HomeMy WebLinkAboutStaff Report 11212City of Palo Alto (ID # 11212)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/5/2020
City of Palo Alto Page 1
Council Priority: Fiscal Sustainability
Summary Title: FY 2021 Electric Rates and Financial Plan
Title: Staff and the Utilities Advisory Commission Request the Finance
Committee Recommend the City Council Adopt a Resolution Approving the
Fiscal Year 2021 Electric Financial Plan and Reserve Transfers, Amending the
Electric Utility Reserve Management Practices, and Increasing Electric Rates
2% Overall by Amending the E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-
7 TOU, E-14, E-NSE and E-EEC Rate Schedules
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission (UAC) requests that the Finance Committee
recommend that the Council adopt a resolution (Attachment A):
1.Approving the Fiscal Year (FY) 2021 Electric Financial Plan (Attachment B) and the
following reserve transfers:
a)Up to $4 million from the Supply Operations Reserve to the Hydroelectric
Stabilization Reserve;
b)Up to $5 million from the Supply Operations Reserve to the Electric Special
Projects (ESP) Reserve;
c)Up to $7 million from the Distribution Operations Reserve to the Capital
Improvement Project Reserve;
d)$3.74 million from the Operations Reserve to the Low Carbon Fuel Standard
(LCFS) Reserve
2.Amending the Electric Utility Reserve Management Practices relating to the CIP, Low
Carbon Fuel Standard, and Rate Stabilization Reserves (as set forth in the Financial Plan)
(Attachment C); and
3.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),
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E-7 (Large Non-Residential Electric Service), E-7-G (Large Non-Residential Green Power
Electric Service), E-7 TOU (Large Non-Residential Time of Use Electric Service), E-14
(Street Lights), E-NSE (Net Metering Net Surplus Electricity Compensation), and E-EEC
(Export Electricity Compensation) (Attachment D).
Executive Summary
The FY 2021 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2025. Costs are projected to rise substantially for the next several years for multiple
reasons. Costs for electric supply purchases are increasing as a result of increases in
transmission costs, and potentially dry hydro conditions may necessitate utilizing funds from
the Hydro Rate Stabilization Reserve starting in FY 2021. Substantial additional capital
investment in the electric distribution system is planned for FY 2021 through FY 2024.
Operational costs in FY 2019 were lower than budgeted due to vacancies and difficulty hiring
contractors but are projected to increase in FY 2020 and beyond as vacancies are filled and new
contracts for maintenance work are put in place. Electric loads have been decreasing, mainly in
the commercial sector, putting upward pressure on rates. However, due to good hydro
conditions in FY 2019 and corresponding surplus sales, revenues were above expenses in FY
2019 and are expected to remain that way in FY 2020. The good hydro conditions are a short-
term phenomenon, though, and are not anticipated to continue. Figure 1 below shows the
primary rate increase drivers.
Figure 1: Allocation of Rate increase
The short-term revenue increase has replenished Operations reserves which had been lower
than target levels. This provides flexibility to offset future one-time expense increases
0.8% supply cost
increase net of
0.4% decrease
from new supply
revenues
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associated with future dry years. But because of the increases in annual expenses described
above, along with decreased sales, an increase in sales revenues is still required to maintain
long term financial health. A 2% rate increase is proposed for July 1, 2020, with 3% to 4%
increases in the following years. While 2% is the overall increase in average rates, different
customer classes will see slightly different increases as shown in Tables 3 and 4. These
variations are due to slight shifts in usage by customer class as well as relative demand by
customer class. Staff calculated the rate increases using the 2016 cost of service analysis
(COSA) model created for the City by EES Consulting, which was implemented on July 1, 2016,
and updated based on the most recent historical data for FY 2019 and projected sales and
demand for FY 2021.
The projections in the attached FY 2021 Financial Plan do not reflect the potential economic
impacts of the shelter in place orders issued by Santa Clara County to combat the COVID-19
pandemic. Staff is separately modeling these impacts and will return to the Finance Committee
with a separate report. Staff continues to recommend an inflationary rate increase for July 1,
2020 given continued cost escalation projected in future years. Staff also intends to provide an
alternative five-year rate forecast if electric rates were left unchanged this year.
At the April 15, 2020 UAC meeting, staff presented the 2% overall increase proposal, and
provided a slide showing the impact of a 0% rate increase as well. The UAC deliberated and
chose to approve staff’s recommended 2% increase option (7-0).
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Background
Every year staff presents the Finance Committee 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.
The Finance Committee reviewed preliminary financial forecasts at its March 3, 2020 meeting.
(Staff Report #11077)
Discussion
Staff’s annual assessment of the financial position of the City’s electric utility is completed in
compliance with cost of service requirements set forth in the California Constitution and
applicable statutory law. The assessment includes making long-term projections of market
conditions, of costs associated with the physical condition of infrastructure, and of other factors
that could affect utility costs. Rates are then proposed that will be adequate to recover
projected costs.
Proposed Actions for FY 2020 and FY 2021:
The FY 2021 Electric Utility Financial Plan includes the following proposed actions:
1. Amend electric rate schedules (see Attachment D) to increase overall electric rates by
approximately 2% effective July 1, 2020;
2. Amend the Electric Utility Reserve Management Practices relating to the CIP, Low
Carbon Fuel Standard, and Rate Stabilization Reserves (as set forth in the Financial Plan)
(Attachment C);
3. Transfer up to $4 million from the Supply Operations Reserve to the Hydroelectric
Stabilization Reserve;
4. Transfer up to $5 million from the Supply Operations Reserve to the Electric Special
Projects (ESP) Reserve;
5. Transfer up to $7 million from the Distribution Operations Reserve to the Capital
Reserve; and,
6. Transfer $3.74 million from the Operations Reserve to the Low Carbon Fuel Standard
(LCFS) Reserve.
The transfer to the Electric Special Projects reserve will repay half of a $10 million temporary
loan taken from the ESP reserve in FY 2018, during the last drought. The transfer to the Capital
Reserve will fund future year CIP increases and balance year to year changes in capital
investment. The transfer to the hydroelectric reserve will bring the reserve closer to its target
level. Both transfers will provide flexibility in preventing or mitigating rate spikes associated
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with future dry years. The LCFS transfer is to better track and manage funds related to the LCFS
program which are currently contained in the Supply Operations Reserve balance.
Staff proposes modifications to the Electric Utility Reserves Management Practices specific to
the CIP reserve. Because of the irregular dollar amounts and timing of CIP projects budgeted to
occur during the forecast period, as well as the potential for new ongoing projects to be
included in the CIP plan in later years, staff recommends that four years of budgeted CIP be
used to calculate the reserve maximum levels rather than the current four months (120 days) of
budgeted expenses. The new minimum CIP Reserve level is 20% of the maximum CIP Reserve
guideline level rather than two months (60 days) of expenses. Staff also proposes that the
Electric Utility Reserves Management Practices be amended to provide that if there are funds in
this reserve in excess of the maximum level, staff must propose in the next Financial Plan to
transfer these funds to another reserve, return the funds to ratepayers, or designate a specific
use of the funds for CIP investments that will be made by the end of the next Financial Planning
Period.
