raises a number of specific points:
1) Water purchase costs – Palo Alto is currently almost entirely reliant on the
SFPUC for its water supply, with no less expensive options used at present (e.g.,
local wells or treated water from the SCVWD). The SFPUC’s cost of water will
increase steeply in the next few years before leveling off. Palo Alto has set its
rates to generate reserves in anticipation of increases in the cost of water among
other cost increases. Palo Alto also does not use significant amounts of
groundwater, which is significantly cheaper than SFPUC water. In addition,
agencies, including Palo Alto, supplement their supplies with recycled water, the
full cost of which may not be included in their water utility budgets. 8
2) Operating costs – Palo Alto’s operating costs are somewhat higher than average,
which is consistent with the higher level of service that appears to be provided
and the Palo Alto’s lower economy of scale.
3) Staff costs – Our reconnaissance level analysis indicates that while salary costs
are comparable to other members of the group, Palo Alto attributes a larger
number of staff to its water utility. As a result, Palo Alto may have higher salary
costs, although a careful review of direct and allocated staff should be conducted
to confirm this9
4) Capital costs (past, present, and projected) – Palo Alto has invested in facilities
and programs to improve its water use efficiency and reliability. By doing so,
Palo Alto has a greater margin of safety during supply shortages. It is possible in
the future that Palo Alto will be able to offset some of this investment with
revenue from the lease of its unused SFPUC entitlement to other BAWSCA
members.
.
5) Transfers out – Very little information was available about transfers out (or in) to
the general fund, reserves, or other enterprises. Further analysis should look at
transfers to determine (1) the types of transfers that are made within each water
utility (e.g., to operating and capital reserves, (2) the minimum and target
balance for each reserve within each water utility, and (3) the types of transfers
made outside each water utility.
8 More expensive recycled water is used on the golf course and Greer Park.
9 Subsequent inquiries have revealed CPAU has larger number of directly assigned staff. Other utilities tend to have
staff residing in the general fund and then the cost is allocated to the water utility.
City of Palo Alto Water Utility Benchmarking Study
HF&H Consultants, LLC September 21, 2010 15
Summarizing the key points from the benchmark categories in this report adds to the
answer:
Benchmark Category Key Findings
Service Area and Infrastructure
• Hillier topography, sparser development, and drier, hotter
climate.
• Capital investment is above average.
• Smaller size has lower economies of scale.
Water Use • Single-family use is near average
• CII use is above average.
• Overall use is average.
Operations and Maintenance • Fully staffed for meter reading, customer service, design.
• Higher peak flows.
• Less storage and more pumping.
Quality of Service • Fewer taste, odor, and pressure complaints.
• Fewer service interruptions.
Financial • Higher current O&M expenses.
• Higher historic and projected capital expenses.
• Rents charged for land occupied by water utility
These findings indicate reasons for why Palo Alto’s costs are higher and its quality of
service is superior.
How do the neighboring utilities compare with respect to the state of their respective
utility infrastructures, emergency preparedness, and reliability? Palo Alto plans to
replace its water utility infrastructure within the average service lives of the facilities.
Palo Alto has the oldest infrastructure of those agencies for which data were available,
with younger/recent growth cities having relatively new infrastructure. All agencies
are focused on replacing old infrastructure, with Palo Alto having one of the more
aggressive capital improvement programs. In some cases, agencies are or will be
converting their customer meters to automated reading technology. The overall effect is
an increased level of capital improvements that will be funded from a combination of
debt and cash.
All of the members of the group provide emergency contacts at all times. All agencies
have on-call crews that allow for quick responses to leaks. Another measure of
emergency preparedness is evidenced by the amount of daily storage that is available;
Palo Alto’s is below average but is constructing more. Palo Alto’s incidence of main
breaks, leaks, and outages is below average, which is further evidence of reliability.
What are CPAU customers getting for the extra money collected for water utility
services? The average residential customer is paying $16.95 or 28% more per month in
Palo Alto compared with other members of the group. Part of the reason is due to the
higher use by Palo Alto’s average customer: Palo Alto residents pay more for more
water. In addition to providing an above-average quantity of water, there are
indications that Palo Alto provides an above-average quality of service based on below-
average complaints and that Palo Alto’s facilities are in above-average repair.
City of Palo Alto Water Utility Benchmarking Study
HF&H Consultants, LLC September 21, 2010 16
Determining whether the above-average cost is commensurate with an above-average
level of service can be approached in various ways. For example, contingent valuation
techniques could be used to poll customers to find out if they would be willing to pay a
specified amount less for a specified lower level of service. Customers could also be
surveyed to determine their satisfaction level, as has been done by the City for the past
seven years. The most recent Service Efforts and Achievements Report notes:
Operating expense for the water utility totaled $19.4 million, including $8.4 million in water
purchases (26% more than five years ago). The average residential water bill has increased
27% over the five-year period. Average residential water usage per capita is down 9% from
five years ago. 81% of surveyed residents rate water quality as good or excellent.10
At a point when costs are climbing and demand is declining, Palo Alto’s rate payers
express a commendable level of satisfaction.
X. Concluding Remarks and Possible Next Steps
The City is one of a few California cities that provides a broad range of utility services.
In actively seeking to improve its services, the City continuously compares itself with
other municipalities. The present benchmarking study is the latest of such efforts. This
study focused on the City’s water utility, which the City’s previous studies identified as
having comparatively high rates.
Comments received on the draft report noted areas where additional work may be
required to completely answer certain questions, to provide greater detail, and to
further support conclusions. The following are some examples of these comments:
• Water losses – The low water losses reported in this study came from the most
recent published sources. City staff is aware that meter inaccuracy in the
SFPUC’s master meters is the primary cause for the low losses. Additional work
is needed to resolve this discrepancy. In addition to reviewing the underlying
meter data, meter calibration and replacement programs could also be compared
among the survey group.
• Reserves – Rates generate revenue not only for current cash flow but also to fund
operating, capital, and other reserves. Palo Alto has set its rates in anticipation of
increases in the SFPUC’s cost of water and other cost increases that may exceed
what has been done by other members in the group. Additional work is needed
to compare information on the types of reserves, fund balances, target balances,
and annual contributions to reserves.
• Non-rate revenue - This report notes that revenue from other non-rate sources
such as connection fees may provide funding for other agencies that helps hold
their rates down. Additional work is needed to determine how differences in
non-rate revenue among the survey group accounts for differences in rates.
10 Service Efforts and Accomplishments Report. City of Palo Alto. December 14, 2009. Page v.
City of Palo Alto Water Utility Benchmarking Study
HF&H Consultants, LLC September 21, 2010 17
• Confirmation - This report relies on our interpretation of information that should
be confirmed by each member in the survey group. All of the data in the
appendix could be submitted to each member for review and confirmation.
• Timeframe – It should be recognized that the analysis is sensitive to the
timeframe for which data were available. Using data for another timeframe
could lead to different findings. A more detailed investigation would use data
from multiple years, rather than for a snapshot of the most recent year (which
varied by benchmark and by agency), in order to spot any trends and to take
short-term anomalies out of the evaluation.
The conclusions reached in the current study could change if additional information
were available or time were available to confirm that our interpretation of data is
correct. Moreover, it should be recognized that the analysis is sensitive to the
timeframe for which data were available. Using data for another timeframe could lead
to different findings.
HFH Consultants, LLC
9/22/2010 1 Benchmark Matrix 7Sep10 v4
City of Palo Alto - Water Utility Benchmark Study
1. BENCHMARKS
Benchmark Palo Alto
Redwood
City
Mountain
View Milpitas Hayward Santa Clara
CWS Bear
Gulch Mean
Palo
Alto vs.
Mean High Low
Population 63,400 83,895 74,762 70,817 150,878 117,242 57,108 88,300 -28%150,878 57,108
Surface area (square miles) 26.0 35.0 12.0 13.6 62.5 19.3 45.3 31 -15%63 12
Water deliveries (million gallons per day) 12.3 10.4 11.4 11.2 18.6 22.2 13.1
Service area characteristics
Population 63,400 83,895 74,762 70,817 150,878 117,242 57,108 88,300 -28%150,878 57,108
Population growth over last ten years 8.6%1.1%-1.7%8.9%17.9%14.4%8.2%4%17.9%-1.7%
Accounts 19,443 23,110 17,229 16,463 32,382 25,481 18,329 21,777 -11%32,382 16,463
Surface area (square miles) 26.0 35.0 12.0 13.6 62.5 19.3 45.3 30.5 -15%62.5 12.0
Residents per square mile 2,438 2,397 6,230 5,207 2,414 6,075 1,261 3,717 -34%6,230 1,261
Accounts per square mile 748 660 1,436 1,211 518 1,320 405 900 -17%1,436 405
Average Temperature (deg F)58.0 59.2 58.0 48.6 58.9 59.0 57.0 2%59.2 48.6
Average annual precipitation (in) 15.37 19.81 15.80 15.04 18.03 14.03 16.35 -6%19.81 14.03
Infrastructure
Miles of distribution mains 219 265 175 203 350 295 324 262 -16%350 175
Accounts per mile of main 89 87 98 81 93 86 57 84 5%98 57
Miles of main per square mile 8.42 7.57 14.58 14.93 5.60 15.28 7.15 10.51 -20%15.28 5.60
Average age of distribution mains (years)61 33 45 43 45 34%61 33
Capital Assets (net book value)
Capital assets per account $3,288 $4,345 $2,279 $2,385 $1,541 $2,672 $5,087 $3,085 7%$5,087 $1,541
Capital assets per hcf $10.65 $19.73 $7.08 $7.18 $5.51 $6.27 $14.54 $10.14 5%$19.73 $5.51
Capital assets per square mile $2,458,500 $2,869,170 $3,271,835 $2,886,913 $798,273 $3,528,231 $2,058,424 $2,553,050 -4%$3,528,231 $798,273
Water use characteristics
Total water supply in mgd (incl losses)12.30 10.43 11.37 11.21 18.57 22.24 13.14 14.18 -13%22.24 10.43
Applied water over service area (feet)0.83 0.52 1.66 1.44 0.52 2.02 0.51 1.07 -23%2.02 0.51
Average flow per account (gpd)
Single-family residential 345 260 241 276 234 323 645 332 4%645 234
Multi-family residential 748 1,183 1,249 673 2,521 935 2,963 1,467 -49%2,963 673
Commercial/Institutional/Industrial 2,061 1,125 1,450 2,136 1,474 3,210 1,039 1,785 15%3,210 1,039
Average 603 433 606 590 483 847 688 607 -1%847 433
Flow distribution by class
Single-family residential 41.5%46.3%24.6%30.1%34.0%24.7%82.1%40.5%3%82.1%24.6%
Multi-family residential 13.6%22.3%27.2%11.0%18.0%20.5%1.7%16.3%-17%27.2%1.7%
Commercial/Institutional/Industrial 40.2%27.2%39.9%45.6%32.2%51.8%12.1%35.6%13%51.8%12.1%
Subtotal 95.3%95.9%91.8%86.7%84.2%97.1%95.9%92.4%3%97.1%84.2%
Losses 4.7%4.1%8.2%13.3%15.8%2.9%4.1%7.6%-38%15.8%2.9%
Total 100.0%100.0%100.0%100.0%100.0%100.0%100.0%
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9/22/2010 2 Benchmark Matrix 7Sep10 v4
City of Palo Alto - Water Utility Benchmark Study
1. BENCHMARKS
Benchmark Palo Alto
Redwood
City
Mountain
View Milpitas Hayward Santa Clara
CWS Bear
Gulch Mean
Palo
Alto vs.
Mean High Low
Operations and maintenance
Mgd per employee 0.28 0.34 0.32 0.36 0.49 0.36 -22%0.49 0.28
Accounts per employee 445 745 492 629 566 576 -23%745 445
Miles of main per O&M employee 8.4 17.7 12.5 10.6 14.2 12.7 -34%17.7 8.4
Mgd per O&M employee 0.47 0.70 0.81 0.56 1.07 0.72 -35%1.07 0.47
O&M employees as a percent of total employees 59%48%40%64%46%52%15%64%40%
Load factors
Peak month to average monthly demand 1.50 1.49 1.53 1.38 1.28 1.25 1.70 1.45 4%1.70 1.25
Peak month to minimum monthly demand 3.21 2.43 2.36 1.88 1.89 1.57 4.26 2.52 28%4.26 1.57
Mgd per booster pump station 2.05 1.04 2.24 2.65 0.22 1.64 25%2.65 0.22
Square miles per pressure zone 0.00 0.00 0.00 0.00 0.00 0.00 #DIV/0!- -
Square miles per booster pump 0.00 0.00 0.00 0.00 0.00 0.00 #DIV/0!- -
Days of Storage 0.85 2.04 1.50 1.45 1.51 1.23 0.84 1.35 -37%2.04 0.84
Gallons of potable storage per account 540 919 987 990 868 1,071 600 854 -37%1,071 540
Quality of service
Complaints per total mgd
Taste and Odor 0.49 1.32 0.45 0.05 0.94 0.81 -40%1.32 0.05
Color 1.22 1.14 0.80 0.48 0.40 1.01 20%1.22 0.40
Turbidity 0.33 1.50 0.54 0.00 0.04 0.60 -46%1.50 -
Worms and other 0.16 0.00 0.00 0.00 0.00 0.04 300%0.16 -
Pressure (High or Low)0.00 0.18 3.21 0.00 0.00 0.85 -100%3.21 -
Other 0.00 2.99 0.00 1.83 0.09 1.23 -100%2.99 -
Total 2.20 7.12 4.99 2.37 1.48 4.54 -52%7.12 1.48
Breaks, leaks, outages per mile of main
Per mgd 3.66 1.41 11.33 6.09 4.00 6.62 -45%11.33 1.41
Per mile of main 0.21 0.09 0.63 0.32 0.30 0.39 -47%0.63 0.09
Expenses
Total expenses (excl non-oper revenue)$25,903,000 $22,171,090 $17,762,098 $17,006,605 $27,088,382 $21,945,000 $18,961,329 $21,548,215 20%$27,088,382 $17,006,605
Budgeted expenses per account $1,332 $959 $1,031 $1,033 $837 $861 $1,034 $1,013 32%$1,332 $837
Operations
O&M cost per account $338 $444 $381 $247 $150 $192 $267 $288 17%$444 $150
Salary and benefits per employee $123,822 $143,833 $112,442 $96,667 $119,191 4%$143,833 $96,667
Average cost of purchased water ($/hcf)$0.17 $0.15 $0.16 $0.16 $0.16 $0.12 $0.15 $0.15 12%$0.17 $0.12
Cost of purchased water as % of total budget 40%34%51%51%55%58%51%49%-18%58%34%
Recent Annual CIP (within last 10 years)$4,100,000 $2,000,000 $4,400,000 $750,000 $4,000,000 $2,300,000 $2,925,000 40%$4,400,000 $750,000
Current Annual Capital Improvements
Annual CIP expense $6,298,750 $3,200,000 $3,420,000 $6,085,000 $2,125,000 $5,467,600 $4,432,725 42%$6,298,750 $2,125,000
Annual CIP expense per account $324 $138 $199 $370 $66 $215 $218 48%$370 $66
Annual CIP expense per hcf $1.05 $0.63 $0.62 $1.11 $0.23 $0.50 $0.69 52%$1.11 $0.23
Annual CIP expense per employee $144,136 $103,226 $97,714 $41,262 $121,502 $101,568 42%$144,136 $41,262
Annual CIP expense per mile of main $28,761 $12,075 $19,543 $29,975 $6,071 $18,534 $19,160 50%$29,975 $6,071
Annual CIP expense compared to depreciation 538%168%207%442%108%558%337%60%558%108%
Debt service as a percent of total budget 14%4%3%7%100%14%3%
Debt service, per account $184 $37 $28 $83 122%$184 $28
Rent as a percent of expenses 7%0%0%0%8%5%0%3%148%8%0%
HFH Consultants, LLC
9/22/2010 3 Benchmark Matrix 7Sep10 v4
City of Palo Alto - Water Utility Benchmark Study
1. BENCHMARKS
Benchmark Palo Alto
Redwood
City
Mountain
View Milpitas Hayward Santa Clara
CWS Bear
Gulch Mean
Palo
Alto vs.
Mean High Low
Revenues
Total annual revenue per account $1,489 $1,140 $1,069 $961 $859 $892 $1,348 $1,108 34%$1,489 $859
Connection fee revenue as a percent of rate rev 2.4%0.5%0.1%0.0%8.3%0.5%0.0%2%42%8%0%
Connection fees per 3/4" connection $3,600 $1,787 $4,620 $1,910 $5,726 $5,305 $3,825 -6%$5,726 $1,787
Rates Structures - -
Quantity charge price signal - residential - -
Number of tiers 2.00 4 3 2 4 1 3 2.71 -26%4.00 1.00
Slope of tiers from lowest to highest ($/hcf)$0.239 $0.093 $0.205 $0.098 $0.029 $0.000 $0.026 $0.098 143%$0.239 $0.000
Ratio of top tier to lowest tier 1.42 2.93 4.09 2.10 1.60 1.00 1.26 2.06 -31%4.09 1.00
Quantity charge price signal - non-residential
Number of tiers 1.00 2 3 1 2 1 1 1.57 -36%3.00 1.00
Slope of tiers from lowest to highest ($/hcf)$0.000 $0.129 $0.017 $0.000 $0.003 $0.000 $0.000 $0.021 -100%$0.129 $0.000
Ratio of top tier to lowest tier 1.00 1.63 1.99 1.00 0.90 1.00 1.00 1.22 -18%1.99 0.90
Service charge structure
Service charge multipliers
For 5/8 inch meter $5.00 $18.02 $5.60 $22.41 $9.00 $8.40 $12.45 $11.55 -57%$22.41 $5.00
For 3/4 inch meter $5.00 $27.03 $5.60 $23.82 $12.20 $8.40 $18.69 $14.39 -65%$27.03 $5.00
For 1 inch meter $6.50 $45.05 $11.20 $33.83 $18.50 $13.40 $24.20 $21.81 -70%$45.05 $6.50
For 1 1/2 inch meter $12.27 $90.10 $18.20 $42.67 $40.60 $24.20 $35.74 $37.68 -67%$90.10 $12.27
For 2 inch meter $19.37 $144.15 $33.90 $55.69 $71.40 $34.10 $54.13 $58.96 -67%$144.15 $19.37
For 3 inch meter $77.65 $270.29 $58.70 $149.09 $180.20 $96.60 $116.42 $135.56 -43%$270.29 $58.70
For 4 inch meter $130.60 $450.49 $92.25 $188.93 $357.00 $134.20 $204.26 $222.53 -41%$450.49 $92.25
For 6 inch meter $260.43 $900.97 $184.70 $288.32 $629.80 $263.90 $352.33 $411.49 -37%$900.97 $184.70
For 8 inch meter $383.67 $900.97 $294.05 $377.74 $871.80 $403.70 $996.05 $604.00 -36%$996.05 $294.05
HFH Consultants, LLC
9/22/2010 4 Benchmark Matrix 7Sep10 v4
City of Palo Alto - Water Utility Benchmark Study
1. BENCHMARKS
Benchmark Palo Alto
Redwood
City
Mountain
View Milpitas Hayward Santa Clara
CWS Bear
Gulch Mean
Palo
Alto vs.
