HomeMy WebLinkAboutRESO 9423Resolution No. 9423
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2015 Financial Plans and Reserve Management Policies for the
Electric, Gas, Wastewater Collection, and Water Utilities, With No Rate
Increases Proposed for Fiscal Year 2015
RECITALS
A. Each year the City of Palo Alto ("City") assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes
making long-term projections of market conditions, assessing the physical condition of the
system and other factors that could affect utility costs, and setting rates adequate to recover
these costs. This task is undertaken with the goal of providing safe, reliable, and sustainable
utility services at competitive rates.
B. This year, staff has developed expanded forecasts, called "Financial
Plans," that include a more comprehensive overview ofthe utility's operations, for Council's
adoption starting in FY 2015.
C. 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 which are attached to
and made a part of the FY 2015 Financial Plans.
D. The 2012 Utilities Reserves Audit performed by the City Auditor included
recommendations related to the management of utility reserves. Staff has changed to the
structure of the utility reserves and the practices for managing them in response to this audit,
and has incorporated these changes into the FY 2015 Financial Plans and Reserves
Management Practices.
E. Staff presented the Financial Plans for the Electric, Gas, Wastewater
Collection, and Water Utilities to the UAC at its March 26, 2014 meeting. Staff's proposal
included a projected 4% rate increases for the Water and Wastewater Collection Utilities. The
UAC voted 4-1 (with Melton opposed and Commissioners Chang and Waldfogel absent) to
recommend that Council adopt the proposed Financial Plans, modified to remove the rate
increases.
F. Staff presented the modified Financial Plans to the Finance Committee at
its April15, 2014 meeting, and the Finance Committee voted unanimously to recommend
that Council approve the proposed Financial Plans, with no proposed rate increases for Fiscal
Year 2015.
The Council of the City of Palo Alto RESOLVES as follows:
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SECTION 1. The Council hereby adopts the FY 2015 to FY 2019 Electric Utility
Financial Plan, including the Electric Utility Reserves Management Practices. These Electric
Utility Reserves Management Practices replace previously adopted Reserves Policies for the
Electric Utility.
SECTION 2. The Council hereby adopts the FY 2015 to FY 2021 Gas Utility
Financial Plan, including the Gas Utility Reserves Management Practices. These Gas Utility
Reserves Management Practices replace previously adopted Reserves Policies for the Gas
Utility.
SECTION 3. The Council hereby adopts the FY 2015 to FY 2019 Wastewater
Collection Utility Financial Plan, including the Wastewater Collection Utility Reserves
Management Practices. These Wastewater Collection Utility Reserves Management Practices
replace previously adopted Reserves Policies for the Wastewater Collection Utility.
SECTION 4. The Council hereby adopts the FY 2015 to FY 2021 Water Utility
Financial Plan, including the Water Utility Reserves Management Practices. These Water
Utility Reserves Management Practices replace previously adopted Reserves Policies for the
Water Utility.
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SECTION 5. The Council finds that the adoption of this resolution does not
constitute a project under Section 21065 of the California Environmental Quality Act {CEQA)
and the CEQA Guidelines, and therefore, no environmental assessment is required.
INTRODUCED AND PASSED: June 9, 2014
AYES: BERMAN, BURT, HOLMAN, KLEIN, KNISS, PRICE, SCHMID, SHEPHERD
NOES:
ABSENT: SCHARFF
ABSTENTIONS:
APPROVED AS TO FORM:
nior Deputy City Attorney
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ATIACHMENT B
FY 2015 TO FY 2019
Definitions and Abbreviations ............................................................................................................................... 2
Executive Summary ............................................................................................................................................... 3
Current State of the Utility .................................................................................................................................... 4
Section I. Utility Overview ......................................................................................................................................... 4
Section II. Current Rates and Competitiveness ......................................................................................................... 5
Section Ill. Rate Design ............................................................................................................................................. 6
Section IV. Current Utility Financial Status ............................................................................................................... 7
Section V. Status of Reserves .................................................................................................................................... 8
Section VI. Status of Bond Covenants ..................................................................................................................... 10
Looking Back ........................................................................................................................................................ 10
Section VII. Background .......................................................................................................................................... 10
Section VIII. Historical Expenses and Revenues ....................................................................................................... 13
Looking Forward .................................................................................................................................................. 15
Section IX. Five Year Financial Forecast .................................................................................................................. 15
1. Overview ...................................................................................................................................................... 15
2. Commodity Supply Costs ............................................................................................................................. 16
3. Operations and Maintenance Costs ............................................................................................................ 17
4. Capital Improvement Program {CIP) ............................................................................................................ 17
5. General Fund Equity Transfer ...................................................................................................................... 18
Section X. Revenue Requirement and Revenue Sources ......................................................................................... 18
Section XI. Projected Consumption ......................................................................................................................... 21
Section XII. Long-term Outlook ............................................................................................................................... 22
Section XIII. Risk Assessment. .................................................................................................................................. 23
Section XIV. Communications Plan ......................................................................................................................... 25
Appendices .......................................................................................................................................................... 26
Appendix A: Electric Utility Financial Forecast Detai/ .............................................................................................. 27
Appendix B: Electric Utility Capita/Improvement Program {CIP} Detai/ .................................................................. 28
Appendix C: Electric Utility Reserves Management Practices .................................................................................. 30
Appendix D: Electric Utility Bond Covenant Details ................................................................................................. 34
Appendix E: Description of Electric Utility Cost Categories ..................................................................................... .36
Appendix F: Samples of Recent Electric Utility Outreach Communications ............................................................. 37
CAISO: California Independent System Operator
CIP: Capital Improvement Program
CPAU: City of Palo Alto Utilities Department
CPUC: California Public Utilities Commission
CVP: Central Valley Project
U7'/L/7 Y TJNANCf/J,L fJL!\f\l
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
Subtransmission 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.
June 16, 014 21Page
I UCTR!C UTIUIY FINANCIAL PLMV
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.
This document presents a financial plan for the City of Palo Alto's Electric Utility for the next
five years. The plan includes 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.
Over the next five fiscal years staff projects that total costs for the Electric Utility will rise by 3
to 4% per year as more renewable projects begin operation. Transmission costs are also
projected to contribute to those increases. Operations and Capital Improvement Program (CIP)
costs are projected to increase at 3% per year. To match revenues to these rising costs, the
financial plan includes the rate trajectory shown in Table 1. This trajectory includes no planned
rate increase for FY 2015. This will allow the utility to draw down accumulated reserves. For
FY 2016 to FY 2019, rates are projected to increase 2 to 3% each year. This is equivalent to
$0.90 to $1.36 per month for the median residential customer's monthly electric bill.
Table 1: Projected Electric Rate Trajectory for FY 2015 to FY 2019
FY2015 FY2016 FY2017 FY2018 FY2019
0% 3% 3% 3% 2%
This Financial Plan includes a set of Electric Utility Reserves Management Practices. These set
forth the reserves held by the Electric Utility, their purposes, and guidelines for managing them.
The Reserves Management Practices make the following changes to the utility's existing
reserves structure:
1. The addition of an Operations Reserve, a CIP Reserve, and an Unassigned Reserve to the
Distribution Fund;
2. The addition of an Operations Reserve, a Hydro Stabilization Reserve, and an
Unassigned Reserve to the Electric Supply Fund;
3. The closure of the Central Valley Project (CVP) Reserve and the transfer of all funds
($314,000) into the new Supply Operations Reserve; and
4. The closure of the Emergency Plant Replacement Reserve and the transfer of all funds
($1 million) into the new Distribution Operations Reserve.
In addition, the plan includes the following transfers:
1. Transfer $9.1 million from the Distribution Rate Stabilization Reserve to the Distribution
Operations Reserve;
2. Transfer $28 million from the Supply Rate Stabilization Reserve to the Hydro
Stabilization Reserve; and
3. Transfer $19.6 million from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve.
june 16, 2014 3 I Page
U.C!WC UTILITY FINANCiAL P/.1\N
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 29,300 customers connected to the
electric system, 26,500 (90%) of which are residential and 2800 (10%) of which are non-
residential. Residential customers consumed 187 gigawatt-hours (GWh) in FY 2013,
approximately 20% of the electricity sold, while non-residential customers consumed 84% or
760 GWh. Residential customers use electricity primarily for lighting, refrigeration, electronics,
and air conditioning.1 Non-residential customers use the majority of their electricity for
cooling, ventilation, lighting, office equipment (offices), cooking (restaurants), and refrigeration
(grocery stores).2
The Electric Utility receives electricity at a single connection point with Pacific Gas and Electric's
(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, 2,004 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
other associated electric equipment, represent the vast majority of the infrastructure used to
deliver electricity in Palo Alto. The City of Palo Alto Utilities Department (CPAU) manages an
ongoing CIP to repair and replace that equipment over time. CIP expense accounts for 8% of
the utility's expenditures.
In addition to the CIP, the Electric Utility performs a variety of maintenance and monitoring
activities on the system. The entire system is monitored from the Utility Control Center (UCC)
using the Supervisory Control and Data Acquisition System (SCADA), and staff members at the
UCC help coordinate the routing of power through the system in response to outages and to
accommodate routine maintenance activities. Other staff members perform routine
maintenance and testing of the substations, test and replace meters, investigate customer
inquiries and complaints related to power quality, clear vegetation from overhead lines, and
diagnose outages and perform emergency repairs. The utility shares the costs of other
operational activities such as customer service, billing, meter reading, supply planning, and
energy efficiency with the City's other utilities. These maintenance and operations expenses, as
well as associated administration, debt service, rent, and other costs, make up 25% of the
utility's expenses.
Electric supply represents the majority of the Electric Utility's costs. Nearly 60% of the utility's
costs are related to purchasing electricity and transporting it to Palo Alto. Roughly 50% of the
electricity is supplied from hydroelectric resources, 21% from Renewable Portfolio Standard
(RPS) eligible renewables, with the remainder purchased in the market from unspecified
1 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
2 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
Jun 16, 014 411'
[ UCIRIC UTiliTY Jlf'JANOM
generating sources. Under the City's Carbon Neutral Plan, the amount of electricity from RPS-
eligible sources will rise to nearly 50% by FY 2017. In the meantime, CPAU purchases
renewable energy certificates (RECs) corresponding to its market purchases.
Since its inception the Electric Utility has provided an annual return to the City's General Fund.
This equity transfer is calculated based on the net book value of the utility's capital assets. The
transfer accounts for 10% of the utility's expenses.
CPAU's last electric rate change took effect on July 1, 2009. Table 2, below, summarizes the
current 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 PaloAitoGreen rates, and solar net metering. Another specialty rate is the E-18
municipal electric rate.
Table 2: Current Electric Rates (12/1/13)
E.:.1 £.:.2(Small E~4"(Nied. E~7 (Large
Rate Component Units I·· (Residential) Commercial) Commercial) Commercial)
Demand (Summer) $/kW N/A N/A 20.54 18.97
Demand (Winter) $/kW N/A N/A 13.84 11.54
Energy (Summer)
Tier 1 $/kWh 0.09524 0.14045 0.08171 0.07808
Tier 2 $/kWh 0.13020 N/A N/A N/A
Tier 3 $/kWh 0.17399 N/A N/A N/A
Energy (Winter)
Tier 1 $/kWh Same as 0.12661 0.07318 0.07209
Tier 2 $/kWh summer N/A N/A N/A
Tier 3 $/kWh energy N/A N/A N/A
Tier amounts:
Tier 1 kWh/day 0-10 N/A N/A N/A
Tier 2 kWh/day 10-20 N/A N/A N/A
Tier 3 kWh/day >20 N/A N/A N/A
Table 3 presents the median residential bills for Palo Alto, PG&E, and the City of Santa Clara
{Silicon Valley Power) for several usage levels. For the median consumption level the annual bill
for calendar year 2013 was $511.42 under current CPAU rates, 23% lower than the annual bill
for a PG&E customer with the same consumption and roughly the same as the annual bill for a
City of Santa Clara customer. The bill calculations for PG&E customers are based on PG&E
Climate Zone X, which includes most surrounding comparison communities. Rates shown below
were effective January 1, 2014. Only a single winter month and a single summer month is
shown due to the fact that PG&E's rates vary frequently due to rate adjustment mechanisms.
June 16, 014 51 Page
f !JCT!?!C UTIL/7 )/ !-JNANC/l\l
Table 3: Residential Monthly Electric Bill Comparison ($/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
300 28.57 39.69 31.90
Winter (Median) 453 48.14 61.57 48.76
(January) 650 75.11 122.14 70.47
1200 170.80 319.20 131.08
300 28.57 $39.69 31.90
Summer (Median) 365 36.69 48.72 39.06
(July) 650 75.11 127.42 70.47
1200 170.80 326.22 131.08
Table 4, below, shows the average monthly electric bill for commercial customers for various
usage levels for the same period. Bills for small commercial customers in Palo Alto are 35%
below what they would be in PG&E territory and 18% below what they would be in Santa Clara
(Silicon Valley Power). For large commercial customers, rates are 23% below PG&E's and are
comparable to Santa Clara's (lower, for the largest commercial customers).
Table 4: Commercial Monthly Electric Bill Comparison (3/1/14, $/mo)
Usage {kwh/mo) Palo Alto PG&E Santa Clara
1,000 134 205 164
160,000 19,267 25,096 18,904
500,000 55,895 73,029 57,069
2,000,000 195,395 255,231 220,654
PG&E currently has recently stated its intention to file an application with the California Public
Utilities Commission (CPUC) that would reduce the number of residential tiers from four to two,
and allow all customers to opt for time-of-use pricing. If approved by the SFPUC, such changes
would be phased in, possibly as soon as 2015.
The Electric Utility's current rate structure and methodology are consistent with the cost of
service analysis (COSA) update in 2007 by Boris Metrics. Staff plans to review and update this
cost of service study in 2014. Before conducting this new cost of service study, staff will review
current rates and the scope of the study with the UAC and Council to determine UAC and
Council policy priorities. There are a variety of rate-related topics currently being discussed by
investor-and publicly-owned utilities across California, including the pros and cons of tiered
rate structures, the impact of customer-owned generation (like net-metered solar) on rates and
revenues, and rate design for electric vehicles. With the Electric Utility's carbon neutral electric
supply, some customers may be interested in gas to electric fuel switching, and the impact of
rate design on this decision also bears some discussion.
June 6, 20:14 61Page
I. UCTRIC UTILITY 1/1\JANC!Al PLAN
SECTION IV. CURRENT UTILITY FINANCIAl STATUS
In FY 2013, electric supply costs represented nearly 60% of the Electric Utility's costs.
Operations and CIP represented one quarter of the costs, and the remaining costs were for
administration and overhead (7%) and the General Fund equity transfer (10%), as shown in
Figure 2. These expenditures are also displayed by category of expenditure in Figure 1. The
vast majority of the utility's revenue came from sales of electricity (92%), with the remainder
coming from capacity and connection fees (2%), and other sources (6%).
Figure 1: FY 2013 Costs by Category Figure 2: FY 2013 Costs by Activity
Admin/
Overhead,
Other, 5%
Table 5 summarizes the Electric Utility's financial outlook for FY 2014. Electric supply costs are
projected to be $1.3 million lower than the adopted budget. While higher costs are projected
due to low output from hydroelectric resources, lower than forecasted transmission costs will
provide some relief, and the cost of renewable energy is forecasted to be much lower
($3.2 million) due to the delayed start of the San Joaquin renewable energy facility and
termination of the Crazy Horse renewable energy project. Commercial load is growing more
slowly than anticipated and, when combined with a shift in commercial consumption patterns,
staff is anticipating sales revenue to be $5.0 million lower than forecast. Other expenses are
projected to be approximately $5.4 million under budget due to savings in a variety of
operations budgets.
Table 5: Projected Electric Utility Net Revenue, FY 2014
Electric -Operating Activity All figures in thousands$ (OOO's)
Adopted Unaudited Projected Projected Variance to
Budget Actuals Activity FY2014 Budget
FY2014 Jui13-Dec13 Jan 14-Jun 14 Activity
Net Sales* 117,019 59,222 52,774 111,996 (5,023)
Other revenues 15,920 7,271 9,504 16,775 855
Purchase cost to serve retail load (72,224) (34,485) (36,448) (70,933) 1,291
Other expenses** (62,935) (32,365) (25,124) (57,489) 5,446
Surplus Energy costs (2,304) (831) {437) (1,268) 1,036
Surplus Energy revenues 2,316 544 519 1,063 (1,253)
Total (2,208) (644) 788 144 2,352
* Includes misc. sales, adjustments, discounts, and bad debt
June 16, 2014 71Page
r CTf\!C U! !LIT)' FINANCIAL f-lLl\!V
SECTION V. STATUS OF RESERVES
Table 6, below, shows the projected status of the Electric Utility's reserves at the end of FY
2014. Total reserves at the end of FY 2014 are projected to be $143.7 million, of which
$70.3 million will be in the Rate Stabilization Reserves. As detailed in Appendix C: Electric Utility
Reserves Management Practices and in Table 4 below, staff has proposed various changes
to the Electric Utility reserves:
1. The addition of an Operations Reserve, a CIP Reserve, and an Unassigned Reserve to the
Distribution Fund;
2. The addition of an Operations Reserve, a Hydro Stabilization Reserve, and an
Unassigned Reserve to the Electric Supply Fund;
3. The closure of the CVP Reserve and the transfer of all funds ($314,000) into the new
Supply Operations Reserve; and
4. The closure of the Emergency Plant Replacement Reserve and the transfer of all funds
($1 million) into the new Distribution Operations Reserve.
In addition, the plan includes the following transfers:
1. Transfer $9.1 million from the Distribution Rate Stabilization Reserve to the Distribution
Operations Reserve;
2. Transfer $28 million from the Supply Rate Stabilization Reserve to the Hydro
Stabilization Reserve; and
3. Transfer $19.6 million from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve.
The addition of an Operations Reserve, CIP Reserve, and Unassigned Reserve will add
transparency and simplify reserves management by providing separate reserves for various
functions that are currently all served by the Rate Stabilization Reserves. The Operations
Reserve will be used to manage contingencies and absorb normal year-to-year cost and
revenue fluctuations. The CIP Reserve will hold funds for expenditure on future budgeted CIP
projects. The Rate Stabilization Reserve will be used to smooth the transition to higher rates. If
the utility accumulates reserves that are not designated for a specific purpose, these will be
placed in the Unassigned Reserve until those funds are either designated for a specific purpose
or returned to ratepayers.
Creating separate CIP, Rate Stabilization, and Unassigned Reserves allows the utility to set
minimum and maximum guidelines for the Operations Reserve and set forth clear actions to be
taken when it is over or under those levels. If funds are to be held for a specific purpose (for
example, a future CIP project) these can be held in a separate reserve designed for that purpose
(in this example, the CIP Reserve). Without a separate reserve, those funds would be held in
the Operations Reserve and could cause it to exceed its maximum guideline, making it difficult
to treat the maximum guideline as a clear limit on the size of the reserve. This proposal also
adds transparency, since the public will be able to see the various purposes for which the utility
is holding reserves.
June 16, 2014
UT!i.ITY f INANOM NAN
Table 6: Projected Electric Utility Reserves, 6/30/2014 ($000)
Projected Proposed Projected
Reserve Reallocation After
Levels of Reserves Reallocation
Electric Supply Fund
Reappropriations & Commitments 200 N/A 200
Electric Special Projects Reserve* 53,356 N/A 53,356
CVP Reserve 314 -314 (closed)
Rate Stabilization Reserve 61,200 -51,407 13,916
Hydro Stabilization Reserve (new) 28,000 28,000
Operations Reserve (new) 19,598 19,598
Unassigned Reserve (new) 0
Total 115,070 0 115,070
Supply Operations Reserve: Days of Expense 90 days
Supply Operations Reserve: Minimum 60 days
Supply Operations Reserve: Target 90 days
Supply Operations Reserve: Maximum 120 days
Electric Distribution Fund
Reappropriations & Commitments 16,645 N/A 16,645
Underground Loan Reserve 738 0 738
Emergency Plant Replacement 1,000 -1,000 (closed)
Public Benefit Reserve 1,103 0 1,103
CIP Reserve (new) 0 0
Rate Stabilization Reserve 9,138 -9,138 0
Operations Reserve (new) 10,138 10,138
Unassigned Reserve (new) 0 0
Total 28,625 0 28,625
Dist. Operations Reserve: Days of Expense 92 days
Dist. Operations Reserve: Minimum 60 days
Dist. Operations Reserve: Target 90 days
Dist. Operations Reserve: Maximum 120 days
*Previously the Calaveras Reserve. See Staff Report 10#2160, November 1, 2011
This plan also involves merging the existing Emergency Plant Replacement Reserve into the
Distribution Operations Reserve. Currently the Emergency Plant Replacement Reserve holds $1
million, enough to pay the City's insurance deductible in the event of a loss of utility equipment
due to an insurable loss. Staff believes that even at minimum levels the Operations Reserve has
adequate funding to cover the insurance deductible, making the Emergency Plant Replacement
Reserve duplicative.
This plan also establishes a Hydro Stabilization Reserve. This is part of the development of a
comprehensive strategy for dealing with the fluctuations in costs created by the utility's
hydroelectric resources. The costs of these resources are largely fixed and must be paid
June 16, 2014 91Page
UTILITY F/!VANC/Ai. PLAN
regardless of the amount of power they generate. That generation is highly variable. When
production is lower than average, CPAU incurs additional costs because it is forced to buy
market energy to replace the lost production. When production is higher than average, CPAU
purchases less market energy and sells surplus energy in the spot markets. The Hydro
Stabilization Reserve is one of several tools that can be used to balance out these fluctuations
from year to year. The guidelines for this reserve will likely be revised in the future when CPAU
establishes a more comprehensive hydro balancing strategy.
This plan will leave 90 days of expenses in the Supply Operations Reserve and 92 days of
expenses in the Distribution Operations Reserve, which is within the long term guidelines set
forth in Appendix C: Electric Utility Reserves Management Practices. $13.9 million will be
retained in the Supply Rate Stabilization Reserve to be drawn down in future years.
SECTION VI. STATUS OF BON[) COVENANTS
The Electric Utility's annual debt service is $100,000 per year. This is related to the 2007
Electric Utility Clean Renewable Energy Tax Credit Bonds, Series A, which will require payments
through 2021. This $1.5 million 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 total capacity of these projects was 250 kilowatt (kW}.
The City is in compliance with all covenants on the bond. Additional detail is provided in
Appendix D.
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 that was later replaced by a diesel engine
in 1914 due to rising fuel oil costs. As demand for electricity and the population 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 until1948, 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
1950 sales of 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:
june 1G, 01 10 I P a g t'
UTILITY F!l\fAf\IC!AL F'LAlV
• 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).
• 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.
• 1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231)
Palo Alto's first new power plant investment in over SO 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.
In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and
in 1996 the State legislature passed Assembly Bill1890, 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
Utilitl 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 20011ed to the suspension of competition 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 the Western Area Power Administration (WAPA)4 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 variability of CVP generation. The new contract would provide
only a third of Palo Alto's requirement, and the monthly variability in CVP generation would be
passed directly through to Palo Alto. As a result, electric supply costs were going to increase
and CPAU would need to begin more actively managing 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 power plant elsewhere. Climate change was also
becoming more of a concern to the community, and gradually CPAU shifted its focus to the
3 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
4 The Western Area Power Administration is 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.
June 1 , 014 11 1 P g
U.COU( UT/Ln \' FI!VA!VCIAL PU\N
procurement of renewable energy, with its first contract for wind power commencing in 2005.
In 2002 CPAU adopted a goal of achieving 20% of its energy supply from renewables by 2015.
In 2011 this goal was increased to 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
hydroelectric supplies, purchases of long-term renewable energy supplies, and short-term
renewable energy supplies via RECs to meet the balance of its needs.
June 16, 20 4 12 I P a g
U)JI..JTY f-1/VANC!i\l PLAN
SECTION VIIL HISTORICAL EXPENSES AND REVENUES
The Electric Utility maintains separate funds for its electric supply portfolio expenses and its
distribution operations and CIP expenses. Table 7 shows the Electric Utility's expenses and
revenues for the past five years.
