HomeMy WebLinkAbout2018-05-15 Finance Committee Agenda Packet Finance Committee
1
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Tuesday, May 15, 2018
Special Meeting
Community Meeting Room
9:00 AM
Agenda posted according to PAMC Section 2.04.070. Supporting materials are available in
the Council Chambers on the Thursday 12 days preceding the meeting.
PUBLIC COMMENT
Members of the public may speak to agendized items. If you wish to address the Committee on any issue that is on this agenda, please complete a speaker request card located on the table at the entrance to the Council Chambers/Community Meeting Room, and deliver it to the Clerk prior to discussion of the item. You are not
required to give your name on the speaker card in order to speak to the Committee, but it is very helpful.
Call to Order
Oral Communications
Members of the public may speak to any item NOT on the agenda.
Action Items Page #s
9:00am - 10:00am 1)FY 2019 Proposed Budget Overview 21-28
10:00am - 10:30am 2) Non-Departmental, Operating Budget Overview 461-464
10:30am - 11:15am 3) City Council Appointed Officials and City Council
a)City Attorney, Operating Budget 119-127
b)City Auditor, Operating Budget 129-140
c)City Clerk, Operating Budget 141-150
d)City Council, Operating Budget 151-155
e)City Manager, Operating Budget 157-169
f)Office of Sustainability, Operating Budget 171-179
11:15am - 12:00pm 4) June 30, 2017 Actuarial Valuation of Palo Alto’s Retiree
Healthcare Plan and Annual Actuarially Determined
Contributions (ADC) for Fiscal Years 2019 and 2020
(Staff Report #9213)
57 (under GF
overview)
12:00pm - 12:15pm 5) Human Resources Department, Operating Budget 251-255
a)General Fund 256-262
b)General Liability Fund, Operating Budget 263-267
c)Employee Benefit Funds
i)General Benefits Fund, Operating Budget 467-472
ii)Workers Compensation Fund, Operating Budget 268-274
d)Retiree Benefit Fund 473-475
12:15pm - 12:30pm 6) Administrative Services Department 181-186
a)General Fund 187-196
b)Printing & Mail Fund 197-201
12:30pm - 1:30pm Lunch Break
Operating Budget
Capital Budget
2 April 17, 2018
MATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE CITY COUNCIL AFTER DISTRIBUTION OF THE AGENDA
PACKET ARE AVAILABLE FOR PUBLIC INSPECTION IN THE CITY CLERK’S OFFICE AT PALO ALTO CITY HALL, 250 HAMILTON AVE.
DURING NORMAL BUSINESS HOURS.
Page #s
1:30pm - 2:00pm 7) Information Technology Department
a) Operating Budget 275-288
b) Capital Budget 601-627
2:00pm - 2:15pm 8) Development Services Department 221-236
2:15pm - 3:00pm 9) Community Services Department 203-220
3:00pm - 4:30pm 10) Utilities Department
a) Electric Fund
i) Operating Budget 407-419
ii) Capital Budget 307-401
iii) Utilities Advisory Commission Recommendation
that the City Council Adopt: 1) a Resolution
Approving the Fiscal Year 2019 Electric Financial
Plan, and 2) a Resolution Increasing Electric Rates
by 6% by Amending the E-1, E-2, E-2-G, E-4, E-4-G,
E-4 TOU, E-7, E-7-G, E-7 TOU and E-14 Rate
Schedules (Staff Report #9158)
b) Fiber Optics Fund
i) Operating Budget 420-427
ii) Capital Budget 403-417
c) Gas Fund
i) Operating Budget 428-439
ii) Capital Budget 419-459
iii) Utilities Advisory Commission Recommendation
that the City Council Adopt: 1) a Resolution
Approving the Fiscal Year 2019 Gas Utility Financial
Plan; and 2) a Resolution Increasing Gas Rates by
4% by Amending Rate Schedules G-1 (Residential
Gas Service), G-2 (Residential Master-Metered and
Commercial Gas Service), G-3 (Large Commercial
Gas Service), and G-10 (Compressed Natural Gas
Service) (Staff Report #9157)
d) Wastewater Collection Fund
i) Operating Budget 440-448
ii) Capital Budget 485-513
e) Water Fund
i) Operating Budget 449-460
ii) Capital Budget 551-597
Adjournment
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City of Palo Alto (ID # 9213)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/15/2018
City of Palo Alto Page 1
Summary Title: OPEB
Title: June 30, 2017 Actuarial Valuation of Palo Alto’s Retiree Healthcare Plan
and Annual Actuarially Determined Contributions (ADC) for Fiscal Years 2019
and 2020
From: City Manager
Lead Department: Administrative Services
Recommendation
Staff recommends that the Finance Committee recommend that City Council review and accept
the June 30, 2017 actuarial valuation of Palo Alto’s Retiree Healthcare Plan and approve full
funding of the annual Actuarially Determined Contributions (ADC) for Fiscal Years 2019 and
2020.
Executive Summary
Per the Governmental Accounting Standards Board (GASB), bi-annually the City Council is
required to review and approve the actuarial valuation for retiree healthcare plan for the
upcoming two fiscal years and approve funding of the annual ADC.
Background
The City of Palo Alto offers its employees and retirees a Retiree Healthcare benefit plan which is
managed and administered by the California Public Employees’ Retirement System (CalPERS), a
State of California Retiree Healthcare Trust program. Bi-annually staff contracts with an actuary
firm which provides an actuarial report detailing the latest status of the City of Palo Alto’s
Retiree Healthcare plans for employees and retirees. The actuarial report is used to calculate
the annual ADC to the trust. In addition, updates on the rate of return, funding status, and
changes to the trust based on various impacts are detailed in the report. Unlike the pension
actuary reports, this actuary details impacts by Fund, Department, Employee Group, and
Healthcare Plans selected.
As a refresher on the CalPERS Retiree Healthcare benefits, there are four groups of benefits
within the plan. Table 1 below outlines the different benefits levels by Group.
City of Palo Alto Page 2
Table 1: City of Palo Alto Retiree Healthcare Benefit Plans and Tiers
Miscellaneous Safety: Fire Safety: Police
Group 1
Retired before January
1, 2007; eligibility
starting at the age 50
and 5 years of service;
full premium up to
family coverage
Retired before January 1,
2007; eligibility starting
at the age of 50 and 5
years of service; full
premium up to family
coverage
Retired before March 1,
2009; eligibility starting at
the age of 50 and 5 years of
service; full premium up to
family coverage
Group 2
Retired between
January 1, 2007 and
May 1, 2011; eligibility
starting at the age 50
and 5 years of service;
same as Group 1, but
premium limited to 2nd
most expensive
medical plan
Retired between January
1, 2007 and December 1,
2011; eligibility starting
at the age 50 and 5 years
of service; same as
Group 1, but premium
limited to 2nd most
expensive medical plan
Retired between March 1,
2009 and April 1, 2015 (POA),
between January 1, 2007 and
June 1, 2012 (PMA) ;
eligibility starting at the age
50 and 5 years of service;
same as Group 1, but
premium limited to 2nd most
expensive medical plan
Group 3
(Retirees) Retired after Group 2, did not elect into Group 4, benefit same as active employees
Group 3
(Active EEs)
Currently active, not in
Group 4. UTLM: 90% of
premium up to 90%
Group 2 Cap; Other
Misc: Flat Dollar Caps
equal to actives
N/A
(All active Group 3 IAFF &
FCA elected into Group
4)
N/A
(All active Group 3 POA &
PMA elected into Group 4)
Group 4
(Government
Code 22893)
Vesting Schedule: 10
years gets 50%, 20
years gets 100%,
formula amount
Vesting Schedule: 10
years gets 50%, 20 years
gets 100%, formula
amount
Vesting Schedule: 10 years
gets 50%, 20 years gets
100%, formula amount
City of Palo Alto Page 3
Discussion
Staff contracted with Bartel Associates, LCC (BA) for this retiree healthcare actuarial report
(Attachment A) since the firm is familiar with the City and has the format set-up from the
previous actuary report assumptions and calculations. Staff previously selected BA in a
competitive process (August 2015) in which 3 responses were received and ranged from
$41,010 to $43,000 in cost with Bartel’s contract award being at $42,575. Since BA is very
familiar with Palo Alto and our benefits structure, BA was selected. The current agreement
(October 2017) was for $50,000; the cost for the actuarial report was the same, but this
contract included additional funding for pension calculations requested by the Finance
Committee and staff.
BA prepared the actuarial analysis to determine the City’s retiree healthcare liability and the
ADC for Fiscal Years 2019 and 2020 – update on the funding status, results of assumptions such
as discount rate (DR), the healthcare plan premiums, and projected future healthcare costs. On
December 21, 2016, the CalPERS Board of Administration lowered the discount rate from 7.25
percent to 6.75 percent for Fund 1, which the City Council approved as the investment option.
The actuarial analysis is based on current employees’ accrued benefit, and retired employees as
of June 30, 2017. Employees and retirees have an open enrollment window in October each
year in which they can make changes to their healthcare plans that take effect in January of the
following year.
CalPERS Projected Contribution levels
The actuary report has two components to the annual billing of the employer portion of retiree
healthcare contributions that comprise the Actuarial Determined Contribution (ADC), 1) the
Normal Cost (NC), and 2) the Unfunded Actuarial Accrued Liability (UAAL).
- NC: This reflects a rate of contribution for the plan of retirement healthcare benefits
provided to current employees based on the current set of assumptions.
- Employer Amortization of UAAL: This is an annual payment calculated to pay down an
agency’s unfunded accrued pension liability. Assuming every assumption in the
actuarial valuation was accurate, an organization would eliminate its unfunded pension
liability if it made these payments annually for 30 years. The City Council approved a
closed amortization period and is at year 26 as of June 30, 2017. The liability grows
when the assumptions goals, such as discount rate, are not met.
This ADC for FY 2019 is $16.0 million, which is $0.9 million less than FY 2018 mostly due to
premium caps, changes in mortality assumptions, and some retirees/spouses being eligible for
Medicare premium plans, which are much lower in cost. For FY 2020 the ADC is $16.5 million,
an increase of $0.5 million over the FY 2019 payment. The General Fund share for FY 2019 is
$10.2 million and $10.5 million for FY 2020. This reflects a decrease of $0.1 million compared
to FY 2018. These payments reflect the blended or combined cost of both the “Normal Cost”
and the “Unfunded Actuarial Accrued Liability”.
City of Palo Alto Page 4
Future ADC’s are estimated to grow from $16.5 million in FY 2020 to $21.0 million in FY 2028 or
by about 27 percent. This is based on a 6.75 percent discount rate. The following graph shows
historical returns back to FY 2009. It uses the unaudited actual investment return for the first
half of Fiscal Year 2018 and the assumed rate of return for the last half of Fiscal Year 2018.
Table 2: Historical Returns of the OPEB Trust
Projected Actuarial Unfunded Accrued Liability
Included in the actuary report is the plan’s “Funded Status.” Overall, the Retiree Healthcare
Trust is funded at 37 percent, which is up from 33 percent in FY 2015. The unfunded UAAL is
$153.5 million as of June 30, 2017 for all funds and $100.4 million for the General Fund. A
couple of years ago, GASB made a change in the calculation of UAAL by requiring the calculation
of “implied subsidy”, which requires an agency to recognize that it pays the same medical
premiums for active employees as those that are retired. The implied subsidy is that the cost of
medical for active employees is lower than retirees, but the agency pays the same premium.
For Palo Alto, this is an issue since it has 967 active employees and 959 retirees. The calculation
increases the UAAL by $29.2 million or 19 percent, without the implied subsidy the UAAL would
be at $124.3 million.
City of Palo Alto Page 5
TABLE 3: Actuarial Unfunded Accrued Liability
As of
June 30, 2015
As of
June 30, 2015
Projected as of
June 30, 2015
Citywide $156,217 153,509 $143,926
Funded Ratio 33% 37% 44%
General Fund $100,408 $100,408 $94,127
% Change from Prior Year Citywide -2% -6%
CalPERS recognizes the varying assumptions that may impact a plan’s unfunded actuarial
accrued liability and therefore a retiree healthcare plan’s funding status, especially the
implications of the discount rate assumption. Therefore, in addition to the actuarial
assumptions used to develop this annual evaluation, BA includes an Analysis of Discount Rate
Sensitivity section in their reports in order to provide some level of sensitivity analysis of the
retiree healthcare plan. At a 6.25 percent discount rate, the plan is estimated to have a total
unfunded accrued liability of $169.1 million compared to $153.5 million at a 6.75 percent
discount rate, and a 35 percent funded status at 6.25 percent discount rate compared to a 37.3
percent funded status at 6.75 percent. The ADC would increase from $16.0 million to $16.7
million for FY 2019.
Conclusion
The City of Palo Alto has already proactively mitigated the increasing costs of healthcare plans
for current and future retirees. It started with cost sharing with employees, capping the plans
covered, and establishing a flat contribution that can be adjusted with each labor agreement.
Staff began funding this Trust in May 2008 at a level of $33 million and it has grown to $102
million as of April 2018. This has proved very beneficial; each year the City Council has
approved the full funding of the ADC, helping to close the unfunded gap. The closing of the
amortization period will allow for funding relief in future years since the City Council can use
the Trust to pay healthcare benefits from deposits and earnings for current and future retirees.
Staff anticipates discussions at the May 15, 2018 Finance Committee meeting and staff from
Bartel Associates will be available for questions and answers. Staff has incorporated the results
of this actuarial valuation into the City Managers Proposed FY 2019 Budget.
Environmental Review
This report is not a project for the purposes of the California Environmental Quality Act.
Environmental review is not required.
City of Palo Alto (ID # 9158)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/15/2018
City of Palo Alto Page 1
Summary Title: FY 2019 Electric Utility Financial Plan and Rate Proposal
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt: 1) a Resolution Approving the Fiscal Year 2019 Electric Financial Plan,
and 2) a Resolution Increasing Electric Rates by 6% by Amending the E-1, E-2,
E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU and E-14 Rate Schedules
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission (UAC) request that the Finance Committee
recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2019 Electric Financial
Plan (Attachment B), including amendments to the Electric Utility Reserves
Management Practices (Attachment C); and
2. Adopt a resolution (Attachment D) amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Small Non-Residential Electric Service), E-2-G (Small Non-Residential
Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-
Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-
7-G (Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-
Residential Time of Use Electric Service), and E-14 (Street Lights).
Executive Summary
The FY 2019 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2028. Costs are projected to rise substantially for the next several years for several
reasons. First, costs for electric supply purchases are increasing as a result of new renewable
energy projects coming online. Increases in transmission costs are also projected. Substantial
additional capital investment in the electric distribution system is planned for FY 2018 through
FY 2023, and operational costs are increasing.
Because of these rising costs, an increase in sales revenues is required. A 6% rate increase is
proposed for July 1, 2018, and a 3% increase projected for July 1, 2019, with (0% to 2%)
City of Palo Alto Page 2
increases projected afterward. While 6% would be the overall increase in sales revenues,
different customer classes will see slightly different increases ranging from 3% to 8%, as shown
in Tables 3 and 4. The proposed rate increases were calculated using the 2016 cost of service
analysis (COSA) model created for the City by EES Consulting, which was implemented on July 1,
2016.
Several reserves transfers were approved in the FY 2018 Electric Financial Plan, but have not
been executed yet. These are summarized below. Due to improved hydroelectric conditions in
FY 2017 and the first half of FY 2018, staff is able to reduce these reserve transfers in the
proposed FY 2019 Electric Financial Plan, particularly the loan from the Electric Special Projects
Reserve. To completely eliminate the loan from the Electric Special Projects Reserve, an 8% rate
increase would be required on July 1, 2018.
Reserve Transfers: Approved, Proposed, and Alternative Transfers
FY 2018 Financial Plan
Approved Transfers
Staff Proposal
(Rate Changes:
6% 2019, 3% 2020)
Alternative
(Rate Changes:
8% 2019, 0% 2020)
Rate Stabilization
Reserve
$9 million $9 million $9 million
Hydroelectric Reserve Up to $11.4 million $1 million (projected) $1 million (projected)
Electric Special
Projects Reserve Loan
$10 million $6 million None
This proposed rate increase is slightly lower than the 8% July 1, 2018 rate increase in staff’s
preliminary rate projections, which was to be followed by a 4% increase on July 1, 2019.
The FY 2019 Electric Financial Plan also includes a change to the reserves policies for the
Hydroelectric Stabilization Reserve, outlining the method used to determine whether the HRA
will be implemented in a given fiscal year, and authorizing staff to transfer funds between the
Operations and Hydroelectric Stabilization Reserve based on a formula that captures the cost
impact or benefit of hydroelectric generation each year.
Background
Every year staff presents the Finance Committee and UAC with Financial Plans for its Electric,
Gas, Water, and Wastewater Collection Utilities and recommends any rate adjustments
required to maintain their financial health. These Financial Plans include a comprehensive
overview of the utility’s operations, both retrospective and prospective, and are intended to be
a reference for UAC and Council members as they review the budget and staff’s rate
recommendations. Each Financial Plan also contains a set of Reserves Management Practices
describing the reserves for each utility and the management practices for those reserves.
Discussion
City of Palo Alto Page 3
Summary of Proposed Actions
The two resolutions recommended for Council adoption will accomplish the following:
1. Increase overall electric rates by 6% effective July 1, 2018;
2. Approve the FY 2019 Electric Financial Plan, including a change to the reserves policies
for management of the Hydroelectric Stabilization Reserve.
Proposed and Projected Sales Revenue Requirement, FY 2019 through FY 2023
The proposed July 1, 2019 rate increase would be the third in a series of rate increases from
FY 2016 through FY 2020. Prior to the first increase on July 1, 2016, rates had not been
increased since July 1, 2009 because costs had been low over that period. Table 1 shows the
proposed and projected rate increases needed to recover costs of operation over the forecast
period in the FY 2019 Electric Financial Plan.
Table 1: Electric Rate Adjustments, FY 2017 to FY 2023
FY 2017
Approved
FY 2018
Approved
FY 2019
Proposed
FY 2020
Projected
FY 2021
Projected
FY 2022
Projected
FY 2023
Projected
11% 14% 6% 3% 2% 0% 1%
These sales revenue increases are for the utility as a whole, but the rate changes will differ for
individual customer classes. Proposed rate increases for each customer class are discussed
below.
Cost drivers and containment
The rate increases are related to several cost factors: increasing transmission costs and new
renewable projects coming online; substantial additional capital investment in the electric
distribution system, and rising operational costs. Historically, total electric utility costs
(excluding short-term drought impacts) were roughly $130 million per year, allowing the
electric utility to go without a rate increase from July 1, 2009 to July 1, 2016. Over the period
from FY 2016 to FY 2019, though, annual costs are increasing to roughly $170 million per year,
approximately 25%, and are projected to stay at that level through at least FY 2022. This trend
can be seen in the chart on page 18 of Attachment B (the FY 2019 Electric Utility Financial Plan).
Figure 1 shows the utility’s costs in FY 2016, FY 2019, and FY 2022. Costs for the Supply Portfolio
steadily increase over that time. Costs for Operations increase slightly. Capital Projects costs
increase significantly in FY 2019 due to major one-time capital expenditures, then are projected
to decrease by FY 2022. The drop in capital expense by FY 2022 means that total electric utility
costs in FY 2019 and FY 2022 are projected to be roughly the same.
City of Palo Alto Page 4
Figure 1: Electric Utility Costs, FY 2016 Actual vs. FY 2019 and FY 2022 Projections
As shown in Figure 2, the contribution to cost increases from FY 2016 to FY 2019 is mostly
related to the Supply Portfolio (which includes transmission and renewable projects) as well as
Capital Projects spending, while by FY 2022 the Supply Portfolio is the largest contributor.
Operations spending is projected to increase somewhat compared to FY 2016. Some of this is
due to projected increases in costs of labor and materials, but most of the apparent increase is
due to the fact that not all budgeted funds for Operations were spent in FY 2016, given staff
vacancies and other factors.
Figure 2: Causes of Electric Utility Cost Increases, FY 2016 vs. FY 2019 and FY 2022
The electric Supply Portfolio increases are related primarily to transmission cost increases and
renewable energy projects coming online, as shown in Figure 3. Transmission costs are incurred
to bring electricity from contracted generation sources to Palo Alto. Staff works to contain
transmission costs through partner agencies, including the Transmission Agency of Northern
California (TANC) and Northern California Power Agency (NCPA), and through direct
City of Palo Alto Page 5
partnerships with other local utilities (Bay Area Municipal Transmission group, BAMx). All of
these groups intervene in transmission proceedings at the Federal Energy Regulatory
Commission (FERC) and the California Independent System Operator (CAISO) and have achieved
some reductions in long-term transmission costs. Staff is beginning to explore strategies for
containing renewable energy costs, and will discuss these strategies in greater detail through
the ongoing Integrated Resource Planning (IRP) process.
Staff also continues to work to contain risks and maximize the value of the hydroelectric power
it buys through the Western Area Power Administration (WAPA). WAPA is preparing for new
contracts with its customers after the current contract expires in 2024, and the City is working
in partnership with NCPA and other WAPA customers to ensure the post-2025 contract terms
preserve the value of the resource. All customers are also working to minimize any cost impacts
to the resource from the proposed California Water Fix. Lastly, working through NCPA, efforts
have been made to ensure fair environmental project cost allocations from the Bureau of
Reclamation for power customers, and to pursue repayment of over-collections from previous
years.
Figure 3: Electric Supply Costs, FY 2016 Actual vs. FY 2019 and FY 2022 Projections
This Financial Plan still contains reserves transfers. Last year’s Financial Plan (FY 2018)
authorized the use of the entire Supply Rate Stabilization Reserve (approximately $9 million),
up to $11.4 million from the Hydroelectric Stabilization Reserve, and a $10 million loan from
the Electric Special Projects Reserves to keep the Supply and Distribution Operations Reserves
above the minimum reserve guidelines. If a 6% rate increase is adopted for July 1, 2018, this FY
2019 Financial Plan proposes reducing the Electric Special Projects Reserve loan to $6 million,
and is projecting only roughly $1 million being needed from the Hydroelectric Rate Stabilization
City of Palo Alto Page 6
Reserve. More information on reserve transfers can be found in the FY 2019 Electric Financial
Plan (Attachment B). Actual expenditures in FY 2017 were lower than budgeted, and cost
savings and revenues from improved hydroelectric generator output also helped mitigate some
of the revenue shortfall that had been projected for FY 2018 in prior Financial Plans.
Staff also recognizes the importance of managing operating costs and maximizing efficiency in
order to minimize rate increases:
As discussed above, staff is working on cost containment measures related to
transmission and renewable energy costs.
City staff looks for opportunities to save money operationally, small opportunities that
add up. For example, the City recently creatively rebid its contract for construction
material supply and spoils hauling to go from using a single vendor to multiple vendors
that each specialized in specific materials, realizing nearly $250,000 in savings over
three years.
The current climate of high construction costs results in less capital replacement for
dollars invested. Staff will continue to prioritize near-term projects to address
immediate needs, and potentially defer projects where system reliability will not be
impacted to ensure full value is extracted from existing infrastructure.
A regular review of performance metrics and expenditures.
Consistent with newly approved Utilities Strategic Plan, cost containment is being instituted as
an ongoing priority and annual cycle. This will include the completion of preliminary out-year
rate forecasts in the fall, which will allow for a review by all Divisions for alignment of multiyear
strategies. This includes ongoing management review of personnel transactions, including
Review/Revisions of position classifications to match evolving needs, Addition/Deletion of
positions to reflect organizational priorities, and Review/Approval to fill individual position
vacancies in conjunction with ASD Budget Office and Human Resources.
Changes from Prior Financial Forecasts
This projection has changed since the FY 2018 Electric Utility Financial Plan presented last year.
Table 2 compares current rate projections to those projected in the last two year’s Financial
Plans. As shown, the FY 2019 rate projections are higher than projected the last two years,
primarily because transmission costs have risen substantially over this period.
City of Palo Alto Page 7
Table 2: Projected Electric Rate Trajectory for FY 2019 to FY 2025
Projection FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Current
(FY 2019 Financial Plan) 6% 3% 2% 0% 1% 1% 1%
Last year
(FY 2018 Financial Plan) 7% 0% 0% 1% 2% 1% 1%
Two years ago
(FY 2017 Financial Plan) 2% 0% 1% 0% 0% 0% 0%
Rate Changes by Customer Class
Table 3 shows the rates that will be used to recover sale revenues for each customer class. The
Street Lighting (E-14) class and the E-4 and E-7 Time of Use (TOU) rates are not shown in the
table, but can be seen in the attached rate schedules (Attachment E). These schedules are
omitted for various reasons: the E-14 rate schedule is not easy to summarize, E-7 TOU rate is
not easy to summarize and is only used by one customer, and the E-4 TOU rate schedule is both
difficult to summarize and not utilized by any customers at this time.
Table 3: Electric Rates (Current and Proposed)
Current Rates
Proposed Rates
(7/1/18)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.12159 0.12871 0.00711 5.8%
Tier 2 Energy ($/kWh) 0.19001 0.19279 0.00277 1.5%
Minimum Bill ($/day) 0.2938 0.3040 0.0102 3.5%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.18885 0.20090 001205 6.4%
Winter Energy ($/kWh) 0.13267 0.13861 0.00594 4.5%
Minimum Bill ($/day) 0.7328 0.7740 0.0412 5.6%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.11673 0.12081 0.00408 3.5%
Winter Energy ($/kWh) 0.08890 0.09297 0.00407 4.6%
Summer Demand ($/kW) 21.05 24.11 3.06 14.5%
Winter Demand ($/kW) 15.36 18.52 3.16 20.6%
Minimum Bill ($/day) 14.8414 15.9946 1.1532 7.8%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.09802 0.10507 0.00705 7.2%
Winter Energy ($/kWh) 0.07188 0.07449 0.00261 3.6%
Summer Demand ($/kW) 23.84 26.77 2.93 12.3%
Winter Demand ($/kW) 15.59 17.01 1.42 9.1%
Minimum Bill ($/day) 42.3648 45.4758 3.111 7.3%
City of Palo Alto Page 8
Table 4 shows the impact of the proposed July 1, 2018 rate changes on the residential and non-
residential bills for various consumption levels. The overall rate change for the residential class
is roughly 8%.
Table 4: Impact of Proposed Electric Rate Changes on Customer Bills
Rate
Schedule
Usage (kwh/mo)
Bill under
Current Rates
($/mo)
Bill Under Rates
Proposed 7/1/18
($/mo)
Change
$/mo %
E-1 300 36.48 38.61 2.14 5.9%
(Summer Median) 330 40.13 42.47 2.35 5.9%
(Winter Median) 453 63.50 66.19 2.69 4.2%
650 100.93 104.17 3.24 3.2%
1200 205.44 210.20 4.76 2.3%
E-2 1,000 162 171 9.09 5.6%
E-4 160,000 24,071 25,984 1,913 7.9%
E-7 500,000 67,466 72,558 5,096 7.6%
E-7 2,000,000 269,863 290,233 20,384 7.6%
Cost of Service Analysis and Rate Study
The rates discussed in the previous section are based on the cost of service methodology
established in the “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2016. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates.