Mean High Low
Average monthly bills
Single-family residential - average
Monthly consumption (hcf)14 10 10 11 9 13 26 13 4%26 9
Monthly quantity charge $72.64 $27.05 $28.81 $21.24 $30.00 $38.36 $105.96 $46.29 57%$105.96 $21.24
Service: 3/4"$5.00 $27.03 $5.60 $23.82 $12.20 $8.40 $18.69 $14.39 -65%$27.03 $5.00
Total $77.64 $54.08 $34.41 $45.06 $42.20 $46.76 $124.65 $60.69 28%$124.65 $34.41
Quantity charge portion 94%50%84%47%71%82%85%73%28%94%47%
Annual SFR bills as percent of MHI 0.74%0.74%0.47%0.58%0.83%0.66%0.67%10%0.83%0.47%
Single-family residential - half of average
Monthly consumption (hcf)7 5 5 6 5 7 13 7 4%13 5
Monthly quantity charge $33.27 $14.40 $11.78 $21.24 $34.00 $19.18 $51.90 $26.54 25%$51.90 $11.78
Service: 3/4"$5.00 $27.03 $5.60 $23.82 $12.20 $8.40 $18.69 $14.39 -65%$27.03 $5.00
Total $38.27 $41.43 $17.38 $45.06 $46.20 $27.58 $70.59 $40.93 -7%$70.59 $17.38
Quantity charge portion 87%35%68%47%74%70%74%65%34%87%35%
Single-family residential - two times average
Monthly consumption (hcf)28 21 19 22 19 26 52 27 4%52 19
Monthly quantity charge $157.00 $60.60 $66.29 $50.28 $67.40 $73.98 $228.44 $100.57 56%$228.44 $50.28
Service: 3/4"$5.00 $27.03 $5.60 $23.82 $12.20 $8.40 $18.69 $14.39 -65%$27.03 $5.00
Total $162.00 $87.63 $71.89 $74.10 $79.60 $82.38 $247.13 $114.96 41%$247.13 $71.89
Quantity charge portion 97%69%92%68%85%90%92%85%14%97%68%
- -
Multi-family residential (1 1/2" meter)- -
Monthly consumption (hcf)30 48 51 27 102 38 120 59 -49%119.81 27.21
Monthly quantity charge $104.73 -$14.67 $34.07 $21.24 $33.50 $38.36 $107.48 $46.39 126%107.48 (14.67)
Service: 1 1/2"$12.27 $90.10 $18.20 $42.67 $40.60 $24.20 $35.74 $37.68 -67%90.10 12.27
Total $117.00 $75.43 $52.27 $63.91 $74.10 $62.56 $143.22 $84.07 39%143.22 52.27
Quantity charge portion 90%-19%65%33%45%61%75%50%79%0.90 (0.19)
Commercial/Institutional/Industrial
Monthly consumption (hcf)83 45 59 86 60 130 42 72 15%130 42
Monthly quantity charge $334.62 $290.50 $341.57 $349.00 $217.63 $132.54 $164.87 $261.53 28%$349.00 $132.54
Service: 3"$77.65 $270.29 $58.70 $157.45 $180.20 $96.60 $116.42 $136.76 -43%$270.29 $58.70
Total $412.27 $560.79 $400.27 $506.45 $397.83 $229.14 $281.29 $398.29 4%$560.79 $229.14
Quantity charge portion 81%52%85%69%55%58%59%65%24%85%52%
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9/22/2010 1 Benchmark Matrix 7Sep10 v4
City of Palo Alto - Water Utility Benchmark Study
2. RATE STRUCTURES AND BILLS
Monthly Service Charge Resi Non-Resi
For 5/8 inch meter $5.00 $18.02 $5.60 $22.41 $23.64 $9.00 $8.40 $12.45
For 3/4 inch meter $5.00 $27.03 $5.60 $23.82 $25.14 $12.20 $8.40 $18.69
For 1 inch meter $6.50 $45.05 $11.20 $33.83 $35.77 $18.50 $13.40 $24.20
For 1 1/2 inch meter $12.27 $90.10 $18.20 $42.67 $45.10 $40.60 $24.20 $35.74
For 2 inch meter $19.37 $144.15 $33.90 $55.69 $58.82 $71.40 $34.10 $54.13
For 3 inch meter $77.65 $270.29 $58.70 $149.09 $157.45 $180.20 $96.60 $116.42
For 4 inch meter $130.60 $450.49 $92.25 $188.93 $199.48 $357.00 $134.20 $204.26
For 6 inch meter $260.43 $900.97 $184.70 $288.32 $304.49 $629.80 $263.90 $352.33
For 8 inch meter $383.67 $900.97 $294.05 $377.74 $398.94 $871.80 $403.70 $996.05
For 10 inch meter $383.67 $900.97 $429.15 $546.80 $577.47 $1,050.40 $498.30 $1,431.82
For 12 inch meter $640.20 $2,054.36
For 14 inch meter $2,801.39
Residential Flow Charges, Per HCF, Per month
Tier 1 0-7 $3.95 0-10 $2.40 0-3 $1.65 0-20 $1.77 0-8 $2.90 All Units $2.74 0-10 $3.65
Tier 2 7+$5.62 11-25 $3.05 4-25 $3.41 20+$3.72 9-25 $3.40 11-36 $3.86
Tier 3 26-50 $4.98 25+ $6.77 26-60 $4.25 36+$4.58
Tier 4 50+ $7.03 60+$4.65
Commercial Flow Charges, Per HCF, Per month
Tier 1 All Units $4.95 0-15 $3.05 0-20 $3.41 All Units $4.04 0-200 $3.65 All Units $2.74 All Units $3.92
Tier 2 15+$4.98 21-200 $3.67 200+$4.20
Tier 3 200+$6.77
Tier 4
Bear GulchPalo Alto Redwood City Mountain View Milpitas Hayward Santa Clara
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9/22/2010 1 Benchmark Matrix 7Sep10 v4
City of Palo Alto - Water Utility Benchmark Study
3. SERVICE AREA CHARACTERISTICS
Palo Alto Redwood
City
Mountain
View Milpitas Hayward Santa
Clara
CWS Bear
Gulch
Service Area Characteristics
Population [5]63,400 83,895 74,762 70,817 150,878 117,242 57,108
# of Households [4]28,291 29,301 33,680 19,376 48,561 44,729
Occupancy Per Household [4]2.33 2.65 2.29 3.54 3.13 2.63
Population, 1999 [5]58,400 83,000 76,025 65,000 128,000 102,500 65,830
10-year Population Increase 9%1%-2%9%18%14%-13%
Median Household Income [1]126,741$ 88,163$ 88,637$ 93,531$ 60,689$ 85,571$
Average Temperature [3]58.0 59.2 58.0 48.6 58.9 59.0
Average annual precipitation (in) [3]15.37 19.81 15.80 15.04 18.03 14.03
Number of SFPUC Connections [5]5 13 6 4 4 2 8
Area size (square miles) [5]26.00 35.00 12.00 13.60 62.50 19.30 45.30
Number of Accounts [5]
Single-family residential 14,804 18,616 11,620 12,232 27,001 17,005 16,723
Multi-family residential 2,243 1,969 2,476 1,839 1,327 4,883 76
Commercial/Institutional/Industrial 2,396 2,525 3,133 2,392 4,054 3,593 1,530
Total accounts 19,443 23,110 17,229 16,463 32,382 25,481 18,329
[1] American Community Survey, 2008
[3] 2005 Urban Water Management Plan (For each respective jurisdiction)
[4] California Department of Finance, City/County Population and Housing Estimates, 1/1/2009 (Table 2, E-5)
[5] BAWSCA 08-09 survey
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9/22/2010 1 Benchmark Matrix 7Sep10 v4
City of Palo Alto - Water Utility Benchmark Study
4. FACILITIES
Palo Alto Redwood
City
Mountain
View Milpitas Hayward Santa
Clara
CWS
Bear
Gulch
Miles of Mains [5]219 265 175 203 350 295 324
Average age, years 61.00 33.00 44.70 43.10
Number of Booster Pump Stations [5]6 10 5 7 59
Number of Treatment Plants --1
Number of pressure zones [5]8 14 3 6 37
Age distribution of mains
0-10 years 8%4%
11-20 years 9%9%
21-30 years 5%10%
31-40 years 13%30%
41-50 years 38%25%
50-60 years 25%20%45%
>70 years 2%2%
100%100%
Storage Reservoirs
Number reservoirs [5]6 12 2 5 6 7 35
Local Storage (mg) [5]10.5 21.24 17 16.3 28.1 27.3 11
Wells
Number of wells 3 7 1 5 27
Capacity (gpm)3575
[5] BAWSCA 08-09 survey
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City of Palo Alto - Water Utility Benchmark Study
5. OPERATIONS
Palo Alto Redwood
City
Mountain
View Milpitas Hayward Santa Clara CWS Bear
Gulch
Employees
Efficiency/Supply 3.00 3.00 3.00 1.00
Administrative 2.00 4.00 3.70
Engineering 7.00 2.00 4.50
Customer Service/Meter Reading 5.70 7.00 7.00 13.50
Other 2.00 14.00 15.00
O&M 26.00 15.00 14.00 33.00 20.80
Total (FTE)43.70 31.00 35.00 0.00 51.50 45.00
Sources of Supply [5]
SFPUC 100%100%86%65%100%12%89%
SCVWD 11%35%0%17%0%
Local 3%0%0%71%11%
Consumption by class (hcf) [5]
Single-family residential 2,491,120 2,358,295 1,365,679 1,645,525 3,083,003 2,682,139 5,264,948
Multi-family residential 818,496 1,136,209 1,509,045 603,880 1,632,319 2,227,045 109,867
Commercial/Institutional/Industrial 2,409,832 1,385,607 2,216,207 2,493,279 2,916,640 5,627,166 775,960
Subtotal 5,719,448 4,880,111 5,090,931 4,742,684 7,631,962 10,536,350 6,150,775
Losses 281,893 210,903 457,025 728,091 1,428,455 316,566 262,269
Total 6,001,341 5,091,014 5,547,956 5,470,775 9,060,417 10,852,916 6,413,044
Losses as a percent of total supplies 4.7%4.1%8.2%13.3%15.8%2.9%4.1%
Consumption by class (mgd) [5]
Single-family residential 5.11 4.83 2.80 3.37 6.32 5.50 10.79
Multi-family residential 1.68 2.33 3.09 1.24 3.35 4.56 0.23
Commercial/Institutional/Industrial 4.94 2.84 4.54 5.11 5.98 11.53 1.59
Subtotal 11.72 10.00 10.43 9.72 15.64 21.59 12.61
Losses 0.58 0.43 0.94 1.49 2.93 0.65 0.54
Average Daily Demand (mgd) [5]12.30 10.43 11.37 11.21 18.57 22.24 13.14
[5] BAWSCA 08-09 survey, Table 4A
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9/22/2010 1 Benchmark Matrix 7Sep10 v4
City of Palo Alto - Water Utility Benchmark Study
6. FINANCIAL
Palo Alto Redwood City Mountain View Milpitas Hayward Santa Clara CWS Bear Gulch
Revenue from rates
Quantity charge revenue 28,948,000$ 17,675,000$ 18,423,146$ 15,828,000$ 24,900,000$ 22,737,489$ 24,716,456$
Service charge revenue -$ 8,661,000$ -$ -$ 2,900,000$ -$ -$
Total rate revenue 28,948,000$ 26,336,000$ 18,423,146$ 15,828,000$ 27,800,000$ 22,737,489$ 24,716,456$
Non-Operating Revenue
Non-Operating Revenue $334,000 $295,000 $417,000 $500,000 $264,387
Connection fee revenue $682,000 $120,000 $10,000 $2,300,000 $113,000
Interest Income $1,265,000 $744,887
PILOT (franchise fees, rent)$1,900,000 $0 $0 $2,180,000 $1,167,000
Total non-operating revenue $4,181,000 $1,159,887 $10,000 $417,000 $4,980,000 $1,280,000 $264,387
Expenses
Salaries & Benefits $5,411,000 $4,458,810 $2,364,447 $5,790,743 $4,350,000
Operating & Maintenance Costs $6,563,000 $10,271,562 $6,561,190 $4,072,073 $4,846,550 $4,895,000 $4,886,474
Water Purchased $10,354,000 $7,440,718 $9,093,359 $8,722,000 $14,800,000 $12,700,000 $9,717,855
Administrative Expenses $1,474,449 $3,859,955
Transfers to the General Fund $0 $1,848,085 $741,518
Property and other taxes $497,045
Debt Service $3,575,000 $633,100 $0 $909,571
Total expenses $25,903,000 $22,171,090 $17,762,098 $17,006,605 $27,088,382 $21,945,000 $18,961,329
Net Revenue $7,226,000 $5,324,797 $671,048 ($761,605)$5,691,618 $2,072,489 $6,019,514
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City of Palo Alto - Water Utility Benchmark Study
7. CAPITAL IMPROVEMENTS
Palo Alto Redwood City Mountain
View Milpitas Hayward Santa Clara CW Bear Gulch
Main replacement
Annual historical main replacement (feet)8,000
Annual projected main replacement (feet)15,840
Capital Assets [1]12,075,000$ 20,582,045$ 4,915,623$ 4,915,623$ 4,446,473$ 2,859,744$ 4,003,286$
Land And Construction in Progress 51,846,000$ 79,838,908$ 34,346,397$ 34,346,397$ 45,445,587$ 65,235,120$ 89,243,321$
Depreciable Assets 63,921,000$ 100,420,953$ 39,262,020$ 39,262,020$ 49,892,060$ 68,094,864$ 93,246,607$
Total capital assets (net book value)1,171,000$ 1,908,781$ 1,653,293$ 1,376,544$ 1,976,578$ 979,338$ 2,177,634$
Depreciation Expense [1]2.3%2.4%4.8%4.0%4.3%1.5%2.4%
Depreciation as a percent of depreciable assets 44.3 41.8 20.8 25.0 23.0 66.6 41.0
Replacement cycle (years)$2,458,500 $2,869,170 $3,271,835 $2,886,913 $798,273 $3,528,231 $2,058,424
Capital assets (net book value) per square mile $10.65 $19.73 $7.08 $7.18 $5.51 $6.27 $14.54
Capital assets (net book value) per hcf $3,288 $4,345 $2,279 $2,385 $1,541 $2,672 $5,087
Capital Improvements $27,414,000 $3,200,000 $3,420,000 $5,300,000 $2,155,000 $2,513,000
Budgeted Capital Improvements $3,500,000
FY 04-05 $2,900,000
FY 05-06
FY 06-07
FY 07-08 $6,085,000 $2,000,000
FY 08-09 $27,414,000 $3,420,000 $2,000,000
FY 09-10 $8,173,000 $2,000,000
FY 10-11 $5,067,000 $2,000,000 $5,834,000
FY 11-12 $6,338,000 $2,000,000 $5,958,000
FY 12-13 $5,617,000 $2,000,000 $5,927,000
FY 13-14 $2,500,000 $6,463,000
FY 14-15 $2,500,000 $3,156,000
FY 15-16 $6,298,750 $3,200,000 $3,420,000 $6,085,000 $2,125,000 $5,467,600
[1] FY 2009 CAFR for each Jurisdiction, respectively
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9/22/2010 1 Benchmark Matrix 7Sep10 v4
City of Palo Alto - Water Utility Benchmark Study
8. SERVICE QUALITY
Palo Alto Redwood
City
Mountain
View Milpitas Hayward Santa Clara CWS Bear
Gulch
Complaints Reported (1)
Taste and Odor 6 15 5 1 21
Color 15 13 9 9 9
Turbidity 4 17 6 0 1
Worms and other 2 0 0 0 0
Pressure (High or Low)0 2 36 0 0
Illnesses (Waterborne)0 0 0 0 0
Other (Specify) (2)34 0 34 2
Total 27 0 81 56 44 33 0
System Problems (1)
Service Connection Breaks/ Leaks 32 4 86 -
Main Breaks/Leaks 13 12 27 89
Water Outages --2 0 -
Boil Water Orders ---0 -
Total 45 0 16 127 113 89 0
(1) From Report to the Drinking Water Program, 2008
(2) Santa Clara: hardness and entrained air.
(2) Mountain View: fluoride, NHCL2, filtrations, particle, gasket degradation and testing.
(2) Hayward: Air in Water and Solids
125
ATTACHMENT B
EXCERPTED DRAFT MINUTES OF UTILITIES ADVISORY COMMISSION Meeting of October 6, 2010
ITEM 4: DISCUSSION: Water Benchmarking Study
Senior Resource Planner Shiva Swaminathan presented the Water Benchmarking Study results to the
UAC.
Commissioner Keller asked about the City’s water losses and the relation to inaccurate master meter data.