Total costs for this utility have decreased 11% since 2009, but there were a variety of notable
cost increases and decreases that contributed to this net change. Commodity costs decreased
Table 7: Electric Utility Historical Expenses ($000)
Sales of Utilities
Retail Sales 104,637 112,105 110,91S 108,344 109,189
Surplus Energy Sales 3,312 1,354 3,680 2,323 1,127
Total, Sales of Utilities 107,949 113,459 114,595 110,667 110,316
lnterest+lnvestment Gain/Loss 7,712 5,749 3,203 4,099 (1,497)
Other Revenues:
Carbon Allowance Revenue 2,713
Service Connection Charges 1,053 1,042 1,329 1,468 1,987
CVP O&M Loan Credit 7,174 6,550 4,763 4,856 5,509
Other Misc. Rev. I Transfers In 3,245 3,744 1,559 2,126 1,510
Total, Other Revenues 11,473 11,336 7,651 8,450 11,720
Total Sources of Funds 127,134 130,544 125,449 123,216 120,538
Purchases of Utilities
Purchases to Serve Load 71,738 60,876 51,605 50,660 54,063
Surplus Energy Cost 3,305 1,439 4,879 3,198 1,740
CVP O&M Loan Advance 7,306 6,398 4,763 4,866 5,Sll
Total, Purchases of Utilities 82,348 68,713 61,247 58,724 61,314
Joint Venture Debt Service 8,086 7,819 7,243 8,803 9,166
Administration 6,591 2,766 6,689 7,738 9,034
Customer Service 1,651 1,897 1,882 1,909 2,007
Demand Side Management 3,409 4,048 3,491 5,010 3,530
Engineering (Operating) 1,055 1,245 1,200 1,204 1,278
Operations & Maintenance 8,590 8,794 9,197 9,290 9,505
Resource Management 2,063 3,033 2,380 2,654 3,024
Rent 3,253 3,813 3,498 3,598 3,704
General Fund Transfers 9,268 11,120 11,195 11,587 11,768
Other Transfers Out 3,395 785 995 299 322
Capital Improvement Programs 9,912 12,598 13,877 7,974 9,775
Total Uses of Funds 139,611 126,633 122,896 118,790 124,425
Into/ Reserves 3,911 2,553 4,427
*2009 costs are modified to remove the effects of a one-time, $2.9 million transfer between the Supply and
Distribution Funds which affects the Other Misc. Rev and Other Transfers Out categories.
J u n 1 6 ' 0 J !J 13 I P a (':
UTIUI
by 22% over that time due to decreases in electricity market prices related to declines in the
cost of natural gas. These decreases were offset by increases in the equity transfer to the
General Fund and non-commodity operations costs. The FY 2010 through FY 2013 equity
transfers were over 20% higher than the FY 2009 transfer due to a change in methodology
adopted in 2009 and first taking effect in FY 2010. Excluding one-time transfers in 2009, non-
commodity costs5 increased by roughly 2% per year from 2009-2013.
Total revenues decreased 5% from FY 2009 to FY 2013, but this was due primarily to a decline in
the interest income/investment category. Sales revenues increased over that period due to a
rate increase on July 1, 2009. In FY 2013 the Electric Utility began receiving revenue related to
the sale of carbon allowances allocated to it as part of the State's cap and trade program. In
FY 2013 the interest income category was affected by the recognition of mark to market
decreases in the value of the City's investment portfolio, though the value of the portfolio was
still positive. Given that the City holds its investments to maturity these unrealized gains and
losses do not impact the utility's long term financial position.
5 All cost categories in Table 7 aside from Purchases of Utilities, Joint Venture Debt Service, CIP, and Equity
Transfers
June l6, 2014
i.U C/7\IC Ul7L/7 Y 1/!VANC!AL PLAN
SECTION IX. FIVE YEAR FINANCIAL FORECAST
. OVERVIEW
Staff has prepared a forecast of costs and revenues through FY 2019. As shown in Table 8 (and
Appendix A: Electric Utility Financial Forecast Detail), total uses of funds for the Electric
Table 8: Five Year Electric Utility Financial Forecast Summary
0.052 0.063 0.061 0.065
947 981 965 963 972
GE IN RETAIL SALES REVENUE 2,571
Sales of Utilities
Retail Sales 109,189 116,630 111,711 111,530 114,469 117,751 122,226 125,316
Surplus Energy Sales 1,127 2,316 1,063 2,395 2,750 4,867 6,763 6,769
Total, Sales of Utilities 110,316 118,946 112,774 113,925 117,219 122,618 128,989 132,085
I nterest+l nvestment Gain/Loss (1,497) 3,199 3,199 1,663 2,181 2,396 2,753 2,722
Other Revenues:
Carbon Allowance Revenue 2,713 4,296 4,296 3,910 3,976 4,299 4,493 4,611
Service Connection Charges 1,987 1,160 2,499 2,269 2,269 2,269 2,269 2,269
CVP O&M Loan Credit 5,509 6,000 5,407 6,000 6,000 6,000 6,000 6,000
Other Misc. Rev. /Transfers In 1,510 1,660 1,745 (52) 131 1,748 1,748 1,748
Total, Other Revenues 11,720 13,116 13,947 12,127 12,377 14,316 14,510 14,628
Total Sources of Funds 120,538 135,260 129,919 127,715 131,777 139,330 146,252 149,436
Purchases of Utilities
Purchases to Serve Load 54,063 66,205 65,454 63,372 64,801 67,002 68,975 68,102
Surplus Energy Cost 1,740 2,304 1,268 2,595 3,026 4,926 6,663 6,586
CVP O&M Loan Advance 5,511 6,000 5,407 6,000 6,000 6,000 6,000 6,000
Total, Purchases of Utilities 61,314 74,509 72,129 71,967 73,828 77,928 81,638 80,688
Joint Venture Debt Service 9,166 9,024 9,024 9,028 9,040 8,854 8,855 8,709
Administration (CIP +Operating) 9,034 7,174 8,001 8,241 8,489 8,743 9,006 9,276
Customer Service 2,007 2,219 2,252 2,319 2,389 2,460 2,534 2,610
Demand Side Management 3,530 4,214 4,326 6,152 6,139 5,659 5,731 5,846
Engineering (Operating) 1,278 1,605 1,522 1,567 1,614 1,663 1,713 1,764
Operations & Maintenance 9,505 10,602 9,458 9,742 10,035 10,336 10,646 10,965
Resource Management 3,024 5,347 3,213 1,894 1,951 2,009 2,069 2,131
Rent 3,704 3,819 3,819 3,934 4,052 4,173 4,299 4,428
General Fund Transfers 11,768 11,203 11,203 11,098 11,017 10,886 10,815 10,853
Other Transfers Out 322 123 281 123 123 123 123 123
Capital! mprovement Programs 9,775 8,605 4,547 7,467 6,662 9,192 9,842 10,842
Total Uses of Funds 124,425 138,445 129,775 133,532 135,337 142,025 147,270 148,235
of) Reserves
June 6. 0 4 15 I P a g e
f L l-CTr?JC UT!LJ T \/ f-!NAf\JClAf~ PLl\!V
Utility are projected to increase by 3% to 4% per year through FY 2019. The cost of purchased
power (which includes Purchases of Utilities and Joint Venture Debt Service) is projected to
. increase at 5%. Non-commodity costs are projected to rise by 3% per year, and CIP costs are
increasing by 2% per year. Sales revenues will need to increase by 2 to 3% per year for FY 2016
to FY 2019 to match these cost increases.
2. COMMODITY SUPPLY COSTS
Table 9 shows the projected costs for the electric supply portfolio. These costs are increasing
by 5% per year, on average, mainly 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.
Table 9: Electric Supply Portfolio Costs, FY 2015 to FY 2019 ($000)
As shown in Table 10, the utility gets 54% of its energy from hydroelectric projects in a normal
year (FY 2014 has been dry). Renewables are currently 21% of the portfolio, and are projected
to rise to 46% in FY 2019. The remainder comes from unspecified market sources.6 The
amount of market energy is projected to steadily decrease until 2017, when all energy is
projected to come from hydro and renewable resources in an average hydro year.
Table 10: Projected Electric Supply Sources, FY 2015 to FY 2019 (GWh)
6 Under the City's Carbon Neutral Plan, CPAU purchases RECs corresponding to the amount of market energy it
purchases.
June 16, 01 16 I Page
Fl. f UTILITY
3. OPERATIONS AND MAINTENANCE COSTS
Operations costs include the Customer Service, Demand Side Management, Operations and
Maintenance, Engineering, Resource Management, and Administration categories in Table 8,
above. Rent and transfers are also included in Operations costs (excluding the General Fund
equity transfer). Appendix E: Description of Electric Utility Cost Categories includes detailed
descriptions of these cost categories. Operations costs are projected to increase by 3% per
year. Salary and benefits, inflation, and other assumptions match those used in the City's long-
range financial forecast.
4. CAPITAL IMPROVEMENT PROGRAM (CIP)
The Electric Utility's CIP is shown in Table 11, and consists of the following programs and
budgets:
• System Capacity and Reliability: CPAU monitors the distribution system and identifies
sections that need upgrades to increase reliability or to provide additional capacity to
deliver power. This category includes activities such as upgrading and replacing
transformers, replacing distribution lines to increase capacity, improving system
protection schemes (fuses, switches, etc.), and upgrading substation equipment.
e Smart Grid and Advanced Metering: This project includes the cost of future upgrades
to the distribution system and metering infrastructure to take advantage of advances in
automation, sensing, and metering technologies. CPAU is currently operating pilot
programs to determine the scope of the upgrades.
e 4/12 kilovolt (kV) Conversion: The distribution system currently has some sections that
operate at 4 kV and some at 12 kV. CPAU is converting the 4 kV sections of the system
to enable them to connect to the rest of the system more effectively, providing greater
reliability. Operating the system at 12 kV also lowers energy losses.
e Undergrounding: This category includes projects to move sections of the overhead
system underground. These projects are generally funded in part by phone and cable
companies, whose systems are undergrounded at the same time.
e Underground System Rebuilding: Underground sections of the distribution system
require periodic replacement due to the wear on the system associated with exposure
to soil and water.
e Software and Equipment: This category includes the costs of upgrades to the software,
communications, and remote monitoring equipment used to monitor the system and
plan upgrades. It includes the cost of upgrades to the SCADA system.
e Customer Connections: This represents the cost when the Electric Utility installs new
services or upgrades existing services at a customer's request in response to
development or redevelopment. Because the Electric Utility charges a fee to these
customers to cover the cost, these are considered to be "customer-funded" projects.
e One-time Projects: This category represents occasional large projects that do not fall
into any other category.
June 16, 2014 17 I P a g e
i i UTiLITY F-)NANC/AL f'Li~!V
Excluding smart grid projects, CIP spending is expected to increase by 3% per year through
FY 2019. Smart grid upgrades, particularly in later years, are projected to cost substantial
amounts of money, but CPAU does not have precise cost estimates yet. CPAU expects to
finance these projects from the Electric Special Projects Reserve, transfers from the water and
gas funds, and possibly through bond financing. Excluding smart grid updates, the CIP plan for
FY 2015 to FY 2019 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 plan are shown in
Appendix 8: Electric Utility Capita/Improvement Program (CIP) Detail.
Table 11: Budgeted Electric Utility CIP Spending
GENERAL FUND EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a rate of return on the
net book value of the utility's capital assets7• The Council adopted this methodology in 2009
and it was first used in FY 2010. The equity transfer decreased in FY 2014 because it is
benchmarked to PG&E's return on equity, which decreased at that time. Changes in the equity
transfer in later years of the forecast are related to forecasted changes in the net book value of
the utility's capital assets based on projected depreciation and capital spending.
7 For more detail, see City Manager's Report 260:09, Finance Committee, May 26, 2009.
Jun 16. 4 18 If' g
$180
0%
$160
$140
$120
$100
$80
$60
$40
$20
$0
f Lf UTILITY FINANCfAL PLAN
Figure 3: Electric Utility Revenue and Cost Projections
0% 0% 3% 3% 3% 2%
Revenue
Iii Purchases
oCIP
ll!Operations
Ill Alternative
Energy &DSM
DCVPO&M
eOebt Service
mGF Transfers
The Electric Utility's costs and revenues from FY 2013 through FY 2019 are shown in Figure 3
below. Revenues are currently below costs, but adequate reserves mean no rate increase is
necessary in FY 2015. Rate increases for FY 2016 to FY 2019 are forecasted to be 2 to 3%. Each
rate increase will increase the median residential monthly electric bill by $0.90 to $1.36 per
month.
This rate trajectory draws the Supply Rate Stabilization Reserve down to zero by FY 2019, as
shown in Figure 4. Figure 5 shows the change in Distribution Fund reserves over the forecast
period. These figures also include the proposed reallocations of reserves described in Section
V. Status of Reserves.
Jun 16, 0 19 I P a e
_$140
II) c ~ $120
~ $100 -
$80
$60
$40
$20
$0
tJT/f_!fY
Figure 4: Electric Supply Fund Reserves
Projected FY 2014 year-end reserves under existing reserves structure
Proposed reallocation (see Section V. Status of Reserves)
II Central Valley Project
~Rate Stabilization
Hydro Stabilization
Reserve
Operations Reserve
Electric Special Projects
II Reappropriations +
Commitments
Act Proj Proj
-$40 II) .2 $35 --~ $30
-$25
$20
$15
$10
$5
$0
Act
Jun 16. 2014
Figure 5: Electric Distribution Fund Reserves
Projected FY 2014 vear-end reserves under existing reserves structure
Proposed reallocation (see Section V. Status of Reserves)
~Rate Stabilization
Operations Reserve
Emergency Plant
Replacement
II Public Benefits
01 !!l Underground Loan .-I ...._
0
('() U;-Ill Reappropriations +
Commitments
20 I Page
t CTRJC UTILITY Fiii!ANC!AL PLAN
SECTION XI. PROJECTED CONSUMPTION
Electricity consumption in Palo Alto is fairly stable due to the city's moderate climate. Summer
air conditioning loads, which have a major impact on other utilities' load profiles, are moderate.
Consumption is projected to stay stable over the forecast period, with growth being offset by
energy efficiency savings. Consumption of electricity for electric vehicles is projected to more
than double each year through the end of the forecast period, but this and other load growth is
offset by improved building code standards, energy efficiency, and substantial numbers of
rooftop solar installations. The total annual output of Palo Alto's net metered rooftop solar
installations8 is projected to be 20.6 GWh by FY 2019, or roughly 2.1% of annual sales, while
annual savings from energy efficiency measures are projected to be 80 GWh (nearly 8% of
annual sales) by that time. Figure 6 presents the historical electric consumption levels (with
and without energy efficiency, solar, and electric vehicles included) from FY 2004 through FY
2013 and projections for FY 2014 through FY 2023. Consumption levels are projected to be 3%
higher in FY 2019 than they were in FY 2013, the most recent year for which complete data is
available.
1,150
1,100
1,050
..c s 1,000
I!)
950
900
850
rl 0 0 N >-u..
Figure 6: Historic and Projected Electric Consumption
~=Purchases
~c'j~f""W/o Energy Efficiency, Electric Vehicles, Photovoltaics
N r<') <;t lfl "' "" 00 ()) 0 0 0 0 0 0 0 0 0 rl
0 0 0 0 0 0 0 0 0 N N N N N N N N N >->->->->->->->->-u.. u.. u.. u... u.. u.. u.. u.. u...
Actual
rl N M rl rl rl
0 0 0 N N N >->->-u... u.. u..
Forecast
"~"~-~';?
<;t lfl "' rl rl rl
0 0 0 N N N >->->-u... u.. u...
"" rl
0 N >-u..
00 ()) 0 rl N rl rl N N N 0 0 0 0 0 N N N N N >->->->->-u.. u... u.. u.. u..
8 This does not include Palo Alto CLEAN (feed-in tariff) projects, which are included in the supply forecast rather
than the demand forecast.
June :!6, 2 4 21 1 P
M N 0 N >-u..
IU UTIL/7\' fiNANCIAL PLAN
SECTION XII. lONG-TERM OUTLOOK
This forecast covers the period from FY 2015 through FY 2019, but there are also various long-
term developments that 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
WAPA for power from the CVP will expire in 2024. Working with WAPA and internally to
determine the future relationship with WAPA 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 represents the utility's largest source of carbon-free electricity. The
utility's three earliest and lowest cost renewable contracts will also begin expiring around that
time, with the first contract expiring in 2021 and the last in 2028. These three contracts, plus
one more expiring in 2030, currently provide 17% to 18% of the energy for the utility's supply
portfolio at prices under $65 per megawatt-hour (MWh). It is difficult to know what renewable
energy prices will be when those contracts expire. Although recent prices have been in that
range, 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. The costs
of the Calaveras hydro project will also change, with debt service costs dropping by half in 2025
as some of the debt is paid off, with 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 there is no
provision for the continuation of these allocations past 2020. 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. 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. However, the utility will also likely
J u n 22 I P a g
UTII.!7Y
begin the rollout of various smart grid technologies, and will also start monitoring 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 the increasing number of rooftop
solar installations. The utility has already started to take some of these factors into account in
its long term planning processes, but will need to continue to incorporate these long-term
issues into its planning methodologies.
Looking out toward 2050 and beyond, if the State were to adopt climate goals consistent with
Executive Orders S-3-05 and B-16-2012 (which state a goal of reducing GHG emissions to 80
percent below 1990 levels by 2050), or if similar local goals were adopted, 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. This scenario would require careful planning for the
associated load growth to make sure the distribution system did not end up overloaded, or
conversely, to avoid overinvestment.
SECTiOI\l Xlll.··· RISI<ASSESSMENT
Each year staff performs a risk assessment to assess the possible contingencies that could affect
the utility's financial position. The contingencies associated with Distribution Fund activities are
assessed separately from Supply Fund contingencies. The Operations Reserves are projected to
be adequate to manage these contingencies over the entire forecast period. As shown in Table
12, staff performs an annual assessment of financial risks for the Distribution Fund due to:
1. the maximum observed one-year distribution revenue variance over the past five years; and
2. an increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 12: Electric Distribution Fund Risk Assessment ($000)
Max. Historical Revenue Variance 8% 8% 8%
,~ffag~~~t'P:~~~tual!li$1<~ , ~ .· 3,4()2 3,402
System Rehabilitation CIP Budget 5,102 4,297
«IPC~i'lftng~ncv @i{}% • '·· 510 430
Total Risk Assessment Value 3,912 3,832 4,091 4,247 4,480
Projected Distribution
Operations Reserve level 11,140 12,460 12,339 12,017 11,474
une J6. 0 4
Ill UTIUT\' FINANCIAL 1'/AN
There are a variety of risks associated with the Supply Fund, which contains the Electric Utility's
supply portfolio. These risks are shown below in Table 13. 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 13 is very low.
Table 13: Electric Supply Fund Risk Assessment
1. Load Net Revenue
2. Production from Hydroelectric
Resources: Western & Calaveras
3. Renewable Production: Landfill &
10. Supplier Default
Electric Supply Fund Risks
Projected Supply Operations +
Stabilization Reserve Levels
0.1
9.3
0.4
million
$47.6
million
12.8
0.4
million
$48.3
million
reduction in
Lower than forecasted hydro
Higher than forecasted renewable output
Of the risks faced by the Electric Utility's Supply Fund, the risk of a dry year with very low
hydroelectric output is 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 still needs to buy
market power to replace the lost output. The converse happens when hydroelectric output is
higher than average. Risks associated with hydroelectric output account for $9.3 million (45%)
of FY 2015 contingencies.
Of the remaining risks for FY 2015, $3.3 million (16%) is related to the projected costs if
transmission cost increases are at the high end of staff's current forecast. Another $3.1 million
(15%) is related to the possibility of changes to WAPA rates for CVP hydropower, and $1.7
million (8%) is related to fluctuations in various market prices. $2.0 million (10%) relates to the
risk associated with the failure of all of the utility's existing landfill gas projects and the costs
associated with replacing that energy at current renewable market prices, though it is highly
unlikely that all three projects would fail.
J ne 16, 014 24 I Page
UTILiTY FINANCIAL PLAN
SECTION XIV. COMMUNICATIONS PLAN
The FY2015 Electric Utility communications strategy covers four primary areas: rates, efficiency,
operations/infrastructure and safety. CPAU has not had an electric rate increase since 2009
and does not expect one in the upcoming year, so there is no need for formal"rate change"
communications at this time, but website and community education about rates is
ongoing. CPAU has been and will continue to communicate about the March 2013 decision to
only purchase carbon-neutral electric supplies, which includes apprising the public of major
renewable energy purchase agreements. Electric use efficiency incentives are promoted year-
round; promotional activity includes bill inserts, website pages, email blasts, 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 ads
in publications, newspaper inserts, social media and email blasts. Safety topics are emphasized
year-round and, while print materials and website pages still feature prominently, CPAU is
turning the outreach emphasis to direct mail, newspaper inserts, social media including video,
cable TV, community safety/emergency preparation meetings and updates to neighborhood
groups. This year, one prominent campaign drew public attention to the ongoing issue of
electrical safety in storms, with the substation crew used as mascots for materials helping
people prepare for and stay safe during windy, wet weather. Also, the ongoing "Keep Calm
and ... " campaign theme was used to launch a new LED light bulb discount program, the latest
technology to be added to the list of efficiency improvements for which rebates are offered.
G _ 0 J 2s I P r;
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Capital Improvement Program (CIP) Detail
Appendix C: Electric Utility Reserves Management Practices
Appendix D: Electric Utility Bond Covenant Details
Appendix E: Description of Electric Utility Cost Categories
Appendix F: Samples of Recent Electric Utility Outreach Communications
j 11 n 1 ~~ ..i ,_) t 26 II' age
ttl'CTf?!C UTtr!TY FINANCIAL PL/~!V
APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
Actual Adopted Projecte
Fiscal Year 2013 2014 2014 2015 2016 2017 2018 2019
•• •. . ·. · .. ··. . . . i~~~l:~
l\s.0.115 $ a·~~~· sc~.i~; .$0.122 f~:£ TOTAL AVERAGE RATE ($/KWH) $ 0.119 0.116 0.126 $ 0.129 I~ COMMODITY COST ($/KWH) $ 0.052 $ 0.063 $ 0.063 $ 0.061 $ 0.062 $ 0.064 $ 0.066 $ 0.065 If\: SALES IN GWH 947 981 965 963 963 965 968 972
[t{ CHANGE IN RETAIL SALES REVENUE 3,089_ 3,085 4,114 2,~1
t Sales of Utilities
Retail Sales 109,189 116,630 111,711 111,530 114,469 117,751 122,226 125,316
Surplus Energy Sales 1,127 2,316 1,063 2,395 2,750 4,867 6,763 6,769
Total, Sales of Utilities 110,316 118,946 112,774 113,925 117,219 122,618 128,989 132,085
I nterest+l nvestment Gain/loss (1,497 3,199 3,199 1,663 2,181 2,396 2,753 2,722
Other Revenues:
Carbon Allowance Revenue 2,713 4,296 4,296 3,910 3,976 4,299 4,493 4,611
Service Connection Charges 1,987 1,160 2,499 2,269 2,269 2,269 2,269 2,269
CVP O&M loan Credit 5,509 6,000 5,407 6,000 6,000 6,000 6,000 6,000
Other Misc. Rev. /Transfers In 1,510 1,660 1,745 (52) 131 1,748 1,748 1,748
Total, Other Revenues 11,720 13,116 13,947 12,127 12,377 14,316 14,510 14,628
Total Sources of Funds 120,538 135,260 129,919 127,715 131,777 139,330 146,252 149,436
Purchases of Utilities
Purchases to Serve Load 54,063 66,205 65,454 63,372 64,801 67,002 68,975 68,102
Surplus Energy Cost 1,740 2,304 1,268 2,595 3,026 4,926 6,663 6,586
CVP O&M Loan Advance 5,511 6,000 5,407 6,000 6,000 6,000 6,000 6,000
Total, Purchases of Utilities 61,314 74,509 72,129 71,967 73,828 77,928 81,638 80,688
Joint Venture Debt Service 9,166 9,024 9,024 9,028 9,040 8,854 8,855 8,709
Administration (CI P +Operating} 9,034 7,174 8,001 8,241 8,489 8,743 9,006 9,276
(ii Customer Service 2,007 2,219 2,252 2,319 2,389 2,460 2,534 2,610
Demand Side Management 3,530 4,214 4,326 6,152 6,139 5,659 5,731 5,846
Engineering (Operating) 1,278 1,605 1,522 1,567 1,614 1,663 1,713 1,764
Operations & Maintenance 9,505 10,602 9,458 9,742 10,035 10,336 10,646 10,965
Resource Management 3,024 5,347 3,213 1,894 1,951 2,009 2,069 2,131
Rent 3,704 3,819 3,819 3,934 4,052 4,173 4,299 4,428
General Fund Transfers 11,768 11,203 11,203 11,098 11,017 10,886 10,815 10,853
Other Transfers Out 322 123 281 123 123 123 123 123
Capital! mprovement Programs 9,775 8,605 4,547 7,467 6,662 9,192 9,842 10,842
Total Uses of Funds 124,425 138,445 129,775 133,532 135,337 142,025 147,270 148,235
Into/ (Out of) Reserves (3,887] (3,185] 144 (5,818] (3,560] . (2,696) J1,019] 1,201
SUPPLY FUND
Reappropriations & Commitments 1,220 1,220 1,220 1,220 1,220 1,220 1,220 1,220
Electric Special Projects 51,838 51,838 53,356 53,356 53,356 53,356 53,356 53,356
Central Valley Project 314 314 ---
Rate Stabilization 65,323 61,305 13,916 8,205 2,596 --
Hydro Stabilization -28,000 28,000 28,000 28,000 28,000 28,000
Operations --19,598 19,593 20,322 20,343 19,647 21,391
Unassigned -------
TOTAL, SUPPLY FUND 118,695 114,676 116,090 110,373 105,494 102,919 102,222 103,967
Risk Assessment Value (Supply) 20,913 25,014
Hydro+ Operations Reserve Level 47,598 47,593 48,322 48,343 47,647 49,391
Supply Operations Reserve:
Min (60 Days Commodity/Operations) 13,065 13,062 13,548 14,110 14,725 14,563
Target (90 Days Commodity/Operations) 19,598 19,593 20,322 21,165 22,087 21,844
Max (120 Days Commodity/Operations) 26,131 26,123 27,095 28,220 29,449 29,126
DISTRIBUTION FUND
Reappropriations & Commitments 16,645 16,645 16,645 16,645 16,645 16,645 16,645 16,645
Plant Replacement 1,000 1,000 0 0 0 0 0 0
Underground Loan 738 738 738 738 738 738 738 738
Public Benefits 2,197 1,215 1,103 ---
Rate Stabilization 3,705 5,520 -- ----
Capital Improvement Program -----
Operations --10,138 11,140 12,460 12,339 12,017 11,474
Unassigned ------
TOTAL, DISTRIBUTION FUND 24,286 25,119 28,625 28,523 29,843 29,722 29,400 28,857
Risk Assessment Value (Distribution) 3,913 3,832 4,090 4,247 4,480
Distribution Operations Reserve:
Min (60 Days O&M) 6,594 6,972 7,081 7,108 7,240 7,401
Target (90 Days O&M) 9,892 10,458 10,621 10,662 10,860 11,102
Max (120 Days O&M) 13,189 13,944 14,162 14,216 14,480 14,802
n e 6 0 27 II' a g c
UI-CTI?IC UTIU!Y FINANCIAL PLAN
APPIZN.OIXB.~ EI,.EGT~IC UTILITY CAPITALIMPROVEMEI\IT P~OGRAM (CIP) DETAIL
310,552 275,000 215,565 280,000 290,000 300,000 300,000 300,000
132,205 180,000 259,198 107,349 185,000 190,000 195,000 195,000 195,000
Electric System Improvements 2,004,352 2,400,000 (900,000} 2,915,214 1,843,781 2,450,000 2,500,000 2,550,000 2,600,000 2,650,000
Utility Site Security 495,996 488,304 420,628 250,000 250,000
230 kV Electric lntertie 162,523 152,109 50,000
Reconductor 60kV Overhead Sys 1,448,301 (350,000} 67,307 62,257
Hanover 22 ~ Xfrmr Replacement 94,009 6,680 5,653
Quarry/Hopkins Substation 60kV line 100,000 750,000
Hansen Way/Hanover 12kV Ties 75,000 200,000 (275,000}
Colorado 20/21 ~Xfrmr Replacement
Sand Hill/ Quarry 12 kV Tie 49,891 200,000 243,397
Underground Dist. System Security 300,000 300,000 300,000
50,000 49,951 400,000
1,794,260
J u b) 2 0 ·1
I.UCTFI!C UTILITY FINANCIAL PLAN
J u ' ) (! 1 29 I P a
APPENDIX C: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a) "Financial Planning Period"-The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b) "Fund Balance"-As used in these Reserves Management Practices, Fund Balance refers
to the Utility's Unrestricted Net Assets.