Although this Financial Plan includes a forecast period of five years, or 60 months, an even
number of years (48 months or 4 years) is used for the CIP Reserve maximum calculation,
because of the irregular size and funding of CIP projects. The new minimum CIP Reserve level is
20% of the maximum CIP Reserve guideline level. This maximum in FY 2021 is $19 million and
the minimum in FY 2021 is $3.8 million, and the reserve is projected to remain within the
min/max guidelines for the duration of the forecast. The CIP reserve will be above the old
guideline levels in FY 2020, but within the guideline range in FY 2021.
Table 1 below shows the effects of the proposed transfers on reserve funds, as well as changes
to the CIP min/max guidelines. The attached Electric Financial Plan (Attachment B) discusses
these reserve changes in greater detail.
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Table 1: Reserves Starting and Ending Balances, Revenues, Expenses, Transfers To/(From)
Reserves, Operations and Capital Reserve Guideline Levels for FY 2020 to FY 2025 ($000)
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Starting Reserve Balances
1 Supply Operations 28,709 30,673 23,773 24,870 24,666 25,275
2 Distribution Operations 16,536 10,758 10,712 11,865 11,714 11,968
3 CIP 880 7,880 11,880 11,880 11,880 11,880
4 Electric Special Projects 41,665 46,665 49,665 49,665 49,665 39,665
5 Hydro Stabilization 11,400 15,400 19,000 19,000 19,000 19,000
6 Low Carbon Fuel Standard (LCFS)- 3,740 3,340 2,140 1,140 1,140
Revenues
7 Supply 117,499 117,603 114,725 113,373 113,429 112,227
8 Distribution 59,204 60,948 62,919 64,807 67,314 69,933
Transfers
9 Supply Operations (12,740) (16,600) (4,000) (3,000) (2,000) -
10 Distribution Operations (7,000) 4,000 4,000 3,000 2,000 -
11 CIP 7,000 4,000 - - - -
12 Electric Special Projects 5,000 5,000 - - - -
13 Hydro Stabilization 4,000 3,600 - - - -
14 Low Carbon Fuel Standard 3,740 - - - - -
Capital Program Contribution
15 Distribution Operations Reserve - - - - - -
16 CIP Reserve
Expenses
17 Supply Expenses (102,794) (107,903) (109,628) (110,578) (110,820) (110,601)
18 Distribution Non-CIP Expenses (42,665) (43,661) (47,680) (48,532) (39,640) (50,394)
19 Planned CIP (15,316) (21,333) (18,086) (19,426) (29,420) (19,298)
20 ESP funded - (2,000) - - (10,000) -
21 Hydro funded - - - - - -
22 LCFS funded - (400) (1,200) (1,000) - -
Ending Reserve Balance
1 + 7 + 9 + 17 Supply Operations 30,673 23,773 24,870 24,666 25,275 26,901
2 + 8 + 10 +
15 + 18 + 19 Distribution Operations 10,758 10,712 11,865 11,714 11,968 12,208
3 + 11 + 16 +
19 CIP 7,880 11,880 11,880 11,880 11,880 11,880
4 + 12 + 20 Electric Special Projects 46,665 49,665 49,665 49,665 39,665 39,665
5 + 13 + 21 Hydro Stabilization 15,400 19,000 19,000 19,000 19,000 19,000
6 + 14 + 22 Low Carbon Fuel Standard 3,740 3,340 2,140 1,140 1,140 1,140
Operations Reserve Guidelines (Supply)
23 Minimum 16,898 17,803 18,218 18,342 18,217 18,181
24 Maximum 33,795 35,607 36,437 36,683 36,434 36,362
Operations Reserve Guidelines (Distribution)
25 Minimum 8,194 8,682 9,098 9,324 9,542 9,771
26 Maximum 12,890 13,822 14,494 14,860 15,217 15,586
CIP Reserve Guidelines
27 Minimum 2,518 3,813 3,811 3,900 3,950 4,031
28 Maximum 5,036 19,066 19,057 19,500 19,752 20,153
Proposed and Projected Sales Revenue Requirement, FY 2021 through FY 2025
The July 1, 2019 rate increase was the fourth and last increase in a series of substantial rate
increases starting in FY 2017. Prior to the first increase on July 1, 2016, rates had not been
increased since July 1, 2009. In FY 2021 to FY 2025, staff forecasts a series of increases of 2% to
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4%. Table 2 shows the sales revenue increases needed to recover costs of operation over the
forecast period in the FY 2021 Electric Financial Plan.
Table 2: Electric Rate Adjustments, FY 2017 to FY 2024
FY 2017
Approved
FY 2018
Approved
FY 2019
Approved
FY 2020
Approved
FY 2021
Proposed
FY 2022
Projected
FY 2023
Projected
FY 2024
Projected
FY 2025
Projected
11% 14% 6% 8% 2% 3% 4% 4% 4%
These retail rate increases are for the electric utility as a whole, but the rate changes will differ
slightly for individual customer classes. Proposed rate increases for each customer class are
discussed below.
Changes from Prior Financial Forecasts
This projection has changed slightly since the FY 2020 Electric Utility Financial Plan presented
last year. Table 3 compares current rate projections to those projected in the last two year’s
Financial Plans. Nearer term forecasts have come down from prior years due to short-term
surplus revenues resulting from better than forecast hydro in FY 2019 and the start of FY 2020.
Increased infrastructure budgets are slightly increasing in the outer year projections.
Table 3: Projected Electric Rate Trajectory for FY 2020 to FY 2025
Projection FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Current
(FY 2021 Financial Plan) 2% 3% 4% 4% 4%
Last year
(FY 2020 Financial Plan) 4% 4% 4% 3% 3%
Two years ago
(FY 2019 Financial Plan) 2% 0% 1% 1% 2%
FY 2021 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table 4 shows the projected rate adjustments over the next five years and their impact on the
annual median residential electric bill (453 kwh per month in winter, 365 kwh per month in
summer).
Table 4: Projected Rate Adjustments, FY 2021 to FY 2025
FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Electric Utility 2% 3% 4% 4% 4%
Estimated Bill Impact ($/mo)* $1.28 1.86 2.55 2.66 2.76
* Estimated impact on median residential electric bill, which is currently $60.70 for CY
2019
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The rate increases are related to several factors: increasing transmission, substantial additional
capital investment in the aging electric distribution system, and operations costs are increasing
due to larger contracting needs since the department has been unable to fill several critical
positions. Revenues have also declined as customer usage has decreased, requiring larger rate
increases to cover fixed expenses and offset the shortfalls.
Historically, total electric utility costs (excluding short-term drought impacts) were roughly
$120 million per year, allowing the electric utility to go without a rate increase from July 1, 2009
to July 1, 2016. Over the period from FY 2016 to FY 2018, though, annual costs (net of energy
supply related revenue, like surplus energy sales) increased to roughly $140 million per year
(costs were unusually low in FY 2019 due to some one-time savings from surplus energy sales).