Electric Bill Comparison with Surrounding Cities
Table 5 compares electric bills under current rates as of March 1, 2018 for residential customers
to those in surrounding communities. Under current rates, CPAU’s customer bills are far below
PG&E’s and are lower than others for non-residential customers, but slightly higher than Santa
Clara’s for higher using residential customers.
Table 5: Average Electric Bill Comparison ($/month)
As of March 1, 2018
Customers
Usage
(KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E Santa Clara
Residential
Customers
300 $ 36.48 $38.61 $ 63.51 $ 35.18
330 (Summer 40.12 42.47 71.70 38.83
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
City of Palo Alto Page 9
Median)
453 (Winter
Median) 63.50 66.19 104.49 53.78
650 100.93 104.17 160.46 77.73
1200 205.45 210.20 314.42 144.59
Non-
Residential
Customers
1,000 161 171 245 181
160,000 23,732 25,984 30,413 20,850
500,000 62,190 72,558 83,820 62,956
2,000,000 268,475 290,233 361,753 256,247
Proposed Change to Reserve Policies
This financial plan proposes a change to Section 7 of the Electric Utility Reserves Management
Practices (see Attachment C), detailing a procedure for calculating the amount of funds staff is
authorized to transfer between the Operations and the Hydroelectric Stabilization Reserves,
based on the extent to which hydroelectric generation deviates from long-term averages. Funds
will be transferred to or from the Hydroelectric Stabilization Reserve on an annual basis based
on the amount of deviation from average hydroelectric generation for each month of the prior
year, multiplied by the average market price for energy for that month.
Commission Review and Recommendation
The UAC reviewed this proposal at its April 12, 2018 meeting. At the meeting staff noted that
the recommendation was a decrease from the earlier increase proposal of 9%. Commissioners
questioned whether it was going to be a dry hydro year in light of the relatively recent wet
weather. Staff commented that while the recent storms had provided some relief, it was still a
relatively dry year. Commissioners also inquired if it was possible to create a ‘smoother’ rate
track, rather than having a 6% increase followed by 3%, etc. Staff responded that the 6% still
required Special Projects Fund and some Hydro Stabilization reserve transfers to keep the
Operations reserve within guideline levels, so the rate track was merited to bring revenues in
line with costs.
Commissioners inquired as to whether supply costs could be contained as they were outside of
the City’s control, and staff responded that the electric portfolio was continually reviewed to
see if selling off higher priced renewables contracts was applicable, and worked with agencies
such as NCPA to help bring down costs. Santa Clara’s lower rates were noted, and staff
responded that their power portfolio and customer mixes were different than Palo Alto, and
they also have their own generation plant which lowers their transmission costs.
In regards to reserve health, Commissioners inquired as to how much power cost could
fluctuate in a drought year. Staff responded that impacts of $8 million or more could be seen,
and the Commission noted that drawing down the Hydro reserve more to help lower rate
increases should not be done at this time. Also, should there be another drought, having lower
reserves might mean the newly passed Hydro Rate adjuster could be implemented at the
City of Palo Alto Page 10
largest level, which would amount to a 10% increase.
The UAC voted to recommend that the Council adopt resolutions approving the FY 2019 Electric
Financial Plan and increasing electric rates by amending Rate Schedules E-1, E-2, E-2-G, E-4, E-4-
G, E-4 TOU, E-7, E-7-G, E-7 TOU, and E-14, all amended to reflect a 6% FY 2019 increase. The
vote was unanimous (5-0, Commissioners Segal and Trumbull absent). Attached is the
excerpted draft minutes from the UAC’s April 12, 2018 special meeting (Attachment F).
Timeline
If the Finance Committee supports the proposed rate adjustments, the City Council will
consider the proposed Financial Plans and amended rate schedules with the FY 2019 budget.
Resource Impact
The proposed July 1, 2018 rate changes are projected to increase sales revenues by $10 million
per year over the forecast period.
Policy Implications
The proposed electric rate adjustments were developed using the 2016 cost of service study
and methodology, and are consistent with the Council adopted Reserve Management Practices
that are part of the Financial Plan.
Environmental Review
The Finance Committee and UAC’s review and recommendation to Council on the FY 2019
Electric Financial Plans and rate adjustments does not meet the California Environmental
Quality Act’s definition of a project, pursuant to Public Resources Code Section 21065, thus no
environmental review is required.
Attachments:
Attachment A: Resolution Approving FY 2020 Electric Utility Financial Plan
Attachment B: FY 2019 Electric Utility Financial Plan
Attachment C: Proposed Changes to Electric Utility Reserve Policies
Attachment D: Resolution Amending Electric Utility Rates Effective FY 2019
Attachment E: Amended Electric Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4-TOU, E-7,
E-7-G, E-7-TOU and E-14
Attachment F: Excerpted Draft UAC Minutes of April 12, 2018 Special Meeting
Attachment A
* NOT YET APPROVED *
6055013
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2019 Electric Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes
making long-term projections of market conditions, the physical condition of the system, and
other factors that could affect utility costs, and setting rates adequate to recover these costs. It
does this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2019 Electric Utility Financial Plan.
SECTION 2. The Council hereby approves the amended Electric Utility Reserves
Management Practices included in the FY 2019 Electric Utility Financial Plan.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
the California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental review is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
Attachment A
* NOT YET APPROVED *
6055013
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2019 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
ATTACHMENT B
2 | Page
FY 2019 ELECTRIC UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2019 Rate and Reserves Proposals ....................................................... 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3C: Reserves Management Practices .............................................................................. 7
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................... 9
Section 4A: Electric Utility History ............................................................................................... 9
Section 4B: Customer Base ........................................................................................................ 11
Section 4C: Distribution System ................................................................................................. 11
Section 4D: Cost Structure and Revenue Sources ...................................................................... 12
Section 4E: Reserves Structure ................................................................................................... 13
Section 4F: Competitiveness ...................................................................................................... 14
Section 5: Utility Financial Projections ................................................................................. 15
Section 5A: Load Forecast .......................................................................................................... 15
Section 5B: FY 2013 to FY 2017 Cost and Revenue Trends ........................................................ 17
Section 5C: FY 2017 Results ....................................................................................................... 18
Section 5D: FY 2018 Projections ................................................................................................ 19
Section 5E: FY 2019 – FY 2028 Projections ................................................................................ 19
3 | Page
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 21
Section 5G: Long-Term Outlook ................................................................................................. 26
Section 6: Details and Assumptions ..................................................................................... 29
Section 6A: Electricity Purchases ............................................................................................... 29
Section 6B: Operations .............................................................................................................. 31
Section 6C: Capital Improvement Program (CIP) ....................................................................... 32
Section 6D: Debt Service ............................................................................................................ 33
Section 6E: Equity Transfer ........................................................................................................ 34
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 34
Section 6G: Sales Revenues ....................................................................................................... 35
Section 7: Communications Plan .......................................................................................... 36
Appendices ......................................................................................................................... 37
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 38
Appendix B: Electric Utility Reserves Management Practices ................................................... 42
Appendix C: Description of Electric utility Operational Activities .............................................. 47
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 48
4 | Page
SECTION 1: DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a
section of the distribution system operates. The transmission system operates at
115-500 kV, and this is lowered to 60 kV in the sub-transmission section of the
Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution
system, and finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum
electricity demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Sub-transmission System: The section of the Electric Utility’s distribution system that operates
at 60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115
kV or more. The voltage at the intersection of the Electric Utility’s distribution system
and PG&E’s transmission system is 115 kV. The Electric Utility does not own or
operate any transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
5 | Page
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Electric Utility for the next ten fiscal
years. This Financial Plan describes how revenues will cover the costs of operating the utility
safely over that time while adequately investing for the future. It also addresses the financial
risks facing the utility over the short term and long term, and includes measures to mitigate and
manage those risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
The Electric Utility’s costs will increase substantially over the next few years, as shown in Table
1. Most of the increases are related to electric supply costs, which are increasing due to
increased transmission costs and the cost of new renewable energy projects coming online.
There are also inflationary increases in operations costs, and some above average capital
investment costs in the short term.
Table 1: Electric Utility Expenses for FY 2017 to FY 2028
Expenses
($000)
FY 2017
(act.)
FY 2018
(est.)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Power Supply
Purchases 80,467 83,506 91,925 94,233 95,111 98,655 98,668 99,059 102,252 103,535 103,178 106,193
Operations 53,034 53,881 54,757 56,293 57,053 57,839 59,600 60,146 56,720 57,677 58,660 59,668
Capital
Projects 11,558 20,961 22,684 18,287 20,097 13,632 14,011 14,400 14,800 15,211 15,633 16,068
TOTAL 145,060 158,348 169,366 168,812 172,261 170,126 172,279 173,605 173,772 176,422 177,471 181,929
To cover these increases in costs, revenues (and therefore rates) need to increase over the next
several years to balance costs and revenues, as shown in Table 2. The table also compares
current rate projections to those projected in last year’s Financial Plan. The rate projections are
slightly higher over the forecast period than last year primarily due to lower actual and
projected sales, increases to transmission cost projections and increases to capital investment
spending.
Table 2: Projected Electric Rates, FY 2019 to FY 2028
Projection FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Current 6% 3% 2% 0% 1% 1% 1% 1% 1% 1%
Last Year 7% 0% 0% 1% 2% 1% 1% 1% 1% N/A
Table 3 shows the projected reserve transfers over the forecast period. The Supply Rate
Stabilization Reserve is projected to be drawn down entirely by the end of FY 2018. Funds are
also projected to be transferred from the Electric Special Projects (ESP) Reserve, and Council
approved the withdrawal of $10 million as part of the FY 2018 Electric Financial Plan. Any
transfers from the ESP Reserve require Council approval. Council also approved using all
6 | Page
remaining funds ($11.2 million) from the Hydro Stabilization Reserve, but ending reserves show
that only $1 million is warranted at this point.
Table 3: Reserves Transfers for FY 2018 to FY 2028 ($000)
Reserve FY 2018 FY 2019 FY 2020 to FY 2028
Supply Reserves
Electric Special Projects (6,000) (771) (1,780)
Hydro Stabilization (1,000) - -
Supply Rate Stabilization (9,011) - -
Supply Operations 8,163
Distribution Reserves
Capital Improvement Program - - -
Distribution Operations 7,848 771 1,780
*
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2019:
1. Increase rates effective July 1, 2018 for a 6% increase in system average rates.
2. Approve a transfer of up to $771,000 from the Electric Special Projects Reserve for
Smart Grid related funding.
SECTION 3: DETAIL OF FY 2019 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The rates discussed in the previous section are based on the cost of service methodology
established in “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2015/16. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates. The COSA is based on design guidelines adopted by Council on September 15,
2015 (Staff Report 6061).
SECTION 3B: CURRENT AND PROPOSED RATES
The City adopted the current rates effective July 1, 2017, when CPAU increased electric rates by
14%. Table 4, below, summarizes the current and proposed rates for the four largest customer
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
7 | Page
classes. The Electric Utility also has specialty rates for smaller groups of customers. These
include variations on its primary rates, such as time of use rates and solar net metering. Staff
proposes a 6% overall increase in revenue. Different customer classes may see different
percentage changes to their rates, based upon their usage of the system and cost to serve each
group.
Table 4: Current and Proposed Electric Rates
Current Rates
Proposed Rates
(7/1/18)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.12159 0.12871 0.00711 5.8%
Tier 2 Energy ($/kWh) 0.19001 0.19279 0.00277 1.5%
Minimum Bill ($/day) 0.2938 0.3040 0.0102 3.5%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.18885 0.20090 001205 6.4%
Winter Energy ($/kWh) 0.13267 0.13861 0.00594 4.5%
Minimum Bill ($/day) 0.7328 0.7740 0.0412 5.6%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.11673 0.12081 0.00408 3.5%
Winter Energy ($/kWh) 0.08890 0.09297 0.00407 4.6%
Summer Demand ($/kW) 21.05 24.11 3.06 14.5%
Winter Demand ($/kW) 15.36 18.52 3.16 20.6%
Minimum Bill ($/day) 14.8414 15.9946 1.1532 7.8%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.09802 0.10507 0.00705 7.2%
Winter Energy ($/kWh) 0.07188 0.07449 0.00261 3.6%
Summer Demand ($/kW) 23.84 26.77 2.93 12.3%
Winter Demand ($/kW) 15.59 17.01 1.42 9.1%
Minimum Bill ($/day) 42.3648 45.4758 3.111 7.3%
These proposed rates were prepared in conformance with the “FY 2017 City of Palo Alto Electric
Cost of Service and Rate Study,” performed by EES Consulting (2016).
SECTION 3C: RESERVES MANAGEMENT PRACTICES
This financial plan proposes a change to Section 7 of the Electric Utility Reserves Management
Practices (See Appendix B: Electric Utility Reserves Management Practices), detailing a
procedure for calculating the amount of funds to transfer to or from the Hydroelectric
Stabilization Reserve.
8 | Page
SECTION 3D: PROPOSED RESERVE TRANSFERS
In the FY 2018 Electric Financial Plan, Council approved several proposed transfers for FY 2017
and FY 2018:
• Transfer up to $911 thousand from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve.
• Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offset
potential costs associated with low hydroelectric generation.
• Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution
Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve.
• Transfer up to $10 million from the ESP Reserve to the Distribution Operations Reserve.
This transfer will be construed as a temporary transfer, to be repaid to the ESP Reserve
within five years.
Ending reserve balances for FY 2017 were higher than projected. Because of this, and to keep
some funds in the Hydroelectric Stabilization Reserve in case of drought, staff only projects that
$1 million will need to be transferred out of the Hydroelectric Stabilization Reserve in FY 2018.
The Electric Special Projects (ESP) reserve in future years shows additional transfers of $2.5
million, to help cover the upgrade of the Electric metering system to AMI. This item has been
discussed in prior years as a possible project to be funded from the ESP.
Proposed transfers for FY 2019 will not be requested by resolution at this time, but will be
requested as part of FY 2019 year-end should ending reserve balances require it.
Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E:
FY 2019 – FY 2028 Projections show the impact of these transfers on reserves levels. Table 5
shows the projected balance of each of the Electric Utility reserves for the period covered by
this Financial Plan. See also: Appendix A: Electric Utility Financial Forecast Detail
Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2017 to FY 2028
Ending Reserve
Balance ($000)
FY 2017
(Act.)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Re-appropriations - - - - - - - - - - - -
Commitments 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971
Underground Loan 730 730 730 730 730 730 730 730 730 730 730 730
Public Benefits 681 - - - - - - - - - - -
Special Projects 51,838 45,838 45,067 42,757 43,247 42,847 42,847 42,847 42,847 42,847 42,847 42,847
Hydro Stabilization 11,400 10,400 10,400 10,400 10,400 13,900 13,900 13,900 13,900 13,900 13,900 13,900
Capital 880 880 880 880 880 880 880 880 880 880 880 880
Rate Stabilization 9,011 - - - - - - - - - - -
Operations 29,913 37,884 32,054 33,249 39,138 38,837 39,720 41,255 44,073 46,167 49,328 49,864
Unassigned - - - - - - - - - - - -
TOTAL 107,424 98,703 92,101 92,987 97,366 100,164 101,048 102,583 105,401 107,495 110,656 111,192
9 | Page
SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4A: ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel
engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity
continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E
proved more economical than the diesel engines, and by the late 1920s CPAU was using its own
diesel engines only during peak demand periods. At that time CPAU owned 45 miles of
distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual
consumption. The diesel engines remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did
throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the
sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto,
which doubled the number of customers. Some was related to the proliferation of electric
appliances, as evidenced by the fact that residential customers were using three times more
electricity in 1970 than they had been in 1950. But the most notable factor was the growth of
industry in Palo Alto during that time. By 1970, commercial customers were using 20 times
more electricity per customer than they had been in 1950. These decades also saw several
other notable events, including:
• 1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of
Reclamation to purchase power from the Central Valley Project (CVP), a contract which
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
• 1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
• 1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
10 | Page
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement
program for its underground system in the early 1990s.
In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and
in 1996 the State legislature passed Assembly Bill 1890, which, among other things, created the
California Independent System Operator (CAISO) to operate the transmission system and the
Power Exchange to facilitate wholesale energy transactions. This restructuring was anticipated
to bring lower costs to consumers, and while CPAU was not required to participate in the
industry restructuring, in 1997 the Council approved a Direct Access Program for the Electric
Utility2 that enabled CPAU to sell electricity outside its service territory and allowed customers
within CPAU’s service territory to choose other providers. The utility unbundled its electric
rates, creating separate supply and distribution components, which would enable customers to
receive only distribution service while purchasing the electricity itself from another provider.
The energy crisis in 2000 to 2001 led to the suspension of direct access by the CPUC in
September 2001 as wholesale energy prices skyrocketed. The Electric Utility was less impacted
than other utilities by the 2000 to 2001 energy crisis thanks to the Calaveras project and its
contract with WAPA for CVP hydropower.
In 2001 CPAU began planning for the impacts associated with the new terms of its contract with
WAPA, set to take effect in 2005. The previous contract had provided 90% of Palo Alto’s power
supply at favorable rates, and PG&E, as a party to the contract, had provided supplemental
power to balance the monthly and annual variability of CVP generation. The new contract
would provide only a third of Palo Alto’s requirement, and the monthly and annual variability in
CVP generation would be passed directly to Palo Alto. As a result, electric supply costs would
increase and CPAU needed to more actively manage its supply portfolio. CPAU began
purchasing power from marketers and also investigated building a power plant in Palo Alto or
partnering in the development of a gas-fired power plant elsewhere. Climate change was also
becoming more of a concern to the community, and gradually CPAU shifted its focus to the
procurement of renewable energy. In 2002 CPAU adopted a goal of achieving 20% of its energy
supply from renewables by 2015. Subsequently CPAU signed its first contract for renewable
power, a contract for energy from a wind generator commencing deliveries in 2005. In 2011 the
renewable energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a
plan to make its electric supply 100% carbon neutral, which it achieves through the
combination of its carbon-free hydroelectric supplies, purchases of long-term renewable energy
supplies, and short-term renewable energy purchases (RECs) to meet the balance of its needs.
2 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
11 | Page
Figure 1: Customer Consumption By Class (FY 2017)
16%
6%
36%
42%
Residential
Small Comm.
Med. Comm.
Large Comm.
SECTION 4B: CUSTOMER BASE
The City of Palo Alto’s Electric Utility
provides electric service to the
residents, businesses, and other
electric customers in Palo Alto. There
are roughly 29,600 customers
connected to the electric system,
25,550 (86%) of which are residential
and 4,050 (14%) of which are non-
residential. Residential customers
consumed 147 gigawatt-hours (GWh)
in FY 2017, approximately 16% of the
electricity sold, while non-residential
customers consumed 84% or 771
GWh. Residential customers use
electricity primarily for lighting,
refrigeration, electronics, and air conditioning.3 Non-residential customers use the majority of
their electricity for cooling, ventilation, lighting, office equipment (offices), cooking
(restaurants), and refrigeration (grocery stores).4
As shown in Figure 1 large customer loads represent a large proportion of sales for the Electric
Utility. The proportion of sales to large vs. small customers is greater than for the City’s other
utilities. For example, the largest customers (the 71 customers on the E-7 rate schedule)
account for around 42% of CPAU’s sales. The next largest customer group (the 830 non-
residential customers on the E-4 rate schedule) represents another 36% of sales. In total, that
means that about 3% of customers account for nearly three quarters of the electric load.
SECTION 4C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 472 miles of
distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are
underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line
transformers, around 1,100 underground and substation transformers, and the associated
electric services (which connect the distribution lines to the customers’ homes and businesses).
These lines, substations, transformers, and services, along with their associated poles, meters,
3 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010 4 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
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Figure 2: Cost Structure (FY 2017)
55%
37%
8%
Commodity
Supply
Operations
Capital
Figure 4: Hydroelectric Variability (FY 2019)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 3: Revenue Structure (FY 2017)
81%
19%
Sales of Electricity
Other Revenue
and other associated electric equipment, represent the vast majority of the infrastructure used
to deliver electricity in Palo Alto.
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 55% of the Electric Utility’s
costs in FY 2017. Operational costs
represented roughly 37%, and
capital investment was responsible
for the remaining 8%. CPAU’s non-
hydro long-term commodity supply
is heavily dependent on long-term
contracts which have little variability
in price. On average, costs for these
long-term contracts are not
predicted to increase as quickly as operations and CIP costs, and will steadily become a smaller
proportion of the Electric Utility’s costs. Staff projects commodity supply costs to be
approximately 56% of total costs in FY 2028.
While average year purchase
costs for the electric utility
are predictable due to its
long-term contracts,
variability in hydroelectric
generation can result in
increased or decreased
costs. This is by far the
largest source of variability
the utility faces. Figure 3
shows the difference in costs
under high, projected, and
low hydroelectric generation scenarios
for FY 2019. Additional costs associated
with a very low generation scenario can
range from $9-11 million per year. For
the current hydroelectric risk assessment
see Section 5F: Risk Assessment and
Reserves Adequacy.
As shown in Figure 4 the Electric Utility
receives 81% of its revenue from sales of
electricity and the remainder from
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connection fees, interest on reserves, cost recovery transfers from other funds for shared
services provided by the electric utility, and other sources. Some revenue sources are primarily
accounting entries that reflect things such as CPAU’s participation in a pre-funding program
associated with its contract with WAPA, as well as accounting entries associated with
occasional sales of surplus hydroelectric energy during wet years. Appendix A: Electric Utility
Financial Forecast Detail shows more detail on the utility’s cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 900 largest customers, which provide a similar share of the utility’s revenue stream.
The utility’s retail rate schedules have no fixed charges, although about 24% of the utility’s
revenue comes from peak demand charges on large non-residential customers. Due to
moderate weather and the prevalence of natural gas heating, however, loads (and therefore
revenues) are very stable for this utility, without the large seasonal air conditioning or winter
heating loads seen at some other utilities.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of
contingencies. It also maintains two funds, the Supply Fund and the Distribution Fund, to
manage costs associated with electricity supply and electricity distribution, respectively. The
City established this separation of supply and distribution costs as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) in the late 1990s and
early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues to
maintain separate funds to facilitate separation of supply and distribution costs in the rates.
This could be important if California ever decides to broadly reintroduce Direct Access, and may
also be useful for rate design as the nature of utility services evolves in response to higher
penetrations of distributed generation.
The summary below describes the various reserves, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserves for Commitments: Reserves equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserves for Reappropriations: Reserves for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve. This is currently an important
reserve for all utility funds, but changes in budgeting practices will change that in future
years, as described in Section 3C (Reserves Management Practices).
• Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which was accumulated during deregulation of California’s electric system to
fund the stranded costs associated primarily with the Calaveras hydroelectric resource
and the California-Oregon Transmission Project. When that reserve was no longer
needed for that purpose, the reserve was renamed and the purpose was changed to
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fund projects with significant impact that provide demonstrable value to electric
ratepayers.
• Hydroelectric Stabilization Reserve: This contingency reserve is used for managing
additional costs due to below average hydroelectric generation, or to hold surpluses
resulting from above average hydroelectric generation.
• Underground Loan Reserve: This reserve is an accounting tool used to offset receivables
associated with loans made through the underground loan program. It is adjusted
according to principal payments made on those loans.
• Public Benefits Reserve: CPAU’s electric rates include a separate charge called the
“Public Benefits Charge” which generates revenue to be used for energy efficiency,
demand-side renewable energy, research and development, and low-income energy
efficiency services. Any funds not expended in the current year are added to the Public
Benefits Reserve for use in future years.
• Capital Improvement Program (CIP) Reserve: The CIP reserve is used to provide
working capital and contingency funds for the CIP program, as well as to accumulate
funds for major future one-time expenditures. This type of reserve is used in other
utility funds (Electric, Gas, and Wastewater Collection) as well.
• Supply and Distribution Rate Stabilization Reserves: These reserves are intended to be
empty unless one or more large rate increases are anticipated in the forecast period. In
that case, funds can be accumulated to spread the impact of those future rate increases
across multiple years. This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Supply and Distribution Operations Reserves: These are the primary contingency
reserves for the Electric Utility, and are used to manage yearly variances from budget
for operational costs and electric supply costs (aside from variances related to
hydroelectric generation). This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves
are for any financial resources not assigned to the other reserves and are normally
empty.
SECTION 4F: COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2017 was
$589.02 under current CPAU rates, 38% lower than the annual bill for a PG&E customer with
the same consumption and approximately 12% higher than the annual bill for a City of Santa
Clara customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X,
which includes most surrounding comparison communities.
Table 6 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara
(Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown
below were in effect as of March 1, 2018.
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Over the next several years low usage customers in PG&E territory are expected to continue to
see higher percentage rate increases than high usage customers as PG&E compresses its tiers
from the highly exaggerated levels that have been in place since the energy crisis. This is likely
to make the bill for the median Palo Alto consumer look even more favorable compared to
most PG&E customers. Even with the compressed tiers, bills for high usage Palo Alto consumers
are likely to remain substantially lower than the bills for high usage PG&E customers.
The bill calculations show bills under the existing rates, not the proposed July 1, 2018 rates.
However, even with the proposed rate increases, Palo Alto’s residential bills will remain
substantially below PG&E’s current rates, but slightly above Santa Clara’s.
Table 6: Residential Monthly Electric Bill Comparison (Effective 3/1/18, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(March)
300 36.48 63.51 35.18
453 (Median) 63.50 104.49 53.78
650 100.93 159.64 77.73
1200 205.45 313.60 144.59
Summer
(July)
300 36.48 63.51 35.18
(Median) 330 40.12 71.70 38.83
650 100.93 161.28 77.73
1200 205.45 315.24 144.59
Table 7 shows the average monthly electric bill for commercial customers for various usage
levels. Even with the proposed rate increases, Palo Alto’s commercial bills will remain
substantially below PG&E’s, and below Santa Clara’s for some commercial customers.
Table 7: Commercial Monthly Electric Bill Comparison (3/1/18, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 161 245 181
160,000 23,732 30,413 20,850
500,000 62,190 83,820 62,956
2,000,000 268,475 361,753 256,247
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 5 shows a 33-year history of Palo Alto electricity consumption. Average electricity
consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then
electricity consumption has declined slowly as a result of a continuing focus on energy
efficiency, as well as the adoption of more stringent appliance efficiency standards and energy
standards in building codes.
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Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2028. Sales after the July
2016 rate change decreased by 6% from projections. To be conservative, the forecast assumes
that current trends continue and sales through the forecast period decline slightly.
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Figure 6: Forecasted Electricity Consumption
SECTION 5B: FY 2013 TO FY 2017 COST AND REVENUE TRENDS
The annual expenses for the Electric Utility remained fairly stable between FY 2013 and FY
2017, as shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail
Section 6A: Electricity Purchases discusses the factors influencing Electric Utility expenses. Since
FY 2012, total expenses for the utility have included the costs of renewable resources coming
online. In FY 2014 through FY 2015 commodity costs were higher due to lower than average
output from hydroelectric resources.