c) "Net Assets"-The Government Accounting Standards Board defines a Utility's Net
Assets as the difference between its assets and liabilities.
d) "Unrestricted Net Assets"-The portion of the Utility's Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital 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 (Hydro Stabilization Reserve)
e) For rate stabilization, as described in Section 11 (Rate Stabilization Reserves)
f) For operating contingencies, as described in Section 12 (Operations Reserves)
g) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserves for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c) As an offset to underground loan receivables, as described in Section 8 {Underground
Loan Reserve)
d) To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e) For future year expenditure on the Electric Utility's Capital Improvement Program (CIP),
as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 11 (Rate Stabilization Reserves)
June 16, 20Ji\ 30 I Page
UTili! 'I'
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 below 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 he
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. Hydro 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 Hydro
Stabilization Reserve by action of the City Council and held to offset higher commodity
supply costs during years of lower than average generation. Withdrawal of funds from the
Hydro Stabilization Reserve requires action by the City Council.
june :!6, 034 31 I P g
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
Funds may be added to the Electric Distribution Fund CIP Reserve by action of the City
Council and held for future year expenditure on the Electric Utility's CIP Program.
Withdrawal of funds from the CIP Reserve requires City Council action. If there are funds in
the CIP 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 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 Section 11 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
jun 1b, 20J 32 I P 3 rz e
rt; rrnc
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 and commodity expense commodity
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: It at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund's Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund's Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund's Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were
funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an
alternative plan that retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
J u n 33 IP d
I; f UTIL!l Y FINAN CiA!
APPENDIXD: ELECTRIC UTILITY BOND COVENANT DETAILS
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:
2007 Clean Renewable
Energy Bonds
Table 14: Electric Utility Debt Service ($000)
100 100 100 100 100 100
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 complies with this covenant
throughout the forecast period, as shown in Table 15.
Table 15: Electric Utility Debt Service Coverage Ratio ($000)
I;:;; .. J:.~~)g.• ·j· :.•· .•. •.··••· •.. •·· FY.2,Q~4. · t=Y29~s· f:Y2QJ6 FY~Q~7' ·! FY·~gli3~ ·.r:V2b19 .> .· ....•. ·.·
Revenues 129,919 127,715 131,777 139,330 146,252 149,436
Expenses (Excluding CIP
and Debt Service) (125,128) (125,965) (128,575) (132,733) (137,328) (137,293)
Net Revenues 4,791 1,750 3,202 6,597 8,924 12,143
Debt Service 100 100 100 100 100 100
Coverage Ratio 4791% 1750% 3202% 6597% 8924% 12143%
The Electric Utility's reserves and net revenue are also pledged as security for the bond
issuances listed in Table 16, even though the Electric Utility is not responsible for the debt
service payments. The Electric Utility's reserves or net revenues would only be called upon if
the responsible utilities are unable to make their debt service payments. Staff does not
currently foresee this occurring. Amounts advanced from one utility to pay debt service for
another utility will be repaid by the borrowing fund.
J u 4 34 I P <1 g
Table 16: Other Issuances Secured by Electric Utility's Revenues or Reserves
1995 Utility Revenue Bonds,
Series A
1999 Utility Revenue Bonds,
Series A
2009 Water Revenue Bonds
(Build America Bonds)
2011 Utility Revenue
Refunding Bonds, Series A
*Net of Federal interest subsidy
June 16
·····.tt.e .... ).h. o.·.·.•·.n.•. s.Jb.··• ... l.e.>u.·. t.·.n.i.t ... i.e.·.s · t\ll~~iiiQ~bt · . " · · · · · ... :service1$ooo) ·
Storm Drain
Storm Drain
Wastewater Collection
Wastewater Treatment
Water
Gas
Water
$680
$1,207
$1,977*
$1,457
Yes
No
No
No
l)t~Uty'~;
~s~r\r~s
No
Yes
Yes
Yes
35 I P g
UTILI fY
APPENDIX E: DESCRIPTION OF ELECTRIC 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 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.
36 I P a g
APPENDIX F: SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
ATIACHMENTC
1 F
Definitions and Abbreviations ............................................................................................................ 2
Executive Summary ............................................................................................................................ 3
Current State of the Utility ................................................................................................................. 4
Section I. Utility Overview ......................................................................................................................... 4
Section II. Current Rates and Competitiveness ......................................................................................... 5
Section Ill. Rate Design ............................................................................................................................. 6
Section IV. Current Utility Financial Status ............................................................................................... 7
Section V. Status of Reserves .................................................................................................................... 8
Section VI. Debt Service .......................................................................................................................... 10
looking Back .................................................................................................................................... lO
Section VII. Background .......................................................................................................................... 10
Section V/11. Historical Expenses and Revenues ...................................................................................... 11
looking Forward .............................................................................................................................. 13
Section IX. Seven Year Financial Forecast ............................................................................................... 13
1. Overview ....................................................................................................................................... 13
2. Commodity Supply Costs .............................................................................................................. 13
3. Operations .................................................................................................................................... 14
4. Capital Improvement Program (CIP) ............................................................................................ 15
5. General Fund Equity Transfer ....................................................................................................... 16
Section X. Revenue Requirement and Revenue Sources ......................................................................... 16
Section XI. Projected Consumption ......................................................................................................... 18
Section X/1. Long-term Outlook ............................................................................................................... 18
Section X/II. Risk Assessment .................................................................................................................. 19
Section XIV. Communications Plan ......................................................................................................... 20
Appendices ...................................................................................................................................... 21
Appendix A: Gas Utility Financial Forecast Detai/ ................................................................................... 22
Appendix 8: Gas Utility Capita/Improvement Program {CIP} Detail ....................................................... 23
Appendix C: Gas Utility Reserves Management Practices ....................................................................... 25
Appendix D: Gas Utility Debt Service Details ........................................................................................... 28
Appendix£: Description of Gas Utility Cost Categories ........................................................................... 30
Appendix F: Gas Utility Communications Samples .................................................................................. 31
ABS: Acrylonitirile butydene styrene, a plastic gas main material
CARB: California Air Resources Board
CIP: Capital Improvement Program
CPAU: City of Palo Alto Utilities Department
CPUC: California Public Utilities Commission
U! /U IY 1/f\iANC!.A!. PLAN
Crossbore: A crossbore exists when one utility line has been drilled or "bored" through a
portion of another line. Gas crossbores 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.
PE or HDPE: Polyethylene, a gas main material (more specifically, High-Density Polyethylene)
PG&E: Pacific Gas and Electric
PG&E City Gate, or City Gate: 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 City Gate.
PVC: Polyvinyl chloride, a plastic gas main material
Therms: The standard unit of measurement for natural gas sales to customers, equal to 100,000
British thermal units. Measures 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.
u n 1 , 0 2IP ge
GAS UTILI! Y FIIVANCIAL
This document presents a financial plan for the City of Palo Alto's Gas Utility for the next seven
years. The plan uses a seven year forecast period to show the complete drawdown of the Rate
Stabilization Reserve by FY 2021. The 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.
Over the next seven fiscal years staff projects that the Gas Utility will see non-commodity costs
rising at roughly 3% per year, though this will be partially offset by a reduction in costs
associated with the projected completion of the crossbore inspection program in FY 2017. To
match revenues to rising costs, the financial plan includes the rate trajectory shown in Table 1.
This trajectory includes no planned rate increase for FY 2015 to FY 2017. This will allow the
utility to draw down accumulated reserves, which result from the fact that new gas main
replacement projects were not added in FY 2014 and FY 2015 in order to complete an unusually
large project, replacing the last of the ABS plastic mains in Palo Alto. For FY 2018 to FY 2021,
rates are projected to increase 3 to 4% each year. This is equivalent to $1.13 to $1.60 per
month for the median residential customer's monthly gas bill.
Table 1: Projected Gas Rate Trajectory for FY 2015 to FY 2021
FY 2015 FY2016 FY2017 FY 2018 FY 2019 FY 2020 FY2021
0% 0% 0% 3% 3% 4% 3%
This Financial Plan includes a set of Gas Utility Reserves Management Practices. These set forth
the reserves held by the Gas Utility, their purposes, and guidelines for managing them. The
Reserves Management Practices make the following changes to the utility's existing reserves
structure:
1. The addition of an Operations Reserve, a Capital Improvement Program (CIP) Reserve,
and an Unassigned Reserve;
2. The closure of the Supply Rate Stabilization Reserve and the transfer of all funds into the
Operations Reserve; and
3. The closure of the Emergency Plant Replacement Reserve and the transfer of all funds
into the new Operations Reserve.
This plan includes $8.5 million to fund the new Operations Reserve, which will come from the
Emergency Plant Replacement and Rate Stabilization reserves.
Jun 16! 2014 31Page
1)\' i'
SECTION I. UTILITY OVERVIEW
The City of Palo Alto's Gas Utility, operated by the City of Palo Alto Utilities Department (CPAU)
provides natural gas service to the residents, businesses, and other gas customers in Palo Alto.
Over 25,600 customers are connected to the natural gas system, approximately 23,900 (93%) of
which are residential and 1700 (7%) of which are non-residential. Residential customers
consume about 14 million therms of gas per year, 46% of the gas sold, while non-residential
customers consume 54% (about 16.4 million therms). Residential customers use gas primarily
for space heating (42% of gas consumed) and water heating (48%), with the remainder
consumed for other purposes such as cooking, laundry, and heating pools and spas. Non-
residential customers use gas for space and water heating (73% of gas consumed), cooking
(20%), and industrial processes (6%).1
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 a variety of natural
gas marketers, with PG&E providing only local transportation service (transportation from the
PG&E City Gate gas delivery hub across PG&E's distribution system 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 throughout the year. 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. The cost of purchased gas and PG&E local transportation
service accounts for roughly one third of the utility's expenditures.
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 25,460 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 it over time. CIP
expense accounts for 20% of the utility's expenditures.
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 another 30% of the utility's expenses. In addition to these ongoing
1 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.
June 16, 014 4IP g
IL!TY!
activities, CPAU has been implementing a program to find and replace crossbores over the last
several years.
Since its inception the Gas Utility has provided an annual return to the City's General Fund. This
is calculated based on the net book value of the utility's capital assets. This equity transfer to
the General Fund accounts for 15% of the utility's expenses.
SECTIONJI. CURRENT RATES AND COMPETITIVENESS
On July 1, 2012 CPAU restructured its rates to allow the commodity component to vary monthly
to match changes in gas market prices. In addition, monthly service charges were increased to
recover the cost providing gas service to customers. Subsequently, on January 1, 2013, CPAU
changed the local transportation component of its rate to reflect changes to PG&E's local
transportation rates. Table 2, below, summarizes the current rates for all customer classes.
Table 2: Current Gas Rates
G"l G-2 (Small G-Zl (Large
Rate Component Units (Residential} Commercial) Commercial) Last Changed
Service Charge $/month 9.88 74.86 361.18 7/1/2012
Distribution (Tier 1) $/therm 0.3883 0.5638 0.5562 7/1/2012
Distribution (Tier 2) $/therm 0.9037 N/A N/A 7/1/2012
Local transportation $/therm 0.0435 0.0435 0.0435 1/1/2013
Administrative $/therm 0.0074 0.0074 0.0074 7/1/2012
Commodity $/therm 0.5339 0.5339 0.5339 (varies monthly)2
(Feb. 2014) (Feb. 2014) (Feb. 2014)
Tier 1 amount
Winter Therms/day 2 N/A N/A 7/1/2012
Summer Therms/day 0.667 N/A N/A 7/1/2012
Table 3 presents the winter and summer residential bills for Palo Alto and PG&E for several
usage levels. The annual gas bill for the median residential customer for calendar year 2013
was $450.37, 9% higher than the annual bill for a PG&E customer with the same consumption.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, which includes
most surrounding comparison communities. Because both utilities' rates vary from month to
month, only a single sample month is shown for each season.
2 For historic commodity rates see the City's website:
http://www.cityofpaloalto.org/gov/depts/utl/residents/rates.asp
June 1 . 014 S!Pae
lJT!t 17-Y
Table 3: Residential Monthly Natural Gas Bill Comparison ($/month)
Usage %
Season (therms) Palo Alto PG&EZone X Difference
30 37.40 33.86 10%
Winter (Median) 54 59.42 60.96 -3%
(Jan 2014} 80 93.58 96.47 -3%
150 193.88 197.73 -2%
10 18.20 10.66 71%
Summer (Median) 18 24.85 19.29 29%
(Jul 2013) 30 39.99 35.88 11%
45 60.20 56.63 6%
Table 4, below, shows the annual average monthly gas bill for commercial customers for various
usage levels for the same period. Bills for Palo Alto customers at the usage levels shown are
23% to 44% higher than under PG&E's rates.
Table 4: Commercial Monthly Average Gas Bill Comparison (CY 2013, $/month)
%
Usage (tberms/mo) Palo Alto PG&E Difference
500 621 490 27%
5,000 5,539 4,495 23%
10,000 11,004 8,189 34%
50,000 54,626 38,001 44%
PG&E currently has two applications under consideration with the California Public Utilities
Commission (CPUC} that, if approved, will narrow the gap between its rates and CPAU's. The
first, its 2014 General Rate Case application, requests rate increases that would increase its
residential customers' bills by 16% on average and its commercial customers' bills by 8 to 30%
depending on usage level and type of service received. Those increases are intended to take
effect in 2014, though the case is still underway. The second, its 2015 Gas Transmission and
Storage (GT&S) application, requests an increase for residential bills by another 13% and
commercial bills by 16 to 20%. The GT&S application would also increase PG&E's local
transportation rates for Palo Alto, but since these are a small part of the Gas Utility's costs the
overall impact on Palo Alto customer bills will be much smaller. In both cases the increases are
mainly related to improvements to PG&E's pipeline safety and maintenance practices.
The Gas Utility's current rates were structured based on the methodology from the April 2012
Gas Utility Cost of Service Study completed by Utility Financial Solutions.3 Staff tentatively plans
to review this cost of service study in two to three years unless any major changes occur to the
utility's operations or customer base that would necessitate an earlier study. The State's cap-
3 Staff Report 10#2812, Finance Committee, May 17, 2012
J ll 1 1 0 j 4
f!V
and-trade program is one factor that could prompt such an update. Starting in 2015 gas
utilities will be required to purchase carbon allowances equal to the carbon emissions
associated with the gas they deliver. The California Air Resources Board's (CARB's) current draft
proposal is to allocate some allowances to affected gas utilities, just as it did for electric
utilities. Some of these allowances could be used for compliance, but some allowances must be
sold in the quarterly allowance auctions. The Gas Utility is required to use revenue from these
sales for the benefit of gas ratepayers or return it to them directly. Designing rates to
accomplish this could require an update to the cost of service study. Before any such update,
staff will review current rates and the scope of the study with the UAC and Council to
determine UAC and Council policy priorities.
SECTIONJV. CURRENTUTILITY FINANCIAL STATUS
In FY 2013, gas purchases represented a third of the Gas Utility's costs, with CIP and Operations
together representing another 39%. The remaining costs were for administration, overhead,
and other costs (12%), and the General Fund equity transfer (15%), as shown in Figure 2. These
expenditures are also displayed by category of expenditure in Figure 1. The utility's revenue in
FY 2013 came almost entirely from gas sales (96%), with the remainder coming from capacity
and connection fees (2%), and other sources (2%).
Figure 1: FY 2013 Costs by Category
Supplies/
Materials/
Other, 7%
Figure 2: FY 2013 Costs by Activity
For FY 2013 expenses exceeded revenues by $4.7 million, as compared to the $3.4 million
planned in the FY 2013 adopted budget (to draw down reserves). This resulted in reserves
totaling $31.7 million as of June 30, 2013, $11.3 million of which was in the Rate Stabilization
Reserve. Total uses of funds were $39.8 million, which was $1.3 million lower than budgeted.
This was mainly a result of savings in gas supply costs. Total sources of funds were $34.3
million, which was $4.9 million lower than budgeted. This was due in part to the fact that the
Gas Utility passed the supply cost savings directly on to its customers, but also because gas
sales were 5% lower than budgeted.
For FY 2014 net revenues are expected to be $4.0 million, $400,000 greater than the $3.6
million projected in the budget. This is due to projected savings of $1.0 million in various
operating budgets, offset in part by slightly lower than projected sales revenue.
J n 0 Jl} 7 I P g c
UTILITY I''
Table 5: Projected Net Revenue, FY 2014
Gas -Operating Activity All figures in thousands$ (OOO's)
Adopted Unaudited Projected Projected Variance to
Budget Actuals Activity FY 2014 Budget
FY2014 Jut 13-Dec 13 Jan 14-Jun 14 Activity
Net Sales* 37,343 36,746 (597)
Other revenues 1,523 1,480 (43)
Purchase costs (15,171) (15,154) {17)
Other expenses** {20,097) {19,095) 1,002
Total 3,598 3,978 380
* Includes misc. sales, adjustments, discounts, and bad debt
** Includes reserve transfers, salaries, allocated charges, other misc. expenses and
encumbrances
SECTION V. STATUS OF RESERVES
Table 6, below, shows the projected status of the Gas Utility's reserves at the end of FY 2014.
Total reserves at year end (June 30, 2014) are projected to be $30.0 million, of which
$16.2 million will be in the Rate Stabilization Reserves. This plan includes changes to the
structure of the utility's reserves, as detailed in Appendix C: Gas Utility Reserves Management
Practices and in Table 6 below, including:
1. The additions of an Operations Reserve, a Capital Improvement Program (CIP) Reserve,
and an Unassigned Reserve;
2. The closure of the Supply Rate Stabilization Reserve and the transfer of all funds into the
Operations Reserve; and
3. The closure of the Emergency Plant Replacement Reserve and the transfer of all funds
into the new Operations Reserve.
The additions of an Operations Reserve, CIP Reserve, and Unassigned Reserve will add
transparency and simplify reserves management by providing separate reserves for various
functions that are currently all served by the Rate Stabilization Reserves. The Operations
Reserve will be used to manage contingencies and absorb normal year to year cost and revenue
variances. The CIP Reserve will hold funds for expenditure on future budgeted CIP projects.
The Rate Stabilization Reserve will be used to smooth the transition to higher rates. If the
utility accumulates reserves that are not designated for a specific purpose, these will be placed
in the Unassigned Reserve until those funds are either designated for a specific purpose or
returned to ratepayers.
J u n 6' 2. 0 4 8IP F
Table 6: Projected Reserves, 6/30/2014 ($000)
Projected Proposed Projected
Reserve Reallocation After
Levels of Reserves Reallocation
Gas Supply Fund
Reappropriations + Commitments 0 N/A 0
Supply Rate Stabilization Reserve 5,600 -5,600 (closed)
Total 5,600 -5,600 0
Gas Distribution Fund
Reappropriations + Commitments 19,363 N/A 19,363
Emergency Plant Replacement 1,000 -1,000 (closed)
CIP Reserve (new) 0 0
Rate Stabilization Reserve 10,637 -2,946 $7,691
Operations Reserve (new) +8,546 $8,546
Unassigned Reserve (new) 0 0
Total 30,000 +5,600 35,600
Operations Reserve: Days of Expense 90 days
Operations Reserve: Minimum 60 days
Operations Reserve: Target 90 days
Operations Reserve: Maximum 120 days
Creating separate CIP, Rate Stabilization, and Unassigned Reserves allows the utility to set
minimum and maximum guidelines for the Operations Reserve and set forth clear actions to be
taken when it is over or under those levels. If funds are to be held for a specific purpose (for
example, a future CIP project) these can be held in a separate reserve (in this example, the CIP
Reserve). Without a separate reserve, those funds would be held in the Operations Reserve
and could cause it to exceed its maximum guideline, making it difficult to treat the maximum
guideline as a clear limit on the size of the reserve. This proposal also adds transparency, since
the public will be able to see the various purposes for which the utility is holding reserves.
This plan also involves merging the existing Emergency Plant Replacement Reserve into the
Operations Reserve. Currently the Emergency Plant Replacement Reserve holds $1 million,
enough to pay the City's insurance deductible in the event of a loss of utility equipment due to
an insurable loss. Staff believes that even at minimum levels the Operations Reserve has
adequate funding to cover the insurance deductible, making the Emergency Plant Replacement
Reserve duplicative.
The Supply Rate Stabilization Reserve (S-RSR) will also be closed at the end of FY 2014 and the
balance (projected to be $5.6 million) transferred to the Operations Reserve. The S-RSR is no
longer necessary because the adoption of a pass-through, month-varying commodity rate
component has eliminated nearly all gas price risk. As gas market prices change, so does the
rate component, passing the changes through to customers almost immediately. What little
intra-month price risk remains can be balanced using the Operations Reserve.
J u n 1
v!
To complete the funding of the Operations Reserve, $2.9 million will be transferred from the
Distribution Rate Stabilization Reserve (which will now simply be called "the Rate Stabilization
Reserve"), retaining $7.7 million in the Rate Stabilization Reserve to be drawn down over future
years as rates increase. Combined with the $1 million from the Emergency Plant Replacement
Reserve and the funds from the S-RSR, the Operations Reserve's initial funding will be $8.5
million, the target level set forth in Appendix C: Gas Utility Reserves Management Practices
(90 days of commodity and O&M expense).
SECTION VI. DEBT SERVICE
The Gas Utility's annual debt service is roughly $800,000 per year. This is related to one bond
issuance that will require payments through 2026. This issuance, the 2011 Series A Utility
Revenue Refunding Bonds, was a joint issuance between the Gas and Water Utilities refinancing
the 2002 Utility Revenue Bonds, Series A, which was issued to finance various capital
improvements for both systems. The City is in compliance with all covenants on the bond.
Additional detail is provided in Appendix D.