Costs are currently projected to increase to roughly $160 million by FY 2025 but will likely be
higher as the impacts of some new capital improvement and replacement projects are
accounted for in 2020.
Figure 1 shows the overall utility’s costs (net of surplus sales revenues) in FY 2015, FY 2020, and
FY 2025. Costs for the electric supply portfolio have decreased slightly between FY 2015 and FY
2020, but much of this is due to one-time surplus hydro revenues in FY 2020 as well as the fact
that customer sales have declined by 1.5% to 2% annually during this time. Assuming normal
hydro conditions going forward, as well as a continuing trend of load loss, costs are projected to
increase by about 1% in the future. Costs for managing the distribution system (e.g.
maintenance, capital investment, customer service, billing, etc.) have increased as well, growing
by 2.6% per year on average in the past, but projected to grow by nearly 4% per year going
forward. Overall, costs are projected to increase by 1.2% per year over the forecast horizon, but
declining loads will necessitate rate increases greater than this to maintain financial health.
Figure 1: Electric Utility Costs, FY 2015 Actual vs. FY 2020 and FY 2025 Projections
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Figure 2 shows electric distribution costs specifically. Capital costs have increased by about 4%
per year on average over the last five years and are projected to be more than 5% per year
going forward. Increased costs are related to greater capital investment in the distribution
system (e.g. underground district rebuilds, as well as substation and upgrades). In the last few
years, the City has experienced a higher number of outages in underground districts due to
aging equipment and infrastructure. Distribution system operational spending is projected to
increase by about 3 to 4% annually. Some of this is due to projected increases in costs of labor
and materials, but also due to higher than anticipated staff vacancies requiring external
contracts.
Figure 2: Electric Distribution Costs, FY 2015 vs. FY 2020 and FY 2025
While net electric supply portfolio cost decreases from FY 2015 to FY 2020, this was mainly due
to surplus energy revenues and decreasing loads driving down generation cost. Transmission
cost increases and, to a lesser extent, operational overhead costs have increased by 8% to 9%
annually in the same timeframe, as shown in Figure 3. In the future, staff forecasts that
increased costs will continue largely come from transmission costs. These increases are due to
rehabilitation and replacement of the existing statewide electric transmission system as well as
expansion of that system to accommodate new generation, mostly renewable. Staff works to
contain transmission costs through partner agencies, including the Transmission Agency of
Northern California (TANC) and Northern California Power Agency (NCPA), and through direct
partnerships with other local utilities (the Bay Area Municipal Transmission group, BAMx).
These groups intervene in transmission proceedings at the Federal Energy Regulatory
Commission (FERC) and the California Independent System Operator (CAISO), and have
achieved some reductions in long-term transmission costs. Staff is beginning to look at
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strategies to achieve cost savings in electric supply and will discuss these strategies in greater
detail through the ongoing Integrated Resource Planning (IRP) process.
Figure 3: Electric Supply Costs, FY 2015 Actual vs. FY 2020 and FY 2025 Projections
With a 2% rate increase, this Financial Plan will seek to maintain stable reserves and counter
erosion to revenue from load.
Staff also recognizes the importance of managing operating costs and maximizing efficiency in
order to minimize rate increases. As discussed above, staff is working on cost containment
measures related to transmission and renewable energy costs. Utility consumers also see some
long-term cost savings from City-wide efforts to manage personnel costs. As reflected in the
Utilities Strategic Plan, staff is exploring additional ways to effectively use available resources,
particularly across Divisions.
Rate Changes by Customer Class
Table 5 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 Time of Use (TOU) and E-7 TOU rates are not shown in
the table but can be seen in the attached rate schedules (Attachment D).
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Table 5: Electric Rates (Current and Proposed)
Current Rates
Proposed Rates
(7/1/2020)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.13757 0.14087 0.00330 2.4%
Tier 2 Energy ($/kWh) 0.19367 0.19609 0.00242 1.2%
Minimum Bill ($/day) 0.3283 0.3344 0.0061 1.9%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.20853 0.21430 0.00577 2.8%
Winter Energy ($/kWh) 0.14624 0.14792 0.00168 1.1%
Minimum Bill ($/day) 0.8359 0.8536 0.0177 2.1%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.12848 0.13792 0.00944 7.3%
Winter Energy ($/kWh) 0.09946 0.10687 0.00740 7.4%
Summer Demand ($/kW) 28.91 28.14 (0.77) -2.7%
Winter Demand ($/kW) 18.97 14.64 (4.33) -22.8%
Minimum Bill ($/day) 17.2742 17.4346 0.1604 0.9%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.11432 0.11689 0.00257 2.2%
Winter Energy ($/kWh) 0.07738 0.08259 0.00521 6.7%
Summer Demand ($/kW) 30.69 28.34 (2.35) -7.7%
Winter Demand ($/kW) 17.05 17.18 0.13 0.8%
Minimum Bill ($/day) 42.3648 42.7994 0.4346 1.0%
Table 6 shows the impact of the proposed July 1, 2020 rate changes on the residential and non-
residential bills for various consumption levels. The rate changes for each customer class are
similar and the overall rate change for the residential class is roughly 1.9%. Their usage as a
class has been consistent from last year, leading to a rate increase that’s the same as the
overall increase. Small commercial (E-2) loads have decreased over time, but their use of the
distribution system has become a little less efficient (e.g. higher peak usage relative to average
usage), leading to a slightly higher overall increase of 2.1%. Medium commercial usage has also
decreased, but their peak demand has also dropped compared to their consumption, meaning
a more efficient use of the overall system and thus a lower overall increase for the class of
1.6%. Large commercial customers have also improved the efficiency of the way they use the
system, limiting the overall increase needed for this customer class to 1.1%.
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Table 6: Impact of Proposed Electric Rate Changes on Customer Bills
Rate Schedule
Usage (kwh/mo)
Bill under
Current
Rates ($/mo)
Bill Under Rates
Proposed 7/1/20
($/mo)
Change
$/mo %
E-1 (Residential) 300 $ 41.27 $42.26 $0.99 2.4%
(Summer Median)
365 52.18 53.35 1.17 2.2%
(Winter Median)
453 69.22 70.61 1.39 2.0%
650 107.37 109.24 1.86 1.7%
1200 213.89 217.09 3.19 1.5%
E-2 (Small Non-
Residential) 1,000 178 182 4 2.1%
E-4 (Medium
Non-Residential) 160,000
27,541 27,977 436 1.6%
E-7 (Large Non-
Residential
500,000 71,534 72,344 810 1.1%
2,000,000 286,135 289,374 3,239 1.1%
Cost of Service Analysis and Rate Study
The rates discussed in the previous section are based on the cost of service methodology
established in the “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2016. Staff updated the model sales and budget projections, including
projected transmission and distribution costs, power supply costs and billing data, in order to
update individual cost of service model components and determine the proposed rates.