Staff explained that Palo Alto has both internal and external master meters and has requested that SFPUC
calibrate its meter. Staff also explained that while the City’s losses were at an industry standard level,
further study will be done to see if we can learn from Santa Clara which has low lost and unaccounted for
levels.
The Commissioners and staff discussed the anticipated water increases over the next few years (7-8% per
year) and how these anticipated increases are communicated to the Council annually. Commissioner
Melton also stated that every opportunity be taken to educate the Council about increasing water rates.
Commissioner Cook asked if staff had looked at groundwater as an alternative source. Staff replied that
this had been evaluated and ruled out because the sustainable yield from the groundwater, according to a
consultant report, is only 500 acre-feet per year, or less than 5% of the City’s total usage. It can, however,
use groundwater for emergencies and during a drought.
1
Comparison Agencies
ATTACHMENT B
2
Statistical Information
2013 Consumption (in CCF)
Population Single Family Per Account Multifamily Per Unit Nonresidential
Palo Alto 66,368 2,442,016 160 741,684 69 1,913,692
Mountain View 77,839 1,338,585 111 1,376,460 80 2,250,719
Redwood City 80,875 2,252,558 119 825,507 75 1,500,632
Santa Clara 120,250 2,603,029 152 2,106,663 98 5,736,888
Hayward 151,582 2,913,392 105 1,300,217 75 2,964,826
3
Comparison Bases
Per Square Mile basis Per CCF basis Per Customer Account basis Per Mile of Main basis
Pros:
Allows cost comparisons without
being skewed by usage patterns or
characteristics of the customer
base. Helps highlight differences
in system characteristics, such as
higher density of development.
Pros:
Provides lowest
common denominator
for the costs
underlying the
volumetric rates.
Pros:
Shows financial impact on each
customer account, allowing
comparison between cities
whose customers use different
amounts of water on average.
Pros:
Allows comparison
between differently sized
cities based on system
characteristics.
Cons:
Must account for large uninhabited
areas within agency boundaries.
(Excluded in this report, due to the
help of Claire Lin, Summer Intern
with the City of Palo Alto)
Cons:
Higher water
consumption can
result in lower rates
with no change in
costs, which can hide
the underlying cost
disparities.
Cons:
Difficult to compare multi-
family and commercial
customer classes on this basis,
since multi-family and
commercial accounts vary
greatly in size and water use.
Cons:
Not all costs are related
to pipeline maintenance.
Differences in pipeline
density can obscure
underlying differences in
operational costs.
•All metrics are presented on per square mile of urban area basis to enable better comparisons
between cities
Comparison bases considered for this report
4
Water Consumption and Revenues
Collected by Customer Class
49%
26%
48%
29%
40%
15%
29%
19%
23%
22%
36% 45%
33%
48%
38%
48%
27%
49%
25%
41%
15%
28%
18%
20%
18%
38% 45%
33%
55%
41%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
PA MTV RC SC HW
Single Family Revenues Multifamily Revenues
Nonresidential Revenues Single Family Water Consumption
Multifamily Water Consumption Nonresidential Water Consumption
5
Single Family Residential Customers
Annual Bill
$253
$61 $117 $82 $68
$260
$130
$231
$86 $126
$182
$90
$114
$77 $71
$45
$22
$40
$19 $22
$417
$234
$244
$212 $245
$1,157
$537
$747
$476
$532
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
PA MTV RC SC HW
Distribution Capital Investment Distribution Operations (Non-Salary)Distribution Operations (Salary)
Non-revenue Water Water
6
Multifamily Residential Customers
Annual Bill
$105
$45 $79 $55 $63
$108
$96
$156
$57
$111
$75
$67
$77
$51
$65
$45
$22
$40
$19
$22
$146
$168
$152
$134
$224
$480
$398
$505
$316
$486
$0
$100
$200
$300
$400
$500
$600
PA MTV RC SC HW
Distribution Capital Investment Distribution Operations (Non-Salary)Distribution Operations (Salary)
Non-revenue Water Water
7
Nonresidential Customers
Annual Bill
$1,070
$414 $753 $656 $337
$1,097
$885
$1,485
$684
$599
$767
$612
$735
$618
$352
$45
$22
$40
$19
$22
$1,905
$1,722
$1,789
$1,827
$1,303
$4,884
$3,655
$4,803
$3,804
$2,613
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
PA MTV RC SC HW
Distribution Capital Investment Distribution Operations (Non-Salary)Distribution Operations (Salary)
Non-revenue Water Water
8
Total Costs per Square Mile
$728,723
$264,140 $493,984 $280,730 $211,016
$747,057
$565,444
$973,829
$293,061 $390,789
$522,762
$390,872
$481,866
$264,549 $220,705
$112,384
$60,925
$125,367
$43,272 $43,320
$1,328,659
$1,113,810
$1,199,339
$790,393 $830,317
$3,439,586
$2,395,192
$3,274,386
$1,672,005 $1,696,147
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
$4,000,000
PA MTV RC SC HW
Distribution Capital Investment Distribution Operations (Non-Salary)Distribution Operations (Salary)
Non-revenue Water Water
9
Budgeted Capital Spending
(FY 2009-2013)
* Estimated based on total budgeted in CIP budgets
$1,410,170
$634,930
$685,437
$254,740
$449,585
$1,634,686
$1,772,123
$226,214
$257,381
$362,308
$1,036,416 $287,849
$253,398
$445,472
$0 $500,000 $1,000,000 $1,500,000 $2,000,000 $2,500,000 $3,000,000 $3,500,000 $4,000,000
Palo Alto
Mountain View
Redwood City*
Santa Clara
Hayward*
Distribution Supply Recycled Water Other
10
Total Cost per CCF
$1.52
$0.62 $1.01 $0.47 $0.71
$1.56
$1.34
$1.98
$0.49
$1.32
$1.09
$0.92
$0.98
$0.44
$0.75
$3.00
$2.78
$2.70
$1.39
$2.95
$7.17
$5.67
$6.67
$2.79
$5.73
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
Palo Alto Mountain View Redwood City Santa Clara Hayward
Distribution Capital Investment Distribution Operations (Non-Salary)Distribution Operations (Salary)Water*
11
Total Cost per Mile of Main
$36,039 $18,415 $19,273 $15,428 $16,834
$36,945
$39,420 $37,994
$16,105
$31,175
$25,853
$27,250 $18,800
$14,538
$17,607
$5,558
$4,247
$4,891
$2,378
$3,456
$65,708
$77,650
$46,792
$43,436
$66,239
$170,103 $166,983
$127,751
$91,885
$135,310
$0
$20,000
$40,000
$60,000
$80,000
$100,000
$120,000
$140,000
$160,000
$180,000
$200,000
Palo Alto Mountain View Redwood City Santa Clara Hayward
Distribution Capital Investment Distribution Operations (Non-Salary)Distribution Operations (Salary)
Non-revenue Water Water
12
Total Cost per Connection
$419
$184 $229 $207 $170
$429
$394 $452
$216 $315
$301
$272 $224
$195 $178
$65
$42 $58
$32 $35
$764
$776 $557
$582 $669
$1,977
$1,668 $1,521
$1,230
$1,367
$0
$500
$1,000
$1,500
$2,000
$2,500
Palo Alto Mountain View Redwood City Santa Clara Hayward
Distribution Capital Investment Distribution Operations (Non-Salary)Distribution Operations (Salary)
Non-revenue Water Water
FINAL MINUTES
Finance Committee Special Meeting
Minutes 4/15/2014
FINANCE COMMITTEE
FINAL EXCERPT
Special Meeting
Tuesday, April 15, 2014
5.Discussion of Water Utility Benchmarking Studies and Future Work
Plan.
Valerie Fong, Utilities Director noted the Agenda Item was for discussion
only. Staff wished to inform the Finance Committee (Committee) regarding
their plans to conduct additional studies. Committee input regarding topics
to review would be appreciated.
Lalo Perez, Director of Administrative Services and Chief Financial Officer
added that the Committee requested Staff return with more information.
Jon Abendschein, Senior Resource Manager reported that Staff provided
summaries of two benchmarking studies conducted over the last few years.
The first was a 2010 study that concluded in 2010. The study reviewed six
comparison agencies and publicly available information and conducted
interviews with staff at those utilities. The City had a higher replacement
cost for facilities and higher Operations and Maintenance (O&M) costs
because Palo Alto's facilities were substantially older than neighboring
agencies' facilities. The consultant discussed the characteristics of the City's
service territory and said Palo Alto was geographically spread out, it had
more hilly terrain and was more seasonally varied. Those characteristics
required a higher level of operating capability and higher expenses. The consultant noted a higher quality of service, for example, a lower number of
outages and fewer complaints. The second survey was an organizational
assessment focused on all Palo Alto utilities, which included a benchmarking
study of Palo Alto Utilities against utilities nationwide. The second study also
found higher O&M expenses. Palo Alto also had more Full Time Employees (FTE) per unit of water delivered than other utilities. The study cautioned
that this measure was affected by the fact that the City directly allocated
administrative FTEs to the Water Fund; whereas, other utilities utilized an
indirect allocation. Staff also reviewed the Fiscal Year (FY) 2012 Bay Area
Water Supply and Conservation Agency (BAWSCA) annual survey and FY
2012 financial statements for comparison cities. Palo Alto residents did have
higher water use per capita than other BAWSCA agencies. Climate and
property characteristics explained the higher usage. The City's older system
ATTACHMENT C
FINAL MINUTES
Finance Committee Special Meeting
Minutes 4/15/2014
resulted in higher O&M and Capital Improvement Program (CIP) expenses.
Staff presented their preliminary analysis to the Utilities Advisory
Commission (UAC), which recommended that Staff complete a more in-
depth analysis. Over the summer Staff planned on performing an in-depth review of data from neighboring cities. The City's rates were higher than
many comparison agencies because of the higher cost of Hetch Hetchy
water. However, some comparison agencies also utilized Hetch Hetchy
water. The question was why the City's costs were higher than the costs of
comparison agencies who used Hetch Hetchy water. One explanation was
that the City was delivering a higher level of service to its customers.
Ideally Staff determined methods to modify costs such that rates were
competitive with comparison agencies' rates. As much of the needed
information was not public record, Staff had to rely on cooperation from
neighboring agencies to obtain data.
Garth Hall, Utilities Advisory Commissioner indicated the UAC agreed with
the next steps that Staff identified and agreed that Staff was halfway
through an important exercise. Palo Alto was known as having higher water
rates. Substantive comparisons of these topics produced much needed
information.
Council Member Holman noted each comparison city was larger than Palo
Alto in terms of population. It appeared as though the City was not
comparing its utility with a comparable population.
Mr. Abendschein explained that each utility was different, and the ones listed
were the closest comparators to Palo Alto.
Council Member Holman felt the City was making an argument that suited its
purpose.
Mr. Abendschein reported economy of scale was not the only factor in any of
the benchmarking studies. There were many other factors discussed in the
comparison of Palo Alto to other utilities.
Council Member Holman requested clarification of the statement that Palo
Alto experienced more seasonal variation in demand, which required a higher level of operating capability.
Mr. Abendschein indicated Palo Alto lot sizes tended to be larger than in
other cities, resulting in more seasonal irrigation.
Council Member Holman interpreted seasonal variation as different weather.
Seasonal variation did not seem logical when reviewing the comparison
cities.
Mr. Abendschein stated there was a great deal of hidden information in the
FINAL MINUTES
Finance Committee Special Meeting
Minutes 4/15/2014
words seasonal variation. Seasonal variation included the peakier loads
associated with larger lot sizes and slightly warmer and dryer microclimate
for Palo Alto
Council Member Holman requested Staff compare Palo Alto to entities that
purchased water from Santa Clara Valley Water District. Palo Alto did have
more FTEs per unit of water; however, Palo Alto provided very good utility
services. She suggested Staff determine whether service would suffer if
there were fewer FTEs. She was interested in a comparison of salary and
benefit costs to other BAWSCA agencies. The next steps needed to include
analysis of the allocation of costs between residential and non-residential
customer classes. The presentation mentioned a cost comparison of
BAWSCA agencies; however, she did not find a comparison related to
allocation.
Ms. Fong remarked that the presentation was an attempt to provide a broad
overview. The Staff report indicated that Staff would ask that question.
Council Member Burt inquired whether Staff intended to determine the
degree to which direct allocation of administrative services affected the cost
per unit delivered.
Mr. Abendschein advised that was the ideal next step. Staff intended on
performing that analysis to the extent that the information was available.
Council Member Burt noted in the 2010 report that Palo Alto's percentage of
lost and unaccounted for water aligned with the industry average of eight to
nine percent; however, Santa Clara County's rate was extremely low. The
2010 benchmark study indicated that factor could be a significant cause for
Santa Clara County's lower water rate.
Mr. Abendschein agreed it could make some difference; however, there were
many factors to consider.
Council Member Burt did not believe a single factor would explain the entire
rate difference. He asked if the purchase of water accounted for half of the
City's costs.
Mr. Abendschein indicated by 2020, water purchases would total approximately half of costs.
Council Member Burt stated three to four percent of total cost was not
insignificant but it could be 10 percent of the difference in cost.
Mr. Abendschein recommended the Committee use caution regarding
outliers and measurement quality.
Ms. Fong reported Staff had some of the same questions as the Committee.
FINAL MINUTES
Finance Committee Special Meeting
Minutes 4/15/2014
That was one question Staff wanted to investigate.
Council Member Burt assumed the economics of recycling wastewater for
irrigation had improved drastically and would become even more economical
by 2020. He asked if Staff would analyze that as a factor in the City's higher
water rates and whether use of recycled wastewater helped close the gap in
rates.
Ms. Fong was not sure a recycled water project was financially viable on its
own. A recycled water project relied on grants. However, Staff said they
would review use of recycled water as a factor.
Council Member Burt recalled that the Santa Clara Valley Water District
volunteered to participate in the City's recycled water project. The
economics were going to be very different in 2020. He requested Staff
include that as a topic for analysis. He wanted a clear explanation of the
respective cost impacts of having storage for emergency water supply and
serving the customers in the foothills area. Staff indicated costs were higher
because the City had to store water. The report needed to state costs were
higher because the City stored water for emergencies and other cities did
not. That comparison was not provided either. He preferred Staff not utilize
the table in the recent benchmarking study because the casual reader might
misread the benchmark on net revenue and think it was a bragging point.
With respect to the accelerated main replacement program, he asked if the
rate of spending would need to continue or would it end once replacement
was complete.
Mr. Abendschein advised that the study of the distribution system would
address the rate of replacement.
Council Member Burt requested an explanation as to why Menlo Park or San
Carlos were not utilized as comparators.
Mr. Abendschein reported the 2010 benchmark study did include Menlo Park.
Council Member Burt asked if Menlo Park would be included in the next
evaluation and how the City compared in 2010.
Mr. Abendschein would need to review the study to answer that question.
Council Member Burt generally recollected that Palo Alto had higher rates
than Menlo Park; yet, Palo Alto had a better economy of scale.
Mr. Hall remarked that Palo Alto was more advanced than many other
utilities in terms of pipe replacement programs. There was a general
consensus among water utility professionals that cities had neglected
replacement programs. When Staff began benchmarking, it would be helpful
to have some type of assessment of where other cities were in terms of
FINAL MINUTES
Finance Committee Special Meeting
Minutes 4/15/2014
replacement. Many utilities utilized bond financing for capital programs,
while the City utilized cash.
Council Member Burt believed the City needed to convey the value of line
replacement to the community.
Chair Berman inquired whether the Hayward designations of outer versus
inner meant a more concentrated population in a smaller geographic area.
Mr. Abendschein explained that a different set of rules applied to water
utilities selling water outside their boundaries. Hayward essentially acted as
a private water seller to people outside their service territory, and the utility
charged those customers higher rates.
Vice Mayor Kniss left the meeting at 9:23 P.M.
CITY COUNCIL MEETING
__05/18/2017__
[X] Placed Before Meeting
[ ] Received at Meeting
Item #_9_
City of Palo Alto
M E M O R A N D U M
TO: Finance Committee
DATE: May 17, 2017
SUBJECT: FY 2018 Budget Wrap‐up Memorandum
Executive Summary
This memorandum includes additional information pertaining to the Fiscal Year 2018 Proposed Budget,
summarizes changes to the City Manager’s Fiscal Year 2018 Proposed Budget, brings forth
recommended actions to revise the Fiscal Year 2018 Proposed Budget, and responds to questions raised
by the Finance Committee during previous budget hearings. Please refer to the table of contents below
for specific items.
Contents
1)ADDITIONAL INFORMATION PERTAINING TO THE FISCAL YEAR 2018 PROPOSED BUDGET ................ 2
2)CHANGES TENTATIVELY APPROVED BY THE FINANCE COMMITTEE ..................................................... 8
3)WRAP‐UP DISCUSSION OF OUTSTANDING ISSUES FROM PRIOR BUDGET HEARING MEETINGS &
ADDITIONAL CHANGES RECOMMENDED ................................................................................................... 10
Staff Recommended Changes to Operating Budget .............................................................................. 10
Budget Process Parking Lot Summary ................................................................................................... 11
Additional Information Pertaining to Parking Lot Issues .................................................................... 12
Changes to the FY 2018‐2022 Capital Budget Publication ..................................................................... 14
Staff Recommended Chages to the Capital Improvement Budget ..................................................... 15
FY 2018 Municipal Fee Schedule ........................................................................................................... 16
FY 2018 Citywide Summary of Revenues and Expenses ........................................................................ 16
4)SUMMARY OF MAY 2017 FINANCE COMMITTEE MEETINGS REGARDING FY 2018 BUDGET ............. 17
Finance Committee Tentative Motions ................................................................................................. 17
Related Memos Distributed At Places ................................................................................................... 18
Future Follow‐up Items .......................................................................................................................... 18
5)LIST OF ATTACHMENTS ....................................................................................................................... 19
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1) ADDITIONAL INFORMATION PERTAINING TO THE FISCAL YEAR 2018 PROPOSED BUDGET
During the Finance Committee hearings, requests for additional information were made by the
Committee members. This section provides the additional information requested by the Finance
Committee and/or provided at staff’s behest in regards to the Fiscal Year 2018 Proposed Budget.