SECTION VII. BACKGROUND
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 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 (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 over 45 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
june 16. /OJ 10 I p E ('
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.4 As of 2013 the Gas Utility
had replaced over 94 miles of steel, ABS, and PVC mains, which represents 45% of the system.
The last ABS main replacement projects are currently underway. This was 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 recent audit.5
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 as well as its competitor, 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 was
to begin purchasing gas from suppliers other than PG&E. In 1997 the CPUC adopted the "Gas
Accord,"6 which enabled the Gas Utility (along with other local transportation-only customers}
to obtain transmission rights on PG&E's Redwood transmission pipeline running from Malin,
Oregon into California.
In 2000 to 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 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 July 2012 Council approved a plan to formally cease the hedging
strategy and pass wholesale gas costs directly to customers through a rate that varied month by
month. The last fixed price gas purchased under the hedging strategy was delivered in October
2013.
Table 7 shows the Gas Utility's expenses and revenues for the past five years. Total costs for
this utility have decreased 13% since 2009, but there were a variety of notable cost increases
4 Staff Report CMR:183:0. Infrastructure Review and Update, March 1, 1990
5 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 A12-11-009/113-03-007 on 5/31/2013
6 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
June 16, 014 11 I P e1 g
UTIUIY rJNANCIAI
and decreases that contributed to this net change. Commodity costs decreased by 46% over
that time due to decreases in gas market prices} but this was offset by increases in the equity
transfer to the General Fund and the cost of distribution fund operations. The FY 2010 through
FY 2013 equity transfers were nearly twice as large as the 2009 transfer due to a change in
methodology adopted in 2009 and first taking effect in FY 2010. Distribution operations costs7
were nearly 35% higher in 2013 than they were in 20091 but much of this was related to
spending on the crossbore program. Excluding the crossbore program, distribution operations
costs have increased 4% per year on average since 2009. Sales revenues decreased in FY 2009
due to a rate decrease prompted by declining gas market prices} and again in FY 2013 as the
utility switched to a pass-through commodity rate. FY 2013 sales volumes were also lower than
normal due to warmer than average weather.
Table 7: Gas Utility Historical Expenses
Utilities Retail Sales 47,250 43,244 42,855 41,034
Service Connection & Capacity Fees 462 451 516 592
Other Revenues & Transfers In 161 1,713 203 103
Interest plus Gain or Loss on Investment 1,614 1,342 821 1,119
Total Sources of Funds 49,487 46,750 44,396 42,847 35,081
Purchases of Utilities:
Supply Commodity 24,486 21,846 20,732 15,356 12,461
Supply Transportation 544 620 706 879 994
Total Purchases 25,029 22,466 21,438 16,235 13,455
Administration (CIP + Operating) 2,181 2,494 2,895 3,473 4,273
Customer Service 1,168 1,134 1,230 1,270 1,358
Demand Side Management 365 428 563 614 630
Engineering (Operating) 310 266 280 333 340
Operations and Maintenance 3,234 3,942 3,297 5,032 4,940
Resource Management 672 696 1,039 729 506
Debt Service Payments 521 505 488 406 296
Rent 205 320 230 230 219
Transfers to General Fund 3,135 5,300 5,304 6,006 5,971
Other Transfers Out 1,648 407 614 170 207
Capital Improvement Programs 7,407 2,389 8,325 7,821 7,562
Total Uses of Funds 45,875 40,348 45,704 42,320 39,756
Into/ Reserves
7 Administration, Demand Side Management, Engineering, O&M, and Resource Management categories inTable 8
J u n 1 6 , 0 12 I P a g e
I iiiJ/\fiJCIAL PLAN
SECTION IX. SEVEN YEAR FINANCIAL FORECAST
1. OVERVIEW
Staff has prepared a forecast of costs and revenues through FY 2021. As shown in Table 8 (and
Appendix A: Gas Utility Financial Forecast Detail), total costs for the Gas Utility are projected
to be at or below FY 2013 levels through FY 2019. Operations costs are projected to increase at
3% per year, but this will be offset by a reduction in costs associated with the projected
completion of the crossbore program by the end of FY 2017. In addition, future ongoing CIP
spending is expected to be lower than it was in FY 2013, a year that saw the commencement of
an unusually large gas main replacement project. The combination of these factors, as well as
the projected accumulation of reserves due to lower CIP budgets in FY 2015 and FY 2016, mean
that CPAU will not need to raise non-commodity rates until FY 2018. FY 2018 through FY 2021
will see 3% to 4% non-commodity rate increases as revenues are brought in line with expenses.
Table 8: Seven Year Gas Financial Forecast Summary
i Actual Adopted Proj. Proj. Proj. Proj. Proj. Proj. Proj. I Proj.
Fiscal Yearl 2013 2014 2014 2015 2016 2017 2018 2019 2020 i 2021
1 RATECHANGE(%)•
2 SALES IN THOUSAND THERMS
Utilities Retail Sales
Service Connection & Capacity Fees
Other Revenues & Transfers In
Interest plus Gain or Loss on Investment
Total Sources of Funds
Purchases of Utilities:
Supply Commodity
Supply Transportation
Total Purchases
Administration (CIP +Operating)
Customer Service
Demand Side Management
Engineering (Operating)
Operations and Maintenance
Resource Management
Debt Service Payments
Rent
Transfers to General Fund
Other Transfers Out
Capital Improvement Programs
Total Uses of Funds
i -13% 0% 0% 0% 0% 0% 3% 3% 4%! 3%
\ 28,901 30,011 28,771 28,881 28,939 28,995 29,060 29.110 29,160 I 29,200
33,759
731
830
(239)
35.081
12.461
994
13,455
4,273
1,358
630
340
4,940
506
296
219
5,971
207
37,343 36,746 34,942 35,150 34,874 36,197 37,864 39,718 41.164
579 580 602 640 662 686 706 706 706
129 112 262 262 262 262 412 412 412
815 693 226 324 321 315 282 261 244
38,865 38.131 36,032 36,376 36,119 37,460 39,264 41,096 42,526
13.793 13.724 12,484 12,504 12,165 12,236 12,603 12,981 13,169
1.377 1,429 1.248 1,522 1,571 1.622 1,673 1.726 1,780
15,170 15,153 13,731 14,026 13,736 13,858 14,276 14.708 14,950
3,352
1.383
1,318
366
4,031
728
801
225
5,811
472
3.891
1,409
610
308
5,060
522
802
225
5,786
206
4,036
1.524
628
319
5,142
758
803
232
5,650
213
4.156
1,568
647
328
5,292
780
804
239
5,802
219
4.290
1,632
667
340
5.491
809
803
246
6.102
225
4,428
1.699
687
353
4,698
840
802
253
6,342
232
4,571 4,719 4,871
1 ,769 1 ,842 1 ,918
708 730 752
367 381 396
4,883 5,076 5,276
871 904 938
801 801 803
261 269 277
6,644 6,968 7,306
239 246 254
7,562 1,595 240 1,816 5.224 4,714 4,822 4,942 4,942 4,942
39,756 35.253 34,212 34,853 39,086 39,057 39,015 40,332 41,584 42,682
future years, only non-commodity rate changes are shown. Commodity rates will vary monthly with market prices.
2. COMMODITY SUPPLY COSTS
The Gas Utility purchases much of its gas for delivery at Malin, which is almost always cheaper
than 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. Commodity costs are
J u n 1 G, 131Page
y
expected to stay steady or decline slightly over the next several years. Figure 2, below, 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 are based on
rates adopted in the most recent update to the Gas Accord.
Local transportation costs decrease on January 1, 2015 due to the expiration of a temporary
adder to PG&E's local transportation rate,8 but in December 2014 PG&E applied to the CPUC to
more than double local transportation costs. In the past the CPUC has only partially approved
such applications, so for future years, staff assumes a one-time 50% increase in local
transportation costs in FY 2016, escalating at 3% per year in subsequent years.
$4.50
$4.00
$3.50
$3.00
$2.50
$2.00
$1.50
$1.00
$0.50
$0.00
Figure 2: Wholesale Gas Price Projections
FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021
OPERATIONS
City Gate
Malin
Operations costs include the Customer Service, Demand Side Management, Operations and
Maintenance, Engineering, Resource Management, and Administration categories in Table 8,
above. Debt service, rent, and transfers are also included in Operations costs (excluding the
General Fund equity transfer). Appendix E: Description of Gas Utility Cost Categories includes
detailed descriptions of the activities associated with these cost categories. Operations costs
are projected to increase by 3% per year. Salary and benefits, inflation, and other assumptions
match those used in the City's long-range financial forecast.
Operations costs for FY 2015 to FY 2017 include funding for the crossbore 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 crossbores, which happen
when a gas service is bored through a sewer lateral. Though crossbores are very rare, they can
create a dangerous situation when a contractor attempts to clear a blocked sewer line, because
8 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.
JUIH' 16, 2014 14 I Page
FJ!V/\NClliL
if the crossbored 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 $1 million per year since FY 2012, and will likely require
additional funding in future years to complete.
4. CAPITAL IMPROVEMENT PROGRAM (CIP)
The Gas Utility's CIP program consists of the following programs and budgets:
e The Gas Main Replacement Program, under which the Gas Utility replaces aging gas
mains
e Customer Connections, which covers the cost when the Gas Utility installs new services
or upgrades existing services at a customer's request in response to development or
redevelopment. The Gas Utility charges a fee to these customers to cover the cost of
these projects.
e Ongoing Projects, which covers the cost of routine meter, regulator, and service
replacement, minor projects to improve reliability or increase capacity, and other
general improvements.
e Tools and Equipment, which covers the cost of capitalized equipment, such as
directional boring equipment.
e One-time Projects, which represents occasional large projects that do not fall into any
other category.
Table 9 shows the current status of these project categories and future budgeted spending.
Table 9: Budgeted Gas CIP Spending
--?-""~ 7~ "' ' ~ ~ ,_,~$ "" -~c~rre"nr '''5PJndTni;''lli' Remain:~~ ~'~'"' "''"'·,~v-,y~--"=«'~"'~y fc, *' c,, ·~~, "'""'""''9 --
PJoject Category ' l!l!ctget* ~±urr, Yr y J~~:t{g~t ~oml)li}jE!d FY 20!5 FUQl& ' FY 2Q17 FY ~018 FY 2QJ.~~
One Time Projects 42 -42 -150 ----
Gas Main Replacement 15,377 (1,429) 13,948 11,623 603 4,161 3,650 3,785 3,878
Tools And Equipment 589 (35) 554 318 100 100 100 100 100
Ongoing Projects 1,117 (157) 960 236 737 763 785 809 833
Customer Connections 820 (370) 449 11 752 790 812 836 861
TOTAL 17,944 (1,991) 15,953 12,188 2,341 5,813 5,347 5,530 5,673
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year
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 VII. Background
for more detail). CPAU has temporarily slowed down its new CIP appropriations in this category
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. A lower rate of ongoing spending on main
replacement is projected after this project is complete, approximately three miles of main each
year, or 1.5% of the system. With the replacement of all ABS mains with PE plastic, the material
at high 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 will
perform a study in 2014 to determine which areas of the system to prioritize.
June 16, OJ 15 I P il g e
if
Ongoing Projects, Tools and Equipment, and Customer Connections are projected to cost
approximately $1.2 million in FY 2015 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 2015 to FY 2019 is funded by utility rates. The details of the plan are shown in Appendix B:
Gas Utility Capita/Improvement Program (CIP) Detail.
5. GENERAL FUND EQUITY TRANSFER
The City calculates the equity transfer from its Gas Utility based on a rate of return on the net
book value of the utility's capital assets9• Council adopted this methodology in 2009 and it was
first used for FY 2010. Based on forecasted rates of capital investment and depreciation, the
equity transfer is projected to increase by 3% to 5% per year over the forecast period.
SECTION X. REVENUI!REQUIREMENTANDREVENUE SOURCES
The Gas Fund's costs and revenues from FY 2013 through FY 2021 are shown in Figure 3 below.
Only distribution rate changes are shown. Revenues will be sufficient to cover costs FY 2014
and FY 2015, but the utility will draw down reserves in the following two fiscal years. From FY
2018 to FY 2021 rates will need to increase 3% to 4% per year to match revenues to costs. Each
of the projected FY 2018 to FY 2021 rate increases will increase the median residential monthly
gas bill by $1.13 to $1.60 per month.
9 For more detail, see City Manager's Report 260:09, Finance Committee, May 26, 2009.
JunE:' J . 0 4 16 I I' g
$50
$45
$40
$35
{j)
$30
c
§ $25
2
y; $20
$15
$10
$5
$0
Figure 3: Gas Utility Revenue and Cost Projections
0%
. Proj. Projected
Revenue
Iii! Purchases
DCIP
llll Operations
E!IIGF
Transfers
~!!~~Debt
Service
This rate trajectory draws the Rate Stabilization Reserve down to zero by FY 2021, as shown in
Figure 4. Figure 4 also includes the proposed reallocations of reserves described in Section V.
Status of Reserves.
_$45
"' 5 $40
~ $35
-$30
$25
$20
$15
$10
$5
$0
Jun 16;
Figure 4: Gas Utility Revenue and Cost Projections
Projected FY 2014 year-end reserves under existing reserves structure
Proposed reallocation (see Section V. Status of Reserves)
. ,; ,.
Rate Stabilization
Operations Reserve
Plant Replacement
Reappropriations +
Commitments
17 I P a g
SECTION XI. PROJECTED CONSUMPTION
Gas usage in Palo Alto is volatile, varying with both the economic and weather conditions. After
a significant drop in usage from 40.7 million therms in FY 1999 to 31.5 million therms in FY
2004, gas usage stabilized somewhat, but continued with its general downward trend,
decreasing by 3.2% in total during the next five years as a result of continued investments in
energy efficiency (EE), reaching 30.5 million therms in FY 2009. Gas consumption is projected
to stay stable over the forecast period, with growth being offset by gas efficiency savings.
Figure 5 presents the historical gas consumption levels (with and without the gas EE programs)
from FY 2004 through FY 2012 and projections for FY 2014 through FY 2021.
Figure 5: Historic and Projected Gas Consumption
Ill I: .2 34.0
:?!
32.0
30.0
Ill E 28.0 ...
OJ
..!:: 1--Gas Sales w/o EE
26.0 -'"'Gas Sales
24.0
22.0
20.0
SECTION XII. LONG.:TERM OUTLOOK
In the longer term (5 to 35 years) 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 tracking, could continue to
J ne 1 , 014 18 I P
UTILITY f iNAN(JAL
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 might drive gas demand lower. It is also difficult to predict
the magnitude of the additional cost impacts associated with cap and trade 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.
As discussed in Section IX. Seven Year Financial Forecast, the future CIP investment needs for
the Gas Utility may be lower than in the past. The Gas Utility has replaced all of its ABS gas
mains and its most problematic steel and PVC mains as well. The PE pipe that is replacing it 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
performing a study in 2014 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.
Assembly Bill 32 (AB32) set a goal of reducing greenhouse gas (GHG) emissions to 1990 levels
by 2020 and then maintaining those reductions. The City has similar goals in its December 2007
Climate Protection Plan, in which it 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. If stricter goals are enacted at the
state or local level, however, it could lead to stranded investment and higher rates as the costs
of the distribution system are recovered over a lower sales base. One example of a stricter
standard is the one the Governor has stated: reducing GHG emissions to 80 percent below 1990
levels by 2050.10 This goal, or less ambitious interim goals, would require legislation to
implement, but it is instructional that in the recent discussion draft of its scoping plan update
CARB says that to meet them, natural gas use would have to be "mostly phased out."11 As
stewards of the Gas Utility, the City should continue to stay aware of developments in state
climate planning, participate as a stakeholder, and consider these types of impacts and ways to
mitigate them when developing its own sustainability goals.
Staff performs an annual assessment of financial risks for the Gas Utility due to:
1. the maximum observed one-year distribution revenue variance over the past five years; and
2. an increase of 10% of planned system improvement CIP expenditures for the budget year.
Commodity price risk is not included in the risk assessment because these costs are passed
directly to customers each month. Table 10 summarizes the risk assessment calculation for the
Gas Utility. The Operations Reserve is projected to be adequate to manage these levels of risk
over the entire forecast period.
10 Executive Orders S-3-05 and B-16-2012.
11 Climate Change Scoping Plan, First Update, Discussion Draft for Public Review and Comment, California Air
Resources Board, October 2013, pg 88.
June 1b, 20 4 19 I P
Table 10: Gas Utility Risk Assessment ($000)
.· ... · ·. FV2015 FV2016 FV2017 FV2018 FV2019 FY2020 FY2.021 ... . ·<
Total Revenue 20,870 20,910 20,923 22,141 23,373 24,783 25,975
Max. Historical Revenue Variance 5% 5% 5% 5% 5% 5% 5%
BudgeHo-Actual Risk 1,044 1,046 1,046 1,107 l,l69 1,239 1,299
System Rehabilitation CIP Budget 1,816 5,224 4,714 4,822 4,942 4,942 4,942
CIP Contiogency @:tO% 182 522 471 482 494 494 494
Total Risk Assessment Value 1,226 1,568 1,517 1,589 1,663 1,733 1,793
Projected Operations Reserve Level 8,380 8,465 8,588 8,556 8,331 8,761 9,092
SECTION XIV. COMMUNICATIONS PlAN
The FY2015 Gas Utility communications strategy covers four primary areas: rates, efficiency,
operations/infrastructure and safety. Since CPAU has moved to market pricing for commodity
rates, and because there are no projected distribution rate changes over this forecast period,
there is no need for formal"rate change" communications at this time, but website and
community education about rates is ongoing. 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 activity includes
bill inserts, website pages, email blasts, 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 ads in
publications, newspaper inserts, social media and email blasts. Safety topics are emphasized
year-round and, while print materials and website pages still feature prominently, CPAU is
turning the outreach emphasis to direct mail, newspaper inserts, social media including video,
cable TV, community safety/emergency preparation meetings and updates to neighborhood
groups.
Stepping up efforts to promote gas safety education, staff focused on youth, obscured meters
and anyone who digs. For younger "customers-to-be" CPAU created a Home Safety Detective
campaign that included special tool kits to help them identify home safety problems. Meter
access awareness was raised via materials featuring photos of the unbelievable ways people
obstruct access to their meters, including using them as bike racks and building storage sheds
around them. Residents of all ages, as well as construction companies etc. were targeted by
the pirate-themed "Call 811 Before you Dig" campaign which emphasized the dangers of doing
any kind of serious excavation without having underground utilities marked first.
J u n 6t 20 I P g e
Appendix A: Gas Utility Financial Forecast Detail
Appendix B: Gas Utility Capital Improvement Program (CIP} Detail
Appendix C: Gas Utility Reserves Management Practices
Appendix D: Gas Utility Debt Service Details
Appendix E: Description of Gas Utility Cost Categories
Appendix F: Gas Utility Communications Samples
J u e 1 ] 4 21 I P a g
APPENDIX A: GAS UTILITY FINANCIALFORECAST DETAIL
Actual Adopted Proj. Proj. ! Proj. Proj. j Proj. Proj. Proj. Proj.
Fiscal Year 2013 2014 2014 2015 2016 2017 2018 2019 2020 2021
1 RATE CHANGE(%)' -13% 0% 0% 0%i 0% O%j 3% 3% 4% 3%
2 SALES IN THOUSAND THERMS 28,901 30,011 28,771 28,881 i 28,939 28,995 29,060 29,110 29,160 29,200 $
4 Utilities Retail Sales 33,759 37,343 36,746 34,942 ; 35,150 34,874 36,197 37,864 39,718 41,164 , Service Connection & Capacity Fees 731 i 579 580 602. 640 662 686 706 706 706 ! Other Revenues & Transfers In 830 I 129 112 262 ' 262 262 262 412 412 412
; Interest plus Gain or Loss on Investment (239)1 815 693 226' 324 321 315 282 261 244
Total Sources of Funds 35,081 38,865 38,131 36,032 ' 36,376 36,119 37,460 39,264 41,096 42,526
1a
Purchases of Utilities:
I:: Supply Commodity , :::I 13,793 13,724 12,484 12,504 12,165 12,236 12,603 12,981 13,169
Supply Transportation 1,377 1,429 1,248 1,522 1,571 1,622 1,673 1,726 1,780 ~i1l Total Purchases 13,455 15,170 15,153 13,731 14,026 13,736 13,858 14,276 14,708 14,950
Administration (CIP +Operating) 4,273 3,352 3,891 4,036 4,156 4,290 4,428 4,571 4,719 4,871
Customer Service 1,358 1,383 1,409 1,524 1,568 1,632 1,699 1,769 1,842 1,918
Demand Side Management 630 1,318 610 628 647 667 687 708 730 752
Engineering (Operating) 340 366 308 319 328 340 353 367 381 396
Operations and Maintenance 4,940 4,031 5,060 5,142 5,292 5,491 4,698 4,883 5,076 5,276 (: j: Resource Management 506 728 522 758 780 809 840 871 904 938
l;t Debt Service Payments 296 i 801 802 803 804 803 802 801 801 803
Rent 219 225 225 232 239 246 253 261 269 277 w ~~ Transfers to General Fund 5,971 5,811 5,786 5,650 5,802 6,102 6,342 6,644 6,968 7,306
Other Transfers Out 207 472 206 213 219 225 232 239 246 254 IJ Capital Improvement Programs 7,562 1,595 240 1,816 5,224 4,714 4,822 4,942 4,942 4,942
Total Uses of Funds 39,756 35,253 34,212 34,853 39,086 39,057 39,015 40,332 41,584 42,682
Into/ (Out of) Reserves 14,675 3,612 3,919 1,179 (2,710 (2,937 (1,554 (1,068 (488 (156
29
30 Reappropriations +Commitments 19,363 19,363 19,363 19,363 19,363 19,363 19,363 19,363 19,363 19,363
31 Plant Replacement 1,000 1,000 0 0 0 0 0 0 0 0 32 CIP Reserve 0 0 0 0 0 0 0 0 0 0
33 Rate Stabilization 11,318 14,916 7,691 9,036 6,379 3,508 1,980 587 0 0
34 Operations Reserve 0 0 8,546 8,380 8,591 8,718 8,690 8,994 9,133 9,054
35 Unassigned 0 0 0 0 0 0 0 0 0 0
36 Total Reserves 31,681 35,279 35,600 36,779 34,332 31,589 30,033 28,945128,496 28,417
37
36 ShortT erm Risk Assessment Value
39
40 Operations Reserve Guidelines
41 Min (60 Days Commodity+ O&M) 5,697 5,587 5,727 5,812 5,793 5,996 6,209 6,396
42 Target (60 Days Commodity+ O&M) 8,546 8,380 8,591 8,718 8,690 8,994 9,313 9,594
43 Max (60 Days Commodity+ O&M) 11,395 11,174 11,454 11,624 11,586 11,993 12,417 12,792
44
J u 22 I P g e
APPEN[)IX B: GAS l.;ffiiJTYCAPITALIMP;ROVEMENTPBOGRAIVI{CIP) DETAil
52
4,673
3,517,548
6,232,030
4,193,363
2,051,126
6,032,679
3,539,566
GAS t!T!UTV FINANCIAL PLAN
602,575 3,540,000
620,650 3,010,000
640,000 3,100,000
23 I P ,;
GAS UTiLITY fiNANCiAL PLAN
J u 0 j 241 p il
PLAN
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 (Reserves for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
Section 3. Distribution Fund Reserves
The Gas Utility's 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) For future year expenditure on 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. Reserves for Commitments
At the end of each fiscal year the Gas Supply Fund and Gas 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 Gas Supply Fund and Gas Distribution Fund, respectively, at
that time.
b 1 0 4 25 I Page
iT\
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Gas Supply Fund and Gas 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. CIP Reserve
Funds may be added to or withdrawn from the CIP Reserve by action of the City Council and
held for future year expenditure on the Gas Utility's CIP Program. Withdrawal of funds from
the CIP Reserve requires Council action. If there are funds in the CIP Reserve at the end of
any fiscal year, any subsequent Gas Utility Financial Plan must result in the withdrawal of all
funds from this Reserve by the end of the Financial Planning Period.
Section 7. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and held
to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate
Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization
Reserve at the end of any fiscal year, any subsequent Gas Utility Financial Plan must result
in the withdrawal of all funds from this Reserve by the end of the Financial Planning Period.
Section 8. Operations Reserve
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 to 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 in for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense 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
J n 16, 20J 26 I P r-e
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
d) Maximum level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this Reserve. Any further increase in the Gas Utility's Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
9, below.
Section 9. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas
Utility's Fund Balance will be held in the Unassigned Reserve. If there are any funds in the
Unassigned Reserve at the end of any fiscal year, the next Financial Plan presented to the
City Council must include a plan to assign them to a specific purpose or return them to the
Gas Utility ratepayers by the end of the first fiscal year of the next Financial Planning Period.
For example, if there were funds in the Unassigned Reserves at the end of FY 2015, and the
next Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a
plan to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff
may present an alternative plan that retains these funds or returns them over a longer
period of time.