Electric Bill Comparison with Surrounding Cities
Table 7 compares electric bills under current rates as of February 1, 2020 for residential
customers to those in surrounding communities. Under current rates, CPAU’s median
residential bills are 39% lower than PG&E’s but about 19% higher than Santa Clara’s. Palo Alto’s
non-residential rates are lower than PG&E’s as well, but Santa Clara’s commercial rates are
lower than Palo Alto’s rates.
Table 7: Average Electric Bill Comparison ($/month)
As of February 1, 2020
Customers
Usage
(KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E Santa Clara
Residential
Customers
300 $ 41.27 $42.26 $ 70.74 $ 36.96
365 (Summer
Median) 52.18 53.35 92.04 45.27
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
City of Palo Alto Page 13
453 (Winter
Median) 69.22 70.61 106.82 56.50
650 107.37 109.24 164.73 81.66
1200 213.89 217.09 327.95 151.91
Non-
Residential
Customers
1,000 178 182 263 190
160,000 27,541 27,977 32,240 21,905
500,000 71,534 72,344 93,260 64,480
2,000,000 286,135 289,374 394,490 269,230
Timeline
The Finance Committee is scheduled to review the FY 2021 Electric Financial Plan in May 2020.
The City Council will consider adopting the Financial Plan and rate amendments as part of the
FY 2021 budget review and adoption process. If Council approves the proposed rate changes,
they will become effective July 1, 2020.
Resource Impact
The FY 2021 Budget is being developed concurrent with these rates and, depending on the final
recommendations from the Finance Committee, adjustments to the budget may be required.
Net of load losses, the proposed rate changes would be effective July 1, 2020 and are projected
to maintain sales revenues roughly equivalent to FY 2020 levels. See the attached FY 2021
Electric Financial Plan for a more comprehensive overview of projected cost and revenue
changes for the next five years.
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.
Stakeholder Engagement
The UAC reviewed preliminary financial forecasts at its December 4, 2019 meeting, and the
Finance Committee reviewed the preliminary forecasts at its March 3, 2020 meeting. At the
April 15, 2020 UAC meeting, staff presented the 2% overall increase proposal, and provided a
slide showing the impact of a 0% rate increase as an alternative. The UAC deliberated and chose
to approve staff’s recommended 2% increase option (7-0). If approved, the Finance
Committee’s recommendation on the FY 2021 Electric rate increases will be presented to City
Council in June during the budget adoption process.
Environmental Review
The Finance Committee’s review and recommendation to Council on the FY 2021 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.
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Attachments:
• Attachment A: Resolution Adopting FY 2021 Electric Financial Plan, Transfers, Electric
Reserves Management Practices and Electric Utility Rates
• Attachment B: FY 2021 Electric Utility Financial Plan
• Attachment C: Electric Utility Reserve Management Practices
• Attachment D: FY 2021 Electric Rates
Attachment A
* NOT YET APPROVED *
6055344
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2021 Electric Utility Financial Plan, Including Proposed Reserve Transfers,
Amending the Electric Utility Reserve Management Practices, and Increasing
Electric Rates by Amending Rate Schedules E-1 (Residential Electric Service), E-
2 (Residential Master-Metered and Small Non-Residential Electric Service), E-
2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium
Non-Residential Time of Use Electric Service), E 7 (Large Non-Residential
Electric Service), E-7-G (Large Non-Residential Green Power Electric Service),
E-7 TOU (Large Non-Residential Time of Use Electric Service), E-14 (Street
Lights), E-NSE (Net Metering Net Surplus Electricity Compensation), and E-EEC
(Export Electricity Compensation)
R E C I T A L S
A. 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.
C. 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.
D. On ____, 2020, 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. The Council hereby approves the FY 2021 Electric Utility Financial Plan.
SECTION 2. The Council hereby approves the following transfers as described in the
FY 2021 Electric Utility Financial Plan:
Attachment A
* NOT YET APPROVED *
6055344
a. Up to $4 million from the Supply Operations Reserve to the Hydro Stabilization
Reserve;
b. Up to $5 million from the Supply Operations Reserve to the Electric Special
Projects Reserve;
c. Up to $7 million from the Distribution Operations Reserve to the CIP Reserve.
d. $3.74 million from the Supply Operations Reserve to the Low Carbon Fuel
Standard Reserve.
SECTION 3. 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, 2020.
SECTION 4. 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, 2020.
SECTION 5. 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, 2020.
SECTION 6. 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, 2020.
SECTION 7. 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, 2020.
SECTION 8. 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, 2020.
SECTION 9. 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, 2020.
Attachment A
* NOT YET APPROVED *
6055344
SECTION 10. 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, 2020.
SECTION 11. 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, 2020.
SECTION 12. 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, 2020.
SECTION 13. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-NSE (Net Metering Net Surplus Electricity Compensation) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-NSE, as amended, shall become
effective July 1, 2020.
SECTION 14. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-EEC (Export Electricity Compensation) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-EEC, as amended, shall become effective July 1, 2020.
SECTION 15. 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.
SECTION 16. The Council finds that approving the Financial Plan and amending the
Electric Utility Reserves Management Practices 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. The Council finds that 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.
Attachment A
* NOT YET APPROVED *
6055344
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After reviewing
the staff report and all attachments presented to Council, the Council incorporates these
documents herein and finds that sufficient evidence has been presented setting forth with
specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2021 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2021 TO FY 2025
2 | Page
FY 2021 ELECTRIC UTILITY
FINANCIAL PLAN
FY 2021 TO FY 2025
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 .................................................................................. 9
Section 3: Detail of FY 2021 Rate and Reserves Proposals ....................................................... 9
Section 3A: Rate Design ............................................................................................................... 9
Section 3B: Current and Proposed Rates ..................................................................................... 9
Section 3C: Bill Impact of Proposed Rate Changes .................................................................... 10
Section 3D: Proposed Reserve Transfers ................................................................................... 11
Section 4: Utility Overview .................................................................................................. 12
Section 4A: Electric Utility History ............................................................................................. 12
Section 4B: Customer Base ........................................................................................................ 15
Section 4C: Distribution System ................................................................................................. 15
Section 4D: Cost Structure and Revenue Sources ...................................................................... 16
Section 4E: Reserves Structure ................................................................................................... 17
Section 4F: Competitiveness ...................................................................................................... 18
Section 5: Utility Financial Projections ................................................................................. 19
Section 5A: Load Forecast .......................................................................................................... 19
Section 5B: FY 2015 to FY 2019 Cost and Revenue Trends ........................................................ 21
Section 5C: FY 2019 Results ....................................................................................................... 22
Section 5D: FY 2020 Projections ................................................................................................ 23
Section 5E: FY 2021 – FY 2025 Projections ................................................................................ 23
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 25
3 | Page
Section 5G: Long-Term Outlook ................................................................................................. 31
Section 6: Details and Assumptions ..................................................................................... 33
Section 6A: Electricity Purchases ............................................................................................... 33
Section 6B: Operations .............................................................................................................. 35
Section 6C: Capital Improvement Program (CIP) ....................................................................... 36
Section 6D: Debt Service ............................................................................................................ 37
Section 6E: Equity Transfer ........................................................................................................ 38
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 38
Section 6G: Sales Revenues ....................................................................................................... 39
Section 7: Communications Plan .......................................................................................... 40
Appendices ......................................................................................................................... 42
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 43
Appendix B: Electric Utility Reserves Management Practices ................................................... 47
Appendix C: Description of Electric utility Operational Activities .............................................. 52
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 53
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 FY 2021 - 2025.