Commodity costs and capital investments are responsible for most of the changes in the
utility’s expenses over the last six years. Operational costs decreased during that time but will
increase once staffing levels return to normal levels.
Actual Projection
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2017 and Projections through FY 2028
SECTION 5C: FY 2017 RESULTS
Total cost of purchasing electricity was lower than the forecast by approximately $3.9 million.
Capital improvement costs were lower than the forecasted level by $9.9 million. Sales revenues
were higher than the forecast by $2.9 million, but there was also $4.8 million in surplus sales
revenue beyond what was budgeted. While net revenues were still lower than cost by $3
million, the net reserve withdrawal was lower than originally anticipated ($25 million). The
lower withdrawal in FY 2017 will allow for reserves to be used in future years.
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Table 8 FY 2017, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues higher than forecast $(2,881) Revenue increase
Wholesale and other revenues higher than
forecast
(5,978) Revenue increase
Lower capital improvement costs (9,932) Cost decrease
Lower purchased electricity costs (3,904) Cost decrease
Higher operations costs 344 Cost increase
Net Cost / (Benefit) of Variances $(22,352)
SECTION 5D: FY 2018 PROJECTIONS
Last year, staff recommended (and Council approved) a 14% rate change for July 1, 2017, the
start of FY 2018. Current sales revenue projections for 2018 are roughly $1.5 million higher than
expected in last year’s financial plan. Based on current hydro conditions, wholesale costs are
again expected to contribute to other revenues being higher by $5.5 million. Purchased
electricity cost projections for 2018 are anticipated to be $4.5 million lower than in last year’s
financial plan. However, capital cost estimates and operations cost estimates (which includes
other than purchased electricity costs) increased by $5.3 million and $3.8 million, respectively.
Table 9 FY 2018, Change in Projected Results, 2018 Forecast vs. 2019 Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues (1,454) Revenue increase
Wholesale and other revenues higher than
forecast
(5,476) Revenue increase
Capital improvement costs 5,388 cost increase
Purchased electricity costs (4,481) cost decrease
Operations costs 3,848 cost increase
Net Cost / (Benefit) of Variances $2,175
SECTION 5E: FY 2019 – FY 2028 PROJECTIONS
As shown in Figure 7 above, staff projects costs for the Electric Utility to increase at a fairly
steady rate through the forecast period. Revenue increases of 6% in FY 2019 and another 3% in
FY 2020 are projected to bring revenues in line with expenses. Rising electricity purchase costs
are the primary contributor to the increases. Electricity purchase costs have increased
substantially since FY 2013 as new renewable projects have come online to fulfill the City’s
environmental goals, and as transmission costs have increased due to improvements being
made to the California grid. Operations costs are expected to increase at or near the inflation
rate (2-4 %/year) through the forecast period. Projected capital expenses for FY 2018 through
FY 2023 are higher in FY 2018 through FY 2021 due to work on the Upgrade Downtown project,
as well as anticipated AMI and smart grid implementation. Once these larger, one-time project
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cost increases are completed, annual CIPs are anticipated to decline back to levels seen in
recent years. This forecast also assumes that smart grid costs are funded from the Electric
Special Projects Reserves.
Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund
Reserves) and Figure 9 (for Distribution Fund Reserves), below. The Supply Rate Stabilization
Reserve will be empty by the end of FY 2018.
Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2017 and Projections through FY 2028
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Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2017 and Projections through FY 2028
SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two contingency reserves, the Supply Operations Reserve and
the Distribution Operations Reserve. This Financial Plan maintains reserves above the reserve
minimum for the Distribution Operations Reserve throughout the forecast period. Reserve
levels also exceed the short-term risk assessment level for the Distribution Fund. The Supply
Operations Reserve, however, may end up below minimum levels and below the short-term risk
assessment level.
There are a variety of risks associated with the Supply Fund as are shown in Table 10. Because
of the high range of uncertainty in energy price predictions more than three years in the future,
this risk assessment is only performed for the first two fiscal years of the forecast period. It is
important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 10 is very low.
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Table 10: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2019 FY 2020
1. Production from Hydroelectric
Resources: Western 6.8 6.2 Lower than forecasted hydro
2. Production from Hydroelectric
Resources: Calaveras 3.3 2.6 Lower than forecasted hydro
3. Market Price (Energy) 2.2 0.8 Higher than forecasted market prices for
energy
4. Transmission/CAISO 3.3 3.3 High-end transmission forecast scenario
5. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
6. Western Cost 3.5 3.5 Risk of rate adjustments from Western
7. Regulatory and Legal 0.0 0.0 Risks associated with legislative uncertainties
Electric Supply Fund Risks $19.9
million
$17.4
million
Projected Supply Operations +
Hydro Stabilization Reserve
Levels
$65.6
million
$65.8
million
Of the risks faced by the Electric Utility’s Supply Fund in FY 2019, the risk of a dry year with very
low hydroelectric output is normally the largest, accounting for nearly half the total cost of all
adverse outcomes. Since the utility’s costs for its hydroelectric resources are almost entirely
fixed, costs do not decline when the output of those resources are low, but the utility needs to
buy power to replace the lost output. The converse happens when hydroelectric output is
higher than average.
Of the remaining risks for FY 2019, $3.3 million is related to the projected costs if transmission
cost increases are higher than staff’s current forecast. $3.5 million is related to the uncertainty
to Western’s rates for Restoration costs.
As shown in Figure 10, the Supply Operations Reserve was below the minimum reserve
guidelines at the end of FY 2017. However, through reserve transfers and rate increases, staff
projects the Supply Operations Reserve to stay within the reserve guideline levels throughout
the forecast period. Figure 11 shows that the combined Hydro Stabilization and Supply
Operations Reserves are projected to be above what is needed for the risk assessment level.
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Figure 10: Electric Supply Operations Reserve Adequacy
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Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 11 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2023. As shown in Figure 12, the Distribution Operations Reserve will stay within the
reserve guidelines over the course of the forecast period, although it was recorded below the
minimum reserve guidelines at the end of FY 2017. The risk assessment includes the revenue
shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 11: Electric Distribution Fund Risk Assessment ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Total non-commodity revenue $49,608 $49,928 $49,744 $50,068 $50,895
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $3,915 $3,941 $3,926 $3,952 $4,017
CIP Budget $22,684 $18,287 $20,097 $13,632 $14,011
CIP Contingency @10% $2,268 $1,829 $2,010 $1,363 $1,401
Total Risk Assessment value $6,184 $5,769 $5,936 $5,315 $5,418
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Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, staff projects the CIP Reserve to be above the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels, CIP Commitments are nearly impossible to project that far out, and
adjustments to the reserve can be made in future years.
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Figure 13: Electric CIP Reserve Adequacy
SECTION 5G: LONG-TERM OUTLOOK
This forecast covers the period from FY 2019 through FY 2028, but various long-term
developments may create new costs for the utility over the next 5 to 35 years. While it is
challenging to accurately forecast the impact these events will have on the utility’s costs, it is
worth noting them as future milestones and keeping them in mind for long-term planning
purposes.
For the supply portfolio, the 2020s will see a number of notable events. The contract with
Western for power from the CVP will expire in 2024. Determining the future relationship with
Western after 2024 will be important in the years leading up to the contract expiration,
especially because this resource represents nearly 40% of the electric portfolio, and is the
utility’s largest source of carbon-free electricity. The utility’s three earliest and lowest cost
renewable contracts will also begin expiring around that time, with the first contract expiring in
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2021 and the last in 2028. These three contracts, plus one more expiring in 2030, currently
provide 17% to 18% of the energy for the utility’s supply portfolio at prices under $65 per
megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those
contracts expire. Although recent prices have been in that range (or even lower), and costs
may decrease in the future, current renewable projects also benefit from a wide range of tax
and other incentives that may or may not be available in the 2020s and beyond. However, staff
is in the process of procuring a replacement for the contract expiring in 2021 at a lower price
than any of the City’s current renewable contracts.
The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs
dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032
(assuming the Utility does not issue any new debt). The project will only be 40 years old at that
time. Calaveras debt service represents roughly 70% of the annual costs of that project (and
nearly 7% of the utility’s total costs), so when the debt is retired, the project could be a low-
cost asset for the utility, providing carbon-free energy equal to around 13% of the Electric
Utility’s supply needs in an average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to 5 million per year in revenue from
allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to
pay for energy efficiency programs and to purchase renewable energy to support the utility’s
Carbon Neutral Plan. Staff expects that revenue source to continue through 2020. However,
discussions at the state level are ongoing and will determine whether or not these allocations
continue past 2020, as well as any restrictions CARB may wish to enact on usage of allocation
sales revenues. If the Electric Utility no longer received these allowances or was limited in how
it could spend revenues, it would have to fund these programs from sales revenues.
Transmission costs are also continuing to rise. If the State continues to increase mandates or
incentives for renewable energy development, integrating these new projects into the
transmission grid will be an ever increasing challenge, some costs of which will be borne by Palo
Alto. The planned expansion of the CAISO to a larger regional grid control area may result in
additional transmission costs that could further increase CPAU’s transmission costs. In addition
to the costs of new transmission lines that will need to be built, flexible resources will be
required to balance rapid changes in wind or solar output throughout the day. Palo Alto will
likely bear some of the costs of these new lines and resources. CPAU is also currently
investigating installing a second transmission interconnection for Palo Alto, which could be
funded by the Electric Special Projects Reserve.
Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these
factors may begin to create notable increases in electric consumption and have a variety of
impacts on the distribution system. As housing stock is turned over, however, stricter building
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codes may help to counteract load growth, as may increasing numbers of rooftop solar
installations. The utility has already started to take some of these factors into account in its
long-term planning processes, but will need to continue to incorporate them into its planning
methodologies.
Over the long term, it is conceivable that electricity could replace natural gas and petroleum
almost entirely. Many, if not most, vehicles would use electricity, though hydrogen is another
potential fuel source under development and other technologies might be developed. Staff are
undertaking initial analysis of these types of scenarios in the context of the Sustainability and
Climate Action Plan (S/CAP) development process. These types of scenarios require careful
planning for the associated load growth to make sure the distribution system does not end up
overloaded, or conversely, to avoid over investment, and the evaluation of changes to utility
distribution system management to accommodate integration of the various technologies
involved in electrification.
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SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: ELECTRICITY PURCHASES
As shown in Figure 14 the utility gets roughly 50% of its energy from hydroelectric projects in a
normal year (FY 2014 and FY2015 were dry). Contracts with renewable sources made up just
over 30% of the portfolio in FY 2016, and 50% in FY 2017. Staff expects contracts with
renewable sources to continue at approximately 50% of the portfolio for the forecast period.
The remainder comes from unspecified market sources. Under the City’s Carbon Neutral Plan,
CPAU purchases RECs corresponding to the amount of market energy it purchases.
Figure 12: Electricity Supply by Source
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Figure 15 shows the historical and projected costs for the electric supply portfolio,5 as well as
average and actual hydroelectric generation.6 Electric supply costs increased in FY 2013, FY
2014, and FY 2015 due to the drought, which reduced the amount of generation from
hydroelectric resources. Costs decreased slightly in FY 2016 due to better than expected market
purchase costs, and FY 2017 and FY 2018 had lower hydroelectric costs. Increases in renewable
energy costs are expected as various renewable projects come online to fulfill the City’s carbon
neutral and RPS goals. Transmission charges are also projected to increase as new transmission
lines are built throughout California to accommodate new renewable projects. In total, electric
supply costs are projected to increase to $85 million by FY 2020, at which point all currently
contracted renewable projects will be online. Supply costs are only projected to change slightly
in subsequent years.
Figure 13: Electric Supply Portfolio Costs, Historical and Projected
5 Costs are shown net of wholesale revenues, and cannot be directly compared with the electric supply purchase
figures shown in Appendix A: Electric Utility Financial Forecast Detail 6 Average hydroelectric generation increased in January of 2015 due to an increase in the utility’s contractual share
of the output of the CVP Federal hydropower project.
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SECTION 6B: OPERATIONS
CPAU’s Electric Utility operations include the following activities:
• Administration, including financial management of charges allocated to the Electric
Utility for administrative services provided by the General Fund and for Utilities
Department administration, as well as debt service and other transfers. Additional detail
on Electric Utility debt service is provided in Section 6D (Debt Service)
• Customer Service
• Engineering work for maintenance activities (as opposed to capital activities)
• Operations and Maintenance of the distribution system; and
• Resource Management
Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 2013 to FY 2017, Operations costs stayed relatively flat. In 2013 there was a one-time
increase in expenses associated with an adjustment to the value of the City’s investment
portfolio. Debt service and transfers costs increase (reflecting transfers in from the ESP
reserve). However, over the forecast horizon, excluding debt service and transfers, staff project
costs to increase by roughly 2-3% per year.
Figure 14: Historical and Projected Electric Utility Operational Costs
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SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
Staff projects CIP spending for FY 2019 through FY 2024 to be consistent with last year’s
forecast, though there is a slight shift in the funding by project category. There will be a
reduction in capital cost and revenue related to the VA Hospital project as the VA will be
responsible for the installation, and associated costs, of electric facilities; there will be a
reduction in funding for Undergrounding as current projects are completed; there will be an
increase in funding for Underground Rebuilding and 4/12kV Conversion as improvements are
made to the system in portions of the Crescent Park/Duveneck/St. Francis/Community
Center/Leland Manor/Garland neighborhoods to facilitate rebuild of the Hopkins Substation;
and increase in funding for replacement of distribution system and substation facilities that are
at the end of their useful life. Other significant projects still slated to continue are deteriorated
wood pole replacements, pole relocations to facilitate the Caltrain Railway Electrification
project, Smart Grid upgrades, and ongoing capital investment in the electric distribution system
to maintain/improve reliability. This forecast assumes that the utility finances smart grid
projects from the Electric Special Projects Reserve and with additional funding from the water
and gas funds, but it would also be possible to use bond financing.
Excluding the one-time projects listed above, the CIP plan for FY 2019 to FY 2023 is primarily
funded by utility rates, but other sources of funds include connection fees (for Customer
Connections), phone and cable companies (primarily for undergrounding), and other funds (for
smart grid). The details of the CIP budget will be available in the Proposed FY 2019 Utilities
Capital Budget. Figure 17 shows the FY 2018 projected budget and the five year CIP spending
plan, although these figures are preliminary pending budget discussions starting in May. The
‘committed’ column represents funds committed to contracts for which work has not yet been
completed or invoices paid.
Figure 15: Electric Utility CIP Spending ($000)
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
One-Time Projects 5,021 (128) 4,893 123 1,400 1,300 10,750 5,000 5,000
System Expansion 3,507 (27) 3,481 - - - - - -
Reliability 3,711 (129) 3,582 153 1,067 317 150 - -
Undergrounding 4,395 (40) 4,355 353 900 - 2,000 2,250 500
4/12 Kv Conversion 270 (1) 269 - - 1,750 800 - -
Underground Rebuilding 3,385 (3) 3,382 3 - 2,656 1,500 350 350
Ongoing Projects 6,714 (882) 5,832 3,255 3,145 3,625 3,280 3,280 3,230
Customer Connections
(Fee Funded)4,087 (1,149) 2,938 589 3,220 3,336 3,456 3,580 3,600
TOTAL 31,091 (2,359) 28,732 4,476 9,732 12,984 21,936 14,460 12,680
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year.
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
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SECTION 6D: DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently
makes payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax
Credit Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction
costs of solar demonstration projects at the Municipal Services Center, Baylands Interpretive
Center, and Cubberley Community Center. The capacity of these projects totaled 250 kW. In
exchange for funding part of the construction costs, the Electric Utility receives the RECs from
these projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are
interest free (the investors receive a tax credit from the federal government). This bond
issuance is secured by the net revenues of the Electric Utility. Debt service for this bond
continues through 2021, and for the financial forecast period is as follows:
Table 11: Electric Utility Debt Service ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2007 Clean Renewable
Energy Bonds 100 100 100 100 - -
The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage
ratio of 125% of debt service. The current Financial Plan maintains compliance with these
covenants throughout the forecast period, as shown in Appendix C.
The Electric Utility also pledges reserves and net revenue as security for the bond issuances
listed in Table 13, even though the Electric Utility is not responsible for the debt service
payments. The Electric Utility’s reserves or net revenues would only be called upon if the
responsible utilities are unable to make their debt service payments. Staff does not currently
foresee this occurring.
Table 12: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Electric Utility’s:
Net Revenues Reserves
1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water $1,457 No Yes
*Net of Federal interest subsidy
34 | Page
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.7 Each year it is calculated
according to the 2009 Council-adopted methodology, and does not require additional Council
action.
SECTION 6F: WHOLESALE REVENUES AND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 19% comes
from other sources. Of these other sources, about 50 to 60% represents wholesale revenues of
surplus energy sales included solely for accounting purposes. These revenues have offsetting
electric supply purchase costs, and do not normally affect the utility’s net position. Of the
remaining revenues, the largest revenue sources are interest on reserves, connection fees for
new or replacement electric services, and carbon allowance revenues associated with the
State’s cap-and-trade program. In FY 2017 these sources represented roughly 28% of revenue
from sources other than electricity sales. The remaining FY 2017 revenues consisted of a variety
of one-time transfers.
Revenues from connection fees have increased since FY 2009 varying from year to year.
Revenue from connection fees decreased slightly during the recession, but has increased
substantially since then, peaking in FY 2016 and declining somewhat in FY 2017. Staff forecasts
slightly higher revenue from this source in 2018 through 2021 with revenue leveling out in
subsequent years.
Staff projects carbon allowance and interest income revenues to stay relatively stable through
the forecast period. However, both of these revenue sources are subject to some uncertainty.
The State’s cap-and-trade program regulations only describe the program through 2020. This
forecast assumes the program will remain in place with similar program design following 2020,
but that may not be the case. CARB is in the process of establishing post-2020 rules.
The forecast for interest income assumes current interest rates continue and there are no
major reserve reductions aside from what is anticipated in this Financial Plan. If interest rates
rise, interest income could increase, and if reserves decrease (due to drought or a withdrawal
from the ESP reserve for a major project), interest income would decrease.
7 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to equity transfer methodology.
35 | Page
SECTION 6G: SALES REVENUES
The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7
provide the basis for sales revenue projections. As discussed in Section 5A, sales revenues for
this utility stay relatively stable due to the mild climate in Palo Alto. In addition, Palo Alto is a
built out City, with incremental growth in population and relatively stable commercial customer
loads.
36 | Page
SECTION 7: COMMUNICATIONS PLAN
The FY 2019 Electric Utility communications strategy covers these primary areas: rates,
efficiency, renewables, operations, infrastructure, safety, and changes to utility economic
conditions in the wake of the drought. CPAU communication methods include use of the
Utilities website, utility bill inserts, messaging on bills and envelopes, email newsletters, print
ads in local publications, videos and participation in community outreach events.
In FY 2019, CPAU is proposing a nine percent increase in electric utility rates. Prior to FY 2017,
electric utility rates had not increased since 2009, as the City has been drawing down reserves
from the Electric Fund. The rate increase will be necessary in FY 2018 and again in FY 2019, as
these reserves drop below the reserve target level. Communications will focus on the reasons
why a rate increase is necessary, due to an increase in transmission fees and new renewable
projects coming online, rising operating and capital costs, and how drought affected the City’s
reserves. Palo Alto purchases a significant portion of its electricity from hydroelectric resources.
Several-year drought conditions reduced available hydroelectric supplies, requiring the City to
purchase more costly replacement electric supplies. Since the State may not received a great
deal of precipitation in the latter part of FY 2018, communications staff will now focus
messaging on how increased hydroelectric supplies could still impact and potentially change the
forecast for electric rates moving forward, at least in the short-term.
Despite these costs and increasing rates, CPAU’s electric utility rates remain lower than the
neighboring community average, including for municipal and investor-owned utilities (PG&E).
Keeping costs low is one of the benefits CPAU offers its customers as a public utility provider.
CPAU will continue to communicate about the environmental benefits of the City’s carbon
neutral electric supply portfolio. Outreach includes apprising the public of major renewable
energy purchase agreements, which contribute toward Palo Alto’s long-term energy security
and commitment to sustainability. Recent power purchase agreements have allowed CPAU to
procure long-term renewable electric supplies at low costs. While upfront capital costs to bring
these renewable projects online may initially contribute towards some increase in CPAU’s
electric rates, staff expect these higher costs to taper off once the projects begin commercial
operations. CPAU will highlight these environmental attributes and value in our
communications.
Throughout the year, communications staff promote CPAU’s electric efficiency services, rebates
and local renewable energy programs. Within the past few years, CPAU has launched new
programs that allow customers to better understand and manage their energy use. Programs
such as the Home Efficiency Genie and commercial energy efficiency programs help residents
and businesses better understand energy usage, activities and/or upgrades they can implement
to improve efficiency and reduce utility costs. CPAU will be launching an upgraded version of its
online utility account services portal (www.cityofpaloalto.org/myutilitiesaccount) this year,
which can provide customers with direct access and more information about utility account and
consumption data.