Section 10. Intra-Utility Transfers between Supply and Distribution Funds
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.
u n 1 , 27 I P ,., c c
y
APPENDIX D: GAS UTILITY DEBT SERVICE DETAILS
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 11. Debt service on this bond will continue through 2026.
2011 Utility
Revenue
Refunding
Bonds, Series A
802
Table 11: Gas Utility Debt Service
803 804 803 802 801 801 803
The 2011 bonds include two covenants stating that 1) the Gas Utility will maintain a debt
coverage ratio of 12.5% of debt service, and 2.) that the City will maintain "Available Reserves"12
equal to five times the annual debt service. The current financial plan complies with these
covenants throughout the forecast period, as shown in Table 12 and Table 13.
Table 12; Debt Service Coverage Ratio ($600)
.·. .·•FV2014·· .FV~()tS 1. FY ZOJ.J; · fY~I)17 FV:Zo18 FY2Q19 FY21)20 ··. FY2021
Revenues 38,131 36,032 35,869 35,596 36,920 36,588 38,871 41,934
Expenses
(Excluding CIP and (33,171) (32,235) (32,549) (33,014) (32,847) (31,901) (33,605) (36,342)
Debt Service)
Net Revenues 4,960 3,797 3,320 2,582 4,073 4,687 5,266 5,592
Debt Service 802 803 804 803 802 801 801 803
Coverage Ratio 618% 473% 413% 322% 508% 585% 657% 696%
Table 13: Debt Service Minimum Reserves ($000)
(· •.. F .···•·.··. ... FV20;1.~· l.fv;zois f~irii6 .. :r¥zoJJ• .fZY~01t4c' FY(Ztll~. <FVz(lzo· . FV201i lc ..... •: · ... ·.
Gas Utilitl 16,237 17,416 14,972 12,231 10,678 9,604 9,167 9,092
Debt Serviceb 802 803 804 803 802 801 801 803
Reserves Ratioc 20x 22x 19x 15x 13x 12x llx llx
a) C/P, 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 14, 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
12 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities
28 I P a g
occurring. Amounts advanced from one utility to pay debt service for another utility will be
repaid by the borrowing fund.
Table 14: Other Issuances Secured by Gas Utility's Revenues or Reserves
1995 Series A Utility
Revenue Bonds
1999 Utility Revenue
Bonds, Series A
2009 Water Revenue
Bonds (Build America
Bonds)
",
'
Storm Drain
Wastewater Collection
Wastewater Treatment
Storm Drain
Water
*Net of Federal interest subsidy
16, 20 /j
$680 Yes
$1,207 No
$1,977* No
No
Yes
Yes
29 I P
APPENDIX E: 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:
111 surveying the gas system (50% of the system each year) and repairing any leaks found;
111 investigating reports of damaged mains or services and perform emergency repairs;
111 building and replacing gas services for new or redeveloped buildings; and
111 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:
o the Field Services team (which does field research of various customer service issues);
111 the Cathodic Protection team (which monitors and maintains the systems that prevent
corrosion in metal pipes and reservoirs); and
111 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.
Jun J(,, (L! 30 I P
APPENDIX F: GAS UTILITY COMMUNICATIONS SAMPLES
ATIACHMENT D
15
Definitions and Abbreviations ............................................................................................... 2
Executive Summary ............................................................................................................... 2
Current State of the Utility .................................................................................................... 3
Section f. Utility Overview ........................................................................................................... 3
Section II. Current Rates and Competitiveness ........................................................................... 4
Section Iff. Rate Design ............................................................................................................... 5
Section IV. Current Utility Financial Status ................................................................................. 5
Section V. Status of Reserves ...................................................................................................... 7
Section VI. Debt Service .............................................................................................................. 8
looking Back ......................................................................................................................... 8
Section VII. Background .............................................................................................................. 8
Section VIII. Historical Expenses and Revenues ........................................................................ 10
looking Forward .................................................................................................................. 10
Section IX. Five Year Financial Forecast .................................................................................... 10
1. Overview ...................................................................................................................... 10
2. Treatment Costs ........................................................................................................... 11
3. Operations .................................................................................................................... 12
4. Capital Improvement Program (CIP) ............................................................................ 12
Section X. Revenue Requirement and Revenue Sources ........................................................... 14
Section XI. Risk Assessment ...................................................................................................... 15
Section XII. Long-term Outlook ................................................................................................. 16
Section XIII. Communications Plan ........................................................................................... 16
Appendices ......................................................................................................................... 17
Appendix A: Wastewater Collection Financial Forecast Detail .................................................. 18
Appendix 8: Wastewater Collection Utility Capita/Improvement Program {CIP) Detail .......... 19
Appendix C: Wastewater Collection Utility Reserves Management Practices .......................... 20
Appendix D: Wastewater Collection Debt Service Details ......................................................... 23
Appendix E: Sample of Wastewater Collection Outreach Materials ......................................... 25
FINANCIAL
CCF-the standard unit of measurement for water delivered to water customers. Equal to one
hundred cubic feet, or roughly 748 gallons. When water usage is used to assess wastewater
charges for commercial customers, it is measured in CCF.
CIP-Capital Improvement Program
CPAU -City of Palo Alto Utilities Department
FOG-Fats, oils, and grease. When flushed into the sewer system, these materials accumulate
in parts of the sewer system and create blockages.
RWQCP -Regional Water Quality Control Plant, the wastewater treatment plant owned and
operated by the City of Palo Alto that serves Palo Alto and several surrounding communities.
This document presents a financial plan for the City of Palo Alto's Wastewater Collection Utility
for the next five years. It 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.
Over the next five fiscal years staff projects that the Wastewater Collection Utility will see
wastewater treatment costs rising 4% to 5% per year and other costs rising at roughly 3% per
year. To match revenues to these rising costs, the financial plan includes the rate trajectory
shown in Table 1. No increase is planned for FY 2015, and for FY 2016 to FY 2019 rates are
projected to increase 7% per year.
These projected rate increases are equivalent to an increase of $2.05 to $2.51 per month for a
residential customer's sewer bill. This rate trajectory will allow the utility to draw down
accumulated reserves, which resulted from the fact that staff did not add a new sewer main
replacement project in FY 2014 and a one-time decrease in treatment costs related to a change
in billing methodology by Palo Alto's Regional Water Quality Control Plant (RWQCP).
Table 1: Projected Wastewater Collection Rate Trajectory for FY 2015 to FY 2019
FY2015 FY2016 FY 2017 FY2018 FY2019
0% 7% 7% 7% 7%
In addition, this Financial Plan includes the Wastewater Collection Utility Reserves Management
Practices. These set forth the various reserves held by the Wastewater Collection Utility, their
purposes, and guidelines for managing them. The Reserves Management Practices make the
following changes to the utility's existing reserves structure:
J u n
o The addition of an Operations Reserve, a Capital Improvement Program (CIP)
Reserve, and an Unassigned Reserve
b, 2014 21Pa c
o The merger of the Emergency Plant Replacement Reserve into the new
Operations Reserve
To fund the new Operations Reserve, a transfer of $2.7 million from the Rate Stabilization
Reserve to the Operations Reserve is included in this plan.
SECfiON I. UTILITY OVERVIEW
The City of Palo Alto's Wastewater Collection Utility, operated by the City of Palo Alto Utilities
Department (CPAU) provides sewer service to the residents and businesses of Palo Alto. It is
distinct from the Wastewater Treatment Utility, operated by the City of Palo Alto Public Works
Department, which provides treatment services for surrounding communities in addition to
Palo Alto. Nearly 27,200 customers are connected to the sewer system, approximately 25,600
(94%) of which are residential and 1,600 (6%) of which are non-residential. Residential
customers pay a flat fee for service. Non-residential customers are billed for sewer service
based on their metered winter water usage. There is little variability in revenues for this utility.
The Wastewater Collection Utility delivers all the wastewater it collects to the RWQCP, a
treatment plant run by the City of Palo Alto under a partnership agreement with several
surrounding communities. Palo Alto is responsible for 38% to 40% of the wastewater sent to
the RWQCP. The cost of running the RWQCP is contained in the Wastewater Treatment Utility
and is not described in detail in this Financial Plan, but since these costs are a major driver of
CPAU's sewer rates there is some discussion of future trends in treatment costs in Section IX.
Five Year Financial Forecast. Treatment costs make up nearly half of the Wastewater Collection
Utility's expenses.
To collect wastewater from its customers and deliver it to the Regional Water Quality Control
Plant (RWQCP), the utility owns roughly 18,000 sewer laterals (which collect wastewater from
customers' plumbing systems) and 217 miles of sewer mains (which transport the waste to the
treatment plant). These laterals and mains, along with the associated manholes and cleanouts,
represent the vast majority of infrastructure used to collect wastewater in Palo Alto. CPAU
conducts a sewer rehabilitation and replacement program to replace mains over time as they
deteriorate or to increase capacity. For more discussion of this program, see Section IX. Five
Year Financial Forecast. CIP expense accounts for roughly a quarter of the utility's
expenditures.
In addition to its CIP, CPAU performs various maintenance activities on the sewer system.
These include inspecting and repairing sewer laterals, responding to sewer overflows, regularly
cleaning sections of the system heavily impacted by fats, oils, and grease (FOG), and building
and replacing sewer laterals for new or redeveloped buildings. The utility also shares the costs
of other operational activities (such as customer service, billing, equipment maintenance, and
street restoration) with the City's other utilities. These maintenance and operations expenses,
as well as associated administration, debt service, rent, and other costs, make up another
quarter of the utility's expenses.
J u n 0 J L] 3IP
SECTION II. CURRENT RATES AND COMPETITIVENESS
The current rates were adopted July 1, 2012, when CPAU increased sewer rates by 5%. The rate
change included a revenue-neutral change to the billing methodology for commercial
customers. CPAU now bases its sewer rates for commercial customers on the previous winter's
water use as opposed to the water use in the actual billing month. This closely approximates
non-irrigation water consumption, which represents actual sewer use.
Table 2, below, summarizes the current rates for all customer classes. CPAU has three sewer
rate schedules: one for residents (S-1), one for commercial customers (S-2), and a special
schedule for restaurants (S-6), which discharge higher than average strengths of grease and oil
and therefore have a greater impact on the sewer system. CPAU also maintains a rate schedule
for industrial dischargers (S-7), but there are currently no customers required to be on this rate
schedule.
Table 2: Current Sewer Rates (Effective 7 /1/2012)
S-1 S-2 S-6
Rate Component Units (Residential) (Commercial) (Restaurant)
Monthly Service Charge $/month 29.31 29.31 29.31
Quantity Rate $/CCF -5.65 8.73
Table 3 shows the sewer bills for residential customers compared to what they would be under
surrounding communities' rate schedules. The annual sewer bill for a Palo Alto customer is
$351.72 under current rates, 30% lower than the average neighboring community. Palo Alto
has the third lowest monthly rate of the group.
Table 3: Residential Monthly Sewer Bill Comparison
Neighboring Communities Neighboring
Menlo Redwood Mountain Santa Community
Palo Alto Park City View Los Altos Clara Hayward Average
29.31 68.33 63.09 26.10 32.36 33.00 27.27 41.69
Based onratesas of January 1/ 2014
Table 4 compares the sewer bills for two classes of commercial customers to what they would
be under surrounding communities' rate schedules. Note that other communities often have
specific rates for industrial customers that discharge high intensity wastewater, such as food
processors or chemical or electronics manufacturers, but Palo Alto does not currently have any
customers that require these special rates. The annual bill for the median Palo Alto commercial
customer is $949, 10% above the average neighboring community. For the average restaurant
the annual bill is $5,867, 7% above the average neighboring community.
J u e 1 0 4 4 I P a g
F/N/\fVC/1\l
Table 4: Commercial Monthly Sewer Bill Comparison
Neighboring Communities Neighboring
Menlo Redwood Mountain Santa Community
Palo Alto Park City View Los Altos Clara Hayward Average
General $79.10 $120.80 $82.88 $54.40 $49.84 $53.71 $69.76 $71.90 Commercial
Restaurant $488.88 $527.52 $703.92 $372.40 $199.36 $420.84 $515.20 $456.54
Based on rates as of January1, 2014
SECTION Ill. RATE DESIGN
The Wastewater Collection Utility's rates are evaluated and implemented in compliance with
the cost of service requirements and procedural rules set forth in the California Constitution
(Proposition 218). Current rates were structured based on the methodology from the January
2011 Wastewater Collection Utility Cost of Service & Rate Study completed by Utility Financial
Solutions1. Staff tentatively plans to review and update this cost of service study in 2 to 3 years,
unless any major changes occur to the utility's operations or customer base that would
necessitate an earlier study. Before conducting any new cost of service study, staff will review
current rates and the scope of the study with the UAC and Council to determine UAC and
Council policy priorities.
SECtiON' IV. CURREN1 UTILITY. FINANCIAL STATUS
In FY 2013, treatment costs represented nearly half ofthe Wastewater Collection Utility's costs,
with the CIP being the next largest expense (23% of costs), then Operations (16%), and finally
administration, overhead, and other costs (14%), as shown in Figure 2. These expenditures are
also displayed by category of expenditure in Figure 1. The utility's revenue in FY 2013 came
primarily from sewer charges (88%), with the remainder coming from capacity and connection
fees (9%L and other sources (3%).
1 Staff Report 10#1399, Finance Committee, March 1, 2011
J u e 1 SIP
Figure 1: FY 2013 Costs by Category
Admin/
14%
Supplies/
Materials/
Other, 5%
47%
Ffl\ll{f\I(J/1L
Figure 2: FY 2013 Costs by Activity
Overhead,
11%
Operations/
16%
Other,3%
Table 5 contains a summary of the Wastewater Collection Utility's financial outlook for FY 2014.
Sales are very stable since 53% of sales are to residential customers, whose rate consists of
fixed monthly service charges. A component of business sales revenues is based on winter
water use levels, which are fairly stable as well. For FY 2014, sales revenues are projected to be
$602,000 below budget due to a decrease in commercial sales related to lower winter water
consumption by those customers. This is offset by an increase in connection and capacity fees
associated with new development and redevelopment. Staff is projecting a one-time reduction
in treatment costs of $1.3 million associated with a change in billing methodology by the
RWQCP. As a result, net revenue is projected to be $3.3 million, $1.5 million higher than
budgeted. However, FY 2014 is an atypical year. Due to staffing constraints, CPAU's Sewer
Rehabilitation and Replacement Program, which costs roughly $3 million per year, has been put
on hold for a year while staff completes a backlog of projects from prior years. If the program
had been funded at its usual rate, and treatment costs were at normal levels, revenues would
not cover all costs this fiscal year.
Table 5: Projected Net Revenue, FY 2014
Wastewater Collection -All figures in thousands ($OOO's)
Operating Activity Adopted Unaudited Projected Projected Variance
Budget Actuals Activity FY 2014 to
FY2014 Jui13~Dec13 Jan 14-Ju/14 Activity Budget
Net Sales to date 15,010 7,265 7,143 14,408 (602)
Other revenues to date 1,534 1,415 779 2,194 660
Treatment costs to date (8,589) (4,295} (2,957) (7,251) 1,338
Other expenses to date (6,120} (2,786) (3,262) (6,048} 72
Total 1,835 1,600 1,703 3,303 1,468
J u n 0 l 6IPag
SECTION V. STATUS OF RESERVES
Table 6, below, shows the projected status of the Wastewater Collection Utility's reserves at
the end of FY 2014. Total reserves at year end (6/30/2014) are projected to be $19.6 million, of
which $7.4 million will be in the Rate Stabilization Reserve. As detailed in Appendix C:
Wastewater Collection Utility Reserves Management Practices and in Table 6, this plan
includes changes to the structure of the utility's reserves, including:
1. Adding an Operations Reserve, CIP Reserve, and Unassigned Reserve
2. Merging the Emergency Plant Replacement Reserve into the Operations Reserve
Table 6: Projected Reserves, 6/30/2.014
Projected Projected
Reserve Levels Reserve Levels
(Current Proposed (Proposed
Reserves Reallocation Reserves
Structure) of Reserves Structure)
($000) ($000) ($000)
Reserve for Reappropriations 8,443 N/A 8,443
Reserve for Commitments 2,727 N/A 2,727
Emergency Plant Replacement 1,000 -1,000 (closed)
CIP Reserve (new) 0 0
Rate Stabilization Reserve 7,407 -2,728 4,679
Operations Reserve (new) 3,728 3,728
Unassigned Reserve (new) 0 0
Total 19,577 19,577
Operations Reserve: Days of Expense 105 days
Operations Reserve: Minimum 60 days
Operations Reserve: Target 105 days
Operations Reserve: Maximum 150 days
The addition of an Operations Reserve, CIP Reserve, and Unassigned Reserve will add
transparency and simplify reserves management by providing separate reserves for various
functions that are currently all served by the Rate Stabilization Reserve. The Operations
Reserve will be used to manage contingencies and absorb normal year to year cost and
revenue variances. The CIP Reserve will hold funds for expenditure on future budgeted CIP
projects. The Rate Stabilization Reserve will be used to smooth the transition to higher rates.
If an unexpected windfall results in the utility accumulating reserves that are not designated
for a specific purpose, these will be placed in the Unassigned Reserve until those funds are
either designated for a specific purpose or returned to ratepayers.
Creating separate CIP, Rate Stabilization, and Unassigned Reserves allows the utility to set
minimum and maximum guidelines for the Operations Reserve and set forth clear actions to be
taken when it is over or under those levels. If funds are required for a specific purpose (for
example, a future CIP project) these can be held in a separate reserve (in this example, the CIP
J u n 1 4 7 I p 'J D ' b"'
F!!Vl~IVC/1\L
Reserve). Without a separate reserve, those funds would end up in the Operations Reserve
and would cause it to exceed its maximum guideline, making it difficult to treat the maximum
guideline as a clear limit on the size of the reserve. This proposal also adds transparency, since
the public will be able to see the various purposes for which the utility is holding reserves.
This plan also involves merging the existing Emergency Plant Replacement Reserve into the
Operations Reserve. Currently the Emergency Plant Replacement Reserve holds $1 million,
enough to pay the City's insurance deductible in the event of a loss of utility equipment due to
an insurable loss. Staff believes that even at minimum levels the Operations Reserve has
adequate funding to cover the insurance deductible, making the Emergency Plant Replacement
Reserve duplicative.
To provide initial funding to the Operations Reserve, $2.7 million will be transferred from the
Rate Stabilization Reserve to the Operations Reserve, retaining $4.7 million in the Rate
Stabilization Reserve to be drawn down over future years as rates increase. Combined with the
$1 million from the Emergency Plant Replacement Reserve, the Operations Reserve's initial
funding will be $3.7 million, the target level set forth in Appendix C: Wastewater Collection
Utility Reserves Management Practices (105 days of commodity and O&M expense).
SECTION VI. DEBT SERVICE
The Wastewater Collection Utility's annual debt service is roughly $128,000 per year. This is
related to one bond issuance that will require payments through 2024. This issuance, the 1999
Utility Revenue Bonds, Series A, is a joint issuance between the Storm Drain, Wastewater
Treatment, and Wastewater Collection Utilities refinancing several different earlier bond
issuances. The City is in compliance with all covenants on that bond. Additional detail is
provided in Appendix D.
The Wastewater Utility commenced operation in 1899 to serve Palo Alto and Stanford. In its
first three decades the system grew to 60 miles of sewers. Raw sewage was discharged into
Mayfield Slough at the edge of the Bay. In the 1930s, at the behest of the State Department of
Health, Palo Alto built the South Bay's first wastewater treatment plant. At that time the sewer
system served 20,500 Stanford and Palo Alto residents and a cannery. The plant was upgraded
twice in the 1940s and 1950s to increase capacity.2 At the same time, the postwar population
and industrial boom in the 1950s required rapid expansion of the sewer system. In the first half
of the 1960s Palo Alto's area doubled, as did wastewater flows, overwhelming the capacity of
several of the utility's "trunk lines," which are the largest diameter main sewer lines carrying
wastewater to the treatment plant. This prompted the City, in 1965, to perform the first of its
2 Long Range Facilities Plan for the Regional Water Quality Control Plant, August 2012, Carollo Engineers, pp 2-1
through 2-2
June 16, 0 4 8IPa e
sewer master plans to identify needed capacity improvements. At that point the Wastewater
Utility's system comprised more than 150 miles of sewer mains?
In 1968 the City signed agreements with the Cities of Mountain View and Los Altos to build a
new regional treatment plant, the RWQCP, which is still in operation today. Since 1940 the City
had been providing treatment services to the East Palo Alto Sanitary District through an existing
agreement, and was also serving Stanford University by transporting wastewater across the
City's sewer system to the treatment plant. Both of these organizations became partners in the
RWQCP as well. At the same time the Town of Los Altos Hills became the sixth partner as it
signed an agreement with the City to connect the Town's sewer system to the City's sewer
system to carry wastewater to the new RWQCP. The current agreements for the RWQCP
extend through 2035.4
In the 1980s the City directed increased attention to the condition of its sewer system,
performing a series of studies of groundwater inflow and infiltration into the system. The study
found high rates of infiltration, estimating that as much as 40% of the water going to the
RWQCP from Palo Alto's system was groundwater and stormwater rather than wastewater.5 In
some parts of Palo Alto the ground had subsided due to groundwater pumping by the water
utility, and though that practice had ceased many years earlier as the water utility switched to
the Hetch Hetchy system, parts of the city had already subsided two to five feet. This
subsidence had damaged several parts of the collection system, leading to reduced slopes for
sewer mains that caused reductions in capacity. In response to these studies the City
commenced an accelerated sewer system rehabilitation program.6 At that point the sewer
system comprised over 190 miles of mains.7
The final study of the 1980s, a Master Plan study in 1988, recommended a variety of capacity
expansions, and in the 1990s the City completed about half of them. However, a 2004 Master
Plan update found that the accelerated sewer rehabilitation plan started in the early 1990's had
substantially reduced infiltration, easing the capacity problems that had led the to the
recommended capacity increases in the 1988 study. Several of the outstanding projects were
canceled and replaced with a different set of projects.8 At the same time the City updated its
hydraulic model and developed greater capacity to do system planning in house.
Today, with a system comprising 217 miles of sewer mains, the Wastewater Collection Utility
continues to serve over 27,000 Palo Alto residences and businesses, and transports wastewater
to the RWQCP for Stanford University and the Town of Los Altos Hills.
3 Wastewater Collection and Storm Drainage, 1965, Brown and Caldwell Consulting Engineers, pp 4, 6-7, 143
4 Long Range Facilities Plan for the Regional Water Quality Control Plant, August 2012, Carollo Engineers, pg 2-2
5 Wastewater Collection System Master Plan -Capacity Assessment, January 2004, MWH Americas, Inc., pg ES-2
6 CMR 183:90, Infrastructure Review and Update, March 1, 1990
7 Master Plan of the Wastewater Collection System, December 1988, Camp Dresser & McKee, Inc., pg 1-2
8 Wastewater Collection System Master Plan-Capacity Assessment, January 2004, MWH Americas, Inc., pg ES-3
u n 1 0 4 9 I a
SECTION VIII. HISTORICAL EXPENSES AND REVENUES
Table 7 shows the Wastewater Collection Utility's expenses and revenues for the past five
years. Treatment charges made up 40% of total expenses in FY 2009, but have been increasing
by 6% per year on average, rising to 47% of total expenses in FY 2013. Total costs for this utility
have increased 3.5% per year on average over the last four years, almost entirely due to these
increases in treatment costs. Excluding treatment costs, costs for this utility have stayed stable
since 2009. Revenues increased in FY 2010 and FY 2013, primarily due to rate increases. One
item of note is the negative interest earned in FY 2013, which represents a decrease in the
market value of the City's investment portfolio that accounting rules require the City to
recognize at the end of each fiscal year. Given that the City holds its investments to maturity
these "mark to market" gains and losses do not impact the utility's long term financial position.