This Financial Plan describes how revenues will cover the costs of operating the utility safely over
that time while adequately investing for the future. It also addresses the financial risks facing the
utility over the short term and long term, and includes measures to mitigate and manage those
risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
The Electric Utility’s costs are projected to increase by about 2.5% per year on average from FY
2021 - 2025, as shown in Table 1. The majority of cost is related to electric supply purchases,
which are increasing mainly due increased transmission costs and are projected to grow at an
estimated 2.2% per year on average. Operations and maintenance costs are about one third of
total costs and are projected to increase by about 2.4% per year on average due to both
inflationary as well as salary and benefits increases. Capital improvement costs are currently
projected to grow by about 4.7% per year on average, mainly precipitated by rebuilds of existing
underground districts as well as substation improvements and voltage conversion projects.
Table 1: Electric Utility Expenses for FY 2019 to FY 2025
Expenses
($000)
FY 2019
(act)
FY 2020
(est) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Power Supply
Purchases
89,625 90,210 95,628 97,956 97,645 97,138 100,815
Operations 53,193 52,254 56,390 58,919 60,957 61,898 58,833
Capital Projects 10,770 15,316 21,333 18,086 19,426 29,420 19,298
TOTAL 153,589 157,781 173,350 174,960 178,028 188,456 178,946
To cover these increases in costs, revenues (and therefore rates) need to increase over the next
several years to balance costs and maintain adequate reserves, as shown in Table 2. The table
also compares current rate projections to those projected in last year’s Financial Plan. The rate
projections are slightly higher toward the end of forecast period than last year, primarily due to
slightly increased projected capital improvement spending.
Table 2: Projected Electric Rates, FY 2021 to FY 2025
Projection FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Current 2% 3% 4% 4% 4%
Last Year 4% 4% 4% 3% 2%
The Electric Utility maintains several reserves for the purposes of rate stabilization, such as the
Hydro Stabilization reserve, which is used to mitigate against both dry and wet hydro conditions.
The Electric Utility also has a CIP Reserve which is used to manage cash flow for capital projects,
and fund capital contingencies such as unexpected spikes in CIP spending which do not merit
separate bond financing.
6 | Page
Staff proposes modifications to the Electric Utility Reserves Management Practices. Specifically,
the modifications set a new maximum CIP Reserve guideline level equal to the average annual
(12 month) CIP budget, for 48 months of budgeted CIP expense.1
Staff also proposes that the Electric Utility Reserves Management Practices be amended to
provide that if there are funds in this reserve in excess of the maximum level, staff must propose
in the next Financial Plan to transfer these funds to another reserve, return the funds to
ratepayers, or designate a specific use of the funds for CIP investments that will be made by the
end of the next Financial Planning Period.
Going forward, this reserve will continue to be used to balance annual fluctuations in CIP costs
and will eventually serve the same function for CIP spending that the Operations reserve does
for the fund as a whole. This ideally will allow for more level funding of CIP projects, translating
to a smoother path of rate increases, as well as allowing for easier tracking and accounting of CIP
project expenses.
Appendix B: Electric Utility Reserves Management Practices, reflects the new maximum and
minimum CIP Reserve guideline levels. Because of the fluctuating dollar amounts and timing of
CIP projects budgeted to occur during the forecast period, as well as the potential for new
ongoing projects to be included in the CIP plan in later years, staff recommends that four years
of budgeted CIP be used to calculate the reserve maximum levels rather than the current four
months (120 days) of budgeted expenses. The new minimum CIP Reserve level is 20% of the
maximum CIP Reserve guideline level rather than two months (60 days) of expenses. This
maximum in FY 2021 is $19 million and the minimum in FY 2021 is $3.8 million.
Table 3 shows the projected reserve transfers over the forecast period. Per Council approval, $10
million was transferred from the Electric Special Projects (ESP) Reserve in FY 2018 to the
Operations Reserve to mitigate higher supply costs due to the drought, the costs of new
renewable energy projects coming online and increasing transmission charges. Any transfers
from the ESP Reserve require Council approval. Staff anticipates repaying this loan in two
installments, with $5 million each from the Supply Operations Reserve in FY 2020 and FY 2021.
Staff also proposes creating a new reserve to track revenues earned and expenses incurred via
the City’s participation in the state’s Low Carbon Fuel Standard (LCFS) Program. LCFS revenues
must be used for specific purposes (such as to promote adoption of electric vehicles), which are
set forth in regulations adopted by the California Air Resources Board.2 Staff recommends
transferring the $3.74 million in LCFS revenues unspent since the City began participating in the
LCFS program from the Supply Operations to the Low Carbon Fuel Standard (LCFS) Reserve, which
will provide better accounting transparency going forward.
1 Each month is calculated based upon 1/12 of the annual budget.
2 An overview of CARB’s LCFS program is provided here:
https://ww2.arb.ca.gov/resources/documents/lcfs-basics
7 | Page
Staff also intends to increase the Hydro Stabilization reserve to the target level, unless those
funds are otherwise needed for dry conditions and/or the Supply Operations reserve. Several
transfers from the Supply fund to the Distribution fund are also anticipated to keep both
Operations funds within guideline levels.
In addition, staff is requesting funding of up to $7 million to the CIP Reserve from the Distribution
Operations Reserve. With Council’s approval of the proposed changes to the Reserve
Management Practices described above, the CIP Reserve will reflect annual fluctuations in CIP
expenditures (money spent on actual projects in a given year). CIP expenditures are currently
reflected in the Operations Reserve. Staff anticipates, once the CIP Reserve has an adequate
ending balance in either FY 2021 or FY 2022, to annually fund the CIP reserve with an amount
based on average anticipated CIP spending for that year, and have any cost savings or over-runs
be reflected in the CIP Reserve instead of the Operations Reserve, as described above. This will
allow for better tracking and accounting of CIP related funds.