City Attorney’s Office Outside Counsel versus In House Counsel (Requested 5/2/2017 by CM Tanaka)
On May 2nd, the Finance Committee requested staff to use no more than half a day’s work to prepare
information describing the workload and budget allocations of in‐house versus outside counsel,
including comparisons with other cities. Attachment A presents background information on the use of
in‐house attorneys vs outside counsel, including a breakdown of the usual types of duties and functions
assigned to each. In general, in‐house staff is used for the regular ongoing legal work, due to both cost
considerations and a need for responsive service. Outside counsel is often used for litigation matters,
affording the ability to rapidly staff up and down in response to litigation developments.
Benchmark City of Palo Alto with Menlo Park and Mountain View (Requested 5/2/2017 by CM Tanaka)
Displayed below are total revenue and total expenditure benchmarks per capita with both the City of
Menlo Park and the City of Mountain View. Expense and Revenue data was obtained from the most
current published budget available for all three cities, the Fiscal Year 2017 Adopted Budgets. Population
data was obtained from the
US Census Bureau, which
provided the most current
population as of July 1st
2015. Daytime population
was obtained from
www.city‐data.com.
Population Type Menlo Park
Mountain
View Palo Alto
Population (US Census Jul 1, 2015)33,449 80,435 66,853
Daytime Population (Daytime www.city‐data.com)52,028 122,465 129,975
There are significant differences between cities in the services delivered to the public, the
means/methods of delivery, and community priorities. These unique characteristics result in major
differences between the categories and methods used to aggregate data. In the attempt to strike a
balance between normalizing the data for proper comparison and maintain proper representation, the
General Fund was focused on as it contained the most overlapping characteristics. These figures reflect
decisions that have been made by the respective City Councils to achieve the priorities and desired
service levels to their communities.
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FY 2017 Adopted Budget: General Fund per Capita
Menlo Park
Mountain
View Palo Alto
Expenses $51,417,563 $108,433,000 $194,165,979
Expenses per Capita $1,537.19 $1,348.08 $2,904.37
Revenues $51,596,888 $118,718,250 $195,078,254
Revenues per Capita $1,542.55 $1,475.95 $2,918.02
FY 2017 Adopted Budget: General Fund per Daytime Population
Menlo Park Mountain
View
Palo Alto
Expenses $51,417,563 $108,433,000 $194,165,979
Expenses per Capita $988.27 $885.42 $1,493.87
Revenues $51,596,888 $118,718,250 $195,078,254
Revenues per Capita $991.71 $969.41 $1,500.89
Citywide Vacancies (Requested 5/2/2017 by CM Holman)
Throughout the City, there are currently approximately 102 positions vacant, the plurality of which can
be found in the Utilities Department. Attachment B outlines the current vacancies in the City by
department and by budgeted funding source. In specific areas, “backfill” is being used to cover the
duties and is noted by an italicized job title. Backfilled could mean using higher class pay per the terms
of the appropriate Memorandum of Understanding (MOU), an overstrength position, additional
overtime, or the use of contractual dollars or temporary help to accomplish the workload associated
with the vacant position.
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Print & Mail Fund Contractual Services Increase (Requested 5/2/2017 by CM Tanaka)
In FY 2017 the Adopted Budget Contract Services expense for the Print and Mailing Services Fund was
$114,711 and is recommended to be increased by $134,931 in FY 2018 to $269,642.
The $134,931 increase is for the ARC copier contract, a newly awarded contract, which replaces the
previous contract for copiers with Toshiba; the Toshiba contract was up for renewal. City Council
approved the ARC copier contract in November 2016 for five years (Report ID # 7046). Upon review of a
procurement analysis of cooperative purchasing agency opportunities for copier contracts from major
providers, all compared contracts would have resulted in an increase to the Toshiba contract costs.
After review, City Staff found that ARC offered the best value for the cost, feature set, and ability to
meet the City’s paperless goals. In comparison to other copier contracts that ranged from $23,297 to
$31,191 per month, ARC was selected at $28,693 per month.
Unlike other providers that charge a fixed lease cost based on limits to print volume, ARC has a service
model that allows the City to reduce costs by reducing print activity. In addition, features such as paper
or toner replacement, which then costs the City staff time to manage and maintain are not included in
low cost contracts. For example, compared to the Toshiba contract, which did not provide paper, the
ARC copier contract includes costs for maintenance and paper. As a result, Supplies and Material costs
were reduced in department budgets by a total of $100,000 to partially offset this increase in the central
contract costs. Other features such as energy efficiency, hole‐punching, color copying, and free color
scanning will support and encourage electronic document production. Over time, the new ARC copiers
will help reduce paper consumption along with costs while also helping the City meet its green goals of
reduced paper consumption. With centralized ARC copiers, the City can also better consolidate and
reduce usage of single purpose laser jet office printers, which have a higher cost‐per‐page‐printed
compared to ARC. Staff will be monitoring the costs of the ARC copier contract and if the costs are more
than anticipated staff can end the contract at any time with advanced notice as allowed by the contract
terms.
The Finance Committee also asked about the volatility of the costs in prior years in the Contract Services
expense category as outlined in the table below.
Printing and Mailing Fund
Dollars by Expense Category
FY 2016
Adopted
Budget
FY 2016
Actuals
FY 2017
Adopted
Budget
FY 2018
Proposed
Budget
Contract Services $165,511 $34,411 $114,711 $249,642
Contract services in this fund are very dependent on the printing activity needs of the City. In addition
to the on‐site print shop services, previously the print shop would coordinate the use of outside printing
vendors for jobs they were unable to complete either due to capacity or not having the necessary
equipment to complete it. The coordination of the use of outside printing vendors was decentralized in
FY 2016, resulting in these cost no longer appearing in this fund but directly in Department’s operating
budget expenses. As a result, significantly lower than budget expenses occurred in FY 2016. The FY 2017
Adopted Budget was reduced by approximately $50,000 to reflect the experiences of FY 2016 and the
decentralization of this activity.
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Internal Services Funds and how they work (Requested 5/2/2017 by CM Fine)
The diagram below provides a visual representation of the funding mechanics of internal service funds
(ISF). This example reflects the primary funding mechanism for the Vehicle Replacement & Maintenance
Fund (“Vehicle Fund”) and illustrates the flow of funds from various other City funds and City
departments to the ISF. The departments and funds contributing to the Vehicle Fund are detailed in blue
on the far left. 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 $1.7
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.
City Manager’s Office Economic Development Recruitment (Requested 5/2/2017 by CM Holman)
A copy of the recruitment brochure for the Economic Development Director position from 2010 was
requested. The City’s retention schedule for recruitment files is 3 years; therefore the brochure and
recruitment details are no longer on file. However, please find Attachment C, a job description which
was updated for the 2010 recruitment and was used as a basis for the brochure. Note that the position
was classified as a Manager (rather than a Director) and reported to a Deputy City Manager. For
reference, the Economic Development Manager did not supervise staff and was paid at approximately
the same salary range as the Budget Manager and the Chief Planning Official, or approximately $167,000
at the top of range.
ASD General Fund
$0.06 M (0.71%)
CSD General Fund
$0.6 M (6.75%)
DSD General Fund
$0.29 M (3.28%)Allocated Charges $1.18 M
Fire General Fund
$1.69 M (19.04%)Contract Services $0.51 M
Library General Fund
$0.01 M (0.07%)General Expense $0.07 M
PCE General Fund
$0.01 M (0.07%)Rents & Leases $0.19 M
PD General Fund
$1.37 M (15.37%)Salary & Benefits $2.29 M
PW General Fund
$1.00 M (11.27%)Supplies & Material $1.17 M
Vehicle Replacements $3.48 M
IT Internal Service Fund
$0.02 M (0.27%)
PW Enterprise Funds
$0.99 M (11.15%)
UTL Enterprise Funds
$2.85 M (32.03%)
$8.89 M
$8.89 M
EXPENSES
Allocated Charges to
Departments for Vehicle
Replacement & Maintenance
REVENUE
Allocated Charges to Departments for
Vehicle Replacement & Maintenance Vehicle Replacement & Maintenance Fund
Subtotal Enterprise
and Other Funds
$3.86 M (43.47%)
Subtotal General Fund
$5.03 M (56.53%)
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Human Resources Grievances and Hotline Complaints Metrics (Requested 5/2/2017 by CM Holman)
Please see the charts below that provide an overview of the Employee Relations caseload for FY 2016
and FY 2017. Note that
Employee Relations is one
division in Human Resources
and the chart does not reflect
other significant HR activities,
such as: 285 recruitments, 80
active workers comp cases,
4,800 Personnel Action Forms
processed, 294 health open
enrollment changes, and 31
retirements handled in the fiscal year.
The City Auditor, who oversees the City’s Fraud, Waste and Abuse Hotline, provided a presentation of
the Hotline to the Policy and Services Committee on March 28, 2017. Attachment D is a copy of the City
Auditor’s power point presentation, along with a link to the most recent
report: http://www.cityofpaloalto.org/civicax/filebank/documents/57007
The City Auditor’s report provides the following summary by year:
City Employees to Human Resources Staffing Ratios (Requested 5/2/2017 by CM Tanaka)
Staff was asked to comment on the ratio of HR to City employees in Palo Alto as compared to Mountain
View. Upon further research, it was noted that the City of Mountain View’s HR count did not include 2.0
FTE’s budgeted in Finance for Risk Management and Workers’ Compensation. A more accurate
comparison is included below, along with comparisons to other local agencies. According to the Society
of Human Resources Management (SHRM), the typical staffing ratio in the private sector is 75‐100
employees to 1 HR staff. In general, public sector requires more staffing in HR, based on factors such as
a unionized environment, management of a Merit Rules system, oversight of complex benefits
regulations and pension plan, and specialized support required for Public Safety personnel. The staffing
analysis indicates that Palo Alto’s ratio compares favorably to other public agencies in the area.
FY2016 –New Cases FY2017 –New Cases
Grievances/Arbitrations 9 Grievances/Arbitrations 9
Meet and Confer 8 Meet and Confer 12
Outside Charges
(DFEH/PERB/EEOC)
4 Outside Charges
(DFEH/PERB/EEOC)
5
Formal Investigations 11 Formal Investigations 6
Employee Relations Cases 13 Employee Relations Cases 11
Total 45 Total 43
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Local Agencies ‐ City FTE to HR Ratio
Source: FTE's from latest Adopted or Proposed Budget as published on the Agency website
Agency City FTE HR FTE HR Ratio Notes
City of Santa Clara 1,071.0 15.00 71:1
City of Redwood City 565.9 8.00 71:1 Does not include Assistant Director who oversees HR
City of Mountain View 603.4 9.50 64:1 Includes 2.0 positions in Finance for Risk Management;
does not include Assistant Director who oversees HR
City of Palo Alto 1,058.0 17.25 61:1
City of Milpitas 340.0 6.00 57:1
City of Fremont 901.3 16.25 55:1 Includes 2.0 positions in City Attorney's Office for Risk Mgmt
and Workers Comp
City of Sunnyvale 901.0 20.00 45:1 City FTE includes combined Police and Fire (Dept of Public
Safety)
City of Alameda 512.0 11.70 44:1 Includes 1.0 Senior HR staff funded in Utilities and 2.7 positions
in the City Attorney's Office for Risk Mgmt and Workers Comp
Note: Excludes Councilmembers and Seasonal/Hourly Employees
Contingent Accounts: historical budget and usage (Requested 5/2/2017 by CM Tanaka)
The annual adopted budget includes six contingent accounts totaling $725,000 annually. These accounts
are typically used for unanticipated events and initiatives throughout a given year. In addition to
contingent accounts, the City typically approves establishing various reserves for specific purposes such
as a salary reserve for labor negotiations or a Sustainability Reserve for the implementation of
sustainability initiatives. Attachment E outlines the last three years of both contingent accounts and
reserves that have been budgeted in the Non‐Departmental section of the annual operating budget.
There are two distinguishing factors of reserves and contingent accounts: 1) contingent accounts are
appropriated annually whereas reserves are typically one‐time in nature, and 2) contingent accounts can
be used with written authorization of the City Manager as outline in Municipal Code Section 2.28.060
whereas reserves require a budget amendment ordinance and thus City Council approval.
Citywide Code enforcement Estimates Revenue implications (Requested 5/9/2017 by CM Holman)
Staff does not believe that a greater use of fines and penalties is warranted given the type of code
enforcement cases being handled and the ability to achieve compliance through other means. If the
Council is interested in increasing the cost recovery of the code enforcement function, staff would
recommend undertaking a nexus study to justify an increase in application fees to cover code
enforcement.
The City could also pursue revenues from vacation rentals with an updated vacation rental ordinance as
other jurisdictions have done. These jurisdictions have allowed a certain number of short term rentals
(i.e. days per year) by owner‐occupants as long as the owners register their properties and pay a
fee. Owners are also required to pay Transient Occupancy Tax (TOT) and violations are aggressively
enforced with fines and penalties for unauthorized rentals. Some jurisdictions have found it useful to
supplement staff with contract enforcement when focusing on this issue, so the increased revenues are
accompanied by some increased costs.
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Development In‐Lieu and Impact Fees (Requested 5/9/2017 by CM Holman)
Annually the City reports out on the City’s various development impact fees. Although in the budget
document these funds are aggregated for reporting simplicity, however, in order to comply with State
law AB 1600, for accounting purposes, these funds are segregated from other funds of the City with
interest on each development fee fund or account credited to that fund or account and used only for
the purposes for which the fees were collected. Per State law (Government Code Section 66006) each
local agency that imposes development impact fees must prepare an annual report providing specific
information about those fees. Typically this report is provided in January or February of the year
following the fiscal year end close, therefore the most recent report for Fiscal Year 2016 was approved
by City Council on February 2, 2017, City Manager Report #7386 Annual Development Impact Fees FY16
which can be found here: http://www.cityofpaloalto.org/civicax/filebank/documents/55646.
SUMC Fund: Past Present & Future (Requested 5/9/2017 by CM Holman)
On an annual basis, Staff brings forward to City Council a report that outlines activities that have
occurred during the time period in regards to the Stanford University Medical Center Fund, including
construction activities and other actions taken to fulfill the obligations of the agreement, discussion of
current and future commitments, and an accounting of funds. The most recent report, City Manager
Report #6358 Stanford University Medical Center Annual Report and Compliance with the Development
Agreement, discusses the SUMC Parties activities during FY 2015, the fourth year of the Agreement.
Staff anticipates that the FY 2016 report will be brought forward for Council review in the late June,
early August timeframe. To date, the SUMC parties have contributed $32.5 million in public benefit
funds and are anticipated to pay an additional $11.7 million upon issuance of the first hospital
occupancy permit, projected to be issued in October/November of 2017. This next phase of funds is
already allocated to the infrastructure plan. The most recent report can be found here:
http://www.cityofpaloalto.org/civicax/filebank/documents/51645.
How many spaces does valet in University Avenue free up? (Requested 5/9/2017 by CM Fine)
The current valet program parks about 50‐60 cars per day, mostly at the High Street Garage. Staff
anticipates that maximizing valet parking at the High Street, Bryant/Lytton, and Cowper/Webster
garages could theoretically increase capacity by a total of about 150 cars per day. Further, staff
anticipates that additional capacity could be added in other lots and garages (including California
Avenue) however, this expansion of the program would require the appropriation of additional funding.
Staff will evaluate the cost effectiveness of this program.
2) CHANGES TENTATIVELY APPROVED BY THE FINANCE COMMITTEE
Throughout the Finance Committee Hearings, the Committee has tentatively approved a number of
components of the City Manager Proposed FY 2018 Operating and Capital Budgets. This section
describes Finance Committee recommended changes made to the budget.
GENERAL FUND
City Auditor’s Office: On May 2, 2017, the Finance Committee tentatively approved the addition of
$20,000 to the City Auditor’s Office budget to conduct a citizen survey of resident opinions on the
quality of code enforcement. This funding will be used to augment the information received through the
Code Enforcement Audit and to help inform the audit recommendations to improve the quality of the
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5/17/2017
Code Enforcement Program. In addition, funding will provide capacity for some customized questions in
the City’s annual National Citizen Survey.
OTHER FUNDS
On May 4, 2017, the Finance Committee tentatively approved changes to the Storm Drainage Fund and
the Wastewater Treatment Fund in recognition of the recent approval of the Storm Water Management
fee in April 2017. A majority of property owners, via a ballot‐by‐mail process, established a base rate of
$13.65 per Equivalent Residential Unit (ERU) per month along with a provision that the City Council
could increase the rate on an annual basis by the local inflation rate (as measured by the Consumer
Price Index) or 6 percent, whichever is less.
Below are the recommended changes to the FY 2018 Proposed Budget, which are detailed in the At
Places Memorandum that can be found here:
http://www.cityofpaloalto.org/civicax/filebank/documents/57694.
Wastewater Treatment Fund
Staffing Realignment:
Shift 2.21 FTE to the Storm Drainage Fund, reduction of $346,648 ongoing.
Storm Drainage Fund
Operating Budget Proposals:
‐ Shift 2.21 FTE from the Wastewater Treatment (WWT) Fund, addition of $346,648 ongoing.
‐ Add 1.0 FTE Associate Engineer position and $40,000 for regulatory requirement consulting
services, addition of $188,189 total ongoing.
‐ Provide funding for a Green Infrastructure Plan related to Storm Water Management, addition
of $341,000 ongoing.
Capital Budget Proposals:
SD‐13003 Matadero Creek Storm Water Pump Station and Trunk Line Improvements
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 5 Year Total
Proposed FY 2018‐
2022 CIP (4/24/17)
$259,632 $0 $0 $0 $0 $259,632
Recommended $259,632 $2,226,000 $0 $0 $0 $2,485,632
SD‐06101 Storm Drain System Replacement and Rehabilitation
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 5 Year Total
$450,000 $465,000 $480,180 $496,551 $513,124 $2,404,855
SD‐20000 Storm Drain Pump Station to Adobe Creek
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 5 Year Total
$0 $0 $500,000 $2,000,000 $0 $2,500,000
SD‐22000 East Bayshore Road and East Meadow Drive Storm Drain System Upgrades
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 5 Year Total
$0 $0 $0 $0 $1,340,000 $1,340,000
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3) WRAP‐UP DISCUSSION OF OUTSTANDING ISSUES FROM PRIOR BUDGET HEARING MEETINGS &
ADDITIONAL CHANGES RECOMMENDED
This section outlines those items recommended by the Finance Committee to be placed in the “Parking
Lot” for further discussion and additional staff‐recommended changes to the proposed budget.