37 | Page
APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
6053706
APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
6053706
(page intentionally left blank)
6053706
1 FISCAL YEAR FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
2
3 ELECTRIC LOAD
4 Purchases (MWh)976,319 980,894 979,005 977,292 945,703 939,991 943,995 940,694 937,221 933,569 931,545 930,263 930,117 929,943 930,376 930,646
5 Sales (MWh)946,841 950,784 936,773 937,157 917,687 909,595 910,883 907,697 904,346 900,823 898,869 897,632 897,492 897,324 897,742 898,002
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1154$ 0.1164$ 0.1158$ 0.1156$ 0.1249$ 0.1421$ 0.1513$ 0.1557$ 0.1593$ 0.1598$ 0.1609$ 0.1625$ 0.1634$ 0.1650$ 0.1666$ 0.1683$
9 Change in System Average Rate 0%1%0%0%10%14%6%3%2%0%1%1%1%1%1%1%
10 Change in Average Residential Bill -4%-1%-5%3%11%11%6%2%2%0%0%1%0%1%1%1%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)1,886,000 305,000 - - - - - - - - - - - - - -
14 Commitments (Non-CIP)2,737,000 3,528,000 3,164,000 3,102,055 3,777,205 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955
15 Restricted for Debt Service - - - - - - - - - - - - - - - -
16 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - - -
17 Central Valley Project Reserve 314,000 313,000 329,000 - - - - - - - - - - - - -
18 Underground Loan Reserve 742,000 738,000 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147
19 Public Benefits Reserves 1,149,000 2,197,000 2,064,000 2,574,000 1,839,000 681,330 - - - - - - - - - -
20 Electric Special Projects Reserve 50,320,000 51,838,000 51,838,000 51,837,855 51,837,855 51,837,855 45,837,855 45,066,855 44,756,855 43,246,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855
21 Hydro Stabilization Reserve - - - 17,000,000 11,400,000 11,400,000 10,400,000 10,400,000 10,400,000 10,400,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000
22 Capital Reserves - - - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964
23 Rate Stabilization Reserves 74,609,000 69,029,000 70,049,000 14,410,840 9,010,840 9,010,840 - - - - - - - - - -
24 Operations Reserves - - - 22,497,607 21,850,187 29,912,981 37,884,461 32,053,564 33,249,194 39,138,346 38,836,530 39,719,824 41,254,722 44,072,659 46,167,305 49,327,672
25 Unassigned - - - - - - - - - - - - - - - -
26 TOTAL STARTING RESERVES 132,757,000 128,948,000 129,178,000 112,152,357 100,444,086 107,424,072 98,703,382 92,101,485 92,987,115 97,366,267 100,164,451 101,047,745 102,582,643 105,400,580 107,495,226 110,655,593
27
28 REVENUES
29 Net Sales 109,974,337 110,246,264 108,873,377 108,312,917 114,624,726 129,258,435 137,836,311 141,304,121 144,032,395 143,988,875 144,612,409 145,833,873 146,687,201 148,083,859 149,581,682 151,104,314
30 Wholesale Revenues 6,635,790 6,010,409 6,267,000 4,301,366 16,188,920 18,115,996 13,718,260 14,366,366 16,106,798 17,749,617 17,407,062 17,763,941 17,932,747 18,052,704 18,231,927 18,351,535
31 Other Revenues and Transfers In 9,624,213 13,669,185 9,688,480 11,714,494 11,225,911 13,776,378 12,781,199 15,649,312 18,168,427 12,895,834 12,896,707 13,341,185 13,815,444 14,273,124 14,759,484 15,001,446
32 TOTAL REVENUES 126,234,340 129,925,858 124,828,858 124,328,776 142,039,557 161,150,809 164,335,770 171,319,799 178,307,620 174,634,326 174,916,179 176,938,999 178,435,392 180,409,687 182,573,093 184,457,295
33
34 EXPENSES
35 Electric Supply Purchases 61,313,637 68,785,977 80,022,010 75,705,000 80,467,136 83,505,886 91,924,961 94,232,563 95,111,327 98,655,001 98,667,977 99,059,024 102,252,401 103,534,874 103,178,257 106,193,402
36 Operating Expenses
37 Administration
38 Allocated Charges 4,399,674 4,139,837 4,511,222 4,934,195 3,990,822 4,304,278 4,412,096 4,522,617 4,635,777 4,751,692 4,870,511 4,992,301 5,117,136 5,245,093 5,376,249 5,510,686
39 Rent 3,875,836 4,051,044 4,147,742 4,997,101 5,121,102 5,284,977 5,443,527 5,606,832 5,775,037 5,948,288 6,126,737 6,310,539 6,499,855 6,694,851 6,895,697 7,102,568
40 Debt Service 9,265,736 9,020,651 9,037,000 8,885,994 8,953,893 8,955,166 8,808,619 8,818,349 8,783,507 8,792,388 9,624,493 9,259,612 4,898,677 4,896,047 4,894,784 4,893,296
41 Transfers and Other Adjustments 16,797,054 11,329,973 11,004,636 11,798,865 12,702,945 13,041,626 13,305,787 14,190,505 14,194,567 14,198,730 14,202,997 14,207,370 14,211,853 14,216,448 14,221,158 14,225,986
42 Subtotal, Administration 34,338,299 28,541,506 28,700,600 30,616,155 30,768,762 31,586,048 31,970,028 33,138,304 33,388,889 33,691,098 34,824,738 34,769,822 30,727,521 31,052,439 31,387,888 31,732,535
43 Resource Management 3,024,268 3,541,524 2,138,615 2,083,812 1,985,620 3,446,889 3,569,550 3,697,054 3,806,324 3,905,053 4,007,389 4,112,406 4,220,176 4,330,770 4,444,262 4,560,728
44 Demand Side Management 3,529,529 3,187,875 3,491,470 3,643,924 4,271,786 4,327,895 4,214,985 3,955,387 3,913,776 3,888,167 3,989,346 4,050,076 4,111,910 4,174,870 4,238,976 4,304,249
45 Operations and Mtc 9,601,481 9,488,627 10,716,881 11,523,881 11,811,016 13,349,204 13,790,502 14,247,795 14,653,401 15,030,198 15,419,751 15,819,400 16,229,407 16,650,041 17,081,577 17,524,297
46 Engineering (Operating)1,114,945 1,102,008 1,230,160 1,592,024 1,656,522 1,963,752 2,016,569 2,070,856 2,124,317 2,177,782 2,232,696 2,288,996 2,346,715 2,405,890 2,466,557 2,528,754
47 Customer Service 2,007,322 2,032,231 1,548,851 1,540,884 2,540,424 2,253,647 2,338,475 2,426,869 2,500,743 2,566,062 2,633,909 2,703,550 2,775,032 2,848,403 2,923,715 3,001,018
48 Allowance for Unspent Budget - - - - - (1,523,291) (1,571,660) (1,621,727) (1,667,008) (1,709,687) (1,753,753) (1,798,955) (1,845,322) (1,892,885) (1,941,675) (1,991,722)
49 Subtotal, Operating Expenses 53,615,844 47,893,770 47,826,576 51,000,680 53,034,130 55,404,145 56,328,449 57,914,537 58,720,442 59,548,674 61,354,076 61,945,295 58,565,440 59,569,529 60,601,301 61,659,859
50 Capital Program Contribution 15,113,859 13,016,111 14,005,915 9,331,367 11,558,306 20,961,467 22,684,258 18,287,069 20,096,699 13,632,467 14,010,831 14,399,781 14,799,614 15,210,638 15,633,168 16,067,528
51 TOTAL EXPENSES 130,043,340 129,695,858 141,854,501 136,037,047 145,059,572 159,871,498 170,937,668 170,434,169 173,928,468 171,836,142 174,032,885 175,404,101 175,617,456 178,315,041 179,412,726 183,920,790
52
53 ENDING RESERVES
54 Reappropriations (Non-CIP)305,000 - - - - - - - - - - - - - - -
55 Commitments (Non-CIP)3,528,000 3,164,000 3,102,055 3,777,205 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955
56 Restricted for Debt Service - - - - - - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 1,000,000 - - - - - - - - - - - - - -
58 Central Valley Project Reserve 313,000 329,000 - - - - - - - - - - - - - -
59 Underground Loan Reserve 738,000 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147
60 Public Benefits Reserves 2,197,000 2,064,000 2,574,000 1,839,000 681,330 - - - - - - - - - - -
61 Electric Special Projects Reserve 51,838,000 51,838,000 51,837,855 51,837,855 51,837,855 45,837,855 45,066,855 44,756,855 43,246,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855
62 Hydro Stabilization Reserve - - 17,000,000 11,400,000 11,400,000 10,400,000 10,400,000 10,400,000 10,400,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000
58 Capital Reserve - - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964
59 Rate Stabilization Reserve 69,029,000 70,049,000 14,410,840 9,010,840 9,010,840 - - - - - - - - - - -
60 Operations Reserve - - 22,497,607 21,850,187 29,912,981 37,884,461 32,053,564 33,249,194 39,138,346 38,836,530 39,719,824 41,254,722 44,072,659 46,167,305 49,327,672 49,864,178
61 Unassigned - - - - - - - - - - - - - - - -
62 TOTAL ENDING RESERVES 128,948,000 129,178,000 112,152,357 100,444,086 107,424,072 98,703,382 92,101,485 92,987,115 97,366,267 100,164,451 101,047,745 102,582,643 105,400,580 107,495,226 110,655,593 111,192,099
63
64 OPERATIONS RESERVE
65 Min (60 days of non-capital expenses)23,548,140 23,011,890 25,284,688 26,254,697 27,887,150 28,525,288 28,948,137 29,816,058 30,267,979 30,586,285 30,716,392 31,257,049 31,536,939 32,379,720
66 Target (90 days of non-capital expenses)33,151,752 32,456,285 35,213,317 36,600,046 38,978,736 39,864,186 40,425,168 41,652,081 42,253,107 42,651,788 42,766,200 43,494,415 43,829,410 45,006,620
67 Max (120 days of non-capital expenses)42,755,364 41,900,681 45,141,947 46,945,394 50,070,321 51,203,084 51,902,198 53,488,104 54,238,235 54,717,290 54,816,007 55,731,781 56,121,881 57,633,519
68 Risk Assessment Value 4,645,297 4,193,350 4,338,548 5,838,255 6,183,701 5,769,290 5,935,703 5,314,839 5,417,963 5,563,442 5,671,929 5,824,643 5,981,673 6,143,144
6053706
1 FISCAL YEAR FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
2
3 REVENUES
4 Net Sales 87%85%87%87%81%80%84%82%81%82%83%82%82%82%82%82%
5 Other Revenues and Transfers In 13%15%13%13%19%20%16%18%19%18%17%18%18%18%18%18%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 46%52%55%54%42%41%49%50%48%49%49%49%51%51%50%51%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%3%3%4%3%3%3%3%3%3%3%3%3%3%3%3%
13 Rent 3%3%3%4%4%3%3%3%3%3%4%4%4%4%4%4%
14 Debt Service 7%7%6%7%6%6%5%5%5%5%6%5%3%3%3%3%
15 Transfers and Other Adjustments 13%9%8%9%9%8%8%8%8%8%8%8%8%8%8%8%
16 Subtotal, Administration 26%22%20%23%21%20%19%19%19%20%20%20%17%17%17%17%
17 Resource Management 2%3%2%2%1%2%2%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 7%7%8%8%8%8%8%8%8%9%9%9%9%9%10%10%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 2%2%1%1%2%1%1%1%1%1%2%2%2%2%2%2%
21 Allowance for Unspent Budget 0%0%0%0%0%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 39%34%31%35%34%32%30%32%32%32%33%33%31%31%31%31%
23 Capital Program Contribution 12%10%10%7%8%13%13%11%12%8%8%8%8%9%9%9%
24 TOTAL EXPENSES 96%97%96%96%83%86%93%92%91%90%90%90%90%90%90%91%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
28 1. Load Net Revenue 77,428 652,853 1,208,477
29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 3,397,119
30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 539,073
31 4. Carbon Neutral Cost 331,630 303,022 114,983
32 5. Market Price 909,196 775,584 1,138,589
33 6. Local Capacity 475,962 408,388 446,695
34 7. Transmission/CAISO 4,555,915 3,741,647 2,806,120
35 8. Plant Outage 1,000,000 1,000,000 1,000,000
36 9. Western Cost 3,130,000 2,704,738 2,973,619
37 10. Regulatory & Legal - - -
38 11. Supplier Default - - -
39 TOTAL 20,170,708 19,380,490 13,624,674
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 196%172%303%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
44 Distribution Revenue Variance 3,244,706 3,260,213 3,182,718 3,742,109 3,915,276 3,940,583 3,926,033 3,951,592 4,016,880 4,123,464 4,191,967 4,303,579 4,418,356 4,536,391
45 10% CIP Program Contingency 1,400,592 933,137 1,155,831 2,096,147 2,268,426 1,828,707 2,009,670 1,363,247 1,401,083 1,439,978 1,479,961 1,521,064 1,563,317 1,606,753
46 Total Risk Asssessment Value 4,645,297 4,193,350 4,338,548 5,838,255 6,183,701 5,769,290 5,935,703 5,314,839 5,417,963 5,563,442 5,671,929 5,824,643 5,981,673 6,143,144
47 Projected Operations Reserve 22,497,607 21,850,187 29,912,981 37,884,461 32,053,564 33,249,194 39,138,346 38,836,530 39,719,824 41,254,722 44,072,659 46,167,305 49,327,672 49,864,178
48 Operations Reserve, % of Risk Value 484%521%689%649%518%576%659%731%733%742%777%793%825%812%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- - 15,208,552 14,498,215 15,472,236 16,163,913 17,553,876 17,965,924 18,133,345 18,744,756 18,928,400 18,961,720 18,799,559 19,040,477 19,012,969 19,540,493
46 Target (90 days of non-capital expenses)- - 22,812,829 21,747,322 23,208,354 24,245,869 26,330,813 26,948,886 27,200,017 28,117,133 28,392,600 28,442,580 28,199,338 28,560,716 28,519,453 29,310,739
47 Max (120 days of non-capital expenses)- - 30,417,105 28,996,429 30,944,472 32,327,825 35,107,751 35,931,847 36,266,689 37,489,511 37,856,800 37,923,439 37,599,117 38,080,955 38,025,937 39,080,986
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- - 8,339,587 8,513,675 9,812,452 10,090,785 10,333,275 10,559,364 10,814,793 11,071,303 11,339,579 11,624,565 11,916,834 12,216,571 12,523,970 12,839,228
51 Target (90 days of non-capital expenses)- - 10,338,923 10,708,963 12,004,964 12,354,177 12,647,923 12,915,301 13,225,151 13,534,948 13,860,507 14,209,208 14,566,862 14,933,699 15,309,957 15,695,881
52 Max (120 days of non-capital expenses)- - 12,338,259 12,904,252 14,197,475 14,617,569 14,962,570 15,271,237 15,635,509 15,998,593 16,381,435 16,793,851 17,216,890 17,650,826 18,095,944 18,552,534
53 Risk Assessment Value 4,645,297 4,193,350 4,338,548 5,838,255 6,183,701 5,769,290 5,935,703 5,314,839 5,417,963 5,563,442 5,671,929 5,824,643 5,981,673 6,143,144
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1140%1193%1315%1326%1391%1451%1583%1625%1651%1699%1563%1639%3183%3231%3246%3330%
57 Available Reserves (5x Debt Service)*13.5 14.0 12.1 10.9 11.7 10.7 10.1 10.2 10.7 11.1 10.2 10.8 20.9 21.3 22.0 22.1
58 *For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 42 | Page
APPENDIX B: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c) For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f) For operating contingencies, as described in Section 12 (Operations Reserves)
g) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserves for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c) As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d) To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 11.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 43 | Page
h) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 14 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Commitments will be set to an amount equal to the total remaining spending
authority for all contracts in force for the Electric Supply Fund and Electric Distribution
Fund, respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Reappropriations will be set to an amount equal to the amount of all remaining
capital and non-capital budgets that will be reappropriated to the following fiscal year for
each Fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of
Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve
and Adoption of Electric Special Project Reserve Guidelines). These policies and timelines
are included from Resolution 9206 as amended to refer to the reserves structure set forth
in these Reserves Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2017;
f) Any uncommitted funds remaining at the end of FY 2022 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
Section 7. Hydroelectric Stabilization Reserve
The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts
associated with variations in generation from hydroelectric resources. Staff will manage the
Hydroelectric Stabilization Reserve as follows:
a) Projected Hydro Output: Near the end of each fiscal year, staff will determine the
actual and expected hydro output for that fiscal year, compare that to the long-term
average annual output level (495,957 MWh as of March 2018), and multiply the
difference by the average of the monthly round-the-clock forward market prices for
each month of the current fiscal year.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 44 | Page
b) Changes in Reserves. Staff is authorized to transfer the amount described in Sec.
7(a) from the Operations Reserve to the Hydroelectric Stabilization Reserve for
hydro output deviations above long-term average levels, or transfer this amount
from the Hydroelectric Stabilization Reserve to the Operations Reserve for hydro
output deviations below long-term average levels.
c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after
the transfers described above shall be the basis for staff’s determination, with
Council approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-
HRA) for the following fiscal year.
d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve
according to the following guideline levels:
Minimum Level $3 million
Target Level $19 million
Maximum Level $35 million
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 60 days of budgeted CIP expense
Maximum Level 120 days of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve
for Commitments as a result of a change in contractual commitments related to CIP
projects. Any other additions to or withdrawals from the CIP reserve require Council
action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 45 | Page
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to d) above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 46 | Page
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were
funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an
alternative plan that retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 47 | Page
APPENDIX C: DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL ACTIVITIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Electric Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process.
It does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
• monitoring the substations and performing routine maintenance;
• performing preventative maintenance on the system;
• monitoring the system’s status from the UCC using SCADA;
• maintaining the SCADA system;
• investigating outages and other customer complaints and performing emergency
repairs;
• clearing vegetation near overhead power lines; and
• testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX D: SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 1 | Page
APPENDIX A: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a)“Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b)“Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c)“Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d)“Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserve for Commitments)
b)For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c)For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d)For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e)For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f)For operating contingencies, as described in Section 12 (Operations Reserves)
g)Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserves for Commitments)
b)For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c)As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d)To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e)For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f)For rate stabilization, as described in Section 11) (Rate Stabilization Reserves)
ATTACHMENT C
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 2 | Page
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 14 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Commitments will be set to an amount equal to the total remaining spending
authority for all contracts in force for the Electric Supply Fund and Electric Distribution
Fund, respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Reappropriations will be set to an amount equal to the amount of all remaining
capital and non-capital budgets that will be reappropriated to the following fiscal year for
each Fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of
Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve
and Adoption of Electric Special Project Reserve Guidelines). These policies and timelines
are included from Resolution 9206 as amended to refer to the reserves structure set forth
in these Reserves Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2017;
f) Any uncommitted funds remaining at the end of FY 2022 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
Section 7. Hydroelectric Stabilization Reserve
The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts
associated with variations in generation from hydroelectric resources. Staff will manage the
Hydroelectric Stabilization Reserve as follows:
a) Projected Hydro Output: Near the end of each fiscal year, staff will calculate the
actual/expected hydro output for that fiscal year, compare that to the long-term
average annual output level (495,957 MWh as of March 2018), and multiply the
difference by the average of the monthly round-the-clock forward market prices for
each month of the fiscal year.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 3 | Page
b) Changes in Reserves: Staff is authorized to transfer the amount described in Sec. 7(a)
from the Operations Reserve to the Hydroelectric Stabilization Reserve for hydro
output deviations above long-term average levels, or transfer this amount from the
Hydroelectric Stabilization Reserve to the Operations Reserve for hydro output
deviations below long-term average levels.
c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after
the transfers described above shall be the basis for staff’s determination, with
Council approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-
HRA) for the following fiscal year.
a)d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve
according to the following guideline levels:
Minimum Level $3 million
Target Level $19 million
Maximum Level $35 million
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 60 days of budgeted CIP expense
Maximum Level 120 days of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve
for Commitments as a result of a change in contractual commitments related to CIP
projects. Any other additions to or withdrawals from the CIP reserve require Council
action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 4 | Page
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to d) above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 5 | Page
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were
funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an
alternative plan that retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
Attachment D
* NOT YET APPROVED *
6055014 1
Resolution No. _________
Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Residential Master-Metered and Small Non-Residential
Electric Service), E-2-G (Residential Master-Metered and Small Non-
Residential Green Power Electric Service), E-4 (Medium Non-
Residential Electric Service), E-4-G (Medium Non-Residential Green
Power Electric Service), E-4 TOU (Medium Non-Residential Time of
Use Electric Service), E 7 (Large Non-Residential Electric Service), E-7-
G (Large Non-Residential Green Power Electric Service), E-7 TOU
(Large Non-Residential Time of Use Electric Service), and E-14 (Street
Lights).
R E C I T A L S
A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2018.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2 (Residential Master-Metered and Small Non-Residential Electric Service) is
hereby amended to read as attached and incorporated. Utility Rate Schedule E-2, as amended,
shall become effective July 1, 2018.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule
E-2-G, as amended, shall become effective July 1, 2018.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2018.
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Non-Residential Green Power Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall
become effective July 1, 2018.
Attachment D
* NOT YET APPROVED *
6055014 2
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Non-Residential Time of Use Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended,
shall become effective July 1, 2018.
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective
July 1, 2018.
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become
effective July 1, 2018.
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Non-Residential Time of Use Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become
effective July 1, 2018.
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated.
Utility Rate Schedule E-14, as amended, shall become effective July 1, 2018.
SECTION 11. The Council makes the following findings:
a. The revenue derived from the adoption of this resolution shall be used only for the
purpose set forth in Article VII, Section 2, of the Charter of the City of Palo Alto.
b. The fees and charges adopted by this resolution are charges imposed for a specific
government service or product provided directly to the payor that are not provided
to those not charged, and do not exceed the reasonable costs to the City of
providing the service or product.
c. The adoption of this resolution changing electric rates to meet operating expenses,
purchase supplies and materials, meet financial reserve needs and obtain funds for
capital improvements necessary to maintain service is not subject to the California
Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec.
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After
reviewing the staff report and all attachments presented to Council, the Council
incorporates these documents herein and finds that sufficient evidence has been
presented setting forth with specificity the basis for this claim of CEQA exemption.
Attachment D
* NOT YET APPROVED *
6055014 3
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-1-1 dated 7-1-20176 Sheet No E-1-1
A. APPLICABILITY:
This schedule applies to separately metered single-family residential dwellings receiving Electric
retail energy sServices from the City of Palo Alto Utilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Eelectric Sservice.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Tier 1 usage $0.072146605 $0.05240164 $0.00417391 $0.128712159
Tier 2 usage
Any usage over Tier 1
0.11347253 0.075157358 0.00417391 0.1927919002
Minimum Bill ($/day) 0.30402938
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Ccustomer’s bill
statement, the bill amount may be broken down into appropriate components ascalculated under Section C.
2. Calculation of Usage Tiers
Tier 1 Eelectricity usage shall be calculated and billed based upon a level of 11 kWh per
day, prorated by Mmeter reading days of Sservice. As an example, for a 30-day bill, theTier 1 level would be 330 kWh. For further discussion of bill calculation and proration,
refer to Rule and Regulation 11.
{End}
ATTACHMENT E
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-2-1 dated 7-1-20167 Sheet No E-2-1
A. APPLICABILITY: This schedule applies to the following Customers receiving Electric Service from the City of Palo Alto Utilities:
1. Small non-residential Customers receiving Nnon-Ddemand Mmetered Eelectric Sservice;
and
1.2. for small non-residential Ccustomers with Accounts at Master-Metered and master-
metered mmulti-family facilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Eelectric Sservice. C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period
$0.1120510591 $0.0790308468 $0.0039100417 $0.1888520090
Winter Period 0.0767807520 0.0535605766 0.0039100417 0.1386113267
Minimum Bill ($/day)
0.73287740
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a cCustomer’s bill
statement, the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-2-2 dated 7-1-20167 Sheet No E-2-2
from November 1 to April 30. When the billing period includes use in both the Summer and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum Ddemand Mmeter will be installed as promptly as is practicable and thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The maximum Ddemand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Ddemand Mmeter which does not reset after a definite time interval may be
used at the City's option. The billing Ddemand to be used in computing charges under this schedule will be the actual maximum Ddemand in kilowatts for the current month. An exception is that the
billing Ddemand for Ccustomers with Thermal Energy Storage (TES) will be based upon
the actual maximum Ddemand of such Ccustomers between the hours of noon and 6 pm
on weekdays.
{End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-2-G-1 dated 7-1-2016 Sheet No E-2-G-1
A. APPLICABILITY: This schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities under the Palo Alto Green Program:
1. Small non-residential Customers receiving Non-Demand Metered Eelectric Sservice; and 2. Customers with Aaccounts at Master-Mmetered multi-family facilities.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Palo Alto
Green
Charge Total
Summer Period
$0.11205105
91
$0.07903084
68
$0.004173
91 $0.0020
$0.190852
0290
Winter Period
0.0752007678
0.0535605766
0.00417391 0.0020
$0.1346714061
Minimum Bill ($/day)
0.73287740
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$0.10591112
05
$0.07903084
68
$0.004173
91
$0.188852
0090
Winter Period
0.0752007678
0.0535605766
0.00417391
0.1346713861
Minimum Bill ($/day)
0.73287740
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-2-G-2 dated 7-1-2016 Sheet No E-2-G-2
Palo Alto Green Charge (per 1000 kWh block) $2.00
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewable
sources, and create a transparent and sustainable market that encourages new
development of wind and solar power. Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-2-G-3 dated 7-1-2016 Sheet No E-2-G-3
4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer-s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option. The billing Demand to be used in computing charges under this schedule will be the
actual maximum Demand in kilowatts for the current month. An exception is that the
billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on weekdays.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-1 dated 7-1-20167 Sheet No E-4-1
A. APPLICABILITY: This schedule applies to Demand metered Ssecondary Electric Service for Ccustomers with a
mMaximum Demand below 1,000 kilowatts. This schedule applies to three-phase Electric
Service and may include Service to master-metered multi-family facilities or other facilities
requiring Demand-metered sServices, as determined by the City.
B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.382.98 $17.6721.13 $21.0524.11
Energy Charge (per kWh)
0.0952609893 0.0175601771 0.00417391 0.1167312081
Winter Period
Demand Charge (per kW) $1.931.87 $13.4316.65 $15.3618.52
Energy Charge (per kWh)
0.0674307109 0.0175601771 0.00417391 0.0889009297
Minimum Bill ($/day) 14.841415.9946 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-2 dated 7-1-20167 Sheet No E-4-2
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a Maximum Demand Mmeter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer-’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Mmeter which does not reset after a definite time interval may be
used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Ccustomers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Ccustomers between the hours of noon and 6 pm
on weekdays.
4. Power Factor For new or existing Ccustomers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing
applicable Mmetering to calculate a Power Factor. The City may remove such
Mmetering from the Service of a Ccustomer whose Demand has been below 200
kilowatts for four consecutive months.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-3 dated 7-1-20167 Sheet No E-4-3
When such metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Ccustomer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent (0.25%) for each one percent (1%) that the monthly Power Factor of the Ccustomer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Mmetering is installed, the monthly Power Factor shall be the Power Factor coincident with the Ccustomer's Maximum Demand.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any City of Palo Alto full-service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Ccustomer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Ccustomer receiving the discount in this section. The
Ccustomer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non-
utility generation source.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-4 dated 7-1-20167 Sheet No E-4-4
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate Mmeter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-1 dated 7-1-20167 Sheet No E-4-G-1
A. APPLICABILITY: This schedule applies to Demand mMetered Secondary Electric Service for Customers with a
mMaximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green
Program. This schedule applies to three-phase Electric Service and may include Service to
Master-metered multi-family facilities or other facilities requiring Demand -mMetered Services, as determined by the City.
B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge (per kW) $2.983.38 $17.6721.13
$21.0524.11
Energy Charge (per kWh)
0.0952609893
0.0175601771
0.0039100417 0.0020
0.1228111873
Winter Period
Demand Charge (per kW) $1.931.87 $13.4316.65
$15.3618.52
Energy Charge (per kWh)
0.0674307109
0.0175601771
0.0039100417 0.0020
0.0909009497
Minimum Bill ($/day) 14.841415.9946
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-2 dated 7-1-20167 Sheet No E-4-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.382.98 $21.1317.67 $24.1121.05
Energy Charge (per kWh) 0.0952609893 0.0175601771 0.0039100417
0. 1167312081
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.931.87 $13.4316.65 $15.3618.52
Energy Charge (per kWh) 0.0674307109 0.0175601771 0.0039100417 0.0889009497
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 14.841415.9946 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-3 dated 7-1-20167 Sheet No E-4-G-3
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the
option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter, which does not reset after a definite time interval, may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand.
5. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full-service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-4 dated 7-1-20167 Sheet No E-4-G-4
6. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change the system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-utility generation source.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-5 dated 7-1-20167 Sheet No E-4-G-5
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-1 dated 7-1-20176 Sheet No E-4-TOU-1
A. APPLICABILITY: This voluntary rate schedule applies to Demand metered Ssecondary Electric Service for
Ccustomers with Demand between 500 and 1,000 kilowatts per month and who have sustained
this level of usage for at least three consecutive months during the most recent 12 month period.
This schedule applies to three-phase Electric Service and may include Service to Mmaster-Mmetered multi-family facilities or other facilities requiring Demand-metered Sservices, as
determined by the City. In addition, this rate schedule is applicable for Ccustomers who did not
pay Ppower Ffactor Aadjustments during the last 12 months. B. TERRITORY: This rate schedule applies everywhereanywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $2.121.76 $6.097.28 $8.219.04
Mid-Peak 0.6466 6.097.28 6.767.92
Off-Peak 0.6466 6.097.28 6.767.92
Energy Charge (per kWh)
Peak $0.1014409248 $0.0175601771 $0.00391417 $0.1229111436
Mid-Peak 0.0983511645 0.0175601771 0.00391417 0.1198213833
Off-Peak 0.0874807146 0.0175601771 0.00391417 0.1089509334
Winter Period
Demand Charge (per kW)
Peak $1.047 $7.499.28 $8.5610.32
Off-Peak 1.047 7.499.28 8.5610.32
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-2 dated 7-1-20176 Sheet No E-4-TOU-2
Commodity Distribution Public Benefits Total
Energy Charge (per kWh)
Peak $0.0816408187 $0.017561771 $0.00391417 $0.1031110375
Off-Peak 0.0573807028 0.017561771 $0.00391417 0.0788509216
Minimum Bill ($/day) 14.841415.9946 D. SPECIAL NOTES: 1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C. 2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays) All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-3 dated 7-1-20176 Sheet No E-4-TOU-3
SEASONAL RATE CHANGES: When the billing period includes use in both the
Summer and the Winter periods, the usage will be prorated based on the number of days
in each seasonal period, and the charges based on the applicable rates therein.. For
further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Demand Mmeter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it
may be removed. The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated tTime periods as defined under Section D.2.
4. Power Factor Adjustment
Time of Use Ccustomers must not have had a Ppower Ffactor Aadjustment assessed on their Service for at least 12 months. Power factor is calculated based on the ratio of
kilowatt hours to kilovolt-ampere hours consumed during the month, and must not have
fallen below 95% to avoid the pPower Ffactor Aadjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be subject to Ppower Ffactor Aadjustments, the Customer will be removed from the E-4-TOU rate schedule and placed on another applicable rate schedule as is suitable to their
kilowatt Demand and kilowatt-hour usage.
5. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 months, the
Customer may request a rate schedule change to any applicable City of Palo Alto full-
service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 6. Primary Voltage Discount
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-4 dated 7-1-20176 Sheet No E-4-TOU-4
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Mmeter and that occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate Mmeter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more
of the non-utility generators on the Customer’s side of the City’s revenue Mmeter are not operating, the Maximum Demand will be reduced by the sum of the
Maximum Generation of those non-utility generators, but in no event shall the
Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-5 dated 7-1-20176 Sheet No E-4-TOU-5
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-1 dated 7-1-20176 Sheet No E-7-1
A. APPLICABILITY: This schedule applies to Demand Mmetered secondary Service for large non-residential
Customers with a Maximum Demand of at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months. B. TERRITORY:
This rate schedule applies everyanywhere the City of Palo Alto provides Electric Service.
C. RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (kW) $3.143.49 $23.6320.35 $26.7723.84
Energy Charge (kWh) 0.1003709353 0.0005300058 0.0041700391 0.1050709802
Winter Period
Demand Charge (kW) $1.841.90 $15.1713.69 $17.0115.59
Energy Charge (kWh) 0.0697906739 0.0005300058 0.0041700391 0.0744907188
Minimum Bill ($/day) 45.475842.3648 D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-2 dated 7-1-20176 Sheet No E-7-2
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one
Aaccount or one Mmeter if the Aaccounts are on one site. A site shall be defined as one
or more utility Aaccounts serving contiguous parcels of land with no intervening public
right-of-ways (e.g. streets) and have a common billing address.