8 | Page
Table 3: Reserves Starting and Ending Balances, Revenues, Expenses, Transfers To/(From)
Reserves, Operations and Capital Reserve Guideline Levels for FY 2020 to FY 2025 ($000)
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Starting Reserve Balances
1 Supply Operations 28,709 30,673 23,773 24,870 24,666 25,275
2 Distribution Operations 16,536 10,758 10,712 11,865 11,714 11,968
3 CIP 880 7,880 11,880 11,880 11,880 11,880
4 Electric Special Projects 41,665 46,665 49,665 49,665 49,665 39,665
5 Hydro Stabilization 11,400 15,400 19,000 19,000 19,000 19,000
6 Low Carbon Fuel Standard (LCFS)- 3,740 3,340 2,140 1,140 1,140
Revenues
7 Supply 117,499 117,603 114,725 113,373 113,429 112,227
8 Distribution 59,204 60,948 62,919 64,807 67,314 69,933
Transfers
9 Supply Operations (12,740) (16,600) (4,000) (3,000) (2,000) -
10 Distribution Operations (7,000) 4,000 4,000 3,000 2,000 -
11 CIP 7,000 4,000 - - - -
12 Electric Special Projects 5,000 5,000 - - - -
13 Hydro Stabilization 4,000 3,600 - - - -
14 Low Carbon Fuel Standard 3,740 - - - - -
Capital Program Contribution
15 Distribution Operations Reserve - - - - - -
16 CIP Reserve
Expenses
17 Supply Expenses (102,794) (107,903) (109,628) (110,578) (110,820) (110,601)
18 Distribution Non-CIP Expenses (42,665) (43,661) (47,680) (48,532) (39,640) (50,394)
19 Planned CIP (15,316) (21,333) (18,086) (19,426) (29,420) (19,298)
20 ESP funded - (2,000) - - (10,000) -
21 Hydro funded - - - - - -
22 LCFS funded - (400) (1,200) (1,000) - -
Ending Reserve Balance
1 + 7 + 9 + 17 Supply Operations 30,673 23,773 24,870 24,666 25,275 26,901
2 + 8 + 10 +
15 + 18 + 19 Distribution Operations 10,758 10,712 11,865 11,714 11,968 12,208
3 + 11 + 16 +
19 CIP 7,880 11,880 11,880 11,880 11,880 11,880
4 + 12 + 20 Electric Special Projects 46,665 49,665 49,665 49,665 39,665 39,665
5 + 13 + 21 Hydro Stabilization 15,400 19,000 19,000 19,000 19,000 19,000
6 + 14 + 22 Low Carbon Fuel Standard 3,740 3,340 2,140 1,140 1,140 1,140
Operations Reserve Guidelines (Supply)
23 Minimum 16,898 17,803 18,218 18,342 18,217 18,181
24 Maximum 33,795 35,607 36,437 36,683 36,434 36,362
Operations Reserve Guidelines (Distribution)
25 Minimum 8,194 8,682 9,098 9,324 9,542 9,771
26 Maximum 12,890 13,822 14,494 14,860 15,217 15,586
CIP Reserve Guidelines
27 Minimum 2,518 3,813 3,811 3,900 3,950 4,031
28 Maximum 5,036 19,066 19,057 19,500 19,752 20,153
9 | Page
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2020:
1. Approve a transfer of up to $4 million from the Supply Operations Reserve to the Hydro
Stabilization Reserve.
2. Approve a transfer of up to $5 million from the Supply Operations Reserve to the ESP
reserve.
3. Approve a transfer of up to $7 million from the Distribution Operations to the Capital
Improvement Program Reserve.
4. Approve a transfer of $3.74 million from the Supply Operations Reserve to the LCFS
Reserve.
Staff proposes the following actions for the Electric Utility in FY 2021:
1. Increase rates effective July 1, 2020 for a 2% increase in system average rates.
2. Amend the Electric Utility Reserves Management Practices relating to the CIP, LCFS and
Rate Stabilization Reserves reflected in Appendix B, Section 10 and described below in
Section 5F: Risk Assessment and Reserves Adequacy
SECTION 3: DETAIL OF FY 2021 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The Electric Utility’s rates are evaluated and implemented in compliance with cost of service
requirements set forth in the California Constitution and applicable statutory law. The proposed
increase discussed in this Financial Plan is based on staff’s assessment of the financial position of
the Electric Utility, and updated using the methodology from the “City of Palo Alto Electric Cost
of Service and Rate Study”3 drafted by EES Consulting, Inc. in 2015/16. Staff updated the model
with updated sales and budget projections, including projected transmission and distribution
costs, power supply costs and billing data, in order to update individual cost of service model
components and determine the proposed rates. The COSA is also 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, 2019, when CPAU increased electric rates by
8%. Table 4, below, summarizes the current and proposed rates for the four largest customer
classes. The Electric Utility also has specialty rates for smaller groups of customers. These include
variations on its primary rates, such as time of use rates and solar net metering. Staff proposes
an 2% overall increase in average rates. Different customer classes may see different percentage
changes to their rates, based upon their usage of the system and cost to serve each group.
3 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
10 | Page
Table 4: Current and Proposed Electric Rates
Current Rates
Proposed Rates
(7/1/20)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.13757 0.14087 0.00330 2.4%
Tier 2 Energy ($/kWh) 0.19367 0.19609 0.00242 1.2%
Minimum Bill ($/day) 0.3283 0.3344 0.0061 1.9%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.20853 0.21430 0.00577 2.8%
Winter Energy ($/kWh) 0.14624 0.14792 0.00168 1.1%
Minimum Bill ($/day) 0.8359 0.8536 0.0177 2.1%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.12848 0.13792 0.00944 7.3%
Winter Energy ($/kWh) 0.09946 0.10687 0.00740 7.4%
Summer Demand ($/kW) 28.91 28.14 (0.77) -2.7%
Winter Demand ($/kW) 18.97 14.64 (4.33) -22.8%
Minimum Bill ($/day) 17.2742 17.4346 0.1604 0.9%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.11432 0.11689 0.00257 2.2%
Winter Energy ($/kWh) 0.07738 0.08259 0.00521 6.7%
Summer Demand ($/kW) 30.69 28.34 (2.35) -7.7%
Winter Demand ($/kW) 17.05 17.18 0.13 0.8%
Minimum Bill ($/day) 42.3648 42.7994 0.4346 1.0%
The overall rate change for the residential class based on the class’ average usage profile is
roughly 1.9%. Residential usage has been fairly consistent from last year, leading to a rate
increase that’s the same as the overall increase. Small commercial (E-2) loads have decreased
over time, but their relative demand on the system tends to be less efficient (e.g. higher peak
usage relative to average usage), leading to a slightly higher overall increase (2.1%). Medium
commercial usage has also decreased, but their load factor has improved (their demand has
decreased relative to energy consumption), meaning a more efficient use of the overall system,
and thus a lower 1.2% overall rate increase for the class of is required. Large commercial usage
has increased as a sector, and demand efficiencies require an overall increase of 1.1%.