Table 7: Historical Expenses, Wastewater Collection Utility
2013
RETAIL SALES REVENUE 13,744 14,490 14,287 14,371 14,094 15,019
CONNECTION AND CAPACITY FEES 601 469 1,081 740 989 1,609
OTHER/TRANSFERS IN 254 278 307 278 264 545
INTEREST 805 674 454 480 494 (211)
TOTAL SOURCES OF FUNDS 15,403 15,910 16,129 15,868 15,841 16,963
PURCHASES/CHARGES OF UTILITIES (TREA1MEN1) 6,131 6,519 7,414 7,954 8,895 8,314
ALLOCATED CHARGES (CIP&OPERAllNG) 639 1,535 1,787 1,522 791 1,926
CUSTOMER SERVICE 301 239 281 266 72 1
DISTRIBUTION OPERATIONS 2,157 1,997 2,227 2,425 2,466 2,617
ENGINEERING (OPERATING) 283 220 195 393 258 271
DEBT SERVICE 128 128 128 128 128 128
RENT 109 115 115 106 106 110
OTHER/TRANSFERS OUT 732 168 267 88 88 147
CAPITAL IMPROVEMENT FUNDING 4,871 4,935 4,630 4,274 4,274 4,094
TOTAL USES OF FUNDS 15,352 15,856 17,157 17,079 17,610
INTO/ RESERVES 52 54
StCT{ON IX. FIVEYEAR FINANCIAL FORECAST
1. OVERVIEW
Staff has prepared a forecast of costs and revenues through FY 2019. As shown in Table 8 (and
Appendix A), the Wastewater Collection Utility's total costs are projected to increase by 4% per
year on average for FY 2015 through FY 2019. The utility's sales revenue will need to increase
un 6, 0 4 10 I Page
by 5% annually, on average, through FY 2019. Although costs are rising at only 4% per year,
revenues are currently below costs in a normal year.9
Over the last several years actual costs for operations, maintenance, and CIP have been
relatively low. The cost of maintaining and replacing the distribution system in FY 2013 was
almost the same as it was in FY 2009, and this has offset the rising cost of treatment. This was
likely due to the economic downturn, which led to lower costs for services and materials. Staff
is starting to see indications that this trend is reversing. Prices are rising for contract services
and materials, and this means that the utility is more likely to see rising costs in the future. If
costs for operations, maintenance, and CIP increase more quickly than projected in this plan,
either due to the improving economy or other factors, larger rate increases may be required.
Table 8: Five Year Financial Forecast Summary
Fiscal 2015 2016 2017 2018
0.0% 7.0% 7.0%
CHANGE IN RETAIL SALES REVENUE 1 1,125
RETAIL SALES REVENUE 15,010 16,018 17,140 18,340 19,624
CONNECTION AND CAPACITY FEES 1,287 1,328 1,369 1,409 1,439
OTHER I TRANSFERS IN 271 271 271 271 271
INTEREST 238 245 253 277 271
TOTAL SOURCES OF FUNDS 16,963 16,544 16,601 16,806 17,862 19,032 20,297 21,605
PURCHASES/CHARGES OF UTILITIES llREATMENl) 8,314 8,589 7,251 8,501 8,926 9,372 9,840 10,332
ALLOCATED CHARGES 1C1P&OPERATINGJ 1,926 1,699 2,333 2,410 2,481 2,566 2,655 2,747
CUSTOMER SERVICE 1 227 229 238 245 255 265 276
DISTRIBUTION OPERATIONS 2,617 2,545 2,557 2,628 2,704 2,808 2,915 3,028
ENGINEERING (OPERATING) 271 301 232 240 247 256 266 277
DEBT SERVICE 128 129 129 129 128 128 128 128
RENT 110 122 122 125 129 133 137 141
OTHER/ TRANSFERS OUT 147 108 108 108 108 108 108 108
CAPITAL IMPROVEMENT FUNDING 4,094 989
ALLOWANCE FOR UNSPENT CAPITAL FUNDS
TOTAL USES OF FUNDS 17,610 14,708
2. TREATMENT COSTS
Treatment expenses represent the Wastewater Collection Utility's share of the costs of
operating the RWQCP. Per the partnership agreements between Palo Alto and its partner
agencies, these charges are assessed based on a formula that takes into account the total
amount of wastewater delivered, the amount of organic material in it, its ammonia content,
and the total suspended solids it is carrying. The Wastewater Collection Utility's assessed share
of the RWQCP's revenue requirement fluctuates in the 38% to 40% range. Mountain View is
9 Note that FY 2014 is atypical because staff did not commence a new sewer system replacement project as it
normally does each year and treatment costs are projected to be low due to a one-time savings related to a
change in treatment billing methodology.
une 1!1, 0 4 11 I P
Flt\Jl\fVC1/\l
the other large agency served by the RWQCP (38% of the revenue requirement for FY 2013)
with other agencies (Stanford, Los Altos, East Palo Alto, and Los Altos Hills) making up the
remainder of the flow to the treatment plant.
In the next five years treatment costs are expected to rise 4% to 5% per year, primarily due to
increased CIP spending by the RWQCP. In the longer term, treatment costs are expected to
continue to rise at that rate as major upgrade and replacement projects are undertaken at the
plant. These costs are described in more detail in Section XII. Long-term Outlook.
3. OPERATIONS
Operations costs include the Customer Service, Distribution Operations, Engineering, and
Allocated Charges categories in Table 8, above. Debt service, rent, and transfers are also
included in this category. Customer Service costs are primarily related to the call center and
collections on delinquent accounts. The Distribution Operations category includes preventative
and corrective maintenance on mains and laterals, investigation of sewer overflows, regular
cleaning of heavily impacted sections of the sewer system, and services shared with other
utilities (such as street restoration and equipment maintenance). Allocated Charges include the
costs of accounting, purchasing, legal, and other administrative functions provided by the City's
General Fund staff, as well as shared communications services and Utilities Department
administrative overhead and billing system maintenance costs.
Operations costs are projected to increase by 3% per year, on average, over the forecast period.
Underlying these projections are salary and benefit, consumer price index, and other cost
projections obtained from the City's long-range financial forecast.
PITAL IMPROVEMENT PROGRAM (CIP)
The Wastewater Collection Utility's CIP consists of the following programs:
• The Sewer System Replacement/Rehabilitation Program, under which the Wastewater
Collection Utility replaces aging sewer mains
e Customer Connections, which covers the cost when the Wastewater Collection Utility
installs new services or upgrades existing services at a customer's request in response
to development or redevelopment. CPAU charges a fee to these customers to cover
the cost of these projects.
• Ongoing Projects, which covers the cost of replacing degraded manholes and sewer
laterals, as well as the cost of capitalized tools and equipment.
The Sewer System Replacement and Rehabilitation Program funds the replacement of
deteriorating sewer mains and projects to increase capacity in various parts of the sewer
system. The sewer system consists of over 217 miles of mains, and CPAU uses a variety of tools
to establish which sections are in need of replacement. Maintenance statistics (such as records
of the location and number of sewer overflows on the system) and videotape of sewer mains
during regular cleaning can reveal areas with large amounts of deteriorating pipe. CPAU uses a
scoring system to prioritize which mains to replace first, and coordinates with the Public Works
J u n 1 (' 'l J J. 12 I Page
street maintenance program to avoid cutting into newly repaved streets. A major goal of the
program is to minimize groundwater and rainwater infiltration. As mains deteriorate they
begin to allow groundwater and rainwater to infiltrate the system. Some level of infiltration is
expected on any sewer system, but if there is too much, the combined flow of wastewater and
groundwater/rainwater can overwhelm the capacity of various parts of the sewer system.
Reducing infiltration can reduce the need to expand the system to accommodate increased
flow. To achieve this goal, deteriorating mains are either repaired with a plastic lining or
replaced. CPAU replaces or repairs approximately 25,000 feet of main per year, or 2.5% of the
system.
The program also funds sewer capacity improvements. CPAU uses a hydraulic model, data from
various flow meters on the system, and land use data to identify sections of the system that are
being overloaded. When sewer mains are operating at or above their capacity on a regular
basis it will increase the likelihood of sewer overflows. The Division also does occasional
comprehensive master plan studies to identify necessary capacity improvements, most recently
in 2004. That study identified eight projects, three of which have been completed. The
remaining four projects are low priority projects and will be scheduled and planned as the need
arises.
Ongoing Projects and Customer Connections are projected to cost approximately $750,000 in
FY 2015 and increase by 2.4% each year through the end of the forecast period. Actual
expenses for these projects fluctuate annually depending on how many defective laterals or
manholes are discovered during routine maintenance, as well as how much development and
redevelopment is going on that prompts the replacement or upgrade of sewer laterals. It is
worth noting that property owners pay a fee for sewer lateral replacement or expansion during
redevelopment, so when costs go up, so does fee revenue.
Aside from customer connections, the CIP plan for FY 2015 to FY 2019 is funded by sewer rates
and capacity fees. The details of the plan are shown in Appendix B: Wastewater Collection
Utility Capita/Improvement Program (CIP) Detail.
Table 9: Projected CIP Spending
' " ~ > spending, Remain.
~ '' ' ' '
' Current
projes;t Category Bydget* Curr. Yr Bu(:lget** Com~nitt~td FY 2015 FY 2016
Sewer Rehab/Augmentation 9,988 (1,708) 8,280 2,900 3,320 3,420
Ongoing Projects 1,333 (38) 1,295 719 375 382
Customer Connections 188 (98) 89 372 383
TOTAL 11,508 (1,844) 9,665 3,619 4,067 4,185
*Includes unspent funds from prev1ous years earned forward or reappropnated mto the current f1scal year
**Equal to CIP Reserves (Reserve for Reappropriations +Reserve for Commitments). See Table 27.
J u n 6,
' ,.,~~ =·~"'.., "" "'~"' =~~
c:
FY~2017 FY 2018 , FY 20!~x
3,523 3,620 3,722
389 396 403
394 405 416
4,306 4,421 4,541
131
SECTION X. REVENUE REQUIREMENT AND REVENUE SOURCES
The revenue requirement is the total amount of revenue that must be collected from
customers in order to meet the planned expenditures for the Wastewater Collection Utility.
Costs for the Wastewater Collection Utility are projected to increase by 4% per year through FY
2019. Without rate increases, by FY 2019 costs would exceed revenues by nearly $5 million per
year. Matching costs to revenues by FY 2019 will require 7% increases in sales revenues each
year for FY 2016 to FY 2019, as shown in Figure 4, below. The plan assumes no rate increase in
FY 2015, which will draw down accumulated reserves, which resulted from the fact that staff
did not add a new sewer main replacement project in FY 2014 and a one-time decrease in
treatment costs related to a change in billing methodology by Palo Alto's Regional Water
Quality Control Plant (RWQCP). Each of the projected FY 2016 to FY 2019 rate increases will
increase residential sewer bills by $2.05 to $2.51 per month.
$25
~$15 Vl c .Q
<I} $10
$5
$0
Figure 3: Wastewater Collection Fund Revenue and Cost Projections
f~evenue
IIIII Treatment
DCIP
lil! Operations
IIIII Debt Service
Actual Proj Projected
Figure 4 also shows the reserve reallocations that implement the proposed Reserves
Management Practices. The utility has seen substantial increases in connection and capacity
fees in recent years, offsetting the need for increased sales revenue, and these are reflected in
the current financial forecast.
Jun 6! 0 4 14 I P a
Figure 4: Wastewater Collection Reserves Projections
$25 i
Projected FY 2014 year-end reserves under existing reserves structure
$20 Proposed reallocation (see Section V. Status of Reserves)
-II)
$15
:~ $10
~
$5
$0
SECTION XI. RISK ASSESSMENT
Rate Stabilization
Operations Reserve
Plant Replacement
II Reappropriations &
Commitments
Staff performs an annual assessment of risks for the Wastewater Collection Utility. For this
evaluation, staff estimates the revenue shortfall due to:
1. the maximum observed budget-to-actual variance in one year during the past five years;
2. an increase of 10% of planned system improvement CIP expenditures for the budget year;
and
3. an increase of 10% in the planned expenditure for treatment costs.
Table 10 summarizes the risk assessment calculation for the Wastewater Collection Utility. The
Operations Reserve is projected to be adequate to manage these levels of risk over the entire
forecast period.
Table 10: Wastewater Collection Risk Assessment
'' /~11;' .. r"g,0:iJ ~ ) · ( .. . .... · .. ·. · ·· · ·.... r ··· FV.l(hs. · '/, <; ,' '_,_, s=v·aoit ·.:'~)c;~,~~ ~· fY~Qt6. : ., 1. ••. ·•• ... .<;;/.. ...... .•. .. i ,:
TotaiRevenue($000)
15,020 16,028 17,150 18,350 19,634
Max. Historical Budget-to-Actual variance 10% 10% 10% 10% 10%
Budget:·to~Actuai.Risk($000) 1,502 1,603 1,715 1;835 1,9'63
System Rehabilitation CIP Budget ($000) 3,695 3,802 3,912 4,016 4,124
CIP··~olltingency @ :j.O% {$000) 370 380 391 402 412
Treatment Budget ($000) 8,501 8,926 9,372 9,840 10,332
lreatmentCostContingency @10% ($000) 850 893 937 984 1,033
Total risk assessment value ($000) 2,722 2,876 3,043 3,221 3,408
Projected Operations Reserve Level ($000) 4,136 4,305 4,495 4,590 4,776
J u n 6 i 0 4 15 I P a
SECTION XII. LONG-TERM OUTLOOK
In the longer term (5 to 35 years) the primary factor that could lead to increased costs for the
Wastewater Collection Utility are major upgrades at the RWQCP, a share of which will be
allocated to the utility as part of treatment costs. These upgrades includes replacement or
rehabilitation of the parts of the facility that pump raw sewage to the main treatment works
(the headworks), separate out primary sludge (the primary settling tank), process sludge (the
biosolids facility), and treat wastewater (the fixed film reactors). Upgrades to the laboratories
and operational buildings are planned as well. In addition, the 72-inch regional trunk sewer line
flowing into the plant needs to be evaluated and rehabilitated. Based on detailed project cost
projections provided by RWQCP staff, treatment costs are likely to continue to increase by
roughly 5% per year through at least 2030. Two of Palo Alto's comparison cities, Mountain
View and Los Altos, are partners in the RWQCP and will see similar increases, but other
comparison agencies may not.
SECTION XIII. COMMUNICATIONS PLAN
The FY 2015 Wastewater Collection Utility communications strategy covers three primary areas:
rates, operations and infrastructure, and safety. There is no need for formal "rate change"
communications at this time, but website and community education about rates is
ongoing. Sewer maintenance and safety promotional activity includes bill inserts, website
pages, email blasts, and the use of social media. To keep customers apprised of the status and
accomplishments of CIP projects, a network of project web pages are maintained; traffic is
driven to the website via ads in publications, newspaper inserts, social media and email
blasts. Safety topics are emphasized year-round and, while print materials and website pages
still feature prominently, CPAU is turning the outreach emphasis to direct mail, newspaper
inserts, and social media including video, cable TV, community safety/emergency preparation
meetings and updates to neighborhood groups.
One major issue for the wastewater utility is handling sewer back-ups due to FOG (fats, oil and
grease) and trash being dumped down drains and toilets. Inspired by a story about a
monstrous "fatberg" in London sewers, staff incorporated that concept into outreach ranging
from advertisements to 3D models for workshops and schools visits. To address another
continuing outreach goal of educating customers about the utility's gas-sewer line crossbore
inspection program, including the importance of calling Utilities first when there is a sewer
back-up, staff ran a successful campaign featuring one of our primary sewer repair crewmen.
J u ll 0 4 16 I a e
Appendix A: Wastewater Collection Financial Forecast Detail
Appendix B: Wastewater Collection Utility Capital Improvement Program (CIP)
Detail
Appendix C: Wastewater Collection Utility Reserves Management Practices
Appendix D: Wastewater Collection Debt Service Details
Appendix E: Sample of Wastewater Collection Outreach Materials
J u n 17 I P a g P
LJTlL!TY
APPENDIX A: WASTEWATER COLLECTION FINANCIAL FORECAST DETAIL
2019
5.0% 0.0%
CHANGE IN RETAIL SALES REVENUE 715
RETAIL SALES REVENUE 15,019 15,010 15,010 16,018 17,140 18,340 19,624
CONNECTION AND CAPACITY FEES 1,609 861 1,287 1,328 1 1,369 1,409 1,439
OTHER/TRANSFERS IN 545 302 271 211 1 271 271 271
INTEREST (21 371 238 245 I 253 277 271
TOTAL SOURCES OF FUNDS 16,963 16,544 16,806 17,8621 19,032 20,297 21,605
PURCHASES/CHARGES OF UTILITIES (TRfATMENlJ 8,314 8,589 8,501 8,926 9,372 9,840 10,332
ALLOCATED CHARGES I"P&OPERATING) 1,926 1,699 2,410 2,481 2,566 2,655 2,747
CUSTOMER SERVICE 227 238 245 255 265 276
DISTRIBUTION OPERATIONS 2,617 2,545 2,628 2,704 2,915 3,028
ENGINEERING (OPERATING) 271 301 232 240 247 266 277
DEBT SERVICE 128 129 129 129 128 128 128
RENT 110 122 122 125 129 137 141
OTHER/ TRANSFERS OUT 147 108 108 108 108 108 108
CAPITAL IMPROVEMENT FUNDING 4,094 989
ALLOWANCE FOR UNSPENT CAPITAL FUNDS
TOTAL USES OF FUNDS 17,610 14,708
ENDING COMMITMENTS & REAPPROPRIATION$ 11,228 11,228 11,228 11,228 11,228 11,228 11,228
ENDING PLANT REPLACEMENT RESERVE 1,000 1,000
ENDING CIP RESERVE
ENDING RATE STABILIZATION RESERVE 4,104 5,940 4,679 2,719 1,363 395
ENDING OPERATIONS RESERVE 3,728 4,136 4,305 4,495 4,590 4,776
UNASSIGNED RESERVES
RISK ASSESSMENT VALUE 2,736 2,424 2,230 2,722 2,876 3,043 3,221 3,409
OPERATIONS RESERVE GUIDELINES
MIN (60 DAYS TREATMENTIO&M EXP) 2,253 2,255 2,130 2,363 2,460 2,569 2,682 2,801
TARGET (105 DAYS TREATMENTIO&M EXP) 2,736 3,947 3,728 4,136 4,305 4,495 4,694 4,901
MAX (150 DAYS TREATMENTIO&M EXP) 4,506 5,638 5,326 5,909 6,151 6,422 6,705 7,002
u n 0 4 18 I P a e
COLLECTION UTILITY FI!VANUAL PLAN
APPENDIX B: WASTEWATER COLLECTION I,JTH.ITY C"AP.ITAt IMPROVEMENT PROGRAM (ClP}Q~tAil
n 0] 19 I F ''
APPENDIX C: WASTEWATER COLLECTION UTILITY RESERVES
MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Wastewater
Collection Utility Financial Plan:
Section 1. Definitions
a) "Financial Planning Period"-The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b) "Fund Balance"-As used in these Reserves Management Practices, Fund Balance refers
to the Utility's Unrestricted Net Assets.
c) "Net Assets"-The Government Accounting Standards Board defines a Utility's Net
Assets as the difference between its assets and liabilities.
d) "Unrestricted Net Assets"-The portion of the Utility's Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Reserves
The Wastewater Collection Utility's Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 3 (Reserve for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 4 (Reserve for Reappropriations)
c) For future year expenditure on the Wastewater Collection Utility's Capital Improvement
Program (CIPL as described in Section 5 (CIP Reserve)
d) For rate stabilization, as described in Section 6 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 7 (Operations Reserve)
f) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 8 (Unassigned Reserves).
Section 3. Reserve for Commitments
At the end of each fiscal year the Reserve for Commitments will be set to an amount equal
to the total remaining spending authority for all contracts in force for the Wastewater
Collection Utility at that time.
Section 4. Reserve for Reappropriations
At the end of each fiscal year the Reserve 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 in accordance with Palo Alto Municipal Code
Section 2.28.090.
J u n 1 014 20 I P a
Section 5. CIP Reserve
Funds may be added to or withdrawn from the CIP Reserve by action of the City Council and
held for future year expenditure on the Wastewater Collection Utility's CIP Program.
Withdrawal of funds from the CIP Reserve requires Council action. If there are funds in the
CIP Reserve at the end of any fiscal year, any subsequent Wastewater Collection Utility
Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the
Financial Planning Period.
Section 6. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and held
to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate
Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization
Reserve at the end of any fiscal year, any subsequent Wastewater Collection Utility
Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the
Financial Planning Period.
Section 7. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Wastewater Collection Utility's Fund Balance not
included in the reserves described in Section 3 to Section 6 above will be included in the
Operations Reserve unless this reserve has reached its maximum level as set forth in Section
7(d) below. Staff will manage the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for
that year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 105 days of O&M and commodity expense
Maximum Level 150 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months
of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Wastewater Collection Utility
shall be designed to return the Operations Reserve to its target level within four years.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this Reserve. Any further increase in the Wastewater Collection
!un 1 , 014 21 I Page
Utility's Fund Balance shall be automatically included in the Unassigned Reserve
described in Section 8, below.
Section 8. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the
Wastewater Collection Utility's Fund Balance will be held in the Unassigned Reserve. If
there are any funds in the Unassigned Reserve at the end of any fiscal year, the next
Financial Plan presented to the City Council must include a plan to assign them to a specific
purpose or return them to the Wastewater Collection Utility ratepayers by the end of the
first fiscal year of the next Financial Planning Period. For example, if there were funds in the
Unassigned Reserves at the end of FY 2015, and the next Financial Planning Period is
FY 2016 through FY 2020, the Financial Plan shall include a plan to return or assign any
funds in the Unassigned Reserve by the end of FY 2016. Staff may present an alternative
plan that retains these funds or returns them over a longer period of time.
J u n 0 22 I Page
APPENDIX D: WASTEWATER COLLECTION DEBT SERVICE DETAILS
The Wastewater Collection Utility currently makes payment on its share of one bond issuance,
the 1999 Utility Revenue Bonds, Series A, which is due to be retired in 2024. This $17.7 million
issuance refinanced various earlier Storm Drain, Wastewater Treatment, and Wastewater
Collection Utility bond issuances. The Wastewater Collection Utility's share of the issuance was
roughly $1.9 million, which represented the second refinancing of the remaining principal of a
1990 bond issuance that itself was a refinancing of a 1985 issuance that financed a variety of
improvements to the sewer system. The cost of debt service for the Wastewater Collection
Utility's share of this bond issuance for the financial forecast period is as follows:
Table 11: Wastewater Collection Utility Debt Service ($000)
· ... ' FV~01.4····. f\',2015 FY2016 FV2017 1·•· FV~(J~.8 -FV2019 .·. ' ' .'.· . . .
1999 Utility
Revenue Bonds, 129 128 129 128 128 128
Series A
The 1999 Utility Revenue Bonds include two covenants stating that 1} the Wastewater
Collection Utility will maintain a debt coverage ratio of 125% of debt service, and 2) that the
City will maintain "Available Reserves"10 equal to five times the annual debt service. The
current financial plan maintains compliance with both covenants throughout the forecast
period. Compliance with covenant one is shown below in Table 12, below. Due to the small
size of the annual debt service payment for these bonds, the Wastewater Collection Utility's
Operations Reserve alone more than satisfies the second covenant at more than 30 times
annual debt service throughout the forecast period.
Table 12: Debt Service Coverage Ratio ($000)
· .. · .. •... ft2ttt.4<i f;Y:2015 f'V<2()16 ··' ~Y~Ol7 FY2oi8 fY2()19 . . ..... ../ .
Revenues
16,601 16,806 17,862 19,032 20,297 21,605
Expenses (Excl. CIP
and Debt Service} (14,169) (14,248) (14,839) (15,498} (16,187) (16,909)
Net Revenues 2,432 2,558 3,023 3,534 4,110 4,696
Debt Service 129 128 129 128 128 128
Coverage Ratio 1885% 1998% 2343% 2761% 3211% 3669%
The Wastewater Collection Utility's reserves (but not its net revenues) are also considered
security for the Storm Drain and Wastewater Treatment Utilities' shares of the debt service on
the 1999 bonds. Throughout the term of the bonds there remains a small risk that the
Wastewater Collection Utility's reserves could be called upon to make a debt service payment
on behalf of one of those utilities if it cannot meet its debt service obligations. Staff does not
10 Available Reserves as defined in the 1999 Utility Revenue Bonds included reserves for the Water, Wastewater
Treatment, Wastewater Collection, Refuse, Storm Drain, Electric, and Gas Utilities
J u n 6 , 0 1 4 23 I
Ill
foresee this occurring based on the current financial condition of those utilities. If the
Wastewater Collection Utility's reserves were used this way, any amounts advanced would
have to be repaid by the borrowing utility.
One other bond series is secured by the net revenues (but not the reserves) of the Wastewater
Collection Utility. The 1995 Series A Utility Revenue Bonds issued for the Storm Drain utility
was secured by the net revenues of the City's "Enterprise," which was defined as the City's
water, gas, wastewater, storm drain, and electric utilities, and are senior to the 1999 bonds
referenced above. Debt service payments of roughly $680,000 per year are made on the 1995
Series A bonds by the City's Storm Drain Utility, and staff does not currently foresee any risk of
that utility being unable to make payment.
n 01 24 I P g e
APPENDIX E.: SAMPLE OF WASTEWATER COLLECTION OUTREACH MATERIALS
CALL (650) 496-6995 AND WE'LL
OUT ON THE DOUBLl: (FOR FREE)
C:all the Utiliti<J,; BEFORE
you call your plumber to have
your sewer cleared.
The City will come out right
away to verify there are no
crossbores and that it is safe
to proceed.
A crcssbore It, when
a gas line intersects a
sewer line.