Staff Recommended Changes to Operating Budget
GENERAL FUND
A summary of the revised FY 2018 General Fund Budgets by Department can be found in Attachment F.
This chart reflects the tentatively approved adjustments thus far and adjustments recommended within
this memorandum; it does not reflect changes to items placed in the “Parking Lot”.
Reallocation of $150k from CMO to Non‐Departmental
This action reallocates the recommended $150,000 in one‐time funding from the City Manager’s Office
to the Non‐Departmental section of the FY 2018 Proposed Operating Budget. These funds are
recommended for an outside study that will help inform the path forward for the City's parking and
transportation efforts, contribute to the integration of a strategic vision across each of those efforts, and
review what organizational structure would best manage these new initiatives. Therefore, given the
citywide nature of this evaluation, funding is more appropriately aligned with citywide initiatives in the
Non‐Departmental section.
AIRPORT FUND
Tie Down Lease and Property Rental Revenues
This action increases the estimate for tie down lease and property rental revenues at the Airport that
were inadvertently cited as $1,011,509 in the FY 2018 Proposed Operating Budget by $500,000. These
revenues are associated with the anticipated sunset of the Fix Based Operator (FBO) leases in April 2017
and were anticipated in the development of the Airport Fund and were included in the 5 year financial
forecast previously provided.
RESIDENTIAL HOUSING IN‐LIEU FUND
Below Market Rate Housing Contract
This action appropriates $137,000 for contract services of Palo Alto Housing Corporation (PAHC) in the
Residential Housing In‐Lieu fund. Funds will be used for oversight of the City's Below Market Rate (BMR)
housing program including administering the sale and re‐sale of new and existing BMR owner units,
maintaining the home purchase waiting list, monitoring occupancy of BMR rental units, providing advice
and consultation to the City regarding negotiations of BMR agreements with developers, and addressing
special issues related to the program as a whole. This program is subject to City Council approval of the
contract, scheduled to be considered on June 5, 2017. This request was excluded from Fiscal Year 2018
proposals due to uncertainty of amounts, which were confirmed upon completion of an RFP in late April.
(Ongoing Costs: $137,000)
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UTILITY FUNDS
In the printing of the FY 2018 Proposed Operating
Budget, the “Capital Improvement” expense category
was inadvertently overstated due to the double
counting of salaries and benefits associated with
capital improvement projects. Therefore, in order to
reflect the lower level of expenses anticipated in FY
2018, it is recommended that the appropriated
expenses in the following funds be adjusted
downward to accurately align with the anticipated
staffing and construction costs. There is no impact to
rates or the financial forecasting in these funds, this was simply a display issue in the Proposed Budget
documents.
Budget Process Parking Lot Summary
During the budget hearings, the Finance Committee moved to make various changes to the proposed
budget primarily by moving items to the “Parking Lot” for further discussion at a future meeting. This
section outlines those items. This table is organized to include the date the action was taken, a short
description of the action that was tentatively approved, and the dollar value (if applicable). Following
the table is additional information for a few select items from the list as denoted by a “*” in the chart.
These items provide additional information requested by the Finance Committee and/or provided at
staff’s behest in regards to the items in the parking lot. Staff hopes that this additional information will
facilitate the Committee’s review, discussion, and approval of these items.
Date Dept Description GF Rev.
All
Funds
Rev. GF Exp.
All Fund
Exp
Requirements/Legal Implications:
5/2 CMO City Manager's Office Staffing
Reorganization (approved by City Council
fall 2016) and the role of economic
development
5/2 Non‐Dept Non‐Departmental Section 0 0 37,814 37,814
5/4 PW Tree Trimming Cycle Time*0 0 338 338
5/4 PW Urban Forest Master Plan*
5/4 PW Vehicle Maintenance and Replacement
Fund*
0 6,863 0 5,035
5/9 PCE YCS Funding (three year matching grants) 0 0 50 50
5/9 PCE University Avenue Parking Fund and
Transportation Management Association
(TMA)*
0 2,514 0 2,876
$0 $9,377 $38,202 $46,113
* These items have additional information provided in the following chart.
Summary of "Parking Lot" Items
($'s in thousands)
Total Parking Lot Items
TBD
N/A
Fund
Recommended
Adjustment
Electric Fund ($5,856,030)
Fiber Fund ($166,370)
Gas Fund ($2,666,977)
Wastewater Collection Fund ($2,155,768)
Water Fund ($1,395,292)
TOTAL ($12,240,437)
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Additional Information Pertaining to Parking Lot Issues
GENERAL FUND
Tree Trimming Cycle Time (Requested 5/4/2017 by CM Holman)
The Committee inquired about why staff proposed to cut tree maintenance and the cost of shortening
the proposed 10‐year cycle to either a 9‐year cycle or an 8‐year cycle. With requests for budget
reductions in FY2018, staff analyzed the three areas in General Fund in which cuts could be made
(Janitorial, Streets and Trees) and determined extending the tree trimming cycle for the next two years
of the contract would be the least impactful on the City. The proposed budget reduction ($338,220) to
extend the cycle to 10 years equates to $1.22 million for Year 2 of the contract. A 9‐year cycle would
cost $1.29 million ($262,887 reduction), an 8‐year cycle would cost $1.37 million ($177,887 reduction)
and a 7‐year cycle would cost $1.55 million in FY2018.
To reiterate impact information submitted during the FY2017 budget hearings regarding tree health, the
10‐year cycle requires removal of 12.5% of the live canopy, whereas the 7‐year cycle removes 8.75% of
the live canopy. That said, the American National Standards Institute (ANSI) A300 pruning standard
allows for up to 25% of the live canopy to be pruned in any one year, although staff recommends less.
Tree maintenance operations will be conducted in accordance with ANSI A300, ANSI Z133, and industry
best practices. In addition, city tree trimming operations are led by an International Society of
Arboriculture (ISA) Certified Tree Worker and supervised by an ISA Certified Arborist to ensure tree
health.
Urban Forest Plan: 3rd Year Initiatives & Elevation of the Office Status (Requested 5/4/2017 by CM
Holman)
The Committee inquired about the programs included in Year 3 of the Urban Forest Master Plan and
what staff can and cannot implement with existing funding and how much the margin would cost. Year 3
programs are items numbered 39‐57 listed on pages 167 ‐173 of the March 2015 publication
(Attachment G). For the purposes of this exercise, programs have been grouped into four main
categories: Community Relations/Public Input (39‐40), Development (41‐49), Solar (50‐51), and Wildlife
(52‐57). Staff anticipates being able to initiate the Community Relations/Public Input programs,
implement the Solar programs, and partially implement a couple of the Development programs with
existing FY2018 budget. The remaining Development programs and all of the Wildlife programs would
require new funding of $90,000 and $25,000, respectively, and were recommended to be deferred to
the Fiscal Year 2019 budget process pending funding availability.
In addition, the Committee inquired about elevating (or increasing the influence of) the Urban Forest
Section of the Public Works Department Public Services Division. The Urban Forester reports directly to
an assistant director within the Public Works Department reflecting a high level within the Department.
This allows the urban forestry group to have a high level of representation within the Department and
ensures that maintaining the urban forest remains a high priority to the Department and its executive
leadership, and that this message is communicated to the Council.
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OTHER FUNDS
University Avenue Parking District Fund
Transportation Management Association (TMA) funding and options for revenue offsets: (Requested
5/9/2017 by CM Fine)
The TMA has provided a high level summary of how it would use additional funding of up to $450,000
annually. The TMA anticipated that the funding would be dedicated to transit passes for low income
workers, carpool subsidies, and first/last mile solutions (e.g. parking at transit stops), and estimate they
could shift 750 people to alternate modes, thereby achieving a 14% reduction in SOV rates from the
original estimate in 2015. (See summary table below.)
TMA Proposal for FY 2018
(Goal = 14% SOV Reduction)
Mode
#
People/Passes
Cost Basis
(based on current $$) Annual Expense
Transit 200 $1,320/year per person
(average)
$264,000
Carpooling 500 (based on current costs) $150,000
First Mile/Other 50 $50,000
Total Program Costs $464,000
TMA Admin/Business Expense $160,000
Total for 2018 $624,000
In regards to funding opportunities for this additional allocation, the primary sources could be further
increasing Parking lot/garage permit fees or pursuing Measure B local street and roads funds that would
potentially start flowing to the City in Q3 of 2017. Parking lot/garage permit fees are proposed to
increase by 20% (Downtown) and 88% (Cal Ave) in the proposed budget, with the increased revenues
mostly going towards needed capital improvements. If fees were increased more, for example by 50%
(Downtown) and 100% (Cal Ave.), staff estimates that this could raise an additional $400K to $500K.
Vehicle Maintenance & Replacement Fund
Cost per vehicle (Requested 5/4/2017 by CM Holman)
The FY 2018 Proposed Capital Budget included a replacement schedule of $3.2 million citywide for
various vehicles. Attachment H displays the list of vehicles scheduled to be replaced along with their
budgeted replacement values.
Breakdown of 57 SUV and sedans (Requested 5/4/2017 by CM Tanaka)
The 57 vehicles included in the infrastructure inventory listed on page 626 of the Fiscal Year
2018 Proposed Capital Budget document are comprised of Sedans and SUVs with 20 used as
pool vehicles and 37 used as special purpose vehicles that are assigned to a department and
used in the service of a particular position’s job responsibilities. These 57 vehicles are parked
throughout the city, with 31 at City Hall, 4 at various fire stations, 2 at the plant, 4 at Elwell
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5/17/2017
Court, 1 at Cubberley, 1 at Lucie Stern Community Center and 14 at the MSC. Below is a
detailed list by fuel source:
28 Unleaded (18 Sedans and 10 SUVs)
‐ Sedans
13 Police special purpose
2 Planning & Community Environment
3 Utilities (1 pool vehicle)
‐ SUVs
3 Police special purpose
4 Fire
2 Planning & Community Environment
1 Public Works (pool vehicle)
22 CNG (22 Sedans)
‐ Sedans
2 Police special purpose
2 Community Services (2 pool vehicles)
3 Fire
6 Utilities (4 pool vehicles)
7 Public Works (6 pool vehicles)
2 Planning & Community Environment (1 pool vehicle)
5 Hybrid (4 Sedans and 1 SUVs)
‐ Sedans
2 PWD (2 pool vehicles)
2 UTL (2 pool vehicles)
‐ SUV
1 PWD pool vehicle
2 Electric (All Sedans)
‐ Sedans
1 PWD
1 UTL
Changes to the FY 2018‐2022 Capital Budget Publication
Throughout the Finance Committee meetings, various sections of the FY 2018‐2022 Capital
Improvement Plan have been tentatively approved with both the General Capital Improvement Fund
and the Utilities funds still to be reviewed on May 18, 2017. While the Finance Committee has not
placed any capital improvement items in the “parking lot,” staff recommend additional changes as a
result of new information and updates to the status of select projects. Below outlines the additional
staff recommended changes including updates to the reappropriation of funds. In addition, it transmits
the letter from the Planning and Transportation Committee (PTC).
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5/17/2017
Planning and Transportation Committee Review
On May 10, 2017, the Planning and Transportation Committee reviewed and approved the FY 2018‐2022
Capital Improvement Plan for compliance with the City’s current Comprehensive Plan. Attachment I is
the letter and additional information the PTC wished to transmit to the Finance Committee. The
transcribed minutes from the meeting are not yet availabe and will be referenced in the City Manager
Report to transmit the final budget adoption for FY 2018 in June 2017.
Staff Recommended Chages to the Capital Improvement Budget
GENERAL CAPITAL IMPROVEMENT FUND: Junior Museum and Zoo capital project
This action establishes a Junior Museum and Zoo Renovation (AC‐18001) capital improvement project
and recommends an initial approriation of funding in the amount of $706,000 offset by a reduction in
funding to the Rinconada Park Improvements Project (PE‐08001) funding in FY 2019. The Community
Services Department (CSD) is planning to move its current Junior Museum and Zoo (JMZ) exhibits and
operation to the Cubberley Community Center during Fiscal Year 2018 to vacate the current site ahead
of the JMZ Rebuild project that is expected to commence in spring 2018. Costs consists of $30,000 in
design costs for renovations at Cubberley; $376,000 in construction & contingency costs (also include
moving costs); and $300,000 in permit and inspection fee costs for the temporary reconfiguration and
operation of JMZ at Cubberley. It is anticipated that during the first six months of FY 2018, funding will
be necessary for this activity and will be needed in advance of staff bringing forward the full contruction
project for the JMZ in coordination with the Friends of the JMZ.
VARIOUS CAPITAL IMPROVEMENT FUNDS: Reappropriations
As described in the Proposed Capital Budget document and discussed during the Finance Committee
Budget Hearings, the City Council approved change in the method for accounting for capital budget
reappropriations is included in the 2018‐2022 Proposed Capital Budget Improvement Program (CIP).
Previously, any unspent capital funds carried forward from one fiscal year to the next automatically, as
long as the project was active. As a result of the October 2014 change to the Municipal Code, City
Council authorization is now required for reappropriations. The FY 2018 budget process continues this
process with the current FY 2018 Proposed Capital Budget including approximately $46.1 million in
reappropriated funds, across all funds.
In the time since the Proposed Budget figures were developed (early spring of 2017), departments have
re‐reviewed current year estimates and the reappropriation amounts built into the proposed CIP.
Additional reappropriation adjustments are recommended as part of this wrap‐up memorandum in
order to update the FY 2018 Capital Budget with current, more refined estimated activity levels in Fiscal
Year 2017.
Cumulatively, this re‐review of projects has resulted in staff’s recommendation to increase the Fiscal
Year 2018 Proposed Capital Budget by a net total of $14.8 million, from $157.2 million to $172 million,
and are recommended in the following funds:
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Fund
Recommended Fiscal Year 2018
Funding Adjustment
Airport Fund $45,000
Capital Improvement Fund $1,280,713
Electric Fund $950,865
Gas Fund $3,495,960
Vehicle Replacement Fund $400,000
Wastewater Collection Fund $448,740
Wastewater Treatment Fund (R) $7,000,000
Water Fund $1,140,717
Total All Funds $14,761,995
(R) Denotes a reappropriation of revenues as well.
These adjustments, as outlined by project in Attachment J, combined with those outlined in the
Proposed Capital Budget will ensure that funds are available at the onset of Fiscal Year 2018 for projects
that have experienced delays in the current year and will reduce the Fiscal Year 2018 Proposed budget
for projects that experienced higher than anticipated expenditure levels within Fiscal Year 2017. In
total, reappropriations of an estimated $60.9 million remain below those assumed in the FY 2017
Adopted Capital Budget of $79.8 million.
FY 2018 Municipal Fee Schedule
While the Municipal Fee Schedule for Fiscal Year 2018 will be discussed by the Finance Committee on
the 18th of May, staff wished to proactively provide additional information pertaining to the City
Manager Report #8020 FY 2018 Proposed Municipal Fee Schedule. Two At Places Memorandum are
anticipated to be distributed on the following topics and can be found referenced on the City’s Budget
website.
‐ Electric Vehicle (EV) Chargers: This memorandum recommends a new EV Charging fee be
established in order to charge for the charging of electric vehicles on City owned property such
as the Civic Center garage.
‐ Parking Permit Fees: This memorandum outlines three corrections to the Municipal fee CMR
and provides additional clarification and justification surrounding the changes in various parking
fees.
FY 2018 Citywide Summary of Revenues and Expenses
After accounting for the various tentatively approved motions and staff recommendations, this section
provides a high level summary of the status of the City’s FY 2018 proposed citywide revenues and
expenses. It should be noted, that this section does not contemplate and items in the “parking lot” at
this time.
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5/17/2017
Additionally, subsequent to the release of the FY 2018 City Manager’s Proposed budget on April 25,
2017, staff found an error in the Citywide revenues and expenses summary tables as reported in the
proposed budget document. It was identified that within these summary tables, a non‐budgeted fund
was included resulting in an overstatement of both revenues and expenses. Revenues were overstated
by $10.07 million, and expenses were overstated by $9.97 million. The chart below restates the FY 2018
Proposed citywide revenues and expenses as they would have been had this non‐budgeted fund been
excluded in the “Revised Citywide Proposed Budget (restated for Correction)” row. Once adjusting for
this, tentatively approved motions by the Finance Committee, current recommendations by staff, the
Citywide budget stands as follows:
Summary of Changes to the FY 2018 Proposed Budget Citywide
($’s in thousands)
Revenues Expenses
Citywide Proposed Budget, released April 25, 2017 $591,651 $661,774
Revised Citywide Proposed Budget
(Restated for Correction)$581,582 $651,801
Finance Committee Hearing Amendments
Tentatively Approved:
Auditor's Office Code Enforcement Survey $0 $20
Storm Drainage Fund Ballot Measure Implementation $0 $979
Staff Recommended:
Airport Tiedown Revenue Correction $500 $0
Below Market Rate Program Oversight Contract $0 $137
Utilities Capital Improvement Program Corrections $0 ($12,240)
Various Capital Reappropriations $7,000 $17,762
Citywide Proposed Revenue and Expenses
(as of May 18th Wrap‐Up)$589,082 $658,459
The FY 2017 Citywide Adopted Revenues and Expenses were $546.3 million and $641.8 million
respectively. The Citywide Proposed Revenues and Expenses as of May 18th reflect year over year
growth of 7.8% in revenues ($42.8 million) and 2.6% in expenses ($16.7 million).
4) SUMMARY OF MAY 2017 FINANCE COMMITTEE MEETINGS REGARDING FY 2018 BUDGET
Finance Committee Tentative Motions
Action Minutes to the Finance Committee Hearings to date can be found on the City’s webpage here:
http://www.cityofpaloalto.org/gov/agendas/finance/default.asp. Specific meetings are linked below.