SECTION 3C: BILL IMPACT OF PROPOSED RATE CHANGES
Table 5 shows the impact of the proposed July 1, 2020 rate changes on the residential and non-
residential bills for various consumption levels
11 | Page
Table 5: Impact of Proposed Electric Rate Changes on Customer Bills
Rate Schedule
Usage (kwh/mo)
Bill under
Current
Rates ($/mo)
Bill Under Rates
Proposed 7/1/20
($/mo)
Change
$/mo %
E-1 (Residential) 300 $ 41.27 $42.26 $0.99 2.4%
(Summer Median)
365 52.18 53.35 1.17 2.2%
(Winter Median)
453 69.22 70.61 1.39 2.0%
650 107.37 109.24 1.86 1.7%
1200 213.89 217.09 3.19 1.5%
E-2 (Small Non-
Residential) 1,000 178 182 4 2.1%
E-4 (Medium
Non-Residential) 160,000
27,541 27,977 436 1.6%
E-7 (Large Non-
Residential
500,000 71,534 72,344 810 1.1%
2,000,000 286,135 289,374 3,239 1.1%
SECTION 3D: PROPOSED RESERVE TRANSFERS
In FY 2018, Council approved a $10 million loan from the Electric Special Projects (ESP) reserve,
and this financial plan includes full repayment by FY 2021. The pace of payback may be
moderated based upon the general financial health of the electric fund. This financial plan
assumes repayment of $5 million in FY 2020 and FY 2021.
In addition, and based upon the actual ending balances of the Supply and Distribution Operations
Reserves, staff intends to put additional funds in both the Hydro Stabilization and Capital
Improvement reserves, to keep their balances within their respective guideline levels and to fund
for contingencies, such as future dry hydro conditions as well as projected higher future CIP needs
and costs.
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
12 | Page
Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 20197 to FY 20258
Ending Reserve
Balance ($000)
FY 2019
(Act.) FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Re-appropriations 7,376 - - - - - -
Commitments 4,269 3,911 3,911 3,911 3,911 3,911 3,911
Low Carbon Fuel
Standard (LCFS) - 3,740 3,340 2,140 1,140 1,140 1,140
Underground Loan 727 727 727 727 727 727 727
Public Benefits 810 1,402 1,935 2,315 2,534 2,642 2,642
Special Projects 41,665 46,665 49,665 49,665 49,665 39,665 39,665
Hydro Stabilization 11,400 15,400 19,000 19,000 19,000 19,000 19,000
Capital 880 7,880 11,880 11,880 11,880 11,880 11,880
Rate Stabilization - - - - - - -
Operations 45,244 41,431 34,485 36,735 36,380 37,243 39,109
Unassigned - - - - - - -
TOTAL 104,636 121,155 124,942 126,372 125,237 116,207 118,073
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
13 | Page
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
• 1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
• 1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement program
for its underground system in the early 1990s.
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 Utility4 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
4 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
14 | Page
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 the Council adopted a goal of achieving 20% of its energy supply from
renewables by 2015. Subsequently the City 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.
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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 29,800 customers
connected to the electric system,
25,700 (86%) of which are residential
and 4,100 (14%) of which are non-
residential. Residential customers
consumed 148 gigawatt-hours (GWh)
in FY 2019, approximately 17% of the
electricity sold, while non-residential
customers consumed 83% or 735 GWh.
Residential customers use electricity
primarily for lighting, refrigeration,
electronics, and air conditioning.5 Non-residential customers use the majority of their electricity
for cooling, ventilation, lighting, office equipment (offices), cooking (restaurants), and
refrigeration (grocery stores).6
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 70 customers on the E-7 rate schedule) account
for around 43% of CPAU’s sales. The next largest customer group (the 890 non-residential
customers on the E-4 rate schedule) represents another 34% of sales. In total, that means that
about 3% of customers account for nearly three quarters of the electric load.
SECTION 4C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 472 miles of
distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are
underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line
transformers, around 1,100 underground and substation transformers, and the associated
electric services (which connect the distribution lines to the customers’ homes and businesses).
These lines, substations, transformers, and services, along with their associated poles, meters,
and other associated electric equipment, represent the vast majority of the infrastructure used
to deliver electricity in Palo Alto.
5 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
6 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
Figure 1: Customer Consumption By Class (FY 2019)
17%
6%
34%
43%Residential
Small Comm.
Med. Comm.
Large Comm.
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SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 58% of the Electric Utility’s
costs in FY 2019. Operational costs
represented roughly 35%, and
capital investment was responsible
for the remaining 7%. 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 2025.
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 76% of its revenue from sales of
electricity and the remainder from
connection fees, interest on reserves, cost recovery transfers from other funds for shared
services provided by the electric utility, accounting entries that reflect things such as CPAU’s
participation in a pre-funding program associated with its contract with WAPA, revenues from
Figure 2: Cost Structure (FY 2019)
58%35%
7%
Commodity Supply
Operations
Capital
Figure 3: Hydroelectric Variability (FY 2019)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 4: Revenue Structure (FY 2019)
76%
24%
Sales of Electricity
Other Revenue
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sales of surplus hydroelectric energy during wet years, as well as LCFS and Cap and Trade
revenues. Appendix A: Electric Utility Financial Forecast Detail shows more detail on the utility’s
cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 960 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 is useful for rate design as the
nature of utility services evolves in response to higher penetrations of distributed generation.
Thus, individual reserves may reside within a particular fund (for instance, Electric Special
Projects is under Electric Supply) or be included within both funds (there are both Supply and
Distribution Reserves for Commitments).
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 re-appropriated
by the City Council, nearly all of which are capital projects. Most City funds, including the
General Fund, have a Re-appropriations Reserve. 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 fund projects
with significant impact that provide demonstrable value to electric ratepayers.
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• Hydroelectric Stabilization Reserve: This contingency reserve is used for managing
additional costs due to below average hydroelectric generation, or to hold surpluses
resulting from above average hydroelectric generation.
• Underground Loan Reserve: This reserve is an accounting tool used to offset receivables
associated with loans made through the underground loan program. It is adjusted
according to principal payments made on those loans.
• Low Carbon Fuel Standard (LCFS) Reserve: This reserve tracks revenues earned via the
sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City,
in accordance with California’s Low Carbon Fuel Standard program.
• 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 can be used to accumulate
funds for future expenditure on CIP projects, as well as to manage cash flow for ongoing
capital projects. This reserve can also act as a contingency reserve for unforeseen capital
expenses. This type of reserve is used in other utility funds (Water, 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 2019 was
$710 under current CPAU rates, about 34% lower than the annual bill for a PG&E customer with
the same consumption and approximately 20% 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 February 1, 2020.
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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, 2020 rates.
However, even with the proposed rate increases, Palo Alto’s residential bills will remain
substantially below PG&E’s current rates, but above Santa Clara’s.
Table 6: Residential Monthly Electric Bill Comparison (Effective 2/1/20, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(March)
300 41.27 70.74 36.96
453 (Median) 69.22 106.82 56.50
650 107.37 164.73 81.66
1200 213.89 327.95 151.91
Summer
(July)
300 41.27 72.75 36.96
(Median) 365 52.18 92.04 45.27
650 107.37 176.62 81.66
1200 213.89 339.83 151.91
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, but above Santa Clara’s.
Table 7: Commercial Monthly Electric Bill Comparison (2/1/20, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 178 263 190
160,000 27,541 32,240 21,905
500,000 71,534 93,260 64,480
2,000,000 286,135 394,490 269,230
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 5 shows a 34-year history of Palo Alto electricity consumption. Average electricity
consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then
electricity consumption has declined slowly as a result of a continuing focus on energy efficiency,
as well as the adoption of more stringent appliance efficiency standards and energy standards in
building codes. Recently, some larger commercial customers have relocated operations or shifted
to more commercial type usage. It is unknown how long this trend may continue.