4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Mmeter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Mmeter which does not reset after a definite time interval may be used at
the City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-3 dated 7-1-20176 Sheet No E-7-3
5. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option to install applicable
Mmetering to calculate a Power Factor. The City may remove such Mmetering from the
Service of a Customer whose Demand has been below 200 kilowatts for four consecutive months. When such metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The pPower fFactor Aadjustment is
applied by increasing the total energy and Demand charges for any month by 0.25 percent (0.25%) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Mmetering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements , as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kVA size limitation.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-4 dated 7-1-20176 Sheet No E-7-4
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Mmeter and that
occasionally require backup power from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate Mmeter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.4) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Mmeter are not operating, the Maximum Demand will
be reduced by the sum of the Maximum Generation of those non-utility
generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-5 dated 7-1-20176 Sheet No E-7-5
Section 2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-1 dated 7-1-20167 Sheet No E-7-G-1
A. APPLICABILITY: This schedule applies to Demand mMetered Service for large non-residential Customers who
choose Service under the Palo Alto Green Program. A Customer may qualify for this rate
schedule if the Customer’s Maximum Demand is at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge ( per kW) $3.143.49 $23.6320.35 $26.7723.84
Energy Charge (per kWh) 0.1003709353 0.0005300058 0.0041700391 0.0020 0.1070710002
Winter Period
Demand Charge (per kW) $1.841.90 $15.1713.69 $17.0115.59
Energy Charge (per kWh) 0.0697906739 0.0005300058 0.0041700391 0.0020 0.0764907388
Minimum Bill ($/day) 45.475842.3648
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-2 dated 7-1-20167 Sheet No E-7-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.143.49 $23.6320.35 $26.7723.84
Energy Charge (per kWh) 0.1003709353 0.0005300058 0.0041700391 0.1050709802
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.901.84 $15.1713.69 $17.0115.59
Energy Charge (per kWh) 0.0697906739 0.0005300058 0.0041700391 0.0744907188
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 45.475842.3648 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C. 2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-3 dated 7-1-20167 Sheet No E-7-G-3
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Request for Service Qualifying Customers may request Service under this schedule for more than one
Account or one Meter if the Accounts are at one site. A site shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and have a common billing address. 5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to the computation of any primary voltage discount. The Ppower fFactor Aadjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-4 dated 7-1-20167 Sheet No E-7-G-4
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile 7. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new
development of wind and solar. Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program. 8. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a qualified line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's Electrical requirements , as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change the system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
9. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(9)(e), applies to Customers that have a non-utility generation source
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-5 dated 7-1-20167 Sheet No E-7-G-5
interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-1 dated 7-1-20167 Sheet No E-7-TOU-1
A. APPLICABILITY: This voluntary rate schedule applies to Demand mMetered secondary Service for non-
residential Ccustomers with a Maximum Demand of at least 1,000KW per month per site, who
have sustained this Demand level at least 3 consecutive months during the last twelve months. In addition, this rate schedule is applicable for customers Customers who did not pay Ppower Ffactor Aadjustments during the last 12 months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $1.922.22 $7.946.84 $9.869.06
Mid-Peak 0.6264 7.946.84 7.488.56
Off-Peak 0.6264 7.946.84 7.488.56
Energy Charge (per kWh)
Peak $0.1014910177 $0.0005300058 $0.0041700391 $0.1061910626
Mid-Peak 0.1277909868 0.0005300058 0.0041700391 0.1324910316
Off-Peak 0.0784208777 0.0005300058 0.0041700391 0.0831209226
Winter Period
Demand Charge (per kW)
Peak $0.9396 $7.686.93 $8.617.89
Off-Peak 0.9396 7.686.93 8.617.89
Energy Charge (per kWh)
Peak $0.0715008036 $0.0005300058 $0.0041700391 $0.0762008484
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-2 dated 7-1-20167 Sheet No E-7-TOU-2
Off-Peak 0.0613805647 0.0005300058 0.0041700391 0.0660806096
Minimum Bill ($/day) 42.364845.4758 D. SPECIAL NOTES:
1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving
Day, and Christmas Day. The dates will be those on which the holidays are legally observed.
SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-3 dated 7-1-20167 Sheet No E-7-TOU-3
period, and the charges based on the applicable rates therein. For further discussion of bill
calculation and proration, refer to Rule and Regulation 11.
3. Request for Service Qualifying Ccustomers may request Service under this schedule for more than one Aaccount or one Mmeter if the Aaccounts are on one site. A site shall be defined as one or more utility
Aaccounts serving contiguous parcels of land with no intervening public right-of-ways (e.g.
streets) and have a common billing address. 4. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Demand Mmeter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for
twelve consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated tTime periods as defined under Section D.2. 5. Power Factor Adjustment
Time of Use Ccustomers must not have had a pPower fFactor aAdjustment assessed on their
Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt-ampere hours consumed during the month, and must not have fallen below 95% to avoid the Ppower Ffactor Aadjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be
subject to Ppower Ffactor Aadjustments, the Customer will be removed from the E-7-TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand
and kilowatt-hour usage.
6. Changing Rate Schedules Customers electing to be served under E-7 TOU must remain on said schedule for a minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a
rate schedule change to any applicable City of Palo Alto full-service rate schedule as is suitable
to their kilowatt Demand and kilowatt-hour usage.
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-4 dated 7-1-20167 Sheet No E-7-TOU-4
7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it has, or will
install, ample facilities for supplying at another voltage equally or better suited to the Customer's
electrical requirements , as determined in the City’s sole discretion. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount)
through transformers to be supplied by the City subject to a maximum kilovolt-ampere size
limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Mmeter and that occasionally require backup
power from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate mMeter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue mMeter are not
operating, the Maximum Demand will be reduced by the sum of the Maximum
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-5 dated 7-1-20167 Sheet No E-7-TOU-5
Generation of those non-utility generators, but in no event shall the Customer’s
Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section
2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No. E-14-1 dated 7-1-20176 Sheet No. E-14-1
A. APPLICABILITY: This schedule applies to all street and highway lighting installations.
B. TERRITORY: Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City.
C. RATES:
Per Lamp Per Month Class A: Utility supplies energy
and switching service only.
Lamp Rating: High Pressure Sodium Vapor Lamps
100 watts 9.668.28
200 watts 17.8315.29
250 watts 21.9218.79
310 watts 27.1223.25 400 watts 34.9229.94
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No. E-14-2 dated 7-1-20176 Sheet No. E-14-2
Per Lamp Per Month – Class C: Utility supplies energy
and switching service and
maintains entire system, including lamps and glassware.
Lamp Rating:
Mercury-Vapor Lamps
400 watts 34.9432.58
High Pressure Sodium Vapor Lamps
70 watts 30.4825.72
100 watts 32.9327.82
150 watts 37.0233.32 250 watts 45.1938.33
Light Emitting Diode (LED) Lamps
70 watts-equivalent 25.0621.07
100 watts-equivalent 26.9122.66 150 watts-equivalent 28.6224.13
250 watts 33.3028.14
D. SPECIAL CONDITIONS:
1. Type of Service: This schedule is applicable to series circuit and multiple street lighting
systems to which the Utility will deliver current at secondary voltage. Unless otherwise
agreed, multiple current will be delivered at 120/240 volts, three-wire, single-phase. In certain localities the Utility may supply service from 120/208 volt star-connected poly-phase
lines in place of 240-volt service. Single phase service from 480-volt sources will be
available in certain areas at the option of the Utility when this type of service is practical
from the Utility's engineering standpoint. All currents and voltages stated herein are
nominal, reasonable variations being permitted. New lights will normally be supplied as multiple systems.
2. Point of Delivery: Delivery will be made to the customer's system at a point or at points
mutually agreed upon. The Utility will furnish the service connection to one point for each
group of lamps, provided the customer has arranged his system for the least practicable number of points of delivery. All underground connections will be made by the customer or
at the customer's expense.
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No. E-14-3 dated 7-1-20176 Sheet No. E-14-3
3. Switching: Switching will be performed by the Utility (on the Utility's side of points of
delivery) and no charge will be made for switching provided there are at least 10 kilowatts of
lamp load on each circuit separately switched, including all lamps on the circuit whether served under this schedule or not; otherwise, an extra charge of $2.50 per month will be made for each circuit separately switched unless such switching installation is made for the
Utility's convenience or the customer furnishes the switching facilities and, if installed on the
Utility's equipment, reimburses the Utility for installing and maintaining them.
4. Annual Burning Schedule: The above rates apply to lamps which will be turned on and off
once each night in accordance with a regular burning schedule agreeable to the customer but
not exceeding 4,100 hours per year. 5. Maintenance: The rates under Class C include all labor necessary for replacement of
glassware and for inspection and cleaning of the same. Maintenance of glassware by the Utility is limited to standard glassware such as is commonly used and manufactured in
reasonably large quantities. A suitable charge will be made for maintenance of glassware of a
type entailing unusual expense. Under Class C, the rates include maintenance of circuits
between lamp posts and of circuits and equipment in and on the posts, provided these are all
of good standard construction; otherwise, the Utility may decline to grant Class C rates. Class C rates applied to any agency other than the City of Palo Alto also include painting of
posts with one coat of good ordinary paint as required to maintain good appearance but do
not include replacement of posts broken by traffic accidents or otherwise.
10. . System Owned In-Part by Utility : Where, at customer's request, the Utility installs, owns, and maintains any portion of the lighting fixtures, supports, and/or interconnecting circuits,
an extra monthly charge of one and one-fourth percent of the Utility's estimate of additional
investment shall be made.
11. Rates For Lamps Not on Schedule: In the event a customer installs a lamp which is not presently represented on this schedule, the Utility will prepare an interim rate reflecting the
Utility's estimated costs associated with the specific lamp size. This interim rate will serve as
the effective rate for billing purposes until the new lamp rating is added to Schedule E-14.
{End}
EXCERPTED DRAFT MINUTES OF THE APRIL 12, 2018 SPECIAL MEETING
UTILITIES ADVISORY COMMISSION
ITEM 1: ACTION: Staff recommendation that the Utilities Advisory Commission recommend the City
Council adopt 1) a Resolution approving the Fiscal Year 2019 Electric Financial Plan, and 2) a Resolution
increasing Electric Rates by 9% by amending the E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU,
and E-14 Rate Schedules.
Ed Shikada, Utilities General Manager, noted a revision in the proposed rate increase. Staff originally
recommended a 9% rate increase but is now proposing a 6% rate increase.
Erik Keniston, Senior Resource Planner, reported that the recommended rate increase for the Electric
Utility is 6% in fiscal year 2019 followed by a 3% increase in fiscal year 2020 and a 2% increase in fiscal
year 2021. With the recommended rate increase, revenue projections should match cost projections. Last
year, staff projected a 7% rate increase. In the short term, staff is projecting a slight increase in Capital
Improvement Program (CIP) expenditures related to one-time projects, but then costs decrease after
2021. Some of the capital investments are related to Smart Grid improvements. In current models, staff
assumes funding for Smart Grid improvements will come from the Electric Special Projects Reserve Fund.
The majority of the change in expenses between fiscal year 2016 and fiscal year 2022 is driven by the
supply portfolio. Between fiscal year 2019 and fiscal year 2022, costs will be about the same overall.
Supply reserves remain relatively healthy. At this time, staff projects a withdrawal from the Hydroelectric
Stabilization Reserve Fund of approximately $1 million. If drought or a dry hydroelectric year occurs,
having more money in the Reserve Fund will be critical to the financial health of the Electric Utility.
In response to Chair Danaher's query asking whether the utility was receiving less hydroelectric power
than expected, Jonathan Abendschein, Assistant Director of Resource Management, explained that March
storms helped alleviate the dry year through February. The City will receive less than average hydroelectric
generation, but it is not extremely low.
Keniston continued his presentation. The Distribution Operations Reserve Fund was below the minimum
guideline level in 2017, but staff will transfer funds so that the balance falls within guideline levels. The
Supply Operations Reserve Fund should meet the target level during the forecast period. The Distribution
Operations Reserve Fund is expected to remain at the target level.
In answer to Chair Danaher's question about reasons for the Supply Operations Reserve Fund rising and
falling in 2018, 2019, and 2020, Keniston indicated it was a result of staff's proposed transfers of funds
between supply and distribution reserve funds.
In reply to Commissioner Johnston's inquiry regarding a way to spread the proposed rate increases over
five years, Keniston advised that the 6% rate increase was needed to keep fund balances within guideline
ranges given the cost projections. Even with the increase, staff planned to withdraw funds from the
ATTACHMENT F
Electric Special Projects Reserve Fund as a temporary loan. Abendschein clarified that the Utility has only
limited control over supply costs because they are influenced long term rather than year-to-year, so it was
difficult to make short-term adjustments to reduce the rate increases. Costs could be controlled over the
long term. For example, the Utility works with partner agencies to intervene in transmission cases, which
can achieve significant savings. One short-term cost containment measure is Northern California Power
Agency's (NCPA) recent refinancing of debt on the Calaveras resource. Palo Alto's share of that savings
will be a few hundred thousand dollars. Noting the Commissioners comment on Silicon Valley Power
having lower rates, he said that Silicon Valley Power, which is the City of Santa Clara's utility, has lower
rates than Palo Alto because it ended its final coal contract in December, has an in-town gas plant on
which there is little debt, and seeks data center and manufacturing customers. Shikada added that the
location of the gas plant allows Santa Clara to avoid the transmission access charge.
Chair Danaher proposed staff include reasons for the rate increase in the staff report to the Council. In
response to his question regarding the cost of a bad drought year to the Utility, Keniston indicated the
Utility could easily exhaust all funds in the Hydroelectric Stabilization Reserve Fund. Abendschein stated
the estimated cost of a drought year is $8-$10 million. Chair Danaher did not believe the Utility has
sufficient reserve fund balances to delay a rate increase.
In reply to Commissioner Forssell's question about whether the hydroelectric rate adjuster would help
the Utility in drought years, Abendschein reported the adjuster will be helpful. When reserve fund
balances are low and the year is dry, the effective percentage increase for the rate adjuster is in the
ballpark of 8%-10% on the bill. If the Council chooses to reduce reserve funds in order to spread rate
increases over future years, the risk of going from no rate adjuster to a full rate adjuster in one year
increases. Higher reserve balances would allow the rate adjuster to be implemented at a lower level
(about 5% bill impact) in the first year and perhaps 10% in the second year.
In response to Vice Chair Ballantine's question about the impact of the Cost of Service Study on the use
of tiered rates, Keniston advised that one tier of rates was eliminated due to the Cost of Service Study.
The existing tier structure will not change.
ACTION: Vice Chair Ballantine moved to recommend the City Council adopt 1) a Resolution approving the
Fiscal Year 2019 Electric Financial Plan, and 2) a Resolution increasing Electric Rates by 6% by amending
the E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU, and E-14 Rate Schedules. Commissioner
Johnston seconded the motion. The motion carried 5-0 with Chair Danaher, Vice Chair Ballantine,
Commissioners Forssell, Johnston, and Schwartz voting yes.
City of Palo Alto (ID # 9157)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/15/2018
City of Palo Alto Page 1
Summary Title: FY 2019 Gas Financial Plan and Proposed Rates
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt: 1) a Resolution Approving the Fiscal Year 2019 Gas Utility Financial
Plan; and 2) a Resolution Increasing Gas Rates by 4% by Amending Rate
Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered
and Commercial Gas Service), G-3 (Large Commercial Gas Service), and G-10
(Compressed Natural Gas Service)
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission (UAC) request that the Finance Committee
recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2019 Gas Utility
Financial Plan (Attachment B); and
2. Adopt a resolution (Attachment C) increasing gas rates by amending Rate Schedules G-1
(Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas
Service), G-3 (Large Commercial Gas Service), and G-10 (Compressed Natural Gas
Service) (Attachment D).
Executive Summary
The FY 2019 Gas Utility Financial Plan includes projections of the utility’s costs and revenues for
FY 2019 through FY 2028. Gas rates related to distribution costs were last adjusted by 8% on
July 1, 2016, and the FY 2018 Financial Plan included a tentative rate increase of 4% for FY 2019.
The proposed FY 2019 Gas Utility Financial Plan includes a 6% increase in distribution rates,
resulting in a 4% overall gas rate increase, on July 1, 2018. Increases of 7% to 8% are projected
over the next three years. In addition, the plan proposes transfers to the Operations Reserve of
$129,000 and $2 million from the Rate Stabilization Reserve in FY 2018 and FY 2019,
respectively, to ensure that there are appropriate financial reserves for contingencies. The Rate
Stabilization Reserve is projected to be zero by the end of FY 2020.
City of Palo Alto Page 2
Gas Utility expenses are projected to increase by roughly 3 to 4 percent annually from FY 2019
to FY 2028. In the short term, some increases in operations costs are related to the cross-bore
inspection program, but capital improvement program (CIP) costs have also increased as the
economy has improved. Future CIP project costs have been revised significantly upwards from
prior forecasts ($3 million to $6 million) to reflect higher bids on gas main replacement projects.
Commodity costs are the most volatile component of the Gas Utility’s expenses, but market
prices have been steady and current forecasts project increases of around 1% to 2% annually.
Gas usage was trending downward over the last several years, most likely due to relatively
warm winter heating seasons, as well as lower hot water usage during the drought, but a cooler
winter and the end of drought restrictions has brought increased usage. Gas usage has
generally decreased to about 7% of pre-drought levels, but as with water, it is difficult to
determine whether long run usage will resume the declining trend seen over the last few
decades.
Background
Every year staff presents the Finance Committee and UAC with Financial Plans for its Electric,
Water, Gas, and Wastewater Collection Utilities and recommends any rate adjustments
required to maintain their financial health. These Financial Plans include a comprehensive
overview of the utility’s operations, both retrospective and prospective, and are intended to be
a reference for UAC and Council members as they review the budget and staff’s rate
recommendations. Each Financial Plan also contains a set of Reserves Management Practices
describing the reserves for each utility and the management practices for those reserves.
Discussion
Staff’s annual assessment of the financial position of the City’s gas utility is completed to ensure
adequate revenue to fund operations in compliance with the cost of service requirements set
forth in the California Constitution. This includes making long-term projections of market
conditions, the physical condition of the system, and other factors that could affect utility costs,
and setting rates adequate to recover these costs.
Proposed Actions for FY 2018
The FY 2019 Gas Utility Financial Plan includes the following proposed action:
1. Reduce the $1.22 million proposed transfer from the Rate Stabilization Reserve to the
Operations Reserve proposed in the FY 2018 Gas Financial Plan to $129,000.
Proposed Actions for FY 2019
The FY 2019 Gas Utility Financial Plan also includes the following proposed actions:
1. Amend gas rate schedules (see Attachment D) to increase rates by approximately 4%.
2. Transfer up to $2 million from the Rate Stabilization Reserve to the Operations Reserve.
The reserve transfers will enable staff to maintain sufficient funds in the Gas Operations
Reserve levels while spreading the required rate increases for the gas utility over several years.
City of Palo Alto Page 3
These proposed actions are described in more detail in the FY 2019 Gas Financial Plan
(Attachment B).
Staff proposes to adjust gas rates as shown in Table 1 and Table 2 below, effective July 1, 2018.
These changes are projected to increase the system average gas rate by roughly 4%. These rate
changes are included in the proposed amended rate schedules in Attachment D.
Table 1: Current and Proposed Monthly Service Charges
Rate Schedule
Monthly Service Charge
($/month)
Change
Current (as of
7/1/16)
Proposed for
FY 2019
($) (%)
G-1 (Residential) $10.32 $10.94 $0.62
6% G-2 (Small Commercial) 78.23 82.94 4.69
G-3 (Large Commercial) 377.43 400.08 22.65
G-10 (CNG) 52.93 56.11 3.18
Table 2: Current and Proposed Gas Distribution Charges
Change
Current (as of
11/1/16)
Proposed
for FY 2019
($) (%)
G-1 (Residential)
Tier 1 Rates $0.3933 $0.4239 $0.0306 7.8%
Tier 2 Rates 0.9319 0.9948 0.0629 6.7%
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.5767 0.6183 0.0416 7.2%
G-3 (Large Commercial)
Uniform Rate 0.5687 0.6098 0.0411 7.2%
G-10 (Compressed Natural Gas)
Uniform Rate 0.0093 0.0100 0.0007 7.2%
Bill Impact of Proposed Rate Changes
Table 3 shows the impact of the proposed July 1, 2018 rate changes on the median residential
bill. The average increase is roughly 4% based on commodity prices in February 2018, but some
customers may see slightly higher or lower increases due to slight changes in the composition
of the utility’s costs, as well as prevailing market prices.
City of Palo Alto Page 4
Table 3: Impact of Proposed Gas Rate Changes on Residential Bills
Usage
(Therms/month)
Bill under
Current Rates
Bill under
Proposed Rates
Change
$/mo. %
Winter (Using February 2018 commodity prices)
30 $36.93 $ 38.47 $ 1.54 4%
54 (median) 58.21 60.49 2.28 4%
80 94.20 98.04 3.84 4%
150 193.98 202.23 8.25 4%
Summer (Using July 2017 commodity prices)
10 18.73 $ 19.90 $ 1.17 6%
18 (median) 25.45 27.08 1.63 6%
30 40.57 43.16 2.59 6%
45 61.26 65.17 3.91 6%
Table 4 shows the impact of the proposed July 1, 2018 rate changes on various representative
commercial customer bills.
Table 4: Impact of Proposed Gas Rate Changes on Commercial Bills
(Using February 2018 commodity prices)
Usage
(Therms/month)
Bill under Current
Rates
Bill under
Proposed Rates
Change
%
500 613 639 4%
5,000 5,430 5,642 4%
10,000 10,781 11,202 4%
50,000 53,493 55,571 4%
FY 2019 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table 5 shows the projected rate adjustments over the next five years and their impact on the
annual median residential gas bill.
Table 5: Projected Rate Adjustments, FY 2019 to FY 2023
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Gas Utility 4% 8% 7% 7% 4%
Estimated Bill Impact ($/mo)* $1.56 $3.25 $3.07 $3.29 $2.01
* estimated impact on median residential gas bill, which is currently $39.09 for CY 2017.
Cost Drivers and Cost Containment
One of the main drivers for the increase in the Gas Utility’s short run costs (and therefore rates)
over the next several years are increases in capital improvement costs. In FY 2014, FY 2015 and
FY 2017, costs for the gas utility were unusually low as new main replacements were not
budgeted. The gas, water and wastewater utilities generally try to perform one main
City of Palo Alto Page 5
replacement construction contract annually in each utility, but in the gas utility completing new
projects was determined infeasible in those years. In FY 2014 and FY 2015, this was due to the
fact that staff was completing a prior major gas main replacement project, the largest in CPAU
history, which completed replacement of all ABS gas mains in Palo Alto. Then, FY 2016 included
replacements of gas mains on University Avenue, a project that has evolved into the Upgrade
Downtown project involving a coordinated replacement of several different types of
infrastructure to avoid multiple disruptions to the business district. This has been a multi-year
planning effort that did not allow for design of other new projects.
This allowed the Gas Utility to temporarily keep rates lower than they would typically have
been needed to be to fund future operations and capital replacement. These future capital
replacement costs will be higher, as well. As the emphasis on infrastructure improvement has
taken hold both regionally and nationally, contractor bids for new projects have risen greatly
from where they were during the last recession. Lastly, one additional project which will
increase costs on a one-time basis is the modification of gas meters to an Advanced Metering
Infrastructure platform (AMI). Much of this project is expected to be completed by FY 2022.
Going forward, main replacement projects will focus on replacing polyvinyl chloride (PVC) and
steel (wrapped with cathodic protection) mains, the materials most at risk of failure on the
system, with polyethelene (PE) mains. Annual operations expense allocations will also include
the elimination of gas cross-bore risks.
Over the longer term, increases to Operations and CIP costs are projected to be roughly
equivalent in terms of driving costs. Growth in these categories of expenses is projected to
increase by about 2 to 3% annually, mainly driven by expected increases in inflation as well as
salaries and benefits costs. In addition, additional costs will be seen over at least the next three
years from the cross-bore inspection program. Gas commodity costs are the most variable,
being subject to market forces. This category of costs is currently forecast to remain relatively
stable, but this can change rapidly.
Figures 1 below illustrates the projected long run changes in the Gas Utility’s costs. The figures
use FY 2013 and FY 2022 as comparison years because of one time savings in FY 2014, FY 2015,
and FY 2017 due to a lack of main replacement funding. Projected cost increases over the
FY 2013 to FY 2022 time period are primarily related to Operations and Capital are roughly
equal in terms of projected cost growth. Commodity costs are projected to be roughly
equivalent between these two time periods, although being market driven, this can change at
any time, with the additional cost or savings passed directly to consumers.
Figure 1: FY 2013 and FY 2022 costs
City of Palo Alto Page 6
It’s worth noting that although costs are increasing 17% over the FY 2013 to FY 2022 time
period, the average customer rate is projected to increase 19% over that period. This is due to
the fact that rates were lower than costs in FY 2013, so will need to rise more steeply than costs
through FY 2022.
Distribution rates were increased only once from July 2012 through today because of the one-
time capital cost savings in FY 2014, FY 2015, and FY 2017 as discussed above. Raising rates
would have resulted in accumulation of reserves in excess of reserve guidelines. The FY 2017
Financial Plan, anticipated further increases in FY 2018 and FY2019 of 9% and 7%, respectively,
to bring distribution revenues in line with costs. Reserve positions at the end of FY 2017
allowed staff to delay these increases. The current projected rate increases simply allow
revenues to rise to match increased costs as staff resumes regular main replacement.
Even though costs have risen in recent years, they have not risen as much as they would have if
City staff did not take efforts to contain costs. Some examples include:
City staff looks for opportunities to save money operationally, small opportunities that
add up. For example, the City recently creatively rebid its contract for construction
material supply and spoils hauling to go from using a single vendor to multiple vendors
that each specialized in specific materials, realizing nearly $250,000 in savings over
three years.
The current climate of high construction costs results in less capital replacement for
dollars invested. Staff will continue to prioritize near-term projects to address
immediate needs, and potentially defer projects where system reliability will not be
impacted to ensure full value is extracted from existing infrastructure.
A regular review of performance metrics and expenditures.
City of Palo Alto Page 7
Consistent with newly approved Utilities Strategic Plan, cost containment is being instituted as
an ongoing priority and annual cycle. This will include the completion of preliminary out-year
rate forecasts in the fall, which will allow for a review by all Divisions for alignment of multiyear
strategies. This includes ongoing management review of personnel transactions, including
Review/Revisions of position classifications to match evolving needs, Addition/Deletion of
positions to reflect organizational priorities, and Review/Approval to fill individual position
vacancies in conjunction with ASD Budget Office and Human Resources.