May 2, 2017 Action Minutes: http://www.cityofpaloalto.org/civicax/filebank/documents/57763
May 4, 2017 Action Minutes: http://www.cityofpaloalto.org/civicax/filebank/documents/57762
May 9, 2017 Action Minutes: http://www.cityofpaloalto.org/civicax/filebank/documents/57862
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Related Memos Distributed At Places
Throughout the Finance Committee Budget Hearings, various memorandums were distributed “At
Places” in order to respond to inquiries made by the Committee or provide additional pertinent
information at staffs behest. In addition, summary presentations were given at each hearing providing
high level overviews of each item. Those presentations as well as the memos listed above can be
referenced on the City of Palo Alto’s Budget Office website under “FY 2018 Budget Hearings” at:
http://www.cityofpaloalto.org/gov/depts/asd/budget.asp
Below is a sumary of the topics included in the “At Places” memorandums.
May 2, 2017: http://www.cityofpaloalto.org/civicax/filebank/documents/57694
‐ Storm Water Management Fee ballot measure implications
May 4, 2017:
‐ Human Resources Allocation Process Staff Report:
http://www.cityofpaloalto.org/civicax/filebank/documents/57746
‐ Airport Fund Loan Repayment to the General Fund:
http://www.cityofpaloalto.org/civicax/filebank/documents/57742
May 9, 2017: http://www.cityofpaloalto.org/civicax/filebank/documents/57780
‐ General Fund Overtime and Salary Comparison (Citywide)
‐ Comparison of Neighboring Airport Tie down Rates and Federal Aviation Administration (FAA)
Grant Assurances
Future Follow‐up Items
During the Finance Committee hearings, the Committee voted to place topics and items in a “Longer
term parking lot” to be considered for further staff follow‐up at a later date. Below is a list of these
items through the May 2, 4, and 9th committee meetings. This list is reflective of referral items from the
Finance Committee to the City Council for direction to Staff to complete and return to the Finance
Committee at a later date.
1. Review of citywide overtime usage
2. Review of the financial reporting display of the unfunded pension liability
3. Report to City Council on the plan and implications for power redundancy
4. Review of charges for services for advanced life support and medical services calls
5. Review of daytime population cost recovery options
In addition, various items have arisen during the budget hearings that are not included in the FY 2018
Proposed Budget. These items were not included as insufficient information is available to provide a
recommended budget action at this time, however, staff does anticipate these could be brought
forward for consideration in the near term. These types of projects include but are not limited to:
‐ Cool Blocks Grant (3 year program)
‐ Consolidated parking permit and citation software management platform
‐ Automated Parking Guidance System
‐ Junior Museum and Zoo
‐ CalTrain means restriction (west side fencing)
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Memorandum
Office of the City Attorney
City of Palo Alto
Date: May 16, 2017
THE HONORABLE CITY COUNCIL
Palo Alto, California
Attn: Finance Committee
RE: Follow‐up information regarding in‐house and outside legal counsel
Dear Members of the Council:
On May 2nd, the Finance Committee requested staff to use no more than a half day’s work to
prepare information describing the workload and budget allocations of in‐house versus outside
counsel, including comparables with other cities.
Background and Comparisons
Most charter cities of Palo Alto’s size maintain an in‐house legal department and retain outside
counsel for litigation and, in some cases, other services. Comparative local jurisdictions have
legal departments containing four to eight in‐house attorneys, with an organizational ratio of
one in‐house attorney for somewhere between 100 and 200 total employees. Palo Alto has
eight in‐house attorneys, with approximately one attorney per 132 total City employees.
The City Attorney assigns work to in‐house and outside counsel based on cost and type of
assignment. In‐house counsel are significantly less costly than outside counsel. The cost of Palo
Alto’s in‐house legal department (including salaries, benefits, staff and overhead) equates to
approximately $172 per attorney hour. This compares with private attorney rates that currently
range from $195 (tort defense counsel) to $570 (highly‐specialized transactional services),
averaging approximately $330 per hour.
In‐house attorneys have greater familiarity with the City’s programs, services and priority
projects, and often superior knowledge and experience in legal sub‐fields regularly needed by
the jurisdiction. Most cities, including Palo Alto, favor in‐house counsel for regular ongoing legal
work, due both to cost considerations and responsive quality service.
Outside counsel are usually the best choice for litigation matters, which require familiarity with
court rules and practices, and ability to rapidly staff up and down in response to litigation
ATTACHMENT A
20
170517 th 0140181
developments. Most cities, including Palo Alto, assign most or all litigation to outside counsel. In
addition, despite higher hourly rates, outside counsel often provide high‐quality and cost‐
effective service for discrete transactional and advice projects requiring knowledge or
experience in sub‐fields outside of customary in‐house practice areas.
FY 2017‐2018 Palo Alto City Attorney Budget, by Functional Area
Consultation and Advisory. The majority of the City’s transactional and advice work is handled
by in‐house staff. This includes the following types of weekly tasks:
drafting and negotiating most professional services and construction contracts
drafting ordinances, resolutions and policies implementing city council and
departmental initiatives
legal guidance and documentation preparation in the land use and development arenas
legal review of all Council materials, and various reports and correspondence
intergovernmental agreements
legal compliance regarding fee and rate‐setting
legal risk management and mitigation
training and regulatory compliance
labor and employment counseling
audit support
governmental ethics, public records and public meeting laws
Projects in certain specialized areas are either assigned to outside counsel or, where in‐house
counsel are primarily responsible, outside counsel are consulted on an as‐needed basis (in
recent years, this work has constituted 15‐20% of outside counsel expenditures):
bond financing
real property acquisition
federal airport regulatory law
tax compliance advice
affordable housing regulation
federal telecommunications regulation
complex infrastructure procurement
Litigation/Claims/Dispute Resolution. Almost all litigation matters are assigned to outside
counsel. This includes suits filed in federal and state courts, as well as disputes adjudicated in
administrative agencies. 80‐85% of outside counsel expenditures are in this area.
In‐house staff attorneys supervise outside counsel, set strategy for all litigation, approve
settlements, oversee claims investigation, and prosecute code enforcement and municipal code
violations.
21
City of Palo Alto Full Time Position Vacancies
(as of May 2017)
GENERAL
FUND
ENTERPRISE
FUNDS
OTHER
FUNDS
GRAND
TOTAL
Administrative Services
Account Specialist 1.00 ‐ ‐ 1.00
Account Specialist‐Lead 1.00 ‐ ‐ 1.00
Administrative Associate III 1.00 ‐ ‐ 1.00
Assistant Director Administrative Services 0.75 0.25 ‐ 1.00
Manager Accounting 1.00 ‐ ‐ 1.00
Senior Business Analyst ‐ ‐ 1.00 1.00
Senior Management Analyst 1.60 ‐ ‐ 1.60
Storekeeper 0.20 0.80 ‐ 1.00
City Auditor's Office
Performance Auditor I 1.00 ‐ ‐ 1.00
City Attorney's Office
Senior Assistant City Attorney 1.00 ‐ ‐ 1.00
Senior Legal Secretary 1.00 ‐ ‐ 1.00
City Manager's Office
Assistant to the City Manager 2.00 ‐ ‐ 2.00
Deputy City Manager 2.00 ‐ ‐ 2.00
Community Services
Coordinator Recreation Programs 1.00 ‐ ‐ 1.00
Producer Arts/Science Programs 1.75 ‐ ‐ 1.75
Development Services
Administrative Associate II 1.00 ‐ ‐ 1.00
Building/Planning Technician 0.90 ‐ ‐ 0.90
Senior Management Analyst 1.00 ‐ ‐ 1.00
Fire
Fire Apparatus Operator 7.00 ‐ ‐ 7.00
Fire Captain 2.00 ‐ ‐ 2.00
Fire Fighter 5.00 ‐ ‐ 5.00
Human Resources
Administrative Assistant 1.00 ‐ ‐ 1.00
Human Resources Technician 1.00 ‐ ‐ 1.00
Senior Human Resources Administrator 1.00 ‐ ‐ 1.00
Information Technology
Manager Information Technology ‐ ‐ 1.00 1.00
Senior Technologist ‐ ‐ 1.00 1.00
Library
Coordinator Library Programs 1.00 ‐ ‐ 1.00
Librarian 2.00 ‐ ‐ 2.00
Manager Library Services 1.00 ‐ ‐ 1.00
Planning & Community Environment
Administrative Associate III 1.00 ‐ ‐ 1.00
Building/Planning Technician 0.10 ‐ ‐ 0.10
Manager Planning 1.00 ‐ ‐ 1.00
Planner 1.00 ‐ ‐ 1.00
DEPARTMENT/JOB TITLE
ATTACHMENT B:
Citywide Vacancies by Department by Funding Source
ATTACHMENT B
22
City of Palo Alto Full Time Position Vacancies
(as of May 2017)
GENERAL
FUND
ENTERPRISE
FUNDS
OTHER
FUNDS
GRAND
TOTAL DEPARTMENT/JOB TITLE
Police
Business Analyst 1.00 ‐ ‐ 1.00
Community Service Officer 1.00 ‐ ‐ 1.00
Police Chief 1.00 ‐ ‐ 1.00
Police Officer 6.00 ‐ ‐ 6.00
Public Safety Communications Manager 1.00 ‐ ‐ 1.00
Public Safety Dispatcher 2.00 ‐ ‐ 2.00
Superintendent Animal Services 1.00 ‐ ‐ 1.00
Veterinarian Technician 1.00 ‐ ‐ 1.00
Public Works
Administrative Associate III 0.01 0.10 0.89 1.00
Engineer 0.10 0.90 1.00
Fleet Services Coordinator ‐ ‐ 1.00 1.00
Motor Equipment Mechanic II ‐ ‐ 1.00 1.00
Program Assistant I ‐ 1.00 ‐ 1.00
Senior Industrial Waste Investigator 0.01 0.99 ‐ 1.00
Utilities
Administrative Associate II ‐ 1.00 ‐ 1.00
Assistant Director Utilities Engineering ‐ 1.00 ‐ 1.00
Business Analyst ‐ 3.00 ‐ 3.00
Customer Service Representative ‐ 1.00 ‐ 1.00
Electrician Assistant I ‐ 1.00 ‐ 1.00
Engineering Manager ‐ WGW ‐ 1.00 ‐ 1.00
Engineering Technician III ‐ 3.00 ‐ 3.00
Heavy Equipment Operator ‐ 1.00 ‐ 1.00
Lineperson/Cable Specialist ‐ 3.00 ‐ 3.00
Metering Technician‐Lead ‐ 1.00 ‐ 1.00
Power Engineer ‐ 2.00 ‐ 2.00
Program Assistant I ‐ 1.00 ‐ 1.00
Senior Resource Planner ‐ 1.75 ‐ 1.75
Substation Electrician ‐ 1.00 ‐ 1.00
Utilities Compliance Technician ‐ 1.00 ‐ 1.00
Utilities Engineer Estimator ‐ 1.00 ‐ 1.00
Utilities Field Services Representative ‐ 1.00 ‐ 1.00
Utilities Install Repair‐Welding Certified ‐ 2.00 ‐ 2.00
Utilities Locator ‐ 2.00 ‐ 2.00
Utilities Supervisor ‐ 3.00 ‐ 3.00
Utilities System Operator ‐ 2.00 ‐ 2.00
Water System Operator I ‐ 1.00 ‐ 1.00
Grand Total 57.42 37.89 6.79 102.10
ATTACHMENT B:
Citywide Vacancies by Department by Funding Source 23
City of Palo Alto
Classification Specification
Title: MANAGER, ECONOMIC DEVELOPMENT
FLSA: EXEMPT
Revision Date: 03/22/10
Reports To: Deputy City Manager Special Projects
Supervises: Yes
Purpose of Classification
The Manager, Economic Development provides overall direction of the City’s Economic Resources Planning
(ERP) program. Under general direction of the Deputy City Manager, plans, organizes and directs the
implementation activities of the ERP Program. The ERP Manager is responsible for formulating policy
recommendations, developing goals and objectives, preparing and monitoring budgets, supervising staff and
directing day-to-day operations.
Distinguishing Characteristics
The incumbent plans and assesses operational goals and objectives related to the ERP program functions. This
position is distinguished from Division Head positions in that the duties relate to programs rather than a division
of a department.
Essential Duties and Responsibilities - Essential and other important responsibilities and duties may include, but are not limited
to, the following:
Exercises independence in conformance of policies, principles, and procedures pertaining to the City’s
Economic Resources Planning program and general direction of the Deputy City Manager for Citywide
economic initiatives and programs.
Provides leadership and general direction for the Economic Resources Planning program.
Makes presentations to the City Council as requested.
Represents the Department and makes oral presentations at community meetings, inter-agency
meetings, conferences, and other events.
Reviews, prepares and presents reports on Economic Resources Planning programs and activities.
Coordinates efforts with other City departments to develop solutions to economic problems facing the
City, including project planning and scheduling.
Coordinates with other agencies and organizations on regional economic development activities.
Recommends, implements, and monitors an annual program budget to achieve program objectives.
Manages, administers, and monitors consultant contracts pertaining to program implementation;
evaluates services performed and costs for services performed by external consultants, vendors, and
contractors.
Keeps the Deputy City Manager informed of program's performance and issues vital to the City and ERP.
Advises the Deputy City Manager on economic development activities, including business assistance,
employment generation and retention, commercial project development and neighborhood commercial
revitalization.
May supervise administrative or intern positions.
Actively involved in review of existing City procedures impacting the business community.
Coordinates project activities with other City departments to provide policy support on economic
development, and business attraction, retention and expansion issues.
Acts as City liaison with representatives of professional and employer groups, the financial community,
community organizations and individuals, on issues concerning economic development and conveys
suggestions and recommendations to the Deputy City Manager.
Provides public information on the importance of business to the maintenance of the community and
City services.
Assesses economic and fiscal impact of business projects to the City and of City projects on the business
community.
ATTACHMENT C
Attachment C:
Economic Development Manager Classification Specification 24
MANAGER, ECONOMIC DEVELOPMENT
EXEMPT
03/22/10
Responsible for trouble shooting and problem solving of specific issues related to business retention
and new business recruitment.
Expedites business projects through City discretionary review and permitting processes.
Re-writes stress coordination with community business, real estate organizations, business associations,
improvement districts and others.
Conducts an on-going process of evaluation and review of program goals, objectives, strategies and
plans to ensure the long-term ability of the program to accommodate appropriate responses to new or
changing issues and opportunities.
Manages and coordinates dissemination of information and provides business assistance and targeted
outreach to businesses in order to enhance the City’s business vitality, positively impact the quality of
life, and sustain and increase City revenues.
Performs related duties and responsibilities as required.
Minimum Qualifications
Sufficient education, training and/or work experience to demonstrate possession of the following knowledge
and skills, which would typically be acquired through:
Bachelor's degree in Planning, Economics or a related field and preferably an advanced degree in Public or
Business Administration, and least three to five years of extensive, progressively responsible administrative
and supervisory experience in positions providing exposures to economic development and planning
activities.
Licensing Requirements: None
Knowledge, Skills and Abilities
Qualification to enter this position requires knowledge of the following:
Knowledge of principles, practices, trends and issues in the areas of economic development and public
administration;
Techniques of management and problem solving methods;
Programs and resources for economic development, public/private sector approaches and techniques
to stimulate and promote economic development activity;
Ability to interact effectively with the public, representatives of business, industry, other governmental
agencies and diverse community groups as well as staff, public officials and advisory boards;
Ability to communicate effectively orally and in writing;
Demonstrated ability to handle complex human and political problems;
Ability to make sound decisions in a manner consistent with the essential job functions;
Clear/thorough understanding of what business needs to be successful in the community and how City
government can help meet those needs;
Knowledge of applicable Federal, State and local laws, rules and regulations;
Supervisory principles and practices;
Familiarity with computer programs dealing with economic development data.
Qualification to enter this position requires skill in:
Skill in analyzing problems and proposing solutions; eliciting the cooperation of others; interpersonal
communication and relations.
Management skills, including ability to organize, prioritize, and evaluate work, as well as the ability to
supervise and direct staff.
Communication and interpersonal relations as applied to interaction with coworkers, supervisor, the
general public, and others.
Attachment C:
Economic Development Manager Classification Specification 25
MANAGER, ECONOMIC DEVELOPMENT
EXEMPT
03/22/10
Working Conditions / Physical Requirements
Work in an office environment; sustained posture in a seated position for prolonged periods of time.
Positions in this class typically require: reaching, standing, walking, lifting, fingering, grasping, talking, hearing,
seeing and repetitive motions.
Light Work: Exerting up to 20 pounds of force occasionally, and/or up to 10 pounds of force frequently, and/or
negligible amount of force constantly to move objects. If the use of arm and/or leg controls requires exertion of
forces greater than that for Sedentary Work and the worker sits most of the time, the job is rated for Light
Work.
JD063
The City of Palo Alto is an Equal Opportunity Employer. In compliance with the Americans with Disabilities Act, the City will
provide reasonable accommodation to qualified individuals with disabilities and encourages both prospective and current
employees to discuss potential accommodations with the employer.