ATIACHMENT E
y 2021
Definitions and Abbreviations ......................•...................•.................................................... 2
Executive Summary .......................................................•.......•.......•......................•...........•.... 2
Current State of the Utility .............•......................................•.....•..•.................•.....•..•........... 3
Section I. Utility Overview ........................................................................................................... 3
Section II. Current Rates and Competitiveness ........................................................................... 4
Section Ill. Rate Design ............................................................................................................... 6
Section IV. Current Utility Financial Status ................................................................................. 7
Section V. Status of Reserves ...................................................................................................... 8
Section VI. Debt Service .............................................................................................................. 9
Looking Back ...................•..............................•.............................................•..•................... 10
Section VII. Background ............................................................................................................ 10
Section VIII. Historical Expenses and Revenues ........................................................................ 11
Looking Forward .................................................................................................................. 12
Section IX. Seven Year Financial Forecast.. ............................................................................... 12
1. Overview ...................................................................................................................... 12
2. Water Purchase Costs .................................................................................................. 13
3. Operations .................................................................................................................... 13
4. Capital Improvement Program (CIP) ............................................................................ 14
Section X. Revenue Requirement and Revenue Sources ........................................................... 15
Section XI. Risk Assessment ...................................................................................................... 17
Section XII. Communications Plan ............................................................................................ 18
Appendices ....•.........•........•.•..•........••..................•..........•.........................••.........•...•...•....•.. 19
Appendix A: Water Utility Financial Forecast Detail ................................................................. 20
Appendix 8: Water Utility Capita/Improvement Program (CIP} Detail ..................................... 21
Appendix C: Water Utility Reserves Management Practices ..................................................... 23
Appendix D: Water Utility Debt Service Details ......................................................................... 26
Appendix E: Description of Water Utility Cost Categories ......................................................... 28
Appendix F: Sample of Water Utility Outreach Communications ............................................. 29
BAWSCA: Bay Area Water Supply and Conservation Agency
CCF: one hundred cubic feet, the standard unit of measurement for water delivered to water
customers. Equal to roughly 748 gallons.
CIP: Capital Improvement Program
CPAU: City of Palo Alto Utilities Department
O&M: Operations and Maintenance
SFPUC: San Francisco Public Utilities Commission
SFWD: San Francisco Water Department
WSIP: the SFPUC's Water System Improvement Program to seismically strengthen the Hetch
Hetchy regional water system.
This document presents a Financial Plan for the City's Water Utility for the next seven years.
The seven-year time frame is meant to show the stabilization of water purchase costs in FY
2020, when the last debt associated with the San Francisco Public Utility Commission's
(SFPUC's) Water System Improvement Program (WSIP) is projected to be issued. The City's
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.
Over the next seven fiscal years staff projects that the Water Utility will see water purchase
costs rising 9.5% per year through FY 2020. Operations costs are projected to rise at roughly 3%
per year. Capital Improvement Program (CIP) costs are assumed to increase by 9.5% per year
on average in this Financial Plan, but there is significant uncertainty in these projections. Costs
per mile of main are increasing, and a 25-year main replacement program initiated in 1993 is
nearing completion. CPAU will initiate a master planning process in FY 2015 to re-evaluate the
current state of the distribution system and determine the necessary rate of main replacement
in future years. This could result in substantially higher CIP expenses than are currently
forecasted.
To match revenues to these rising costs, the Financial Plan includes the rate trajectory shown in
Table 1. This trajectory includes a 0% rate increase in FY 2015. While there are uncertainties
regarding future CIP costs (pending the completion of the distribution system master plan,
slated for FY 2015), as well as the potential for the SFPUC establishing mandatory restrictions in
water consumption at their April meeting, the utility currently has adequate reserves to defer a
rate increase at this time. This will allow CPAU to wait until the distribution master planning
study is complete to gain more certainty about future CIP costs.
For FY 2016 to FY 2020, rates are projected to increase 5% to 7% each year. After that, rate
increases are expected to reflect inflation. Each annual increase during FY 2016 to FY 2020 is
u 0 2IP
equivalent to an increased cost of $4.00 to 5.00 per month for a median residential customer's
water bill.
Table 1: Projected Water Rate Trajectory for FY 2015 to FY 2019
FY20 FY 2016 FY 2017 FY 2018 FY2019 FY2020 FY 2021
o% I 7% 6% 6% 6% 5% 1%
This Financial Plan includes the Water Utility Reserves Management Practices, which describes
the various reserves held by the Water Utility, their purposes, and guidelines for managing
them. The Reserves Management Practices make the following changes to the utility's existing
reserves structure:
1. The addition of an Operations Reserve, a CIP Reserve, and an Unassigned Reserve
2. The merger of the Emergency Plant Replacement Reserve into the new Operations
Reserve
Under this plan, the initial funding for the Operations Reserve will be $8.6 million, $7.6 million
from the Rate Stabilization Reserve, and $1 million from the Emergency Plant Replacement
Reserve. With this initial funding the Operations Reserve will be at its target level. In addition,
a $6 million transfer from the Rate Stabilization Reserve to the CIP Reserve preserves funding
for future CIP projects that may be identified during the master planning process.
SECTIOr·if./ UTILITY OVERVIEW
The City of Palo Alto's Water Utility provides water service to the residents and businesses of
Palo Alto, plus a handful of residential customers not in Palo Alto (Los Altos Hills, primarily).
Nearly 20,300 customers are connected to the water system, approximately 16,500 (81%) of
which are separately metered residential customers and 3,800 (19%) of which are commercial,
master-metered residential, irrigation and fire service customers.
The use of water is fundamental in people's daily lives. Most individuals require a modest
amount of water for drinking, cooking, bathing and general cleaning, as winter time usage
levels can attest to. A large measure of Palo Alto's water usage is used for irrigation, and that
amount is heavily weather dependent. Therefore, there is significant variability in the amount
of water that is demanded from the system, month to month and year to year.
To deliver water to its customers, the utility owns roughly 233 miles of mains (which transport
the water from the SFPUC meters at the City's borders to the customer's service laterals and
meters), eight wells (to be used in emergencies), five water storage reservoirs (also for
emergency purposes) and several tanks used to moderate pressure and deal with peaks in flow
and demand (due to fire suppression, heavy usage times, etc.). These represent the vast
majority of the infrastructure used to distribute water in Palo Alto. The City of Palo Alto's
Utilities Department (CPAU) conducts a water main replacement program to replace mains over
time as they deteriorate or to increase capacity. CIP expense accounts for around six percent of
u n 3IP g
the utility's expenditures, though CIP spending has varied substantially from year to year
recently due to the seismic rehabilitation of Palo Alto's emergency water supply system.
In addition to its CIP, CPAU performs various maintenance activities on the water system.
These include inspecting and repairing water mains, laterals and meters, monitoring water
quality, monitoring the different pressure zones, and building and replacing water laterals and
mains for new or redeveloped buildings. The utility also shares the costs of other operational
activities (such as customer service, billing, equipment maintenance, and street restoration)
with the City's other utilities. These maintenance and operations expenses, as well as
associated administration, debt service, rent, and other costs, make up just under half of the
utility's expenses.
The Water Utility purchases all of the water it delivers from the SFPUC, which owns and
operates the Hetch Hetchy reservoir in Yosemite, CA. CPAU is one of several agencies that
purchase water from the SF PUC, all of whom are members of the Bay Area Water Supply and
Conservation Agency (BAWSCA). Palo Altans use roughly 7% of the water delivered by the
SFPUC to BAWSCA member agencies. Purchase costs make nearly half of the Water Utility's
expenses.
SECTION II. CURRENT RATES AND COMPETITIVENESS
The current rates were adopted July 1, 2013, when CPAU increased water rates by 7%. Table 2,
below, summarizes the current rates for all customer classes. CPAU has five rate schedules: one
for separately metered residents (W-1), one for commercial and master-metered multi-family
residential customers {W-4), and specific schedules for irrigation-only services (W-7), services to
fire sprinkler systems in buildings and private hydrants (W-3), and for service to fire hydrant
rental meters used for construction (W-2). All customers pay a monthly customer charge,
based on the size of their inlet meter. All customers are also charged for each CCF {one
hundred cubic feet) of water used. Separately metered residential customers are charged on a
tiered basis, with the first 0.2 CCF/day (6 CCF for a 30 day billing period) at a lower price, and all
other units used at a higher rate. All other customers, including commercial customers, pay a
uniform price for each CCF used.
J 1 41Pag
Table 2: Water Rates (Effective 7 /1/2013)
Monthly Service
Size ($/month based on meter size)
14.67 14.67 00
125.00
Table 3 shows the current water bills for residential customers compared to what they would be
under surrounding communities' rate schedules. CPAU has the highest monthly bills of the
group, although bills for smaller water users are less than in some surrounding communities.
Table 3: Residential Monthly Water Bill Comparison
47.46
84.75
*All comparisons using 5/8" meter size
Table 4 shows the annual average monthly water bill for commercial customers for various
water usage levels. Redwood City is notable in that their irrigation rates are set on a budget
basis, and as such each parcel has a unique baseline value. For purposes of this comparison,
the budget was assumed to be equal to the usage amount.
un 16, 01 SIPag
Table 4: Commercial Monthly Water Bill Comparison
Comrnerdai(W-4) (5/8'' meters)
(Annual median) 12 88.47 72.70 81.42 71.40 67.44 55.58 40.68
(Annualaverage) 64 408.27 409.75 371.96 354.80 312.88 250.20 216.96
Irrigation (W-7) (1 W' meters}
(Winter median) 9 121 167 100 76 86 73 31
(Summer median) 37 332 313 256 229 218 178 125
(Winter average) 56 474 412 362 332 308 249 190
(Summer average) 199 1,550 1,157 1,161 1,121 982 785 675
SECTION IH. RATEDESIGN
The Water Utility's rates are evaluated and implemented in compliance with the cost of service
requirements and procedural rules set forth in the California Constitution under Article 13 (per
Proposition 218). Current rates were structured based on the methodology from the March
2012 Palo Alto Water Cost of Service & Rate Study by Raftelis Financial Consultants, Inc 1. Staff
plans to review and update this cost of service study in 2 to 3 years, unless any major changes
occur to the utility's operations or customer base that would necessitate an earlier study.
Before conducting any new cost of service study, staff will review current rates and the scope of
the study with the Utilities Advisory Commission (UAC) and Council to determine UAC and
Council policy priorities.
California is currently experiencing a severe drought. On January 31, 2014, the SFPUC
requested a 10% voluntary reduction. In April, the SFPUC will announce to BAWSCA members
whether they will face mandatory restrictions. Currently, Palo Alto is following a Stage 1
drought response as outlined in the City's Urban Water Management Plan,2 which seeks to
achieve 10% voluntary reductions through outreach and increased rebates for water
conservation measures. If the SFPUC asked for mandatory reductions, the City would likely
follow a Stage 2 response, seeking 10 to 20% mandatory reductions in usage. In addition to
doing outreach and offering higher rebates, drought rate schedules would be imposed and the
City would increase its enforcement of the water use ordinance. Staff is not anticipating the
need for a Stage 3 response (20 to 35% reduction) or Stage 4 response (35 to SO%) at this time.
CPAU is also investigating the feasibility of separating out its wholesale water purchase costs on
the retail rate schedules. Doing so would allow the utility to use a simpler notification process
1 Staff Report 10#2676, Finance Committee, April 18, 2012
2 Staff report 10#1688, City Council, 6/13/2011
J u n 61
when changing rates solely to pass through increased wholesale water costs. It would also
make the reason for such rate increases more transparent to customers.
SECTION IV. CURRENT UTILITY FINANCIAL STATUS
In FY 2013, water purchase costs represented nearly half of the Water Utility's costs (47%), with
O&M costs being the next largest expense (21%), then Other costs (debt service, rent and
transfers) at 17%, followed by administration (9%} and CIP costs (6%), as shown in Figure 2.
These figures are also shown by expenditure category in Figure 1. The utility's revenue in
FY 2013 was primarily from water charges (92%}, with the remainder from capacity and
connection fees (5%), and other sources (3%).
Figure 1: FY 2013 Costs by Category
Supplies,
Equip, &
Other, 20%
17%
Admin/
Overhead,
9%
Water
Purchases,
47%
CIP,6%
Figure 2: FY 2013 Costs by Activity
Operations
,21%
Admin/
9% CIP, 6%
Water
Purchases,
47%
Table 5 contains a summary of the Water Utility's financial outlook for FY 2014 as of Q2. Water
sales have been higher than budget estimates due to dry weather conditions. However, with
voluntary restrictions called for the by SFPUC (and the potential for larger cutbacks should
further precipitation fail to arrive), water sales are projected to decrease by the end of the year.
SFPUC rates for FY 2014 are lower than budget projections, however. This was due to a
temporary discount of the water rates to return excess funds collected by the SFPUC in the
previous fiscal year. As a result, despite lower consumption, water purchase costs are
estimated to be $1.7 million below budget. Purchase costs and sales revenues may end up
higher than forecasted if customers do not make the requested voluntary reductions.
The increases to "Other revenue" reflect higher connection fee income to date. Included in
"Other expenses" are proposed CIP cost increases of $3.97 million dollars. These are related to
a budget adjustment to a water main replacement project as well as funding for main
replacements as part of the California Avenue Streetscape Project.
J u 7jP
WA UTILITY
Table 5: Projected Water Utility Net Revenue, FY 2014
Includes misc. sales, adjustments, discounts, and bad debt
** Includes reserve transfers, salaries, allocated charges, other misc. expenses, and encumbrances
SECTIONV. STATUS OF RESERVES
Table 6, below, shows that the projected balance of the Water Utility's reserves at the end of
FY 2014 is $33.4 million. As detailed in Appendix C: Water Utility Reserves Management
Practices and in Table 6, this plan includes changes to the structure of the utility's reserves,
including:
1. Adding an Operations Reserve, a CIP Reserve, and an Unassigned Reserve; and
2. Merging the Emergency Plant Replacement Reserve into the Operations Reserve.
Table 6: Projected Water Utility Reserves, 6/30/2014
* Balances at the end of FY 2013. Final FY 2014 to be determined.
The additions of an Operations Reserve, a CIP Reserve, and an Unassigned Reserve will add
transparency and simplify reserves management by providing separate reserves for various
functions that are currently all served by the Rate Stabilization Reserve. The Operations
Reserve will be used to manage contingencies and absorb normal year-to-year cost and
J u n () 8IP
revenue variances. The CIP Reserve will hold funds for expenditure on future CIP projects
which are larger than usual, but not expected to be debt funded. The Rate Stabilization
Reserve will be used to smooth the transition to higher rates. If the utility accumulates
reserves that are not immediately designated for a specific purpose, these will be placed in the
Unassigned Reserve until those funds are either designated for a specific purpose or returned
to ratepayers.
Creating separate CIP, Rate Stabilization, and Unassigned Reserves allows the utility to set
minimum and maximum guideline levels for the Operations Reserve and set forth clear actions
to be taken when it is over or under those levels. If funds are required for a specific purpose
(for example, a future CIP project) these can be held in a separate reserve (in this example, the
CIP Reserve). Without a separate reserve, those funds would end up in the Operations Reserve
and would cause it to exceed its maximum guideline, making it difficult to treat the maximum
guideline as a clear limit on the size of the reserve. This proposal also adds transparency, since
the public will be able to see the various purposes for which the utility is holding reserves.
This plan also involves merging the existing Emergency Plant Replacement Reserve into the
Operations Reserve. Currently the Emergency Plant Replacement Reserve holds $1 million,
enough to pay the City's insurance deductible in the event of a loss of utility equipment due to
an insurable loss. Staff believes that even at minimum levels the Operations Reserve has
adequate funding to cover the insurance deductible, making the Emergency Plant Replacement
Reserve duplicative.
To manage uncertainty in future CIP funding levels, this plan allocates $6 million to the CIP
Reserve from the Rate Stabilization Reserve. This funding amount will be revised following the
completion of the water distribution system master plan. The Operations Reserve's initial
funding will be $8.6 million, the target level set forth in Appendix C: Water Utility Reserves
Management Practices (90 days of commodity and operations and maintenance (O&M)
expense), with $7.6 million transferred from the Rate Stabilization Reserve and $1 million from
the Emergency Plant Replacement Reserve. The Rate Stabilization Reserve will retain $3.4
million to be drawn down over future years.
The Water Utility's annual debt service is roughly $3.2 million per year. This is related to two
bond issuances, one requiring payments through 2026, the other through 2035. The first
issuance, the 2011 Utility Revenue Refunding Bond, Series A, was a joint issuance between the
Water and Gas Utilities refinancing the 2002 Utility Revenue Bonds, Series A, which was issued
to finance various capital improvements for both systems. The second, larger issuance is the
2009 Water Revenue Bond, Series A (Direct Payment Build America bond) used to finance
construction of the Emergency Water Supply and Storage project (the El Camino Reservoir, new
wells, rehabilitation of existing wells and tanks, etc.) The City is in compliance with all
covenants on both bonds. Additional detail is provided in Appendix D.
n 91
SECTION VII. BACKGROUND
0 1\
The Water Utility was established on May 9, 1896, two years after the City was incorporated.
Voters of the 750 person community approved a $40,000 bond to buy local, private water
companies who operated one or more shallow wells to serve the nearby residents. The City
grew and the well system expanded until nine wells were in operation in 1932. Palo Alto began
receiving water from the San Francisco Water Department (SFWD) in 1937 to supplement these
sources.
A 1950 engineering report noted, "the capricious alternation of well waters and the San
Francisco Water Department water ... has made satisfactory service to the average customer
practically impossible". By 1950, only eight wells were still in operation. Despite this,
groundwater production increased in the 1950's leading to lower groundwater tables and water
quality concerns. In 1962, a survey of water softening costs to City customers determined that
the City should purchase 100% of its water supply needs from the SFWD. A 20-year contract
was signed with San Francisco, and the City's wells were placed in standby condition. The
SFWD later became known as the SFPUC. Since 1962 (except for some very short periods) the
City's entire supply of potable water has come from the SFPUC.
As the City grew, so did the number of mains in the system. The system of mains expanded
along with the town, while existing sections of the system continued to age. In the mid-1980s,
the number of breaks in cast iron mains installed during the 1940s and earlier started to
accelerate. In FY 1994, to combat deterioration of older sections of the system, an analysis of
cost effective system improvements was performed and the rate of main replacement was
increased from one mile per year to three. A plan to replace 75 miles of deficient mains within
25 years was begun.
In 1999, a study of system reliability concluded that major upgrades were needed to the
distribution system to provide adequate water supply during a natural disaster. This ultimately
resulted in the $40 million Emergency Water Supply and Storage Project, still underway, which
involved a new underground reservoir in El Camino Park, the siting and construction of several
emergency supply wells, and the upgrade of several existing wells and the Mayfield pump
station.
At the same time that CPAU was evaluating the reliability of its own system, the SFPUC in
consultation with BAWSCA members, was evaluating the reliability of the Hetch Hetchy water
system, which crosses two major fault lines between the Sierras and the Bay Area. That
evaluation concluded that major upgrades to the system were required. This planning process
culminated in the SFPUC's $4.6 billion Water System Improvement Project (WSIPL which is
ongoing.
J u 10 I P g
\It!!\ lJ7'lLIT'Y
SECTION VIII. HISTORICAL EXPENSES AND REVENUES
Table 7 shows the Water Utility's expenses and revenues for the past five years. Water supplies
made up 33% of total expenses in FY 2009, but have been increasing by 18.4% per year on
average, rising to 47% of total expenses in FY 2013. Total costs for this utility have risen 8% on
average over the last four years, mainly due to increasing water supply costs. Excluding water
supply, CIP and debt service costs (the 2009 bond resulted in large financing costs starting in
2010), costs for this utility have increased by 5% annually on average since 2009. Rate
increases occurred in all years except 2011, with sales dropping in 2010. Connection and
capacity fee income has also been on the rise. One item of note is the negative interest earned
in FY 2013, which represents a decrease in the market value of the City's investment portfolio
that accounting rules require the City to recognize at the end of each fiscal year. Given that the
City holds its investments to maturity these "mark to market" gains and losses do not impact
the utility's long term financial position.
Table 7: Historical Expenses, Water Collection Utility ($000)
Fiscal Year 2009 I 2010 I 2011 2012 2013
i !
' i I I 6 REVENUE ' I
7 Utilities Retail Sales 25,1981 24,5411 24,821 30,674! 34,765
8 Service Connection & Capacity Fees 8481 6941 1,146 1 ,445! 1,918
9 Other Revenues plus Transfers In 1,640 1,951 i 1,706 995: 3,196
10 Interest & Gain or Loss on Investment 1,788 1,5721 727 673, -205
11 Sub Total 29,474 28,758! 28,400 33,787• 39,674
12 ! !
13 Total Sources of Funds 29,474 28,7581 28,400 33,787! 39,674
14 OPERATING EXPENSE I i ~
15 Water Supply Purchases 8,4431 9,0611 10,678 14,889: 16,605
16 Administration 2,162 2,1681 2,559 2,7741 3,181
17 Customer Service 1,436 1 ,372! 1,476 1 ,545j 1,585
18 Engineering (Operating) 333 2631 247 301 i 339
19 Operations & Maintenance 4,040 4,2571 4,885 4,901 j 4,944
' 553[ 20 Resource Management 394 486i 576 558 I 21 Debt Service & Other Related 426 1,5891 2,143 2,064! 1,950
22 Rent 1,919 2,1071 2,122 2,157! 1,912
23 Transfers Out 4,554 2821 442 104' 2,055
24 CIP (Non Bond) 2,605 6,189! 5,348 4,369! 2,345
I
25 SubTotal 26,312 27,7751 30,476 33,6571 35,473
26 1 !
27 Total Uses of Funds 26,312 27,775! 30,476 33,657i 35,473
28 I
29 Into/ (Out of) Reserves 3,162 983 i (2,077) 131 4,201
u 111 !.,'' / g
SECTION IX. SEVEN YEAR FINANCIAL fORECAST
1
2
1. OVERVIE\N
Staff has prepared a forecast of costs and revenues through FY 2021. As shown in Table 8 (and
Appendix A), the Water Utility's total costs are projected to increase by roughly 3.5% to 4% per
year on average for FY 2015 through FY 2021. The forecast assumes a sales revenue decrease
in FY 2015 due to voluntary water use restrictions. Although most costs are rising at only 4%
per year, revenues are currently below costs in a normal year. Also noticeable are the lower
than budgeted purchase costs for FY 2014 (due to the SFPUC water rates being much lower
than forecast), and higher CIP spending in FY 2014 as well (the result of new funding for the
California Avenue project, as well as increased costs for existing water main replacement
projects).
Table 8: Seven Year Water Utility Financial Forecast Summary ($000)
Actual Adopted Projected i Fiscal Year 2013 2014 2014 2015 2016 2017 2018 2019 2020 2021
c<,, <>Y<"o "''·''· ~~>icJi'·'c'ftCif/ '"">''"''· .X ,got. I·•<J<W· ,( '{% ,RA'I'I;cc S''';.:,. c·c•
4.88o 4.a'o8 '''/'~.808 4,i5'1 4,s45 4,893
'tc,;•;.\>7~
SALES UNITS (THOUSAND CCFs) 4,300 4,798 4,941 4,990
3 REVENUE
44,6511 4 Utilities Retail Sales 36,062 36,781 36,781 33,001 38,973 41,675 47,875 50,709 51,706
5 Service Connection & Capacity Fees 1,918 868 1,153 1,100 1 '117 1,136 1,156j 1,176 1,198 1,219
6 Other Revenues plus Transfers In 1,877 1,048 1,048 1,055 1,063 1,071 1,0821 1,093 1,075 1,075
7 Interest & Gain or Loss on Investment -218 682 682 487 589 623 722, 7181 714 694
8 Sub Total 39,639 39,379 39,664 35,643 41,741 44,506 47,610[ 50,863 53,695 54,694
9 CIP Bond Proceeds I Reserve 0 0 0 0 41,74~1 0 Oi 0 0 0
10 Total Sources of Funds 39,639 39,379 39,664 35,643 44,506 47,6101 50,863 53,695 54,694
11 OPERATING EXPENSE
21,2481 12
13
14
15
16
17
18
19
20
21
22
Water Supply Purchases 16,605 16,708 14,995 16,521 19,789 20,016 24,208 25,664 24,811
Administration 2,423 2,793 2,490 2,583 2,660 2,745 2,833i 2,924 3,018 3,115
Customer Service 1,585 1,988 1,740 1,806 1,858 1,932 2,008j 2,088 2,160 2,234
Engineering (Operating) 339 356 294 305 314 326 3391 351 365 379
Operations & Maintenance 4,944 5,851 5,111 6,345 6,530 6,777 7,033 7,300 7,578 7,867
Resource Management 558 625 549 569 586 608 6311 655 680 705
Debt Service & Other Related 3,219 3,220 3,220 3,219 3,223 3,219 3,2231 3,221 3,221 3,221
Rent 1,912 1,969! 1,969 2,028 2,089 2,151 2,2161 2,282 2,351 2,421
Transfers Out* -3,521 3621 362 369 376 384 3911 399 407 415
CIP 2,345 5,201 9,171 5,045 6,779J 7,013 8,2281 8,224 8,470 8,724
Total Uses of Funds 30,409 39,073 39,901 38,790 44,204[ 45,170 48,1491 51,653 53,913 53,893
Over the last several years actual costs for operations, maintenance, and CIP have been lower,
likely due to the economic downturn, which led to lower costs for services and materials. Staff
is starting to see indications that this trend is reversing. Prices are rising for contract services
and materials, and this indicates that the utility will see rising costs in the future. If costs for
operations, maintenance, and CIP increase more quickly than projected in this plan, either due
to the improving economy or other factors, larger rate increases may be required.
u n l 12 I P
While water itself is essentially a 'free' resource, resulting from snow melt in the Sierras, the
cost of maintaining the reservoirs and pipelines which supply that water are not. Currently, the
SFPUC is in the midst of a $4.6 billion dollar capital improvement program (the WSIP) to
upgrade and seismically retrofit the regional water system. The vast majority of costs are being
collected via a volumetric (per CCF) charge, rather than through monthly fixed charges.