Changes from Preliminary Financial Forecast
After presenting the preliminary financial forecast to the UAC on February 7, 2018, additional
budget information and changes to usage projections have been changed in outer years, but
the FY 2019 proposal of a 4% overall rate increase remains the same.
Gas Bill Comparison with Surrounding Cities
Table 6 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of July 2017 (to illustrate a summer month bill) and
February 2018 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2017 was $469.05, about 14% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 6: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(February 2018)
30 36.93 42.39 -12.9%
(Median) 54 58.21 76.31 -23.7%
80 94.20 126.58 -25.6%
150 193.98 264.07 -26.5%
Summer
(July 2017)
10 18.73 13.01 44.0%
(Median) 18 25.45 23.41 8.7%
30 40.57 45.24 -10.3%
45 61.26 72.72 -15.8%
Table 7 shows the monthly gas bills for commercial customers for various usage levels for rates
in effect as of February 2018. Bills for CPAU customers at the usage levels shown are around 2%
to 27% higher for commercial customers than for PG&E customers. This is a substantial
improvement over the calendar year 2013 bill comparison, when commercial gas bills for CPAU
customers were 27% to 44% higher than for PG&E customers. This is primarily attributable to
PG&E’s increased distribution rates as the commodity rates for CPAU and PG&E are very similar,
both being based on spot market gas prices.
City of Palo Alto Page 8
Table 7: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect February 2018)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 613 600 2%
5,000 5,430 5,242 4%
10,000 10,781 9,211 17%
50,000 53,493 42,036 27%
Commission Review and Recommendation
The UAC reviewed this proposal at its April 12, 2018 meeting. After a brief presentation by staff,
Commissioners noted that capital costs are a driver, and that discussing the safety aspects of
future projects should be something staff should focuses on when communicating to the public.
Commissioners also sought clarification as to how the reserve guideline levels were derived,
how they followed cost increases, as well as how the reserve funds were separated. The UAC
voted 4-0 (Commissioners Trumbull and Segal absent) to recommend staff’s proposal.
Attached is the excerpted draft minutes from the UAC’s April 12, 2018 meeting (Attachment E).
Timeline
If the Finance Committee supports the proposed rate adjustments, the City Council will
consider adopting the Financial Plan and rate amendments as part of the FY 2019 budget
review and adoption process. If Council approves the proposed rate changes, they will become
effective July 1, 2018.
Resource Impact
Normal year sales revenues for the Gas Utility are projected to increase by roughly 4% ($1.2
million) as a result of the proposed rate increases, not including fluctuations in commodity
revenue/cost. See the attached FY 2019 Gas Financial Plan for a more comprehensive overview
of projected cost and revenue changes for the next ten years.
Policy Implications
The proposed gas rate adjustments are consistent with Council-adopted Reserve Management
Practices that are part of the Financial Plan, and were developed using a cost of service study
and methodology consistent with industry-accepted cost of service principles.
Environmental Review
The Finance Committee and UAC’s review and recommendation to Council on the FY 2019 Gas
Financial Plan and rate adjustments does not meet the California Environmental Quality Act’s
definition of a project, pursuant to Public Resources Code Section 21065, thus no
environmental review is required.
Attachments:
Attachment A: Resolution Approving FY 2019 Gas Utility Financial Plan
City of Palo Alto Page 9
Attachment B: FY 2019 Gas Utility Financial Plan
Attachment C: Resolution Amending Gas Rates Utility for FY 2019
Attachment D: Amended Rate Schedules G-1, G-2, G-3 and G-10
Attachment E: Excerpted Draft UAC Minutes of April 12, 2018 Special Meeting
Attachment A
NOT YET APPROVED
180327 jb 6055005
Resolution No. ____
Resolution of the Council of the City of Palo Alto Approving the
FY 2019 Gas Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes
making long-term projections of market conditions, the physical condition of the system, and
other factors that could affect utility costs, and setting rates adequate to recover these costs. It
does this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby adopts the FY 2019 Gas Utility Financial Plan.
SECTION 2. The Council hereby approves the transfer of up to $129,000 in FY 2019
from the Rate Stabilization Reserve to the Operations Reserve, as described in the FY 2019 Gas
Utility Financial Plan approved via this resolution.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental assessment is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
Attachment A
NOT YET APPROVED
180327 jb 6055005
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2019 GAS
UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
ATTACHMENT B
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M a r c h 2018 2 | P a g e
GAS UTILITY FINANCIAL PLAN
FY 2019 TO FY 2028
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2018 Rate and Reserve Proposals ........................................................ 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3C: Proposed Reserve Transfers ...................................................................................... 9
Section 4: Utility Overview .................................................................................................. 10
Section 4A: Gas Utility History ................................................................................................... 10
Section 4B: Customer Base ........................................................................................................ 11
Section 4C: Distribution System ................................................................................................. 12
Section 4D: Cost Structure and Revenue Sources ...................................................................... 13
Section 4E: Reserves Structure ................................................................................................... 13
Section 4F: Competitiveness ...................................................................................................... 14
Section 4G: Gas Supply Rates .................................................................................................... 15
Section 5: Utility Financial Projections ................................................................................. 16
Section 5A: Load Forecast .......................................................................................................... 16
Section 5A: FY 2013 to FY 2017 Cost and Revenue Trends ........................................................ 17
Section 5B: FY 2017 Results ....................................................................................................... 18
Section 5C: FY 2018 Projections ................................................................................................. 19
Section 5D: FY 2019-FY 2028 Projections .................................................................................. 19
Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 20
Section 5F: Long-Term Outlook ................................................................................................. 22
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Section 6: Details and Assumptions ..................................................................................... 23
Section 6A: Gas Purchase Costs ................................................................................................. 23
Section 6B: Operations .............................................................................................................. 24
Section 6C: Capital Improvement Program (CIP) ....................................................................... 25
Section 6D: Debt Service ............................................................................................................ 27
Section 6E: Equity Transfer ........................................................................................................ 28
Section 6F: Revenues ................................................................................................................. 28
Section 6G: Communications Plan ............................................................................................. 29
Appendices ......................................................................................................................... 31
Appendix A: Gas Financial Forecast Detail ................................................................................ 32
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 33
Appendix C: Gas Utility Reserves Management Practices ......................................................... 35
Appendix D: Description of Gas Utility Cost Categories ............................................................ 39
Appendix E: Gas Utility Communications Samples .................................................................... 40
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SECTION 1: DEFINITIONS AND ABBREVIATIONS
ABS: Acrylonitirile butydene styrene, a plastic gas main material
AMI: Advanced Metering Infrastructure
CARB: California Air Resources Board
CIP: Capital Improvement Program
CNG: Compressed Natural Gas
CPAU: City of Palo Alto Utilities Department
CPUC: California Public Utilities Commission
Cross-bore: A cross-bore exists when one utility line has been drilled or “bored” through a portion
of another line. Gas cross-bores can occur in sewer lines as a result of “horizontal boring”
construction practices.
Distribution: transportation of gas to customers.
GMR Program: Gas Main Replacement Program
Local Transportation: transportation of gas to Palo Alto across PG&E’s distribution system from
PG&E City Gate.
Malin: a delivery hub referred to in gas purchase contracts and located in Malin, Oregon, where
the northern end of PG&E’s Redwood Transmission Pipeline is located.
MMBtu: Millions of British thermal units, a unit of gas measurement equal to ten therms.
Commonly used for high volume gas measurement. Wholesale purchases of gas from suppliers
are typically measured in MMBtu.
O&M: Operations and Maintenance
PE or HDPE: Polyethylene, a gas main material (more specifically, High-Density Polyethylene)
PG&E: Pacific Gas and Electric
PG&E Citygate, or Citygate: a delivery hub referred to in gas purchase contracts. Any gas delivered
to PG&E’s distribution system (such as gas delivered at the southern end of PG&E’s Redwood
Transmission Pipeline) is said to have been delivered at PG&E Citygate.
PVC: Polyvinyl chloride, a plastic gas main material
Summer: April 1 to October 31
Therms: The standard unit of measurement for natural gas sales to customers, equal to 100,000
British thermal units. Therms measure the heating value of the gas, rather than its volume.
Transmission: transportation of gas between major gas delivery hubs via a gas transmission
pipeline, such as PG&E’s Redwood pipeline.
UAC: Utilities Advisory Commission, an appointed body that advises the City Council on CPAU
issues.
Winter: November 1 to March 31
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SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Gas Utility for the next ten years. This
Financial Plan provides revenues to cover the costs of operating the utility safely over that time
while adequately investing for the future. It also addresses the financial risks facing the utility
over the short term and long term, and includes measures to mitigate and manage those risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
This financial plan projects non-commodity costs to increase from FY 2019 through FY 2028 at
about 3.5% per year on average. In the short term, some of these cost increases are related to
the cross-bore inspection program, but capital improvement program (CIP) costs have also
increased as the economy has improved. The national and regional focus on infrastructure
improvement has created more demand, and the pool of skilled construction labor has not grown
at the same pace. While CPAU generally plans a new gas main replacement project every year,
recent larger than expected bids have required resizing and redesign of some existing planned
projects. Because of this (as well as the complexity of the project), CIP costs for FY 2018 increased
for the University Avenue Business District project, which is scheduled to begin construction in
mid-2018. Due to the amount of planning required for this project, no new CIP work was
budgeted for FY 2017, and because of the complexity of the University Avenue project, no CIP
work is budgeted for FY 2019, resulting in one-time cost savings. The next new main replacement
project after the University Avenue project will take place in FY 2020. Table 1 shows the Gas
Utility expenses over the period of this financial plan.
Table 1: Gas Utility Expenses for FY 2017 to FY 2028 (Thousand $’s)
Expenses
($000)
FY
2017
(act.)
FY
2018
(est.)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Commodity costs 12,563 14,137 13,022 12,851 13,040 13,233 13,499 13,855 14,188 14,576 14,731 14,932
Operations 21,050 20,302 20,509 21,133 20,579 21,874 22,508 23,270 24,048 24,879 24,303 24,649
Capital Projects 2,214 7,804 5,197 10,217 12,080 9,815 9,892 9,970 10,050 10,131 10,214 10,299
TOTAL 35,827 42,243 38,728 44,202 45,698 44,922 45,898 47,095 48,286 49,587 49,248 49,880
To ensure that revenues cover projected rising costs, the financial plan includes the rate
trajectory shown in Table 2.
Table 2: Projected Gas Rate Trajectory for FY 2019 to FY 2028
Projection FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Current Financial Plan 4% 8% 7% 7% 4% 4% 1% 1% 0% 2%
FY 2018 Financial Plan 4% 6% 6% 5% 3% 3% 2% 1% 0% N/A
FY 2017 Financial Plan 7% 4% 1% 1% 1% 1% 1% 1% N/A N/A
The Gas Utility has a Rate Stabilization Reserve, which can be used to smooth rate increases over
several years. This Financial Plan projects that these reserves will be exhausted by the end of FY
2020. The Gas Utility also has a CIP Reserve to help offset one-time and/or unanticipated, spikes
GAS UTILITY FINANCIAL PLAN
M a r c h 2018 6 | P a g e
in CIP spending which do not merit separate bond financing. Table 3 shows the projected reserve
transfers over the forecast period.
Table 3: Transfers To/(From) Reserves for FY 2018 to FY 2028 ($000)
Reserve FY 2018 FY 2019 FY 2020 to FY 2028
Rate Stabilization (129) (2,006) (4,404)
CIP - - (3,820)
Operations 129 2,006 8,224
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Gas Utility in FY 2018:
1. Amend the proposal of a $1.2 million transfer from the Rate Stabilization Reserve to the
Operations Reserve, as proposed in the FY 2018 Gas Financial Plan, to a transfer of
$129,000, based on projected ending Operations Reserve levels.
Staff proposes the following actions for the Gas Utility in FY 2019:
2. Increase distribution rates by 6% (a 4% overall increase) for FY 2019, primarily reflecting
increases to capital expenditures and also increased operations costs. See Section 3B:
Current and Proposed Rates for more details.
3. Transfer $2 million from the Rate Stabilization Reserve to the Operations Reserve. See
Section 3D: Proposed Reserve Transfers for more details.
SECTION 3: DETAIL OF FY 2018 RATE AND RESERVE PROPOSALS
SECTION 3A: RATE DESIGN
The Gas Utility’s rates are evaluated and implemented in compliance with cost of service
requirements. The Gas Utility’s current rates are based on the methodology from the April 2012
Gas Utility Cost of Service Study completed by Utility Financial Solutions.1 In preparation for an
update to the study, staff discussed a proposed scope with the Utilities Advisory Commission in
October 2016, and the Council in November 2016 2. The updated study is projected to be
completed by late FY 2018 or the early part of FY 2019, and will provide guidance for the next
proposed rate action.
SECTION 3B: CURRENT AND PROPOSED RATES
On July 1, 2012 CPAU restructured its rates so that the commodity component varied monthly to
match changes in gas market prices.3 In addition, CPAU increased monthly service charges to
recover the cost of providing gas service to customers. In January 2015, the Council adopted a
1 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
2 Staff Report 7416 11/14/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54576
3 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
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new rate component to collect the costs of purchasing allowances for the purpose of compliance
with the State’s cap-and-trade program.4 This component changes depending on the cost of
allowances and gas demand. In October 2016, the Council adopted a resolution changing the
Local Transportation rate (which had been collapsed into the Distribution rate in 2015 to
streamline bill presentation), to be a pass-through of PG&E’s Gas Transportation Rate to
Wholesale/Resale Customers (G-WSL) charge to Palo Alto.5 This went into effect November 1,
2016. In December 2016, Council approved a carbon neutral gas plan, with a goal of achieving a
carbon neutral gas portfolio by FY 2018.6 The plan is for costs associated with the plan to be a
passed through directly to customers as well, although the rate impact is not to exceed $0.10 per
therm. Three years’ worth of volumetric rate history can be found on Palo Alto’s website.7
CPAU has four rate schedules: one for separately metered residential customers (G-1), one for
small commercial and master-metered multi-family residential customers (G-2), one for
customers using over 250,000 therms per year (G-3) and a specific schedule for the Compressed
Natural Gas station (G-10). All customers pay a monthly service charge, which represents meter
reading, billing, and other customer service costs, as well as a portion of operations and
maintenance cost. All customers are also charged for each therm of gas used. Separately metered
residential customers are charged on a tiered basis, differentiated by season. During the winter
months, the first 2 therms per day (60 therms for a 30 day billing period) are charged a base price
per CCF, and all additional units charged a higher price per therm. During the summer months,
the first tier level is 0.667 therms per day, or 20 therms for a 30 day billing period. Commercial
customers pay a uniform price for each therm used.
Table 4 shows the current monthly service charges for all rate schedules. Table 95 shows the
consumption charges related to distribution charges. As mentioned earlier, commodity charges
change monthly, and transportation charges are tied to the PG&E G-WSL rate schedule. Some
recent commodity price history is discussed in Section 6A: Gas Purchase Costs.
4 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537
5 Staff Report 7260 10/17/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54165
6 Staff Report 7533 12/05/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54882
7 Monthly Gas Commodity & Volumetric Rates http://www.cityofpaloalto.org/civicax/filebank/documents/30399
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Table 4: Current and Proposed Monthly Service Charges
Rate Schedule
Monthly Service Charge
($/month)
Change
Current (as of
7/1/16)
Proposed for
FY 2019
($) (%)
G-1 (Residential) $10.32 $10.94 $0.62 6%
G-2 (Small Commercial) 78.23 82.94 4.69 6%
G-3 (Large Commercial) 377.43 400.08 22.65 6%
G-10 (CNG) 52.93 56.11 3.18 6%
Table 5: Current and Proposed Gas Distribution Charges
Change
Current (as of
11/1/16)
Proposed
for FY 2019
($) (%)
G-1 (Residential)
Tier 1 Rates $0.3933 $0.4239 $0.0306 7.8%
Tier 2 Rates 0.9319 0.9948 0.0629 6.7%
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.5767 0.6183 0.0416 7.2%
G-3 (Large Commercial)
Uniform Rate 0.5687 0.6098 0.0411 7.2%
G-10 (Compressed Natural Gas)
Uniform Rate 0.0093 0.0100 0.0007 7.2%
SECTION 3C: BILL IMPACT OF PROPOSED RATE CHANGES
Table 6 shows the impact of the proposed July 1, 2018 rate changes on the median residential
bill. The average increase is roughly 4% based on prices in February 2018, but some customers
may see slightly higher or lower increases due to slight changes in the composition of the utility’s
costs, as well as prevailing market prices.
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Table 6: Impact of Proposed Gas Rate Changes on Residential Bills
Usage
(Therms/month)
Bill under
Current Rates
Bill under
Proposed Rates
Change
$/mo. %
Winter (Using February 2018 commodity prices)
30 $36.93 $ 38.47 $ 1.54 4%
54 (median) 58.21 60.49 2.28 4%
80 94.20 98.04 3.84 4%
150 193.98 202.23 8.25 4%
Summer (Using July 2017 commodity prices)
10 18.73 $ 19.90 $ 1.17 6%
18 (median) 25.45 27.08 1.63 6%
30 40.57 43.16 2.59 6%
45 61.26 65.17 3.91 6%
Table 7 shows the impact of the proposed July 1, 2018 rate changes on various representative
commercial customer bills.
Table 7: Impact of Proposed Gas Rate Changes on Commercial Bills
(Using February 2018 commodity prices)
Usage
(Therms/month)
Bill under Current
Rates
Bill under
Proposed Rates
Change
%
500 613 639 4%
5,000 5,430 5,642 4%
10,000 10,781 11,202 4%
50,000 53,493 55,571 4%
SECTION 3D: PROPOSED RESERVE TRANSFERS
The FY 2018 Financial Plan proposed a $1.2 million transfer from the Rate Stabilization Reserve
into the Operations Reserve in FY 2018. Lower actual expenses in FY 2017 resulted in higher
ending reserve balances than initially projected, so staff recommends revising the transfer down
to $129,000 at this time. A tentative transfer of $2 million in FY 2019, followed by $4.4 million in
FY 2020, is included in the financial projections in this Financial Plan. In addition, $3.8 million in
the CIP Reserve may need to be utilized in FY 2021. This will help mitigate additional, one-time
costs related to the replacement of gas meters for AMI deployment. The transfers in general will
enable CPAU to maintain adequate Operations Reserve levels while moderating the pace of
increase in gas rates. The impact of these transfers on reserves levels can be seen in Appendix A:
Gas Utility Financial Forecast Detail.
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SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information and to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4A: GAS UTILITY HISTORY
On September 22, 1917, the City of Palo Alto issued a bond to purchase the property of Palo Alto
Gas Company and continue it as a municipal enterprise. At the time, the system was comprised
of 21 miles of mains, 1,900 meters, and was valued at $65,500. PG&E supplied the gas, which
was synthesized from coal at its Potrero gasification facility. Almost immediately the City faced
challenges. Losses were at nearly 25% according to PG&E’s master meter, and PG&E had filed
with the Railroad Commission (the forerunner to today’s CPUC) to increase rates by nearly 72.5%.
Despite these initial hurdles, Palo Alto’s system grew tremendously, and by 1924 revenues had
exceeded those of the electric utility. Sales were such that the annual reports of the time noted
gas usage “appears to be greater than that of any other city in the state, showing that gas is a
very popular form of fuel in Palo Alto.” Just prior to the acquisition of the neighboring town of
Mayfield’s gas system (centered around today’s California Avenue) in 1929, the miles of main in
service and customers connections had doubled.
Notable changes to the gas supply itself came in 1930, when PG&E ceased supplying purely
manufactured (or coal) gas from its Potrero Hill facility in San Francisco and instead switched to
natural gas. In 1935, a supplementary butane injection system (later retired) was purchased from
Standard Oil to mitigate large wintertime peaks. Gas sales were at 248,658 million cubic feet
(MCF) with 4,849 active services.
Early gas mains in Palo Alto were made of steel, but in the 1950s, like many other utilities, CPAU
switched to ABS plastic. CPAU switched to PVC plastic in the early 1970s, but around 100 miles
of ABS mains had already been installed. A 1990 evaluation of the system found a steadily
increasing rate of gas leaks associated with those mains, something that other gas utilities had
also been experiencing. To reduce leaks, CPAU accelerated its main replacement program from
7,000 feet (1.3 miles) of replacements per year to 20,000 feet (3.8 miles) per year. This would
enable the utility to replace all of its ABS and its most vulnerable steel and PVC mains with
polyethylene (PE) mains over the course of the following 36 years.8 As of 2015 the Gas Utility
had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic
protection was not effective. Current main replacement projects will target the last ~800 feet of
remaining ABS main as well as tackling PVC replacement. A PVC risk analysis to determine the
appropriate footage of annual PVC replacement for future CIP projects is currently being
conducted. This is an example of how local control of its Gas Utility has provided Palo Alto
residents with substantial benefits. During the 1990s and 2000s, while CPAU was increasing its
8 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990
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main replacement rate to ensure a robust gas distribution system, PG&E was underspending on
safety-related infrastructure, according to a past audit.9
In the 1990s, while grappling with the issues surrounding its distribution system, CPAU was also
participating in major changes to the structure of the gas industry in California. Until 1988 CPAU
had a formal policy of setting its rates equal to PG&E’s rates and successfully did so with the
exception of one year in the mid-1970s. At times this led to inadequate revenue (1974 to 1981)
as PG&E, the City’s only gas supplier, regularly filed requests with the CPUC to increase the
wholesale gas supply rates charged to the Gas Utility. In the 1990s, as the CPUC began
deregulating the natural gas industry in California, the Gas Utility began purchasing gas from
suppliers other than PG&E. In 1997 the CPUC adopted the “Gas Accord,”10 which enabled the Gas
Utility (along with other local transportation-only customers) to obtain transmission rights on
PG&E’s Redwood transmission pipeline running from Malin, Oregon into California.
In 2000/2001 the California energy crisis occurred, causing major disruptions to the Gas Utility’s
supply costs. Wholesale gas prices rose over 500% between January 2000 and January 2001. The
Council approved drawing down reserves to provide ratepayer relief and, for two years following
the crisis, CPAU rates were above PG&E’s as reserves were replenished. In April 2001 the Council
approved a hedging practice of buying fixed price gas one to three years into the future. After
reaching a low point in October 2001, prices continued to rise, and as a result the CPAU hedging
strategy frequently resulted in a wholesale supply cost advantage compared to PG&E until prices
began to decline steeply in mid-2008. At that point the Gas Utility’s wholesale supply costs
became higher than market gas prices due to fixed price contracts entered into prior to 2008. As
a result the Gas Utility’s wholesale supply costs were higher than PG&E’s for several years. In
2012 Council approved a plan to formally cease the hedging strategy and purchase all gas on the
short-term (“spot”) markets. As of July 1, 2012, the commodity portion of the gas rates changes
every month based on the spot market gas price.
SECTION 4B: CUSTOMER BASE
CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas
customers in Palo Alto. Close to 23,600 customers are connected to the natural gas system,
approximately 22,000 (93%) of which are residential and 1,600 (7%) of which are non-residential.
Residential customers consume about 11 to 13 million therms of gas per year, roughly 45% of the
gas sold, while non-residential customers consume 55% (about 14 to 16 million therms).
Residential customers use gas primarily for space heating (46% of gas consumed) and water
heating (42%), with the remainder consumed for other purposes such as cooking, clothes drying,
9 Focused Financial Audit of The Pacific Gas & Electric Company’s Gas Distribution Operations, Overland Consulting,
made available through a CPUC Administrative Law Judge’s ruling on A12-11-009/I13-03-007 on 5/31/2013
10 CPUC decision 97-08-055. Since then, the Gas Accord has been amended four times, with the most recent being
Gas Accord V, application A.09-09-013
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and heating pools and spas.11 Non-residential customers use gas for space and water heating
(73% of gas consumed), cooking (20%), and industrial processes (6%).12
The Gas Utility receives gas at the four receiving stations within Palo Alto where CPAU’s
distribution system connects with Pacific Gas and Electric’s (PG&E’s) system. These receiving
stations are jointly operated by CPAU and PG&E. CPAU purchases gas from various natural gas
marketers, with PG&E providing only local transportation service (transportation from the PG&E
City Gate gas delivery hub to Palo Alto). CPAU also has transmission rights on PG&E’s transmission
pipeline from Malin, Oregon to PG&E City Gate, allowing it to purchase lower priced gas at that
location. CPAU does not produce or store any natural gas, and purchases gas in the monthly and
daily spot markets. The cost of the purchased gas is passed through directly to customers through
a rate adjuster that varies monthly with market prices. In a similar fashion, the cost for local
transportation is now tied to PG&E’s G-WSL rate schedule, and varies when and if PG&E changes
its rate schedule. The cost of purchased gas and PG&E local transportation service usually
account for roughly one third of the utility’s expenditures.
SECTION 4C: DISTRIBUTION SYSTEM
To deliver gas from the receiving stations to its customers, the utility owns 210 miles of gas mains
(which transport the gas to various parts of the city) and close to 23,600 gas services (which
connect the gas mains to the customers’ gas lines). These mains and services, along with their
associated valves, regulators, and meters, represent the vast majority of the infrastructure used
to deliver gas in Palo Alto. CPAU has an ongoing CIP to repair and replace its infrastructure over
time, the expense of which normally accounts for around 15 to 20% of the utility’s expenditures.
Costs for main replacements have been going up in recent years.
In addition to the CIP, the Gas Utility performs a variety of maintenance activities related to the
system, such as monitoring the system for leaks, testing and replacing meters, monitoring the
condition of steel pipe, and building and replacing gas services for buildings being built or
redeveloped throughout the city. The utility also shares the costs of other system-wide
operational activities (such as customer service, billing, meter reading, supply planning, energy
efficiency, equipment maintenance, and street restoration) with the City’s other utilities. These
maintenance and operations expenses, as well as associated administration, debt service, rent,
and other costs, make up roughly half of the utility’s expenses. In addition to these ongoing
activities, CPAU has conducted a program to find and replace cross-bores over the last several
years. Currently, $1 million is budgeted per year for the cross-bore program through FY 2021.
However, the ongoing cross-bore investigation may require additional funding, or extend for
longer into the future, as the remaining sewer lines are more difficult to examine than the
majority of the wastewater collection system that has been examined to date.
11 http://energyalmanac.ca.gov/naturalgas/overview.html
12 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Statistics shown are for
end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located.
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SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 1, the Gas
Utility receives 95% of its revenue
from sales of gas and the
remainder from capacity and
connection fees, interest on
reserves, and other sources.
Appendix A: Gas Utility Financial
Forecast Detail shows more detail
on the utility’s cost and revenue
structures.
As shown in Figure 2, in FY 2017,
gas purchase costs accounted for
roughly 31% of the Gas Utility’s
costs. This percentage can vary
widely from year to year, as this
cost is based upon market
purchases, and now also includes
costs related to cap and trade.