Attachment C:
Economic Development Manager Classification Specification 26
POLICY AND SERVICES COMMITTEE
MARCH 28, 2017
DISCUSSION OF THE FRAUD,
WASTE, AND ABUSE HOTLINE
Office of the City Auditor
Harriet Richardson, City Auditor
BACKGROUND
•Council adopted current hotline administration
policy in May 2013, after a 10‐month pilot period
•Third‐party vendor administers the hotline; available
to employees only, 24/7/365
•Callers can remain anonymous or provide their name
•Hotline Review Committee triages all calls; makes
decision about whether to investigate
•34 calls received since hotline’s inception
2
ATTACHMENT D
27
3/28/2017
PRIMARY REASONS
FOR PROPOSED CHANGES
•Lack of clarity among employees regarding purpose
of hotline
◦Most calls do not relate to fraud, waste, or abuse
◦Several calls were various versions of two separate
issues; 11 for one issue; 2 for another
•14 calls investigated; only 2 substantiated
•Previously allowed investigating department access
to case management system; narrative not clear if
sufficient investigative work done to close case
3
PRACTICES OF OTHER
JURISDICTIONS
•Provide hotline information at new employee
orientations
•Hang information posters at key points in facilities;
update at least annually
•Create and distribute brochures/wallet cards
•Provide information on employee pay stubs 2x/year
•Conduct mandatory annual training/presentations
•Provide information in all‐employee e‐mails
4
ATTACHMENT D:
City Auditor's Fraus Waste, and Abuse Hotline Presentation 28
3/28/2017
ATTACHMENT D:
City Auditor's Fraus Waste, and Abuse Hotline Presentation
PRACTICES OF OTHER
JURISDICTIONS
•Dedicated internet/intranet pages
◦“Frequently Asked Questions” section with clear
definitions
◦Tips for filing a complaint
◦Reports on number of cases received, investigated,
outcomes
◦Descriptions of substantiated cases
•Articles in employee newsletters
•If external reporting is allowed –notices on utility bills,
booths at community events, and T.V. advertisements
5
PROPOSED CHANGES
•Clarifies:
◦Employees should report fraud, waste, or abuse that
directly relates to City activities (e.g., employee or
contractor)
◦The hotline is not only for anonymous reporting
◦Language regarding the investigative process; including
use of external investigator as needed
◦Reports to Council are done through Auditor’s Office
quarterly reports, not as an information report
6
29
3/28/2017
PROPOSED CHANGES
•Updates list of Hotline Review Committee alternate
members
•Limits access to case management system
•Added language:
◦Office of the City Auditor and Human Resources should
coordinate regarding cases appropriate for hotline vs.
Human Resources review
◦Corrective action may be taken when a case is substantiated
◦Advertising the hotline
7
OPPORTUNITIES TO IMPROVE
THE HOTLINE
•Coordinate with Human Resources regarding
employee advice line:
◦Advice line currently in beta testing
◦Advertising materials and training/presentations
can distinguish between hotline‐appropriate cases
and personnel matters/ management decision
◦Hotline Review Committee can refer callers to
advice line when appropriate
8
ATTACHMENT D:
City Auditor's Fraus Waste, and Abuse Hotline Presentation 30
3/28/2017
CONCLUSIONS
•Education is key to successful hotlines
•Hotlines may not generate a lot of calls, but the ones
they receive should be appropriate for the hotline’s
purpose
•Hotlines should be viewed as “insurance” in the line
of defense against fraud, waste, and abuse
9
FINAL SLIDE
10
Council Direction: Provide direction to the City Auditor
regarding methods for advertising the hotline
Motion: Recommend that the City Council accept the
proposed changes to the City Employee Fraud, Waste, and
Abuse Hotline Administration Policy
ATTACHMENT D:
City Auditor's Fraus Waste, and Abuse Hotline Presentation 31
Contingent Accounts
FY 2015
Budget
FY 2015
Actuals
FY 2016
Budget
FY 2016
Actuals
FY 2017
Adopted
FY 2018
Proposed
City Manager* 250,000 43,540 250,000 161,125 250,000 250,000
City Council 250,000 250,000 105,000 250,000 225,000
City Attorney 250,000 205,000 100,000 100,000 100,000 100,000
Human Resources 50,000 50,000 50,000 50,000 50,000
HSRAP ‐ Emerging Needs ‐ ‐ ‐ ‐ 50,000 50,000
Innovations & Special Events 50,000 33,633 50,000 43,041 50,000 50,000
Sub‐Total Contingent Accounts:850,000$ 282,173$ 700,000$ 459,166$ 750,000$ 725,000$
Reserve Accounts
FY 2015
Budget
FY 2015
Actuals
FY 2016
Budget
FY 2016
Actuals
FY 2017
Adopted
FY 2018
Proposed
Shuttle Service Reserve 1,000,000
Cubberley Covenant Not to Develop Reserve 1,917,356
TMA Reserve 150,000 150,000 ‐ ‐ ‐ ‐
Planning and Transportation Reserve ‐ ‐ 500,000 500,000 500,000 ‐
Sustainability Reserve ‐ ‐ ‐ ‐ 250,000 ‐
Budget Uncertainty Reserve ‐ ‐ ‐ ‐ 2,000,000 ‐
FY 2018 Operations Reserve ‐ ‐ ‐ ‐ ‐ 500,000
Salary Reserve 2,737,960 ‐ 1,647,599 1,520,392 400,000
Sub‐Total Reserves: 5,805,316$ 150,000$ 2,147,599$ 2,020,392$ 2,750,000$ 900,000$
*As part of the FY 2015 Mid‐Year Budget report, $112,356 was used from the BSR to offset previously incurred expenses from the City Manager's
Contingency, including $25,000 for the "Know Your Neighbors" program, and $87,356 for Ada's Café. If these costs had not been offset, the total use of the
contingency would have been $155,896.
Non‐Departmental Contingent Accounts and Reserves
ATTACHMENT E
32
Department
FY 2015
Actuals
FY 2016
Actuals
FY 2017
Adopted
FY 2018
Proposed
FY 2018
Change $
FY 2018
Change
Administrative Services 7,133 7,497 7,798 8,033 235 3.0%
City Attorney 2,586 2,796 3,179 3,356 177 5.6%
City Auditor 1,100 1,112 1,221 1,301 80 6.6%
City Clerk 1,079 1,001 1,370 1,374 4 0.3%
City Council 361 430 501 500 (1) ‐0.2%
City Manager 2,365 3,097 2,882 3,158 276 9.6%
Community Services 23,042 24,272 25,390 27,454 2,064 8.1%
Development Services 9,893 10,665 12,169 12,540 371 3.0%
Fire 26,191 27,553 28,947 31,774 2,827 9.8%
Human Resources 3,263 3,559 3,357 3,757 400 11.9%
Library 7,980 7,960 8,992 9,446 454 5.0%
Non‐Departmental 13,722 6,235 10,139 8,435 (1,704) ‐16.8%
Office of Emergency Services 1,169 1,044 971 1,039 68 7.0%
Office of Sustainability 496 495 499 524 25 5.0%
Planning and Community Environment 7,434 8,880 8,768 8,452 (316) ‐3.6%
Police 34,559 35,666 38,137 42,333 4,196 11.0%
Public Works 13,274 14,326 16,224 17,013 789 4.9%
Sub‐total Departments: 155,647$ 156,588$ 170,544$ 180,489$ 9,945$ 5.8%
Transfer to Infrastructure 21,610 29,366 18,486 24,677 6,191 33.5%
Operating Transfers‐Out 2,606 5,095 5,136 4,885 (251) ‐4.9%
Grand Total: 179,863$ 191,049$ 194,166$ 210,051$ 15,885$ 8.2%
General Fund Expenses By Department
(Revised as of May 18, 2017)
ATTACHMENT F
33
#
Description may be
abbreviated; for complete
language, see "Goals, Policies,
& Programs."Ch
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1
Ye
a
r
2
Ye
a
r
3
Ye
a
r
4
Ye
a
r
5
Ye
a
r
6
Ye
a
r
7
Ye
a
r
8
Ye
a
r
9
Ye
a
r
1
0
Source / Notes
Program Orgazational & Logistical Needs Fiscal Needs & Benefits
Pe
r
s
o
n
n
e
l
($
1
,
5
8
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
39
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r
Pe
r
s
o
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n
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l
($
1
5
,
8
0
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
40
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r
s
o
n
n
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l
($
7
9
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
41
Ot
h
e
r
Ye
a
r
3
Year 3 programs 39 and 40 focus on public participation in urban forest policy.
2.
A
.
i
i
i
.
ye
s
Al
l
Ne
e
d
s
Be
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f
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s
ye
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an
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s
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,
ne
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,
ne
x
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s
…establish a recurring forum
that provides the community
an opportunity to
communicate with staff and
members of the decision
making bodies about tree
concerns and ideas.
es
t
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3.
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.
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4.
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.
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B
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m
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Consider development
requirements such as no net
loss of canopy or minimum
tree plantings (related to
Policy 1.G and related
programs.)
Work with the Sustainability
Plan team to evaluate the
establishment of an oversight
group (elected or appointed
by the City Council), to
investigate and comment on
the impact of projects on the
urban forest and overall
ecosystem.
PW
D
,
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,
D
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Year 3 programs 41 through 48 focus on design standards relative to canopy density and composition.
City of Palo Alto Urban Forest Master Plan Implementation Plan
ATTACHMENT G
34
#
Description may be
abbreviated; for complete
language, see "Goals, Policies,
& Programs."Ch
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2
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3
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4
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5
Ye
a
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6
Ye
a
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7
Ye
a
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8
Ye
a
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9
Ye
a
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1
0
Source / Notes
Program Orgazational & Logistical Needs Fiscal Needs & Benefits
Pe
r
s
o
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l
($
3
,
1
6
0
)
Development Services
42
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5
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0
0
0
)
Development Services
Pe
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s
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n
e
l
($
1
,
5
8
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
43
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r
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s
o
n
n
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l
($
1
,
5
8
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
44
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3
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f
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f
i
t
s
1.
G
.
i
.
Develop canopy thresholds—
possibly based on zoning and
land use goals of the
Comprehensive Plan…
ye
s
ye
s
an
a
l
y
s
i
s
,
n
e
x
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p
s
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an
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s
PW
D
,
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&
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,
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S
ye
s
1.
G
.
i
i
.
Explore the possibility of
mandates for certain projects
to meet minimum canopy
thresholds and possible
incentives such as increased
density.
ye
s
ye
s
Ne
e
d
s
Be
n
e
f
i
t
s
st
a
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s
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,
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&
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,
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S
Establish a baseline for
existing ratios of native
species...and formalize goals
for increasing those ratios…
Pl
a
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t
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g
s
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.
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s
i
s
,
n
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x
t
s
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s
City of Palo Alto Urban Forest Master Plan Implementation Plan
ATTACHMENT G
35
#
Description may be
abbreviated; for complete
language, see "Goals, Policies,
& Programs."Ch
a
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i
a
Ye
a
r
1
Ye
a
r
2
Ye
a
r
3
Ye
a
r
4
Ye
a
r
5
Ye
a
r
6
Ye
a
r
7
Ye
a
r
8
Ye
a
r
9
Ye
a
r
1
0
Source / Notes
Program Orgazational & Logistical Needs Fiscal Needs & Benefits
Pe
r
s
o
n
n
e
l
45
Ot
h
e
r
Pe
r
s
o
n
n
e
l
($
3
,
1
6
0
)
Grants, Revenue
46
Ot
h
e
r
$2
0
,
0
0
0
Cap and trade
(one time--likely year 2)
Pe
r
s
o
n
n
e
l
($
7
9
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
47
Ot
h
e
r
Ye
a
r
3
an
a
l
y
s
i
s
,
n
e
x
t
s
t
e
p
s
Ne
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d
s
Be
n
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f
i
t
s
ye
s
im
p
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t
a
t
i
o
n
ye
s
y
e
s
ye
s
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d
s
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e
f
i
t
s
ye
s
ye
s
ye
s
Be
n
e
f
i
t
s
Ne
e
d
s
4.
I
.
v
i
.
Coordinate between
departments and with partners
re:
• Appropriate mixes of trees,
shrubs, and grasses
• Natural cycles of
disturbance such as fire
• Response to use and
impacts.
• Appreciation by the
community.Co
m
m
u
n
i
c
a
t
i
o
n
p
r
o
c
e
d
u
r
e
s
,
B
o
a
r
d
s
&
C
o
m
m
i
s
s
i
o
n
s
Al
l
an
a
l
y
s
i
s
,
n
e
x
t
s
t
e
p
s
2.
A
.
i
i
.
re
v
e
n
u
e
,
g
r
a
n
t
s
,
c
o
n
t
r
a
c
t
s
PW
D
,
U
t
i
l
i
t
i
e
s
,
C
S
O
ma
y
b
e
ye
s
4.
E
.
i
.
Consider incentives to plant
additional trees, either
through additional points via
LEED certification , Build It
Green (BIG) Green Points, or
similar certification systems
such as those defined by the
Sustainable Sites Initiative.Tr
e
e
T
e
c
h
n
i
c
a
l
M
a
n
u
a
l
,
st
a
n
d
a
r
d
c
o
m
m
e
n
t
s
PW
D
,
P
&
C
E
,
D
S
,
U
t
i
l
i
t
i
e
s
Work with the Sustainability
Plan team to evaluate future
participation in carbon credit
programs.
ye
s
ye
s
City of Palo Alto Urban Forest Master Plan Implementation Plan
ATTACHMENT G
36
#
Description may be
abbreviated; for complete
language, see "Goals, Policies,
& Programs."Ch
a
n
g
e
s
t
o
Po
l
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i
a
Ye
a
r
1
Ye
a
r
2
Ye
a
r
3
Ye
a
r
4
Ye
a
r
5
Ye
a
r
6
Ye
a
r
7
Ye
a
r
8
Ye
a
r
9
Ye
a
r
1
0
Source / Notes
Program Orgazational & Logistical Needs Fiscal Needs & Benefits
Pe
r
s
o
n
n
e
l
($
3
,
1
6
0
)
Development Services
48
Ot
h
e
r
$6
5
,
0
0
0
$6
5
,
0
0
0
$6
5
,
0
0
0
$6
5
,
0
0
0
$6
5
,
0
0
0
$6
5
,
0
0
0
$6
5
,
0
0
0
$6
5
,
0
0
0
Fee/Permit (no change in development
activity-
likely begin year 5)
Pe
r
s
o
n
n
e
l
($
3
,
1
6
0
)
Development Services
49
Ot
h
e
r
($
4
5
,
2
2
5
)
Development Services
Pe
r
s
o
n
n
e
l
($
1
,
5
8
0
)
Utilities, grants
50
Ot
h
e
r
($
2
0
,
0
0
0
)
Utilities, grants
$1
0
,
0
0
0
Grant
(One time--likely in year 3)
Ye
a
r
3
st
a
n
d
a
r
d
c
o
n
d
i
t
i
o
n
s
,
A
R
B
,
I
R
,
Bl
d
g
.
p
e
r
m
i
t
s
PW
D
,
P
&
C
E
,
D
S
,
U
t
i
l
i
t
i
e
s
ye
s
ye
s
2.
A
.
i
v
.
Work with the Utilities
Department to publish tools
and priorities for citing of
solar collection devices.
Be
n
e
f
i
t
s
ye
s
an
a
l
y
s
i
s
,
ne
x
t
s
t
e
p
s
Ne
e
d
s
Be
n
e
f
i
t
s
1.
E
.
i
i
i
.
Evaluate effectiveness of
requirement for 50% shading
for parking lots (public and
private). Identify reasons for
success and failure. Give
special consideration to the
impact of substituting solar
panels for trees to meet this
requirement.
st
a
n
d
a
r
d
c
o
n
d
i
t
i
o
n
s
,
A
R
B
,
I
R
,
bu
i
l
d
i
n
g
p
e
r
m
i
t
s
PW
D
,
P
&
C
E
,
D
S
ye
s
an
a
l
y
s
i
s
,
n
e
x
t
s
t
e
p
s
Ne
e
d
s
ye
s
ye
s
ye
s
ye
s
ye
s
an
a
l
y
s
i
s
,
n
e
x
t
s
t
e
p
s
Ne
e
d
s
Be
n
e
f
i
t
s
1.
E
.
i
v
.
Consider requiring new
commercial, multi-family,
and single-family housing
projects to provide street trees
and related irrigation systems.
Note: The requirement for
public art may be a useful
model.
st
a
n
d
a
r
d
c
o
n
d
i
t
i
o
n
s
,
A
R
B
,
I
R
,
bu
i
l
d
i
n
g
p
e
r
m
i
t
s
PW
D
,
P
&
C
E
,
D
S
ye
s
ye
s
Year 3 programs 49 through 51 focus on design standards relative to solar program concerns.
City of Palo Alto Urban Forest Master Plan Implementation Plan
ATTACHMENT G
37
#
Description may be
abbreviated; for complete
language, see "Goals, Policies,
& Programs."Ch
a
n
g
e
s
t
o
Po
l
i
c
i
e
s
o
r
Pr
o
c
e
d
u
r
e
s
De
p
a
r
t
m
e
n
t
a
l
Co
l
l
a
b
o
r
a
t
i
o
n
Ch
a
n
g
e
s
t
o
Mu
n
i
C
o
d
e
St
a
k
e
h
o
l
d
e
r
Pa
r
t
i
c
i
p
a
t
i
o
n
St
a
f
f
Ed
u
a
t
i
o
n
Co
m
m
u
n
i
t
y
Ou
t
r
e
a
c
h
/
Mo
n
i
t
o
r
i
n
g
Cr
i
t
e
r
i
a
Ye
a
r
1
Ye
a
r
2
Ye
a
r
3
Ye
a
r
4
Ye
a
r
5
Ye
a
r
6
Ye
a
r
7
Ye
a
r
8
Ye
a
r
9
Ye
a
r
1
0
Source / Notes
Program Orgazational & Logistical Needs Fiscal Needs & Benefits
Pe
r
s
o
n
n
e
l
($
7
,
9
0
0
)
Utilities
51
Ot
h
e
r
($
2
0
,
0
0
0
)
Utilities
Pe
r
s
o
n
n
e
l
($
7
9
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
52
Ot
h
e
r
($
1
0
,
0
0
0
)
General Fund/ Development Services
Pe
r
s
o
n
n
e
l
($
1
9
,
7
5
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
53
Ot
h
e
r
($
1
0
,
0
0
0
)
CSD
Ye
a
r
3
Ne
e
d
s
Be
n
e
f
i
t
s
PW
D
,
C
S
D
ye
s
ye
s
ye
s
ye
s
an
a
l
y
s
i
s
,
ne
x
t
s
t
e
p
s
Ne
e
d
s
Be
n
e
f
i
t
s
im
p
l
e
m
e
n
t
a
t
i
o
n
ye
s
ye
s
ye
s
ye
s
4.