Wholesale water rate projections are dependent on water usage, and as usage falls, the
volumetric rates will necessarily rise. Figure 3 shows the SFPUC's latest wholesale water rate
projection compared to the projection from a year ago.
Figure 3: Projected SFPUC rate changes
$5.00
$4.50
.e-' "'~
$4.00
/
" Jan 2014
$3.50 ·~"~Jan 2013
$3.00
$2.50
FY FY FY FY FY FY FY
2015 2016 2017 2018 2019 2020 2021
Part of the reason this plan contains a seven year view for the Water Utility is to show that,
based on the SFPUC's projections, wholesale water rate increases are expected to peak in FY
2020. Until then, purchase costs are expected to rise 9.5% per year on average .
. OPERATIONS
Operations costs include the Customer Service, Operations and Maintenance, Engineering,
Resource Management, and Administration categories in Table 8, above. Debt service, rent,
and transfers are also included in Operations costs.
J 13 I P
Appendix E: Description of Water Utility Cost Categories includes detailed descriptions of the
activities associated with these cost categories.
Operations costs are projected to increase by 3.5% per year, on average, over the forecast
period. Underlying these projections are salary and benefit, consumer price index, and other
cost projections obtained from the City's long-range financial forecast.
4. CAPITAL IMPROVEMENT PROGRAM (CIP)
The Water Utility's CIP consists of the following programs and budgets:
• The Water System Replacement/Rehabilitation Program, under which the Water Utility
replaces aging water mains
• Customer Connections, which covers the cost when the Water Utility installs new
services or upgrades existing services at a customer's request in response to
development or redevelopment. CPAU charges a fee to these customers to cover the
cost of these projects.
• Ongoing Projects, which covers the cost of replacing old/under-recording meters and
degraded boxes and covers, as well as the cost of capitalized tools and equipment.
• One Time Projects, which cover specific, non-recurring replacement of system
resources (such as water tank re-coatings)
Table 9 outlines the current FY 2014 adopted budget, with actuals and remaining budget as of
December 31, 2013. Also included is the five year CIP spending plan, although these figures are
preliminary pending budget discussions starting in May. The 'committed' column represents
open contracts for which work has not yet been completed or invoices paid.
Table 9: Budgeted Water Utility CIP Spending ($000)
.· SR«;!hding, Remain.
~ ~ ' . -: --~ ~ ""'' ~~ ~"' )__,. 01' , " ~ '!"~. I Current "' ;; • I
\. f' Eroj~~t Category !;!_u£jget* •. Cu!r· Yr f:3ydg§j .~o.mmi!te~ .• FY ;~!,)15 JoY g_O,l6 :Ji'!'i!fi~~'. ~3':,?flj§, 0F,Y&Ql,2~
One Time Projects 13,656 (1,579) 12,076 4,023 2,980 --
Water Main Replacement 6,460 (262) 6,197 374 -4,836 4,635
Ongoing Projects 3,708 (712) 2,996 755 1,625 1,483 1,906
Customer Connections 449 (240) 209 11 450 460 473
TOTAL 24,272 (2,794) 21,478 5,163 5,055 6,779 7,014
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year
**Equal to Reserve for Reappropriations +Reserve for Commitments.
-
6,126
1,617
486
8,228
The Water System Replacement and Rehabilitation Program funds the replacement of
deteriorating water mains. The water system consists of over 236 miles of mains,
approximately 2000 fire hydrants, and over 20,000 metered service connections spanning 9
pressure zones over a 26 square mile service area. CPAU utilizes an asset management
database in conjunction with hydraulic modeling software in prioritizing capital
improvements. Mains are selected by researching the maintenance history of the system and
identifying those that are undersized, corroded, and subject to recurring breaks. CPAU uses a
scoring system based on criticality in order to prioritize which mains to replace first, and
coordinates with the Public Works street maintenance program to avoid cutting into newly
repaved streets. CPAU replaces approximately 3 miles of main per year, or 1.3% of the system.
n 1 14 I
-
6,048
1,686
500
8,234
Costs for the water main replacement program are increasing for a variety of reasons:
e Fire Code regulations now mandate fire sprinklers for new residential units. To
accommodate increased fire flows, new main replacement projects require larger
diameter pipe.
e CPAU has switched to high-density polyethylene (HOPE) for its mains. Installation costs
for this material are slightly higher, though lifecycle costs are lower, and the material
performs better. Joints in distribution mains are the most likely place for failure, and
sections of HOPE pipe can be fused together rather than connected with fittings. In the
long run, this will reduce losses and maintenance costs.
e To take full advantage of HOPE's fusibility, CPAU is now replacing the services along
with the water mains with new HOPE services. In the past, the existing services were
reconnected, regardless of the material. This new practice costs more in the short run,
but will provide long term benefits.
e lastly, as the economy begins to recover, costs have begun to escalate.
These factors have created some uncertainty in future main replacement costs. In addition, the
25 year main replacement program initiated in 1993 is nearing completion. This makes it a
good time to re-evaluate the program. CPAU will initiate a master planning process in FY 2015
to evaluate the current state of the distribution system and determine the necessary rate of
main replacement in future years. This could result in higher CIP expenses than are currently
forecasted.
Ongoing Projects and Customer Connections are projected to cost approximately $1.8 million in
FY 2015 and increase by 3.5% each year through the end of the forecast period. Actual
expenses for these projects fluctuate annually depending on how many defective meters are
discovered and replaced during routine maintenance, as well as how much development and
redevelopment is going on that prompts the replacement or upgrade of water services. It is
worth noting that property owners pay a fee for water service replacement or expansion during
redevelopment, so when costs go up, so does fee revenue.
Aside from customer connections, the CIP plan for FY 2015 to FY 2019 is funded by utility rates
and capacity fees. The details of the plan are shown in Appendix B: Water Utility Capital
Improvement Program {CIP) Detail.
SECTtONX. REVENUE.REQUIREMENJ.AND RfVENUESOURCES
The revenue requirement is the total amount of revenue that must be collected in order to
meet the planned expenditures for the Water Utility. Costs for the Water Utility are projected
to increase by 4% per year or more through FY 2020, as shown in Figure 4, below. As previously
mentioned, future CIP spending levels are uncertain, and CPAU will complete a distribution
system master plan in the upcoming year to determine future year CIP needs. The High Cost
scenario in Figure 4 shows the necessary rate increases under a higher CIP cost scenario in
which the master planning process reveals a need for accelerated main replacement and the
replacement of one of the major mains in the foothills. With a 0% increase in FY 2015,
matching costs to revenues by FY 2021 will require 5 to 7% increases in sales revenues each
n 15 I P
year for FY 2016 to FY 2020. Each of the projected FY 2016 to FY 2020 rate increases will
increase median residential water bills by $4.00 to $5.00 per month.
,.......
(/) c
0
$60
$50
$40
= $30 :E ........-
Y7
$20
$10
$0
Figure 4: Water Fund Revenue and Cost Projections
c:::::JAddtl CIP, High
Cost Scenario
~!!ii!i!!i!!~Water Supply
c::::::I CIP -Non Bond
~Operations
l!!iili!!i!!l Debt Service
<t&Revenue, High
Cost Scenario
Figure 5 illustrates how the existing reserves would be reallocated according to the proposed
Reserves Management Practices and how the balances of the different reserves would change
over the financial forecast period. For the Water Fund, the CIP reserve would be drawn down
by FY 2019 and the Rate Stabilization Reserve would be drawn down by FY 2016.
u e 16 I
Figure 5: Water Fund Revenue and Cost Projections
$40 Vi Projected FY 2014 year-end reserves under existing reserves structure
I::
Proposed reallocation :: $35
~ -$30 (see Appendix C: Water Utility Reserves Management Practices)
$25
$20
$15
$10
$5
$0
SECTION XI.
'<;!" '<;!" 1.() \.0 .-1 .-1 .-1 .-1 ....... ....... ....... ....... 0 0 0 0 ("() ("() ("() ("() ....... ....... ....... ....... \.0 \.0 \.0 \.0
Act Proj Proj
RISK ASSESSMENT
!' 00 Cl)
.-1 .-1 .-1 ....... ....... ....... 0 0 0 ("() ("() ("() ....... ....... ....... \.0 \.0 \.0
0 N ....... 0 ("() ....... \.0
.-1
N ....... 0 ("() ....... \.0
Rate Stabilization
r:2l CIP Reserve
Operations Reserve
Plant Replacement
Reapp/Commit
Staff performs an annual assessment of risks for the Water Utility. For this evaluation, staff
estimates the revenue shortfall due to:
1. the maximum observed budget-to-actual variance in one year during the past ten years;
2. an increase of 10% of planned system improvement CIP expenditures for the budget year;
Table 10 summarizes the risk assessment calculation for the Water Utility. The Operations
Reserve is projected to be adequate to manage these risks over the entire forecast period.
Table 10: Water Risk Assessment ($000)
.··s·£·.[~·,!~:.x·: .. r .. s: .. ·.·J;~·~.;; ?~······· .·.· ...• • F~2Q:t,$c FV~Ol.G ·FY20~'i. FY.~Oi1J? .• F\t•~oJ,$'/
Total Revenue $33,001 $38,973 $41,675 $44,651 $47,875
Max. Historical Budget-to-Actual variance 12% 12% 12% 12% 12%
4~010 5,425
System Rehabilitation CIP Budget $5,045 $6,779 $7,013
505 . 678 701 823 .• 822
Total Risk Assessment value 4,514 5,413 5,765 6,248 6,639
Projected Operations Reserve Level 8,321 7,382 7,718 9,179 10,389
17 1 P g
SECTION XII. COMMUNICATIONS PLAN
The FY 2015 Water Utility communications strategy covers these primary areas: water
conservation, drought, rates, operations and infrastructure, and safety. Drought and water
efficiency are at the forefront of today's communications, with 10% voluntary restrictions
underway and a "Keep Calm and Save Water" campaign being pushed by Customer Service and
Marketing. CPAU is constantly updating its website with new information as it arises, and Staff
is planning for what may be needed should the SFPUC call for mandatory cutbacks at their April
announcement. There is no need for formal"rate change" communications at this time, but
website and community education about rates is ongoing. Water conservation activity includes
bill inserts, website pages, email blasts, and the use of social media. To keep customers
apprised of the status and accomplishments of CIP projects, a network of project web pages are
maintained; traffic is driven to the website via ads in publications, newspaper inserts, social
media and email blasts. Safety topics are emphasized year-round and, while print materials
and website pages still feature prominently, CPAU is turning the outreach emphasis to direct
mail, newspaper inserts, and social media including video, cable TV, community
safety/emergency preparation meetings and updates to neighborhood groups.
18 I
Appendix A: Water Utility Financial Forecast Detail
Appendix B: Water Utility Capital Improvement Program (CIP) Detail
Appendix C: Water Utility Reserves Management Practices
Appendix D: Water Utility Debt Service Details
Appendix E: Description of Water Utility Cost Categories
Appendix F: Sample of Water Utility Outreach Communications
4-19 I
APPENDIX A: WATER UTILITY FINANCIAL FORECAST DETAIL
Actual Adopted Projected I i i I
Fiscal Year 2013 2014 2014 2015 2016 I 2017 2018 I 2019 2020 2021
C•tZ·i:~r!'/ol I I
·ilL··~ <•••;:. //.•••··'"· .;; ... • •• '·'; ···•·· ;.;.;. ••..• ;g.,j . • .. ;;<6% ..... ;~:~~~~~·~~&~! 1';;. •• ;; ••nffii>¥ 1 • ,~,~ '""·'>. ·····~· .;,; . ;c)o1;''1 •
4,798 .· -"" r· •>.•;•.n"'
2 SALES UNITS (THOUSAND CCFs) 4,880 4,808 4,808 4,300 4,751 I 4,8 4,893 4,941 4,990
j I I 3 REVENUE
38,973:
I
4 Utilities Retail Sales 36,062 36,7811 36,781 33,001 41,6751 44,6511 47,875 50,709 51,706
8681 I 1,1561 5 Service Connection & Capacity Fees 1,918 1,153 1,1001 1 '117 i 1,1361 1 '176 1 '198 1,219
6 Other Revenues plus Transfers In 1,877 1,048 1,048 1,055 1,~~~1 1,0711 1,0821 1,093 1,075 1,075
4871 6231
I
7 Interest & Gain or Loss on Investment -218 682 682 7221 718 714 694
8 Sub Total 39,639 39,379 39,664 35,643 41,741! 44,506 47,6101 50,863 53,695 54,694
9 CIP Bond Proceeds I Reserve 0 0 0 0 0! O\ Oi 0 0 0 I
10 Total Sources of Funds 39,639 39,379 39,664 35,643 41,741 i 44,5061 47,6101 50,863 53,695 54,694
11 OPERATING EXPENSE I
20,0161 21,2481 12 Water Supply Purchases 16,605 16,708 14,995 16,521 19,7891 24,208 25,664 24,811
13 Administration 2,423 2,793 2,490 2,5831 2,6601 2,7451 2,833 2,924 3,018 3,115
14 Customer Service 1,585 1,988 1,740 1,8061 1,8581 1,9321 2,0081 2,088 2,160 2,234
15 Engineering (Operating) 339 356 2941 305 3141 326\ 3391 351 365 379
16 Operations & Maintenance 4,944 5,8511 5,111 6,345 6,5301 6,7771 7,033 7,300 7,578 7,867
17 Resource Management 558 625 5491 569 586j 6081 6311 655 680 705
18 Debt Service & Other Related 3,219 3,220 3,220 3,219 3,2231 3,2191 3,2231 3,221 3,221 3,221
19 Rent 1,912 1,969 1,9691 2,028 2,0891 2,151 2,2161 2,282 2,351 2,421
20 Transfers Out • -3,521 362 362 369 376i 384 391 i 399 407 415
21 CIP 2,345 5,201 9,171 5,045 6,779! 7,013j 8,228! 8,224 8,470 8,724
22 Total Uses of Funds 30,409 39,073 39,901 38,790 44,2041 45,1701 48,1491 51,653 53,913 53,893
23 Into/ (Out of) Reserves 9,230 306 (236) (3,146) (2,463)1 (664)1 (539)1 (790) (218) 801
24 Ending Commitments/Reappropriations 15,401 15,401 15,401 15,401 15,401 15,4011 I 15,401 15,401 15,401 15,4011
25 Ending Plant Replacement Reserve 1,000 1,000 0 0 0 oi Oi 0 0 0
26 Ending CIP Reserve 0 0 6,000 6,0001 5,000 4,0001 2,00~1 0 0 0
27 Ending Rate Stabilization Reserve 17,227 17,533\ 3,435 524 0 01 0 0 0
28 Ending Operations Reserve 0 0 8,556 8,321 7,382 7,7181 9,179; 10,389 10,170 10,972
29 Unassigned Reserves 0 0 0 0 0 27,11~1 26,58~1 0 0 0
30 Total Unrestricted Reserves 33,628 33,935 33,392 30,246 27,783 25,790 25,572 26,373
' I ;
31 Risk Assessment Value 4,991 4,514 5,413 5,7651 6,2481 6,639 7,008 7,154
I I
I I
32 Operations Reserve Guidelines
65621 7,1391 33 Min (60 Days Commodity/O&M Exp) 5,704 5,547 6,152 6,272 7,470 7,425 7,615
34 Target (90 Days) 8,556 8,321 9,228 9,409 9,844 10,7081 11,205 11 '138 11,422
35 Max (120 Days) 11,408 11,094 12,304 12,545 13,125 14,2781 14,940 14,850 15,230
I l
20 I t:·
APPENDIX 13:WAlERUTIUTYCAPITALIMPROVEMENT PROGRAM ((:IP)DETAIL
WMR-Project 24
WMR-Project 25
WMR-Project 26
WMR -Project 27
WMR -Project 28
WMR -Project 29
124,689
396,726
696,378 2, 736,906
505,000
J u n 1 6'
2,000,000
113,179
210,940
5,368,099
505,000
299,262
23,334
51,047
WATEf\ UTILITY FINANCIAL PLAN
4,396,800
439,680 4,111,740
523,000 5,568,744
556,874 5,498,160
211 p g ('
WATEfl UTILITY FINANCIAL PLAN
Appendix B: Water Utility Capital Improvement Program (CIP} Detail (Continued)
lv n 7 (} 1 22 I
APPENDIX C: WATER UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Water Utility
Financial Plan:
Section 1. Definitions
a) "Financial Planning Period"-The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, for the Water Utility Financial Plan
delivered in conjunction with the FY 2015 budget, FY 2015 to FY 2021 is the Financial
Planning Period.
b) "Fund Balance"-As used in these Reserves Management Practices, Fund Balance refers
to the Utility's Unrestricted Net Assets.
c) "Net Assets"-The Government Accounting Standards Board defines a Utility's Net
Assets as the difference between its assets and liabilities.
d) "Unrestricted Net Assets"-The portion of the Utility's Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Reserves
The Water Utility's Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 3 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 4 (Reserve for Re-appropriations)
c) For future year expenditure on the Water Utility's Capital Improvement Program (CIP),
as described in Section 5 (CIP Reserve)
d) For rate stabilization, as described in Section 6 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 7 (Operations Reserve)
f) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 8 (Unassigned Reserves).
Section 3. Reserve for Commitments
At the end of each fiscal year the Reserve for Commitments will be set to an amount equal
to the total remaining spending authority for all contracts in force for the Water Utility at
that time.
Section 4. Reserve for Re-appropriations
At the end of each fiscal year the Reserve for Re-appropriations will be set to an amount
equal to the amount of all remaining capital and non-capital budgets that will be re-
appropriated to the following fiscal year in accordance with Palo Alto Municipal Code
Section 2.28.090.
Section 5. CIP Reserve
Funds may be added to or withdrawn from the CIP Reserve by action of the City Council and
held for future year expenditure on the Water Utility's CIP Program. If there are funds in
J u n I 2 0 4 23 I
the CIP Reserve at the end of any fiscal year, any subsequent Water Utility Financial Plan
must result in the withdrawal of all funds from this Reserve by the end of the next Financial
Planning Period.
Section 6. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and held
to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate
Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization
Reserve at the end of any fiscal year, any subsequent Water Utility Financial Plan must
result in the withdrawal of all funds from this Reserve by the end of the next Financial
Planning Period.
Section 7. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Water Utility's Fund Balance not included in the reserves
described in Section 3-Section 6 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 7(d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for
that year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months
of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Water Utility shall be designed
to return the Operations Reserve to its target level within four years.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Water Utility's Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
8, below.
24 I P g
Section 8. Unassigned Reserve
If the Operations Reserve reaches its maximum levet any further additions to the Water
Utility's Fund Balance will be held in the Unassigned Reserve. If there are any funds in the
Unassigned Reserve at the end of any fiscal year, the next Financial Plan presented to the
City Council must include a plan to assign them to a specific purpose or return them to the
Water Utility ratepayers by the end of the first fiscal year of the next Financial Planning
Period. For example, if there were funds in the Unassigned Reserves at the end of FY 2015,
and the next Financial Planning Period is FY 2016 through FY 2021, the Financial Plan shall
include a plan to return or assign any funds in the Unassigned Reserve by the end of
FY 2016. Staff may present an alternative plan that retains these funds or returns them
over a longer period of time.
2s I P
APPENDIX D: WATER UTILITY DEBT SERVICE DETAILS
The Water Utility currently makes payment on its share of two bond issuances. The first is the
2009 Water Revenue Bond, Series A, issued for $35 million, and to be retired by 2035. As part
of the 'Build America' bond program, there is an interest payment subsidy from the Federal
Government of 35%. There is always the possibility that the federal government will choose to
stop payment on this subsidy. The automatic federal spending cuts under the Budget Control
Act {BCA) of 2011 have already reduced the subsidy by $50,000 per year, and if planned cuts
through 2021 proceed without amendment, staff estimates that the subsidy would be reduced
by over $200,000 per year by 2021. The Bipartisan Budget Act of 2013, which relieved some of
the discretionary spending cuts in the 2011 BCA, did not affect automatic cuts to the subsidy,
and actually extended the automatic cuts through 2023.
The second bond issuance is the 2011 Utility Revenue Refunding Bond, Series A, which is to be
retired in 2026. This $17.2 million issuance refinanced an earlier Water and Gas Utility bond
issuance, the 2002 Utility Revenue Bonds, Series A, which was issued to finance various capital
improvements for both systems. The Water Utility's share of the issuance was roughly $7.8
million.
The cost of debt service for the Water Utility's share of these bond issuances for the financial
forecast period is as follows:
......... .......... ... fi\'20.14
.. · ; .. {$000)
2009 Water
Revenue Bonds, 1,977
Series A
2011 Utility
Revenue Bonds, 656
Series A
Table 11: Water Utility Debt Service
FY2015 · F~~~16
($0Qo) . ($00t)) .
1,986 2,002
656 657
FV 2017 FY~018 FY:2919 F\'~()20, FY·2021
($()00} . >.t$0:(}0) • ($000) .J {$000) {$000)
2,012 2,031 2,046 2,064 2,079
657 656 654 656 657
Both the 2009 and 2011 Bonds include the following covenants: 1) net revenues plus Available
Reserves shall at least equal125% of the maximum annual debt service, and 2) Available
Reserves shall be at least 5 times the maximum annual debt service. Note that "Available
Reserves," as defined for both bonds, is defined as reserves for the Water, Gas and Electric
systems, not just the Water system.
The current Financial Plan maintains compliance with these covenants throughout the forecast
period. Due to the relatively small size of the annual debt service payments for these bonds in
relation to the size of Available Reserves, ($149.5 million at the end of FY 2013, over 55 times
the maximum annual debt service alone), the Water Utility more than satisfies both covenants.
The Water Utility's Operations Reserve satisfies the first covenant on its own at more than 3
times annual debt service throughout the forecast period.
The net revenues (but not the reserves) of the Water Utility are also pledged for one other
bond as shown in Table 12 below, even though the Water Utility is not responsible for the debt
J n 26 I P
service payments. The Water Utility's reserves or net revenues would only be called upon if the
responsible utilities are unable to make their debt service payments. Staff does not currently
foresee this occurring. Requirements of the California Constitution require that any amounts
advanced from one utility to pay debt service for another utility must be repaid by the
borrowing fund.
Table 12: Other Issuances Secured by Water Utility's Revenues or Reserves
1995 Series A Utility
Revenue Bonds
. R~~#g~$~·~~~
.btili~ie~. ·
Storm Drain $680
s~cyiedb •. , .• Nit.>
.·;R~~~.l~e~· ·· ·
Yes No
27 I P a g
APPENDIX E: DESCRIPTION OF WATER 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 Water Utility's share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process.
It does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU's key account representatives, who work with large
commercial customers who have more complex requirements for their water services.
Resource Management: This category includes water procurement, contract management,
water resource planning, rate setting, interaction with BAWSCA, the SFPUC, and the SCVWD,
and tracking of legislation and regulation related to the water industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
• investigating reports of damaged mains or services and perform emergency repairs;
o testing and operating valves;
o monitoring water quality and reservoir levels;
o monitoring the status of the different pressure zones;
o flushing water at hydrants and other closed end points of the system;
o building and replacing water services for new or redeveloped buildings; and
o 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:
o the Field Services team (which does field research of various customer service issues);
o the Cathodic Protection team (which monitors and maintains the systems that prevent
corrosion in metal tanks and reservoirs); and
o the General Services team (which manages and maintains equipment, paves and
restores streets after gas, water, or sewer main replacements, and provides welding
services)
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City's General Fund staff, as well as shared communications services, CPAU administrative
overhead, and billing system maintenance costs.
Engineering (Operating): The Water Utility's engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
j u 28 I P
APPENDIX F: SAM.PLE OF WATER UTILITY OUTREACH COMMUNICATIONS
Add native, Bay friondiy and lower-wator-usinrl plants to
cre<)to a now landscape or updat<J your <>ld orw~wH'II help
With the cost throu9h our Landscape RHbate Program.