Operational costs in FY 2017
represented roughly 51%, of
expenses and capital investment
was responsible for the remaining
18%. CIP is normally about 20% of
expenses, but this may be lower in
times when new budgeting for
projects is deferred, as happened in FY 2017.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains six reserves for its Gas Utility to manage various types of contingencies. The
summary below describes each of these briefly. See Appendix C: Gas Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
Reserve for Commitments: A reserve equal to the utility’s outstanding contract liabilities
for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
Reserve for Reappropriations: A reserve for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including the
General Fund, have a Reappropriations Reserve.
Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to accumulate
funds for future expenditure on CIP projects and is anticipated to be empty unless a major
one-time CIP expenditure is expected in future years. This CIP can also act as a
Figure 2: Cost Structure (FY 2017)
51%
31%
18%
Operations
Gas Purchases
Capital
Figure 1: Revenue Structure (FY 2017)
95%
5%
Sales of Gas
Other Revenue
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contingency reserve for the CIP. This type of reserve is used in other utility funds (Electric,
Water, and Wastewater Collection) as well.
Rate Stabilization Reserve: This reserve is intended to be empty unless one or more large
rate increases are anticipated in the forecast period. In that case, funds can be
accumulated to spread the impact of those future rate increases across multiple years.
This type of reserve is used in other utility funds (Electric, Water, and Wastewater
Collection) as well.
Operations Reserve: This is the primary contingency reserve for the Gas Utility, and is
used to manage yearly variances from budget for operational gas costs. This type of
reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as well.
Unassigned Reserve: This reserve is for any funds not assigned to the other reserves and
is normally empty.
SECTION 4F: COMPETITIVENESS
Table 8 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of July 2017 (to illustrate a summer month bill) and
February 2018 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2017 was $469.05, about 14% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 8: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(February 2018)
30 36.93 42.39 -12.9%
(Median) 54 58.21 76.31 -23.7%
80 94.20 126.58 -25.6%
150 193.98 264.07 -26.5%
Summer
(July 2017)
10 18.73 13.01 44.0%
(Median) 18 25.45 23.41 8.7%
30 40.57 45.24 -10.3%
45 61.26 72.72 -15.8%
Table 9 shows the monthly gas bills for commercial customers for various usage levels for rates in
effect as of February 2018. Bills for CPAU customers at the usage levels shown are around 2% to
27% higher for commercial customers than for PG&E customers. This is a substantial
improvement over the calendar year 2013 bill comparison, when commercial gas bills for CPAU
customers were 27% to 44% higher than for PG&E customers. This is primarily attributable to
PG&E’s higher distribution rates as the commodity rates for CPAU and PG&E are very similar, both
being based on spot market gas prices.
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Table 9: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect February 2018)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 613 600 2%
5,000 5,430 5,242 4%
10,000 10,781 9,211 17%
50,000 53,493 42,036 27%
SECTION 4G: GAS SUPPLY RATES
Starting in July 2012, CPAU replaced a “laddering” hedging strategy for purchasing gas supplies
with a strategy to buy gas on the short-term, or “spot” markets and pass the commodity cost to
customers on a monthly basis. Figure 3 shows the actual commodity prices charged. Commodity
prices have fluctuated by around $0.20 over the last two years, but have generally been lower
than prices seen in 2013 and 2014.
Figure 3: Gas Commodity Rates from July 2012 through February 2018
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SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Gas usage in Palo Alto is volatile, varying with both economic and weather conditions. As shown
in Figure 4, in the early 1970’s, gas purchases reached over 45 million therms per year. Usage
dropped dramatically in the 1976/1977 drought when customers saved significant amounts of
(hot) water by upgrading to efficient showerheads. During the 1980s and 90s average gas usage
was around 36 million therms per year. Usage dropped again in the early 2000’s. In FY 2001, gas
prices escalated during the California energy crisis and Palo Alto’s rates increased by nearly 200%.
From 2003 to 2011, usage decreased by 2.3% mainly as a result of continued customer
investments in energy efficiency.
In 2014 and 2015, unusually warm winters, as well as ongoing drought, caused gas usage to
tumble to historic lows. In FY 2017 and FY 2018, as the drought has eased, gas usage has started
to increase again.
Figure 4: Historic Gas Consumption
Gas consumption, as denoted by the dotted line in Figure 5, is projected to recover somewhat
and resume the long run trend of decreasing usage over the forecast period, although changes
such as replacement of gas appliances with electric appliances or customer behavior may result
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in lower long run usage. As with prior drought/gas usage declines in the past, it is likely that
consumption will not come back to pre-conservation levels. It is too early to tell, however, where
the new ‘normal’ level of consumption will be.
Figure 5: Forecast Gas Consumption
SECTION 5A: FY 2013 TO FY 2017 COST AND REVENUE TRENDS
Figure 6 and Appendix A: Gas Utility Financial Forecast Detail show how costs have changed
during the last five years as well as how staff project costs to change over the next decade.
The annual expenses for the gas utility decreased substantially between 2013 and 2017. Lower
gas sales in conjunction with the drought, as well as lower gas market prices in FY 2015 and FY
2016 (as shown in Figure 3 above) resulted in lower overall commodity expenses. FY 2014, FY
2015 and FY 2017 were notable due to the fact that no new funding was added for main
replacement projects. In FY 2014 and FY 2015, this was due to the fact that staff was completing
a prior major gas main replacement project, the largest in utility history, which completed
replacement of ABS gas mains in Palo Alto. The FY 2016 project included replacements of gas
mains on University Avenue, a project that has evolved into the Upgrade Downtown project
involving a coordinated replacement of several different types of infrastructure to avoid multiple
disruptions to the business district. This has been a multi-year planning effort that did not allow
for design of other new projects. This allowed the Gas Utility to temporarily keep rates lower
than they will need to be to fund future operations and capital replacement.
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Revenues have generally matched expenses in most years and were higher than expenses in FY
2017. As shown in Figure 6 below, revenues were below cost in FY 2013 and nearly at cost in FY
2016. The absence of new budget funding for main replacement projects for several years, as
well as the availability of relatively large reserves, forestalled the need for rate increases until
now.
As shown in Figure 6, the last adjustment to gas distribution rates was in July 2016 when CPAU
increased rates by 8%. In FY 2012, commodity rates were changed to a market-based, monthly
pass-through cost—and commodity rates (and usage) fell, so revenues (and gas supply costs)
actually declined in FY 2013 after the rate increase. Figure 6 assumes no change in gas supply
costs over the forecast period to illustrate the impact of proposed distribution rate changes on
the overall customer bill. In reality, gas supply costs are uncertain and are passed through to
customers as they change month to month.
Figure 6: Gas Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2017 and Projections through FY 2028
SECTION 5B: FY 2017 RESULTS
Sources of funds for FY 2017 were lower than projections by $885,000, but operational expenses
came in well below the expected budget. Total FY 2017 expenses were $32.7 million compared
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to projections of $36.9 million in the FY 2018 Financial Plan. Table 10 summarizes the variances
from forecast.
Table 10: FY 2017, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Purchase costs lower than forecast (479) Cost savings
Operations cost savings (3,774) Cost savings
Decreased interest income and other
non-sales revenues 1,753
Revenue decrease
Increased sales revenues (867) Revenue increase
Net Cost / (Benefit) of Variances (3,368)
SECTION 5C: FY 2018 PROJECTIONS
Current projections indicate that sales revenues will be slightly higher than last year’s forecast,
but other revenues have been revised downwards based on prior year actuals. While gas
purchase costs are not projected to increase appreciably during the forecast period, the current
financial plan anticipates CIP costs will be substantially higher in FY 2018 than projected in the
prior financial plan. Table 11 summarizes the current and projected variances from the FY 2018
Financial Plan.
Table 11: FY 2018 Projected Results vs. Current Financial Plan Forecast ($000)
Net Cost/ (Benefit) Type of change
Sales revenues higher than forecast (160) Revenue increase
Other revenues and interest lower than forecast 1,272 Revenue decrease
Purchase cost decrease (2,108) Cost decrease
Operations & maintenance and customer service
cost decreases
(1,477) Cost decrease
Capital Improvement Cost increases 5,730 Cost increase
Net Cost / (Benefit) of Variances 3,259
SECTION 5D: FY 2019-FY 2028 PROJECTIONS
Figure 6 above shows that staff projects costs for the Gas Utility to rise substantially in FY 2018,
and then to increase at around 2.9% per year on average through FY 2028. In Operations, there
is a short run addition of $1 million, starting in FY 2019, for cross-bore inspections (this expense
is projected to continue for at least three years), as well as general inflationary increases of
around 2 to 3% per year. Salaries and benefits expenses are projected to rise at 3 to 4% per year,
per the City’s Long Range Financial Plan. Construction costs continue to increase, which resulted
in increased costs in FY 2018 for the University Avenue Business District project, which is
scheduled to begin construction in mid-2018. Due to the amount of planning required for this
project, no new CIP work was budgeted for FY 2017, and because of its complexity, no CIP work
is budgeted for FY 2019, resulting in one-time cost savings. The next new main replacement
project after the University Avenue project will take place in FY 2020, and ongoing main
replacement is expected to be more expensive. In addition to these trends, additional costs
related to AMI deployment are projected in FY 2020 and 2021. Gas commodity costs are the most
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variable component but are currently projected to increase by less than 2% annually. Since this
is a pass-through cost to customers, the risk of these costs being higher or lower than expected
has a minimal impact on reserves.
As shown in Figure 7, this financial plan projects the Rate Stabilization Reserves to be depleted
by FY 2020.
Figure 7: Gas Utility Reserves
Actual Reserve Levels for FY 2017 and Projections through FY 2028
SECTION 5E: RISK ASSESSMENT AND RESERVES ADEQUACY
This financial plan projects the Gas Utility’s primary contingency reserve, the Operations Reserve,
to be within guideline levels throughout the forecast period, barring either short-run budget
savings and/or larger future increases. Figure 8 shows the Operations Reserve within the
guideline levels.
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Figure 8: Operations Reserve Adequacy
Forecasted Operations Reserve levels also exceed the short-term risk assessment for the Utility.
Table 12 summarizes the risk assessment calculation for the Gas Utility through FY 2023. The
same methodology is used for FY 2024 through FY 2028 as well. The risk assessment includes the
revenue shortfall that could accrue due to:
1. Lower than forecasted distribution sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 12: Gas Risk Assessment ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Total non-commodity revenue $21,457 $23,226 $25,843 $28,443 $29,930
Max. revenue variance, previous ten years 16% 16% 16% 16% 16%
Risk of revenue loss $3,441 $3,725 $4,144 $4,561 $4,799
CIP Budget $3,894 $8,875 $10,697 $8,391 $8,425
CIP Contingency @10% $389 $888 $1,070 $839 $842
Total Risk Assessment value $3,830 $4,612 $5,214 $5,400 $5,642
Finally, the City created the CIP Reserve at the end of FY 2015 to act as a contingency reserve for
capital improvement projects. Current guidelines state that the balance of this reserve should fall
between 12 and 24 months of budgeted CIP expense, but staff will continue to review this reserve
and the appropriateness of the current minimum and maximum guideline levels.
At the end of FY 2017, the sum of the CIP Reserve and existing Commitments was $8 million, as
shown in Figure 7.
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SECTION 5F: LONG-TERM OUTLOOK
In the longer term (5 to 35 years out) it is very difficult to predict the Gas Utility’s commodity
costs. A variety of long-term trends could affect commodity costs either positively or negatively.
Continuing improvement in gas extraction technology, such as fracking, could continue to create
generous supplies of gas, but these technologies are also under greater scrutiny with respect to
their environmental impacts. On the demand side, a continued shift from coal to natural gas for
electricity generation, an expansion of export capabilities, or an increase in manufacturing in the
U.S. might drive up natural gas prices, but other factors, such as generally more mild winters,
might drive gas demand lower. It is also difficult to predict the magnitude of the additional cost
impacts associated with the State’s cap-and-trade program over the long term. In the face of this
uncertainty, CPAU is able to protect the financial position of the Gas Utility by continuing its
current strategy of passing these costs directly to its customers via month-varying rate
adjustment mechanisms. The City pursues a policy of purchasing offsets to make gas usage in
Palo Alto carbon neutral. The cost is not to exceed $0.10/therm.
Future CIP investment needs for the Gas Utility may be lower than in the past, although costs per
foot for main replacement have been increasing substantially. The Gas Utility has replaced nearly
all of its ABS gas mains and its most problematic steel and PVC mains as well. The PE pipe being
used now is expected to have at least a fifty-year lifetime, and there is growing evidence that it
may last much longer than that. This would result in lower CIP investment over the long term.
CPAU is considering performing a study in the near future to develop its future main
replacements priorities and strategy.
Long-term state or local climate goals could also have a major impact on the Gas Utility. The
Global Warming Solutions Act, Assembly Bill 32 (AB32), set a goal of reducing greenhouse gas
(GHG) emissions to 1990 levels by 2020. In its December 2007 Climate Protection Plan, the City
set a goal of lowering emissions to 15% below 2005 levels by 2020. As a community Palo Alto
achieved these goals in 2012 even with continued use of natural gas for heating, cooking, and
industrial processes. However, to achieve the recently adopted Sustainability and Climate Action
Plan (S/CAP) goal of an 80% reduction in carbon emissions by 2030, or the State’s adopted goal
of an 80% reduction in emissions by 2050, extensive electrification of gas-using appliances is
necessary. If significant amounts of electrification occurred, stranded investment and higher
rates could be required as the costs of the distribution system are recovered over a lower sales
base. It is instructional that, in the recent discussion draft of its scoping plan update, CARB says,
to meet those goals, natural gas use would have to be “mostly phased out.”13 Staff intends to
begin evaluating how to manage potential impacts of these trends over the next few years.
13 Climate Change Scoping Plan, First Update, Discussion Draft for Public Review and Comment, California Air
Resources Board, October 2013, pg 88.
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SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: GAS PURCHASE COSTS
The Gas Utility purchases much of its gas for delivery at Malin, Oregon which is almost always
cheaper than delivery at PG&E Citygate, even including the costs of transmission from Malin to
Citygate. The Gas Utility purchases gas on a month-ahead and day-ahead basis in the spot market.
The last few years have seen gas prices in a relatively narrow but low band. High levels of natural
gas in storage, along with warmer than normal weather on the West coast has kept prices low,
as shown in Figure 9.
Figure 9: Gas Market Prices at PG&E Citygate
Gas commodity costs are expected to increase slowly but steadily over the next several years.
Figure 10 shows the projected gas prices used to generate this forecast. Projections for
transmission costs associated with transporting gas over PG&E’s Redwood transmission pipeline
(from Malin, Oregon to the PG&E Citygate) are based on rates adopted in the most recent update
to the Gas Accord.
Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary
adder to PG&E’s local transportation rate,14 but in December 2014 PG&E applied to the CPUC to
14 California Public Utilities Commission Advice Letter 3430-G, effective January 1, 2014. Also see CPUC Decision
12-12-30 regarding the Pipeline Safety Enhancement Plan Adder.
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more than double local transportation costs. The application was not settled until late 2016. As
these charges are dictated by PG&E and are outside of Palo Alto’s control, staff proposed making
these costs pass-through charge, similar to the commodity charge, and this became effective in
November 2016.
Figure 10: Wholesale Gas Price Projections
SECTION 6B: OPERATIONS
Operations costs include the Customer Service, Demand Side Management, Operations and
Maintenance (including Engineering), Resource Management, and Administration categories in
Figure 11, below. Debt service, rent, and transfers are also included in Operations costs
(excluding the General Fund equity transfer). Appendix D: Description of Gas Utility Cost
Categories includes detailed descriptions of the activities associated with these cost categories.
Operations costs are projected to increase by 2 to 4% per year. Salary and benefits, inflation, and
other assumptions match those used in the City’s long-range financial forecast.
Operations costs for FY 2019 to FY 2021 include funding for the cross-bore program. In the 1970s
CPAU, like many other utilities, adopted horizontal drilling as an alternative to trenching when
installing new gas services. This created the possibility of cross-bores, which can happen when a
gas service is bored through a sewer lateral. Though cross-bores are very rare, they can create a
dangerous situation when a contractor attempts to clear a blocked sewer line, because if the
cross-bored gas service is damaged during the line, clearing it can result in a gas leak. CPAU has
been inspecting new gas services since 2001, and in 2011 began video inspections of the sewer
laterals at the location of horizontally-drilled gas services installed before 2001. This inspection
program has cost roughly $1 million per year since FY 2012. While a majority of sewer laterals
have been inspected, staff has come across several services which are not able to be scoped,
either due to infiltration by roots or broken/collapsed pipe segments. Staff has included $3
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million in additional funding between FY 2019 and FY 2021 for this program, but the program will
likely require additional funding in future years to complete.
Figure 11: Historical and Projected Operational Costs
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
The Gas Utility’s CIP program consists of the following programs and budgets:
The Gas Main Replacement Program, under which the Gas Utility replaces aging gas
mains ranked to have the highest threat scores within the system.
Customer Connections, which covers the cost when the Gas Utility installs new services
or upgrades existing services at a customer’s request in response to development or
redevelopment. The Gas Utility charges a fee to these customers to cover the cost of
these projects.
Ongoing Projects, which covers the cost of routine meter, regulator, and service
replacement, minor projects to improve reliability or increase capacity, and other general
improvements.
Tools and Equipment, which covers the cost of capitalized equipment, such as directional
boring, gas pipeline maintenance and emergency equipment.
One-time Projects, which represents occasional large projects that do not fall into any
other category.
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Table 13 shows the current status of these project categories and future projected spending.
Table 13: Budgeted Gas CIP Spending ($000)
The Gas Main Replacement (GMR) Program is in the final stages of completing a major milestone
with the replacement of gas mains made from Acrylonitrile-Butadiene-Styrene (ABS) plastic. The
program to replace ABS and other low-performing materials within the gas system started in the
1990s (see Section 4A: Gas Utility History for more detail). CPAU temporarily slowed down its FY
2014 and 2015 CIP appropriations in this category in order to finalize the last major ABS main
replacement project and to catch up on projects that had accumulated due to staffing issues.
With the replacement of all ABS mains with Polyethylene (PE) plastic near completion, the
material most at risk for failure is the remaining Polyvinyl chloride (PVC) plastic and steel
(wrapped, with cathodic protection). The next focus of the GMR program will be the replacement
of all PVC mains with PE mains. CPAU is considering updating the Gas System Master Plan to
determine which sections of pipeline to prioritize and assist in determining the pace of main
replacement (approximately three miles of main each year, or 1.5% of the system).
The current budget for the gas main replacement program takes into account the recent rise in
construction costs. Several factors are contributing to the increase in construction costs and
include economic recovery in the Bay Area, a greater focus on infrastructure improvement by
many municipal agencies, and the higher demand for utility contractors within these fields. CPAU
has seen the replacement cost per linear foot increase by 25% to 50% over the last couple of
years. The Gas Utility posted the most recent project for competitive bid (the Upgrade Downtown
Project) and this resulted in very few contractor bids and an eventual contract price that was
much higher than estimated (staff has requested $6.7 million additional funding in FY 2018
related to this project) . Staff is beginning to include the higher construction cost in future project
estimates in order to maximize the amount of pipe replaced, as well as insuring the overall
integrity of the gas system. Currently, CPAU plans to replace as many aging mains as possible
within its current budget. However, if this trend of higher construction cost continues, the Gas
Utility may require larger CIP budgets and as a result, an increase in rates.
Staff has also included projections for costs related to AMI deployment, primarily centered
around meter replacement costs in FY 2021.
Staff projects ongoing projects, tools and equipment, and customer connections to cost
approximately $2.7 million in FY 2019 and remain relatively flat through the end of the forecast
period. In practice, these projects can fluctuate dramatically depending on prices of material,
system conditions and the pace of development and redevelopment in the city. It is worth noting
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
One Time Projects 129 (1) 128 42 1,680 530 2,320 - -
Gas Main Replacement 10,913 (225) 10,688 311 600 7,150 7,150 7,150 7,150
Tools And Equipment 89 (5) 84 15 370 120 120 100 100
Ongoing Projects 1,455 (164) 1,291 134 1,044 1,075 1,107 1,141 1,175
Customer Connections 1,414 (418) 997 99 1,303 1,342 1,383 1,424 1,467
TOTAL 14,001 (812) 13,189 600 4,997 10,218 12,080 9,815 9,892
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
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that fee revenue pays for the Customer Connections program, so when costs go up fees will be
adjusted as well. .
Aside from customer connections and transfers from other funds, the CIP plan for FY 2019 to FY
2023 is funded by utility rates. Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
shows the details of the plan.
SECTION 6D: DEBT SERVICE
The Gas Utility currently makes debt service payments on one bond issuance, the 2011 Series A
Utility Revenue Refunding Bonds. This bond issuance was to refinance the $18 million principal
remaining on the Utility Revenue Bonds, 2002 Series A issued for the Gas and Water Utilities to
finance various improvements to the distribution systems. $9.4 million of this issuance was
secured by the net revenues of the Gas Utility. Table 14 shows debt service for this bond for the
financial forecast period. Debt service on this bond will continue through 2026.
Table 14: Gas Utility Debt Service
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
2011 Utility Revenue
Refunding Bonds, Series A
802 801 801 803 804 805 803 800 803 1
The 2011 bonds include two covenants stating that 1) the Gas Utility will maintain a debt
coverage ratio of 125% of debt service, and 2) that the City will maintain “Available Reserves”15
equal to five times the annual debt service. The current financial plan complies with these
covenants throughout the forecast period, as shown in Table 15 and
Table 16.
Table 15: Debt Service Coverage Ratio ($000)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Revenues 37,112 36,361 38,526 41,445 44,381 46,250 47,956 48,837 49,742 49,505
Expenses
(Excluding CIP and
Debt Service)
(26,079) (25,309) (25,572) (25,192) (25,765) (26,408) (27,104) (27,763) (28,489) (28,865)
Net Revenues 11,033 11,052 12,954 16,253 18,616 19,842 20,852 21,074 21,253 20,639
Debt Service 802 801 801 803 804 805 803 800 803 1
Coverage Ratio 1375% 1381% 1618% 2023% 2315% 2464% 2596% 2633% 2648% N/A
15 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities
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Table 16: Debt Service Minimum Reserves ($000)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Gas Utilitya 22,986 20,619 14,943 10,690 10,149 10,501 11,362 11,913 12,882 13,140
Debt Serviceb 802 801 801 803 804 805 803 800 803 1
Reserves Ratioc 29x 26x 19x 13x 13x 13x 14x 15x 16x N/A
a) CIP, Rate Stabilization, Operations, and Unassigned Reserves
b) Gas Utility’s share of the debt service on the 2011 bonds.
c) Calculated using only Gas Utility reserves. The actual reserves ratio for the 2011 bonds is calculated based on the
combined Electric, Gas, and Water Utility reserves and total debt service and is higher than shown here.
The Gas Utility’s reserves and net revenue are also pledged as security for the bond issuances
listed in Table 17, even though the Gas Utility is not responsible for the debt service payments.
The Gas Utility’s reserves or net revenues would only be called upon if the responsible utilities
are unable to make their debt service payments. Staff does not currently foresee this occurring.
Table 17: Other Issuances Secured by Gas Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Gas Utility’s:
Net Revenues Reserves
1995 Series A Utility
Revenue Bonds Storm Drain $680 Yes No
1999 Utility Revenue
Bonds, Series A
Wastewater Collection
Wastewater Treatment
Storm Drain
$1,207 No Yes
2009 Water Revenue
Bonds (Build America
Bonds)
Water $1,977* No Yes
*Net of Federal interest subsidy
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Gas Utility based on a methodology adopted by
Council in 2009 that has remained unchanged since.16 Each year it is calculated according to the
2009 Council-adopted methodology, and does not require additional Council action.
SECTION 6F: REVENUES
The Gas Fund receives most of its revenues from sales of gas, but about 5% comes from other
sources. The largest of these comes from service connection and capacity fees, followed closely
by sales of allowances related to California’s cap-and-trade program. Another revenue item
related to the cap-and-trade program is collected in customers’ bills. While the State provides
CPAU with a certain number of free allowances each year, the Gas Utility is required to sell a
portion of those in accordance with the regulations. In order to have enough allowances to cover
16 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed changes
to equity transfer methodology.
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customers’ natural gas emissions, CPAU must buy allowances at market, and subsequently passes
through the cost of those allowances to customers. The regulations do not allow the revenue
derived from the sale of the free allowances to offset allowance purchases, thus the pass-through
rate component.
This financial plan bases sales revenue projections on the load forecast in Section 5A: Load
Forecast. Except where stated otherwise, these load forecasts are based on normal weather.
Weather can vary substantially, however, and this can affect revenues substantially. Also,
changes in customer behavior, as well as changes to more efficient gas appliances, or switching
to electric appliances, will modify these forecasts. Staff continually evaluate forecasts to see
when new trends emerge.
SECTION 6G: COMMUNICATIONS PLAN
The FY 2019 communications strategy covers four primary areas: operations, infrastructure,
safety, efficiency, renewables and rates. Since moving to market pricing for commodity rates, the
City’s website posts changes to the commodity rates monthly. The City promotes gas use
efficiency incentives year-round, but most heavily during winter months to impact heating
activities. Promotional methods include community outreach events, print ads in local
publications, utility bill inserts, messaging on the bills and envelopes, website pages, email blasts,
videos for the web and use of social media.
To keep customers apprised of the status and accomplishments of capital improvement projects,
the City maintains a network of project web pages. Print and digital ads, social media and email
blasts drive traffic to the website. CPAU emphasizes safety topics year-round. CPAU is engaging
in several campaigns and programs in FY 2019 to promote gas utility efficiency and awareness of
the City’s carbon neutral natural gas utility. Programs such as the Home Efficiency Genie and
commercial energy efficiency programs help residents and businesses better understand energy
usage, activities and/or upgrades they can implement to improve efficiency and reduce utility
costs. CPAU will be launching an upgraded version of its online utility account services portal
(www.cityofpaloalto.org/myutilitiesaccount) this year, which can provide customers with direct
access and more information about utility account and consumption data.
Stepping up efforts to promote gas safety education, staff is focusing outreach among
stakeholders to increase awareness of the need to call USA (811) before digging for anyone who
may excavate in and around Palo Alto, such as plumbers and contractors. Staff is also focusing
outreach on the importance of contacting CPAU to check for potential sewer and gas line cross-
bores prior to clearing a sewer line. Additional outreach messaging includes keeping fats, oils and
greases out of drains, and ensuring clear access to meters. CPAU has developed a number of
safety outreach materials to distribute to customers at community outreach events, emergency
preparedness fairs, school and business meetings. The use of materials featuring photos of some
unusual ways people obstruct access to their meters, including using them as bike racks and
building storage sheds around them, highlights meter access awareness.
CPAU will continue to promote safety, infrastructure, operations, efficiency and rate adjustment
messages through a variety of marketing and media channels. Every year, CPAU publishes an
updated gas safety awareness brochure and mails it to all customers in Palo Alto, as well as to
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plumbers, contractors and excavators that may work in and around the area. Staff talk with
business customers at special facilities meetings, attend neighborhood safety and emergency
preparedness fairs and offer presentations to school and community groups. While print
materials and website pages still feature prominently, CPAU is increasing emphasis on outreach
through email newsletters, direct mail, newspaper inserts, social media and online videos. The
Gas Safety Public Awareness Plan contains saved copies of all outreach materials and logs of
activities; the Department of Transportation reviews this Plan at least once per year.