K
.
i
v
.
3.
A
.
i
x
.
Be
n
e
f
i
t
s
2.
A
.
v
.
Work with the Sustainability
Team and/or the Utilities
Department and Canopy to
create a guidance
document—how to
successfully incorporate solar
collection and trees into site
design—for those considering
solar.st
a
n
d
a
r
d
c
o
n
d
i
t
i
o
n
s
,
A
R
B
,
I
R
,
Bl
d
g
.
p
e
r
m
i
t
s
...develop programs to
familiarize residents with
Palo Alto’s Urban Forest
birds and butterflies practices.
PW
D
,
U
t
i
l
i
t
i
e
s
P
&
C
E
,
D
S
ma
y
b
e
ye
s
Educate the development
community about minimizing
project effects on local
wildlife.
Tr
e
e
T
e
c
h
n
i
c
a
l
M
a
n
u
a
l
,
st
a
n
d
a
r
d
c
o
m
m
e
n
t
s
,
&
d
r
a
w
i
n
g
s
PW
D
,
P
&
C
E
,
D
S
,
U
t
i
l
i
t
i
e
s
,
C
S
O
Year 3 programs 52 through 57 focus on design standards relative to wildlife concerns.
im
p
l
e
m
e
n
t
a
t
i
o
n
Ne
e
d
s
City of Palo Alto Urban Forest Master Plan Implementation Plan
ATTACHMENT G
38
#
Description may be
abbreviated; for complete
language, see "Goals, Policies,
& Programs."Ch
a
n
g
e
s
t
o
Po
l
i
c
i
e
s
o
r
Pr
o
c
e
d
u
r
e
s
De
p
a
r
t
m
e
n
t
a
l
Co
l
l
a
b
o
r
a
t
i
o
n
Ch
a
n
g
e
s
t
o
Mu
n
i
C
o
d
e
St
a
k
e
h
o
l
d
e
r
Pa
r
t
i
c
i
p
a
t
i
o
n
St
a
f
f
Ed
u
a
t
i
o
n
Co
m
m
u
n
i
t
y
Ou
t
r
e
a
c
h
/
Mo
n
i
t
o
r
i
n
g
Cr
i
t
e
r
i
a
Ye
a
r
1
Ye
a
r
2
Ye
a
r
3
Ye
a
r
4
Ye
a
r
5
Ye
a
r
6
Ye
a
r
7
Ye
a
r
8
Ye
a
r
9
Ye
a
r
1
0
Source / Notes
Program Orgazational & Logistical Needs Fiscal Needs & Benefits
Pe
r
s
o
n
n
e
l
($
3
,
1
6
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
54
Ot
h
e
r
Pe
r
s
o
n
n
e
l
($
7
,
9
0
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
55
Ot
h
e
r
($
5
,
0
0
0
)
General Fund
Pe
r
s
o
n
n
e
l
($
1
,
5
8
0
)
General Fund: Estimated portion of one-time
cost for temporary personnel to underfill for
regular staff completing Master Plan
programs.
56
Ot
h
e
r
Ye
a
r
3
Be
n
e
f
i
t
s
PW
D
,
C
S
D
ye
s
ye
s
ye
s
Ne
e
d
s
Be
n
e
f
i
t
s
Ne
e
d
s
Tr
e
e
T
e
c
h
n
i
c
a
l
M
a
n
u
a
l
PW
D
,
C
S
D
...educate citizens about
correct pruning at the best
time to protect bird habitat
and nesting.
Tr
e
e
T
e
c
h
n
i
c
a
l
M
a
n
u
a
l
im
p
l
e
m
e
n
t
a
t
i
o
n
Ne
e
d
s
Be
n
e
f
i
t
s
PW
D
,
C
S
D
ye
s
im
p
l
e
m
e
n
t
a
t
i
o
n
ye
s
ye
s
ye
s
ye
s
ye
s
im
p
l
e
m
e
n
t
a
t
i
o
n
4.
A
.
i
i
i
.
Provide education to staff and
ensure that tree maintenance
practices continue to consider
bird nesting seasons.
3.
A
.
v
i
i
i
.
Partner with Santa Clara
Valley Audubon Society for
the Palo Alto Christmas Bird
Count, Spring Bird Count,
and the Backyard Bird Count.
3.
A
.
x
.
City of Palo Alto Urban Forest Master Plan Implementation Plan
ATTACHMENT G
39
#
Description may be
abbreviated; for complete
language, see "Goals, Policies,
& Programs."Ch
a
n
g
e
s
t
o
Po
l
i
c
i
e
s
o
r
Pr
o
c
e
d
u
r
e
s
De
p
a
r
t
m
e
n
t
a
l
Co
l
l
a
b
o
r
a
t
i
o
n
Ch
a
n
g
e
s
t
o
Mu
n
i
C
o
d
e
St
a
k
e
h
o
l
d
e
r
Pa
r
t
i
c
i
p
a
t
i
o
n
St
a
f
f
Ed
u
a
t
i
o
n
Co
m
m
u
n
i
t
y
Ou
t
r
e
a
c
h
/
Mo
n
i
t
o
r
i
n
g
Cr
i
t
e
r
i
a
Ye
a
r
1
Ye
a
r
2
Ye
a
r
3
Ye
a
r
4
Ye
a
r
5
Ye
a
r
6
Ye
a
r
7
Ye
a
r
8
Ye
a
r
9
Ye
a
r
1
0
Source / Notes
Program Orgazational & Logistical Needs Fiscal Needs & Benefits
Pe
r
s
o
n
n
e
l
($
7
,
9
0
0
)
General Fund Utilities
57
Ot
h
e
r
Ye
a
r
3
($160,225)
($85,320)
$95,000
$406,681
$256,136
Personnel i.e., temporary personnel underfilling for regular staff who are
working on Year 3 programs.
Costs such as materials and contracts fort Year 3 programs.
Benefits of Year 3 programs.
Benefits from programs implemented in Years 1- 2 that recur in Year 3.
Year 3 net
PW
D
,
U
t
i
l
i
t
i
e
s
ye
s
ye
s
Y
e
a
r
3
S
u
m
m
a
r
y
4.
H
.
i
i
i
.
Evaluate adequacy of contract
cycle pruning policy and
ensure that pruning continues
to consider bird nesting...
Tr
e
e
r
e
m
o
v
a
l
p
o
l
i
c
y
ye
s
an
a
l
y
s
i
s
,
n
e
x
t
s
t
e
p
s
Ne
e
d
s
Be
n
e
f
i
t
s
City of Palo Alto Urban Forest Master Plan Implementation Plan
ATTACHMENT G
40
Department Unit Year Mileage Model Replc Est. Cost
FY 2018 Vehicle Replacenet Schedule by Fund
ASD 1243 2005 Electric Forklift 50,000
CSD 2110 1999 27688 Ford Van 45,000
CSD 2350 1999 73000 Ford F-150 32,000
CSD 2740 2004 6420 Tractor/Mower 135,000
CSD 2765 2000 72,120 F-350 Wildland 135,000
CSD 2767 2003 74,034 F-350 Wildland 135,000
CSD 2791 1999 1793HR John Deere tractor 112,000
CSD 5002 2006 125,904 Honda Accord Sedan 35,000
PWD 3520 2001 53,576 Ford F-550 w/ chipper body 83,000
POLICE 5141 2011 87,713 Crown Vic Patrol Car 60,000
POLICE 5144 2011 90,851 Crown Vic Patrol Car 60,000
POLICE 5248 2010 80,440 Crown Vic Patrol Car 60,000
POLICE 5251 2010 94,255 Crown Vic Patrol Car 60,000
POLICE 5252 2010 45,094 Crown Vic Patrol Car 60,000
POLICE 5254 2010 123,580 Crown Vic Patrol Car 60,000
POLICE 5255 2009 86,252 Crown Vic Patrol Car 60,000
POLICE 5258 2009 100,547 Crown Vic Patrol Car 60,000
POLICE 5402 2006 104,004 Toyota Sienna van 45,000
POLICE 5453 2006 81,233 Ford Explorer 60,000
POLICE 5464 2005 94,700 Toyota Sienna van 45,000
FIRE 6034 2003 47,682 Ford Ranger command 50,000
FIRE 6178 2008 5,724 Ford F-550 Wildland Unit 210,000
FIRE 6215 2001 52,200 Chevy Suburban command 125,000
Total-General Fund 1,777,000
REFUSE 4381 2003 71,646 Ford Ranger PU 38,000
Total-Refuse Fund 38,000
STORM DRAIN 4701 1998 GMC Jimmy SUV 32,000
Total-Storm Drain Fund 32,000
UTIL-ELECT 7403 2002 88,702 Freightliner 210,000
UTIL-ELECT 7590 2001 82,949 Step Van 90,000
Total - Electric Fund 300,000
UTIL-GAS 8277 2008 4404HR Cat Backhoe 155,000
UTIL-GAS 8280 1997 67,000 Ford Truck - HD 186,000
UTIL-GAS 8348 2008 4439HR Cat Backhoe 155,000
Total - Gas Fund 496,000
UTIL-WATER 7174 2003 82,697 Ford F-250 70,000
UTIL-WATER 7176 2005 99,266 Ford F-350 4x4 120,000
UTIL-WATER 7284 2008 4063HR Cat Backhoe 155,000
UTIL-WATER 7361 2002 74,442 Astro Van 45,000
UTIL-WATER 7362 2002 84,020 Astro Van 45,000
Total-Water Fund 435,000
UTIL-SEWER 8738 2008 3925HR Cat Backhoe 155,000
Total-Wastewater Fund 155,000
GRAND TOTAL 3,233,000
ATTACHMENT H
41
May 12, 2017
Honorable City Council
C/O City of Palo Alto
250 Hamilton Avenue
Palo Alto, CA 94301
RE: Review of 2018-2022 Proposed Capital Improvement Program (CIP)
The Planning and Transportation Commission (PTC) reviewed the 2018-2022 Capital Improvement Plan
(CIP) on Wednesday, May 10, 2017 and determined that all of the new Capital Improvement Projects
included in the 2018-2022 Capital Budget are consistent with the adopted 1998-2010 Comprehensive
Plan and recommended forwarding this finding to the City Council Finance Committee and the City
Council. The motion was made by Vice Chair Asher Waldfogel and seconded by Commissioner Ed
Lauing. The motion was approved by a vote of 5-0-2 (Commissioners Doria Suma and Eric Rosenblum,
absent).
Attached to this letter are recommendations from individual commissioners for consideration in next
year’s Capital Budget.
Respectfully submitted
Michael Alcheck, Chair
Planning and Transportation Commission
ATTACHMENT I
42
Attachment
Recommendations for Inclusion in Next Year’s Capital Budget
•Include a CIP item for the 2018 capital budget to assess the feasibility of improving bicycle and
pedestrian access from East Bayshore Road to West Bayshore Road with improvements such
as signage, curb ramps, pedestrian crossing and landscape maintenance.
•Include a CIP item to assess the feasibility of making safety improvements at University Avenue
and El Camino Real looking at collision history for bikes and pedestrian for FY 2019 to 2023
Capital Budget.
ATTACHMENT I:
Letter from Planning and Transportation Committee
ATTACHMENT I
43
Project ID Project Title
FY 2018 Funding:
Proposed Capital
Budget Document
FY 2018 Funding
Adjustment
FY 2018 Revised
Funding: Proposed
Capital Budget
Document
Airport Fund
AP-16000 Airport Apron Reconstruction $ 5,600,490 $ 30,000 $ 5,630,490
AP-16002 Wildlife Hazard Plan $ 8,415 $ 15,000 $ 23,415
Total Airport Fund $ 5,608,905 $ 45,000 $ 5,653,905
Capital Improvement Fund
AC-14001 Baylands Nature Interpretive Center Exhibit Improvements $ - $ 56,000 $ 56,000
AC-17000 Performing Arts Visual Venues Soft Goods Replacement $ - $ 55,000 $ 55,000
AC-86017 Art In Public Spaces $537,807 $ (2,500) $535,307
OS-00001 Open Space Trails and Amenities $175,000 $ 18,652 $193,652
OS-00002 Open Space Lakes And Pond Maintenance $ 72,791 $(27,791) $ 45,000
OS-09001 Off-Road Pathway Resurfacing And Repair $215,522 $ 20,587 $236,109
PE-11000 Rinconada Library New Construction and Improvements $995,706 $(15,389) $980,317
PE-13012 Structural Assessment of City Bridges $ - $ 25,000 $ 25,000
PE-14018 Baylands Boardwalk Improvements $ 22,199 $(22,199) $ -
PE-15003 Fire Station 3 Replacement $ 5,845,584 $ 55,000 $ 5,900,584
PE-17000 Mitchell Park Adobe Creek Bridge Replacement $250,000 $ (2,994) $247,006
PE-17008 City Hall Floor 4 Remodel $467,100 $ (9,573) $457,527
PE-17009 City Hall Floor 5 Remodel $518,000 $ (7,019) $510,981
PE-18000 New California Avenue Area Parking Garage $ 9,479,713 $(38,264) $ 9,441,449
PF -01003 Building Systems Improvements $238,599 $100,000 $338,599
PF-02022 Facility Interior Finishes Replacement $363,451 $ 40,000 $403,451
PF-93009 Americans With Disabilities Act Compliance $440,367 $ (1,163) $439,204
PG-06001 Tennis and Basketball Court Resurfacing $469,391 $ 89,039 $558,430
PG-06003 Benches, Signage, Walkways, Perimeter Landscaping $274,255 $ 1,172 $275,427
PG-13001 Stanford/Palo Alto Playing Fields Soccer Turf Replacement $ - $502,139 $502,139
PG-13003 Golf Reconfiguration & Baylands Athletic Center Improvements $ - $ 53,991 $ 53,991
PG-15000 Buckeye Creek Hydrology Study $ 44,801 $ (2,095) $ 42,706
PL-14001 Midtown Connector $ - $ 53,120 $ 53,120
PL-15003 Residential Preferential Parking $192,400 $ 40,000 $232,400
PL-15004 Downtown Parking Wayfinding $ 95,421 $300,000 $395,421
Total Capital Improvement Fund $ 20,698,107 $ 1,280,713 $ 21,978,820
Electric Fund
EL-02010 SCADA System Upgrades $ 60,000 $ 59,196 $119,196
EL-02011 Electric Utility Geographic Information System $228,663 $(63,663) $165,000
EL-04012 Utility Site Security Improvements $ 70,960 $ 15,613 $ 86,573
EL-06001 230 Kv Electric Intertie $113,119 $ 14,255 $127,374
EL-10006 Rebuild Underground District 24 $643,113 $277,087 $920,200
EL-11003 Rebuild Underground District 15 $114,181 $ 30,000 $144,181
EL-11010 Underground District 47-Middlefield, Homer, Webster, Addison $ 1,397,480 $476,976 $ 1,874,456
EL-11014 Smart Grid Technology Installation $ 1,521,766 $(521,766) $ 1,000,000
CAPITAL BUDGET REAPPROPRIATIONS
ATTACHMENT J
44
Project ID Project Title
FY 2018 Funding:
Proposed Capital
Budget Document
FY 2018 Funding
Adjustment
FY 2018 Revised
Funding: Proposed
Capital Budget
Document
CAPITAL BUDGET REAPPROPRIATIONS
EL-12001 Underground District 46 - Charleston/El Camino Real $ 1,397,480 $(497,480) $900,000
EL-13007 Underground Distribution System Security $300,000 $290,534 $590,534
EL-15000 Colorado/Hopkins System Improvement $ 1,525,000 $ 50,000 $ 1,575,000
EL-16002 Capacitor Bank Installation $ - $350,000 $350,000
EL-17001 East Meadows Circles 4/12Kv Conversion $ - $ 50,000 $ 50,000
EL-17005 HCB Pilot Wire Relay Replacement $167,000 $107,559 $274,559
EL-17007 Facility Relocation for Caltrain Modernization Project $ 1,550,000 $150,000 $ 1,700,000
EL-89031 Communications System Improvements $359,821 $(137,446) $222,375
EL-89038 Substation Protection Improvements $400,000 $200,000 $600,000
EL-89044 Substation Facility Improvements $195,000 $100,000 $295,000
Total Electric Fund $ 10,160,003 $950,865 $ 11,110,868
Gas Fund
GS-11002 Gas Distribution System Improvements $238,870 $241,178 $480,048
GS-12001 Gas Main Replacement - Project 22 $ - $ 3,254,782 $ 3,254,782
Total Gas Fund $238,870 $ 3,495,960 $ 3,734,830
Vehicle Replacement Fund
VR-15000 Scheduled Vehicle and Equipment Replacement - Fiscal Year 2015 $990,736 $ 50,000 $ 1,040,736
VR-16000 Scheduled Vehicle and Equipment Replacement - Fiscal Year 2016 $953,985 $150,000 $ 1,103,985
VR-17000 Scheduled Vehicle and Equipment Replacement - Fiscal Year 2017 $ 2,118,057 $200,000 $ 2,318,057
Total Vehicle Replacement Fund $ 4,062,778 $400,000 $ 4,462,778
Wastewater Collection Fund
WC-14001 Wastewater Collection System Rehabilitation/Augmentation Project 27 $ - $ 97,440 $ 97,440
WC-15001 Wastewater Collection System Rehabilitation/Augmentation Project 28 $351,300 $351,300 $702,600
Total Wastewater Collection Fund $351,300 $448,740 $800,040
Wastewater Treatment Fund
WQ-14001 New Dewatering and Loadout Facility $ 15,167,666 $ 7,000,000 $ 22,167,666
Total Wastewater Treatment Fund $ 15,167,666 $ 7,000,000 $ 22,167,666
Water Fund
WS-09000 Seismic Water System Upgrades $ 1,130,877 $ (2,283) $ 1,128,594
WS-12001 Water Main Replacement - Project 26 $ - $ 1,143,000 $ 1,143,000
Total Water Fund $ 1,130,877 $ 1,140,717 $ 2,271,594
GRAND TOTAL $ 57,418,506 $ 14,761,995 $ 72,180,501
ATTACHMENT J
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