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APPENDICES
Appendix A: Gas Financial Forecast Detail
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
Appendix C: Gas Utility Reserves Management Practices
Appendix D: Description of Gas Utility Cost Categories
Appendix E: Gas Utility Communications Samples
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APPENDIX A: GAS FINANCIAL FORECAST DETAIL
($'000)($'000)
Actual Actual Actual
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
1 RATE CHANGE (%)*12%0%0%0%8%0%4%8%7%8%4%4%1%1%0%1%
2 SALES IN THOUSAND THERMS 28,901 28,117 28,881 26,719 27,829 27,434 27,289 26,752 26,847 26,547 26,245 25,939 25,726 25,507 25,095 25,071
3
4 Utilities Retail Sales 33,759 34,843 29,515 28,065 34,110 34,012 33,096 34,849 37,506 40,126 41,690 43,082 43,663 44,218 43,971 44,693
5 Service Connection & Capacity Fees 731 654 748 961 940 1,048 1,079 1,111 1,145 1,179 1,179 1,179 1,179 1,179 1,179 1,179
6 Other Revenues & Transfers In 830 313 414 2,346 694 1,508 1,818 2,261 2,599 2,895 3,185 3,467 3,740 4,074 4,079 4,205
7 Interest plus Gain or Loss on Investment (239)706 450 730 13 545 368 304 196 181 196 228 255 272 276 284
8 Total Sources of Funds 35,081 36,517 31,127 32,102 35,758 37,112 36,361 38,526 41,445 44,381 46,250 47,956 48,837 49,742 49,505 50,361
9
10 Purchases of Utilities:
11 Supply Commodity 12,461 12,992 9,537 6,648 9,720 9,998 8,587 8,226 8,205 8,200 8,268 8,429 8,569 8,708 8,855 9,001
12 Supply Transportation 994 1,333 982 (1,051)2,843 3,331 3,507 3,473 3,482 3,490 3,497 3,504 3,510 3,515 3,520 3,524
13 Total Purchases 13,455 14,325 10,519 5,597 12,563 13,329 12,094 11,699 11,687 11,690 11,765 11,933 12,079 12,223 12,375 12,525
14
15 Administration (CIP + Operating)4,273 3,988 4,007 3,337 2,450 2,519 2,577 2,640 2,707 2,775 2,845 2,906 2,968 3,051 3,106 3,178
16 Customer Service 1,358 1,338 1,195 1,097 1,581 1,643 1,700 1,781 1,858 1,925 1,992 2,051 2,107 2,155 2,184 2,237
17 Demand Side Management 630 438 632 566 855 879 900 922 945 969 993 1,015 1,036 1,065 1,084 1,110
18 Engineering (Operating)340 352 369 426 355 367 377 390 404 416 428 439 450 461 469 480
19 Operations and Maintenance 4,940 4,119 4,403 4,153 4,321 5,482 5,651 5,871 5,087 5,261 5,433 5,586 5,732 5,868 5,953 6,094
20 Resource Management 506 516 556 3,002 566 1,393 1,530 1,777 1,999 2,210 2,420 2,626 2,830 3,093 3,107 3,176
21 Debt Service Payments 296 805 804 249 227 802 801 801 803 804 805 803 800 803 1 1
22 Rent 219 419 431 443 455 467 480 492 505 519 532 546 561 574 587 601
23 Transfers to General Fund 5,971 5,811 5,730 6,194 6,594 7,035 6,888 7,069 7,069 7,972 8,214 8,629 9,072 9,547 9,539 9,538
24 Other Transfers Out 207 606 151 303 510 523 533 543 554 566 579 590 601 617 628 642
25 Capital Improvement Programs 7,620 1,026 1,832 6,889 2,214 7,804 5,197 10,217 12,080 9,815 9,892 9,970 10,050 10,131 10,214 10,299
26 Total Uses of Funds 39,814 33,743 30,629 32,256 32,690 42,243 38,728 44,202 45,698 44,922 45,898 47,095 48,286 49,587 49,248 49,880
27
28 Into/ (Out of) Reserves (4,733)2,773 498 (154)3,067 (5,131)(2,367)(5,676)(4,253)(541)352 861 551 155 257 481
29
30 Reappropriations + Commitments 19,363 11,305 6,491 6,255 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209
31 Plant Replacement 1,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
32 CIP Reserve 0 0 1,591 3,820 3,820 3,820 3,820 3,820 0 0 0 0 0 0 0 0
33 Rate Stabilization 11,318 15,981 7,215 6,018 6,539 6,411 4,291 0 0 0 0 0 0 0 0 0
34 Operations Reserve 0 0 10,847 10,296 13,549 8,547 8,300 6,915 6,482 5,941 6,293 7,153 7,705 8,673 8,930 9,411
35 Unassigned 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 1
36 Total Reserves 31,681 27,286 26,144 26,389 28,117 22,986 20,619 14,943 10,690 10,149 10,501 11,362 11,913 12,882 13,140 13,621
37 (1,142)245 1,728 (5,131)(2,367)(5,676)(4,253)(541)352 861 551 968 258 481
38 Short Term Risk Assessment Value 1,226 3,753 3,516 3,928 3,830 4,612 5,214 5,400 5,642 5,843 5,919 5,991 5,935 6,034
39
40 Operations Reserve Guidelines
41 Min (60 Days Commodity + O&M) 5,620 5,000 5,690 5,698 5,533 5,576 5,488 5,706 5,828 5,986 6,142 6,308 6,242 6,328
42 Target (90 Days Commodity + O&M) 8,429 7,500 8,535 8,547 8,300 8,364 8,232 8,560 8,742 8,978 9,213 9,462 9,362 9,492
43 Max (120 Days Commodity + O&M) 11,239 10,000 11,380 11,396 11,067 11,152 10,976 11,413 11,656 11,971 12,284 12,616 12,483 12,656
44
City of Palo Alto
Gas Utility
Fiscal Year
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APPENDIX B: GAS UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
ONE TIME PROJECTS
GS-15001 Security at Receiving Stations 64,700 64,700 - (1,101) 128,299 41,534 - - - - -
Unk AMI Project 180,000 530,000 2,320,000 - -
GS-18000 Gas ABS/Tenite Replacement - 1,500,000 - - - -
Subtotal, One-time Projects 64,700 64,700 - (1,101) 128,299 41,534 1,680,000 530,000 2,320,000 - -
GAS MAIN REPLACEMENT (GMR) PROGRAM
GS-11000 GMR - Project 21 100,000 100,000 - - 200,000 - - - - - -
GS-12001 GMR - Project 22 (150,372) 3,104,410 6,722,029 (224,576) 9,451,491 310,563 600,000
GS-13001 GMR - Project 23 337,000 700,000 - - 1,037,000 - - 6,500,000 - - -
GS-14003 GMR - Project 24 - - - - - - - 650,000 6,500,000 - -
GS-15000 GMR - Project 25 - - - - - - - - 650,000 6,500,000 -
GS-16000 GMR - Project 26 - - - - - - - - - 650,000 6,500,000
GS-20000 GMR - Project 27 - - - - - - - - - - 650,000
GS-20001 GMR - Project 28 - - - - - - - - - - -
Subtotal, Gas Main Replacement Program 286,628 3,904,410 6,722,029 (224,576) 10,688,491 310,563 600,000 7,150,000 7,150,000 7,150,000 7,150,000
TOOLS AND EQUIPMENT
GS-13002 General Shop Equipment/Tools - 50,000 - - 50,000 - 350,000 100,000 100,000 100,000 100,000
GS-14004 Gas Distribution System Model 19,574 19,574 - (4,660) 34,488 14,914 20,000 20,000 20,000
Subtotal, Tools and Equipment 19,574 69,574 - (4,660) 84,488 14,914 370,000 120,000 120,000 100,000 100,000
ONGOING PROJECTS
GS-11002 Gas System Improvements 75,624 555,672 - (114,215) 517,081 37,979 246,036 253,417 261,020 268,851 276,916
GS-03009 System Ext. - Unreimbursed - 204,455 - (19,127) 185,328 - 421,180 433,816 446,830 460,234 474,042
GS-80019 Gas Meters and Regulators 126,772 492,453 - (30,676) 588,549 96,096 376,652 387,952 399,591 411,579 423,926
Subtotal, Ongoing Projects 202,396 1,252,580 - (164,018) 1,290,958 134,075 1,043,868 1,075,185 1,107,441 1,140,664 1,174,884
CUSTOMER CONNECTIONS (FEE FUNDED)
GS-80017 Gas System Extensions 74,468 1,339,823 - (417,703) 996,588 98,562 1,303,315 1,342,415 1,382,688 1,424,169 1,466,894
Subtotal, Customer Connections 74,468 1,339,823 - (417,703) 996,588 98,562 1,303,315 1,342,415 1,382,688 1,424,169 1,466,894
GRAND TOTAL 647,766 6,631,087 6,722,029 (812,058) 13,188,824 599,648 4,997,183 10,217,600 12,080,129 9,814,833 9,891,778
Funding Sources
Connection Fees 1,017,000 - 1,078,935 1,111,303 1,144,642 1,178,981 266,894
Utility Rates 5,614,087 6,722,029 3,918,248 9,106,297 10,935,487 8,635,852 9,624,884
CIP-RELATED RESERVES DETAIL
6/30/2017
(Actual)
6/30/2018
(Unaudited)
Reappropriations 298,178 12,589,176
Commitments 349,588 599,648
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APPENDIX C: GAS UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Gas Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015
to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets
as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Gas Utility’s Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
Section 3. Distribution Fund Reserves
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Gas Utility’s Capital
Improvement Program (CIP), as described in Section 6 (CIP Reserve)
d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 8 (Operations Reserve)
f) Any funds not included in the other reserves will be considered Unassigned Reserves and
shall be returned to ratepayers or assigned a specific purpose as described in Section 9
(Unassigned Reserves)
Section 4. Reserve for Commitments
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Commitments will be set to an amount equal to the total remaining spending authority for
all contracts in force for the Wastewater Collection Utility at that time.
Section 5. Reserve for Reappropriations
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Reappropriations will be set to an amount equal to the amount of all remaining capital and
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non-capital budgets, if any, that will be re-appropriated to the following fiscal year for each
fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels are
calculated for each fiscal year of the Financial Planning Period based on the levels of CIP
expense budgeted for that year.
Minimum Level 12 months of budgeted CIP expense
Maximum Level 24 months of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve for
Commitments as a result of a change in contractual commitments related to CIP projects.
Any other additions to or withdrawals from the CIP reserve require Council action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP Reserve
for the purpose of determining compliance with the CIP Reserve minimum guideline
level.
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve reaching
its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is
below its minimum level at the end of FY 2017, staff must present a plan by June 30,
2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff
may present, and the Council may adopt, an alternative plan that takes longer than
one year to replenish the reserve, or that does so in a shorter period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds may
be added to this reserve. If there are funds in this reserve in excess of the maximum level
staff must propose to transfer these funds to another reserve or return them to
ratepayers in the next Financial Plan. Staff may also seek Council approval to hold funds
in this reserve in excess of the maximum level, if they are held for a specific future purpose
related to the CIP.
Section 7. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and held
to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate
Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization
Reserve at the end of any fiscal year, any subsequent Gas Utility Financial Plan must result in
the withdrawal of all funds from this Reserve by the end of the Financial Planning Period.
Section 8. Operations Reserve
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The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves
described in Section 4-Section 7 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for that
year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months of
the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Gas Utility’s Fund Balance
shall be automatically included in the Unassigned Reserve described in Section 9, below.
Section 9. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas Utility’s
Fund Balance will be held in the Unassigned Reserve. If there are any funds in the Unassigned
Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council
must include a plan to assign them to a specific purpose or return them to the Gas Utility
ratepayers by the end of the first fiscal year of the next Financial Planning Period. For
example, if there were funds in the Unassigned Reserves at the end of FY 2015, and the next
Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a plan
to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff may
present an alternative plan that retains these funds or returns them over a longer period of
time.
Section 10. Intra-Utility Transfers Between Supply and Distribution Funds
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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.
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APPENDIX D: DESCRIPTION OF GAS UTILITY COST CATEGORIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Gas Utility’s share of the call center, meter reading,
collections, and billing support functions. Billing support encompasses staff time associated with
bill investigations and quality control on certain aspects of the billing process. It does not include
maintenance of the billing system itself, which is included in Administration. This category also
includes CPAU’s key account representatives, who work with large commercial customers who
have more complex requirements for their gas services.
Resource Management: This category includes gas procurement, contract management, rate
setting, and tracking of legislation and regulation related to the gas industry.
Operations and Maintenance: This category includes the costs of a variety of distribution system
maintenance activities, including:
surveying the gas system (50% of the system each year) and repairing any leaks found;
investigating reports of damaged mains or services and perform emergency repairs;
building and replacing gas services for new or redeveloped buildings; and
testing and replacing meters to ensure accurate sales metering.
This category also includes a variety of functions the utility shares with other City utilities,
including:
the Field Services team (which does field research of various customer service issues);
the Cathodic Protection team (which monitors and maintains the systems that prevent
corrosion in metal pipes and reservoirs); and
the General Services team (which manages and maintains equipment, paves and restores
streets after gas, water, or sewer main replacements, and provides welding services,
including certified gas line welding services)
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services and Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering gas efficiency programs and the
direct cost of rebates paid.
Engineering (Operating): The Gas Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX E: GAS UTILITY COMMUNICATIONS SAMPLES
Attachment C
* NOT YET APPROVED *
6055006
Resolution No. _________
Resolution of the Council of the City of Palo Alto Increasing Gas
Rates by Amending Rate Schedules G-1 (Residential Gas Service),
G-2 (Residential Master-Metered and Commercial Gas Service), G-3
(Large Commercial Gas Service), and G-10 (Compressed Natural Gas
Service Service)
R E C I T A L S
A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
B. On ____, 2018, the City Council heard and approved the proposed rate increase
at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-1 (Residential Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-1, as amended, shall become effective July 1, 2018.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-2 (Residential Master-Metered and Commercial Gas Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule G-2, as amended, shall
become effective July 1, 2018.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-3 (Large Commercial Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-3, as amended, shall become effective July 1, 2018.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-10 (Compressed Natural Gas Service Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule G-10, as amended, shall become effective
July 1, 2018.
SECTION 5. The City Council finds as follows:
a. Revenues derived from the gas rates approved by this resolution do not exceed the
funds required to provide gas service.
b. Revenues derived from the gas rates approved by this resolution shall not be used
for any purpose other than providing gas service, and the purposes set forth in
Article VII, Section 2, of the Charter of the City of Palo Alto.
Attachment C
* NOT YET APPROVED *
6055006
SECTION 6. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
SECTION 7. The Council finds that the adoption of this resolution changing gas rates
to meet operating expenses, purchase supplies and materials, meet financial reserve needs and
obtain funds for capital improvements necessary to maintain service is not subject to the
California Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec.
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After reviewing
the staff report and all attachments presented to Council, the Council incorporates these
documents herein and finds that sufficient evidence has been presented setting forth with
specificity the basis for this claim of CEQA exemption.
Attachment C
* NOT YET APPROVED *
6055006
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-1 Effective 97-1-20187
dated 119-1-20176 Sheet No G-1-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from City of Palo Alto
Utilities:
1. Separately-metered single-family residential Customers.
2.Separately-metered multi-family residential Customers in multi-family residential facilities.
B. TERRITORY:
This schedule applies anywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ....................................................................................................$10.9432
Tier 1 Rates: Per Therm
Supply Charges:
1.Commodity (Monthly Market Based) .......................................... $0.10-$2.00
2.Cap and Trade Compliance Charge ..................................................$0.00-$0.25
3. Transportation Charge........................................................................$0.00-$0.15
4.Carbon Offset Charge ........................................................................$0.00-$0.10
Distribution Charge: .............................................................................................$0.42393933
Tier 2 Rates: (All usage over 100% of Tier 1)
Supply Charges:
1.Commodity (Monthly Market Based) .......................................... $0.10-2.00
2.Cap and Trade Compliance Charge ...................................................$0.00-$0.25
3. Transportation Charge........................................................................$0.00-$0.15
4.Carbon Offset Charge ........................................................................$0.00-$0.10
Distribution Charge: .............................................................................................$0.99489319
D. SPECIAL NOTES:
1. Calculation of Cost Components
ATTACHMENT D
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-2 Effective 97-1-20187
dated 119-1-20176 Sheet No G-1-2
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance
with the state’s Cap and Trade Program, including the cost of acquiring compliance
instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap
and Trade Compliance Charge will change in response to changing market conditions,
retail sales volumes and the quantity of allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse
gases produced in the burning of natural gas. The Carbon Offset Charge will change in
response to changing market conditions, changing sales volumes and the quantity of
offsets purchased within the Council-approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges
will fall within the minimum/maximum ranges set forth in Section C.
2. Seasonal Rate Changes:
The Summer period is effective April 1 to October 31 and the Winter period is effective from
November 1 to March 31. When the billing period includes use in both the Summer and the
Winter periods, the usage will be prorated based on the number of days in each seasonal
period, and the charges based on the applicable rates for each period. For further discussion
of bill calculation and proration, refer to Rule and Regulation 11.
3. Calculation of Usage Tiers Tier 1 natural gas usage shall be calculated and billed based upon a level of 0.667 therms per
day during the Summer period and 2.0 therms per day during the Winter period, rounded to
the nearest whole therm, based on meter reading days of service. As an example, for a 30
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-3 Effective 97-1-20187
dated 119-1-20176 Sheet No G-1-3
day bill, the Tier 1 level would be 20 therms during the Summer period and 60 therms during
the Winter period months. For further discussion of bill calculation and proration, refer to
Rule and Regulation 11.
{End}
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-1 Effective 97-1-20187
dated 119-1-20176 Sheet No G-2-1
A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use less than 250,000 therms per year at one site.
2. Master-metered residential Customers in multi-family residential facilities.
B. TERRITORY: This schedule applies anywhere the City of Palo Alto provides Gas Service. C. UNBUNDLED RATES: Per Service Monthly Service Charge: ...............................................................................................$82.9278.23
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................... $0.10-$2.00
2. Cap and Trade Compliance Charges ................................................. $0.00-0.25
3. Transportation Charge........................................................................$0.00-$0.15
4. Carbon Offset Charge ........................................................................$0.00-$0.10
Distribution Charge: ........................................................................................................$0.61835767
D. SPECIAL NOTES:
1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with
the state’s Cap and Trade Program, including the cost of acquiring compliance instruments
sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade
Compliance Charge will change in response to changing market conditions, retail sales
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-2 Effective 97-1-20187
dated 119-1-20176 Sheet No G-2-2
volumes and the quantity of allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced in the burning of natural gas. The Carbon Offset Charge will change in response to
changing market conditions, changing sales volumes and the quantity of offsets purchased
within the Council-approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges will
fall within the minimum/maximum ranges set forth in Section C.
{End}
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-1 Effective 97-1-20187
dated 119-1-20176 Sheet No G-3-1
A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from the City of Palo
Alto Utilities:
1. Commercial Customers who use at least 250,000 therms per year at one site. 2. Customers at City-owned generation facilities.
B. TERRITORY:
This schedule applies anywhere the City of Palo Alto provides Nnatural Ggas Sservice.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: $400.08377.43
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................................... $0.10-$2.00
2. Cap and Trade Compliance Charges ...................................................... $0.00-0.25
3. Transportation Charge .......................................................................... $0.00-$0.15 4. Carbon Offset Charge ........................................................................... $0.00-$0.10
Distribution Charge: .....................................................................................................$0.60985687
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as
calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance
with the state’s Cap and Trade Program, including the cost of acquiring compliance
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-2 Effective 97-1-20187
dated 119-1-20176 Sheet No G-3-2
instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap
and Trade Compliance Charge will change in response to changing market conditions,
retail sales volumes and the quantity of allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases produced in the burning of natural gas. The Carbon Offset Charge will change in
response to changing market conditions, changing sales volumes and the quantity of
offsets purchased within the Council-approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges
will fall within the minimum/maximum ranges set forth in Section C. 2. Request for Service A qualifying Customer may request service under this schedule for more than one
account or meter if the accounts are located on one site. A site consists of one or more
contiguous parcels of land with no intervening public right-of- ways (e.g. streets). 3. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable City of Palo Alto full-service rate schedule.
{End}
COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-1 Effective 97-1-20187
dated 119-1-20176 Sheet No.G-10-1
A. APPLICABILITY:
This schedule applies to the sale of natural gas to the City-owned compressed natural gas (CNG) fueling station at the Municipal Service Center in Palo Alto.
B. TERRITORY: Applies to the City’s CNG fueling station location located at the Municipal Service Center in City of Palo Alto.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ...............................................................................................$56.1152.93
Per Therm
Supply Charges:
Commodity (Monthly Market Based) ................................................................ $0.10-$2.00
Cap and Trade Compliance Charges .............................................................. $0.00 to $0.25
Transportation Charge........................................................................................ $0.00-$0.15
Carbon Offset Charge ........................................................................................ $0.00-$0.10
Distribution Charge ....................................................................................................$0.01000.0093
D. SPECIAL CONDITIONS
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for
any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount
may be broken down into appropriate components as calculated under Section C. The Commodity charge is based on the monthly natural gas Bidweek Price Index for delivery at
PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the
state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to
cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will
COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-2 Effective 97-1-20187
dated 119-1-20176 Sheet No.G-10-2
change in response to changing market conditions, retail sales volumes and the quantity of
allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases produced
in the burning of natural gas. The Carbon Offset Charge will change in response to changing market
conditions, changing sales volumes and the quantity of offsets purchased within the Council-
approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for
delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges will fall
within the minimum/maximum range set forth in Section C.
{End}
EXCERPTED DRAFT MINUTES OF THE APRIL 12, 2018 SPECIAL MEETING
UTILITIES ADVISORY COMMISSION
ITEM 2. ACTION: Staff recommendation that the Utilities Advisory Commission recommend that the City
Council adopt 1) a Resolution approving the Fiscal Year 2019 Gas Utility Financial Plan, and 2) a Resolution
increasing Gas Rates by 4% by amending Rate Schedules G-1 (Residential Gas Service), G-2 (Residential
Master-Metered and Commercial Gas Service), G-3 (Large Commercial Gas Service), and G-10
(Compressed Natural Gas Service).
Eric Keniston, Senior Resource Planner, reported staff recommends a 4% rate increase in fiscal year 2019
followed by increases of 8% and 7%. Again, a projected increase in capital investment costs drives the rate
increase. Currently, gas supply is projected to remain relatively flat; although, the projection can change
at any time. Gas supply and operations are expected to increase by approximately the rate of inflation.
Over the long term, operations, distribution, and capital improvements are major cost drivers. Commodity
costs decreased overall between fiscal year 2013 and fiscal year 2022. The Operations Reserve Fund is
projected to decrease. The proposed rate increases anticipate staff reducing the Rate Stabilization
Reserve Fund to zero by fiscal year 2020. Costs for commodity, Cap-and-Trade, carbon neutrality, and
transmission will continue to pass through to customers. Reserve funds are quite healthy at the current
time; however, staff anticipates cost increases for capital spending will reduce reserve fund balances to
the minimum guideline level in approximately 2022. Larger subsequent rate increases will be necessary
to retain reserve fund balances at the minimum level. For the Operations Reserve Fund, the risk
assessment level is slightly below the minimum guideline level, which is only $6 million. The change to
most customers' bills will be about 4%. Palo Alto residential bill amounts during winter months are well
below PG&E's bill amounts and slightly higher than PG&E's during summer months. Commercial bill
amounts are about the same as PG&E's commercial bills.
In answer to Commissioner Johnston's question regarding Tables 1 and 2 in the staff report about what
parts of the bill were being increased, Keniston explained that staff increased the distribution component
by 6% such that the net effect on the overall bill is 4%. The distribution component is not a pass-through
cost. Distribution is comprised of all operations within the City system, maintenance of mains, and capital
improvements for mains. Distribution is driving the overall increase in the short-term. The gas main
replacement project will drive the increase in 2019, and meters compatible with advanced metering
infrastructure (AMI) will drive the increase in 2020 and 2021. Ed Shikada, Utilities General Manager,
reported the cost for the gas main replacement project is $7 million in fiscal year 2020 and beyond. Staff
is beginning to explore the possibility of spreading the cost of AMI through debt financing.
Commissioner Schwartz suggested staff frame the increase in terms of safety and emissions control and
talk about the benefits of capital improvements rather than merely the projects. Staff should include in
the staff report historical data refuting the concept that maintenance should be deferred to the future
when costs will be less.
ATTACHMENT E
In reply to Commissioner Forssell's query about the impact of higher-than-expected bids for capital
improvement projects on the health of the Gas Utility if reserves declined, Keniston indicated staff would
withdraw money from reserve funds to cover the increased costs if the utility received higher than
expected bids. Currently, reserve funds can absorb higher-than-expected bids, but in later years it could
result in a higher rate increase.
In response to Chair Danaher's request for an explanation of the structure of the minimum and maximum
reserve guidelines, why those guidelines were not increasing despite costs increasing, and of the
elimination of the Rate Stabilization Reserve Fund, Keniston stated the minimum guideline level for the
Operations Reserve is calculated as 60 days of operating and commodity expenses. The maximum
guideline level is 120 days of operating and commodity expenses. The other reserve funds, like the Rate
Stabilization Reserve, were used for specific purposes. Jonathan Abendschein, Assistant Director of
Resource Management, clarified that most of the cost increases were related to capital improvement
costs, which were not used to calculate the minimum and maximum guideline levels, and therefore the
minimum and maximum guideline levels were not increasing significantly.
In answer to Commissioner Forssell's asked a follow-up question, noting that operational costs were
increasing at the rate of inflation and the guideline levels should increase. Abendschein explained that
there were near-term one-time operational costs that increased the guideline levels in the near term.
When those costs were removed from the budget in later years, it ended up offsetting inflationary
increases for the purpose of guideline calculation.
In answer to Chair Danaher's query about capital costs and the Operations Reserve Fund, Keniston advised
that the Capital Improvement Program (CIP) budget covers capital costs. Dave Yuan, Strategic Business
Manager, reported that staff doubled the budget for capital projects. Abendschein added that staff uses
the Operations Reserve Fund for capital cost variances but ensures the balance remains within the
guidelines.
ACTION: Commissioner Johnston moved to recommend the City Council adopt 1) a Resolution approving
the Fiscal Year 2019 Gas Utility Financial Plan, and 2) a Resolution increasing Gas Rates by 4% by amending
Rate Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas
Service), G-3 (Large Commercial Gas Service), and G-10 (Compressed Natural Gas Service). Vice Chair
Ballantine seconded the motion. The motion carried 5-0 with Chair Danaher, Vice Chair Ballantine, and
Commissioners Forssell, Johnston, and Schwartz voting yes.