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Figure 3: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2028. The forecast assumes a
1.5% demand drop per year through FY 2025, continuing the pattern seen over the last several
years. These projections will be revised if continuing sales patterns indicate further declines, or
changes in customer mix occur.
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Figure 4: Forecasted Electricity Consumption
SECTION 5B: FY 2015 TO FY 2019 COST AND REVENUE TRENDS
As shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail, the
annual expenses for the Electric Utility remained fairly stable between FY 2015 and FY 2017, but
increased in FY 2018. On the capital side, the large Upgrade Downtown CIP project got underway
in FY 2018, which was a much larger project than usual. Electric supply costs increased as new
renewable projects came online, and transmission costs rose and have continued to rise as
improvements are made to the overall California grid.
Section 6A: Electricity Purchases discusses the factors influencing Electric Utility expenses. Since
FY 2012, total expenses for the utility have included the costs of renewable resources coming
online. In FY 2014 through FY 2015 commodity costs were higher due to lower than average
output from hydroelectric resources. Transmission costs have increased, as projected in prior
financial plans. Better than average hydro conditions in FY 2019 led to lower than expected
generation expenses as well as better than expected surplus energy revenues.
Commodity costs have increased, on average, by about 3% per year over this timeframe.
Operations costs have increased by about 4% annually on average. Revenues have increased on
average by about 5% per year over this period, although FY 18 sales revenues were lower than
projected due to declining sales.
Actual Projection
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2019 and Projections through FY 2025
SECTION 5C: FY 2019 RESULTS
FY 2019 saw slightly better sales than expected, but the largest revenue increase were surplus
energy sales revenues resulting from better than forecast hydro conditions as well as higher
market prices than usual. In addition, operations and capital improvement costs were lower than
projected. Overall reserves were higher by $19.3 million, which brings the Operations Reserves
to above target level and is allowing the Electric fund to start repaying loans taken from the
Electric Special Projects Reserve, as well as fund the CIP reserve.
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Table 8 FY 2019, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues higher than forecast ($1,914) Revenue increase
Surplus sales, interest, and other income higher
than expected
(11,861) Revenue increase
Lower operating expense (3,675) Cost decrease
Lower capital expense (1,872) Cost decrease
Net Cost / (Benefit) of Variances ($19,322)
SECTION 5D: FY 2020 PROJECTIONS
Last year, staff recommended (and Council approved) an 8% rate change for July 1, 2019. Sales
are still declining but not as fast as projected earlier, and staff is estimating $1.9 million higher
sales for FY 2020 prior to Covid-19 pandemic. Other revenues are projected to be about $6.1
million higher, primarily from good hydro and market price conditions continuing into FY 2020
and increasing surplus sales. Revenues from these surplus sales would be used to offset costs by
approximately $5.4 million. A revised operations cost outlook reduced projected expenses by
about $3 million compared to FY 2019.
Table 9 FY 2019, Change in Projected Results, 2020 Forecast vs. 2019 Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues increase (1,868) Revenue increase
Wholesale and other revenues higher than
forecast
(6,056) Revenue increase
Purchased electricity costs (5,405) cost decrease
Operations costs (3,048) cost decrease
Net Cost / (Benefit) of Variances ($16,378)
SECTION 5E: FY 2021 – FY 2025 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 between 2% to 4% are projected to keep
revenues in line with expenses over the next five years. Rising electricity purchase costs are the
primary contributor to the increases. Electricity purchase costs are increasing substantially, as
transmission costs rise to make improvements 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 are higher due to the rebuilding of existing underground districts,
substation and line voltage upgrades. The City is also evaluating the cost and scope of other
system resiliency projects, such as pole replacements, which may increase costs as well as rates
in the future.
The forecast also assumes the Smart Grid project to bring advanced metering to the Electric, Gas
and Water utilities will start with $5 million in FY 2021 and additional $7 million in FY 2022 and
FY 2023. Funding for this project will come out of the Electric Special Projects reserve, as can be
seen in Figure 8 below and in Appendix A: Electric Utility Financial Forecast detail.
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Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund
Reserves) and Figure 9 (for Distribution Fund Reserves), below.
Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2019 and Projections through FY 2025
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Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2019 and Projections through FY 2025
SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two primary contingency reserves, the Supply Operations
Reserve and the Distribution Operations Reserve. In the past, the Supply and Distribution funds
had Rate Stabilization Reserves (RSR) but both have been drawn to zero, as approved in prior
financial plans. In addition, the Electric Utility has a Hydro Stabilization reserve, an Electric Special
Projects reserve and a Capital reserve, which can be utilized with prior Council approval.
This Financial Plan maintains reserves above the reserve minimum for the Distribution
Operations Reserve throughout the forecast period. Reserve levels also exceed the short-term
risk assessment level for the Distribution Fund. The Supply Operations Reserve is also currently
within guideline levels.
There are a variety of risks associated with the Supply Fund as are shown in Table 10. Because of
the high range of uncertainty in energy price predictions more than three years in the future, this
risk assessment is only performed for the first two fiscal years of the forecast period. It is
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important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 10 is very low.
Table 10: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of
Adverse
Outcomes (M$)
Estimates of
Adverse
Outcomes (M$)
FY 2021 FY 2022
1. Load Net Revenue 3.3 3.3
2. Hydro Production:
Western & Calaveras 6 7.9
3. Renewable Production:
Landfill & Wind & Solar 1.8 1.7
4. Carbon Neutral Cost 1.5 1.5
5. Market Price 0.8* 0.9**
6. Local Capacity 1.2 1.6
7. Transmission/CAISO 3.8~ 3.9~
8. Plant Outage 1.0 1.0
9. Western Cost 2.0 2.4
10. Regulatory & Legal 0.0 0.0
11. Supplier Default 0.2† 0.2†
Electric Supply Fund Risks $ 21.6 million $ 24.4 million
Of the risks faced by the Electric Utility’s Supply Fund, the risk of a dry year with very low
hydroelectric output is normally the largest, accounting for nearly one third the total cost of all
adverse outcomes. Since the utility’s costs for its hydroelectric resources are almost entirely
fixed, costs do not decline when the output of those resources are low, but the utility needs to
buy power to replace the lost output. The converse happens when hydroelectric output is higher
than average.
Of the remaining risks for FY 2021, $3.8 million is related to the projected costs if transmission
cost increases are higher than staff’s current forecast. $3.3 million is related to the uncertainty
with surplus energy sales revenues, and uncertainties with regards to renewables production as
well as possible adjustments from Western account for about $2 million each.
As shown in Figure 10, staff projects the Supply Operations Reserve to stay within the reserve
guideline levels throughout the rest pf the forecast period. Figure 11 shows that the combined
Hydro Stabilization, Supply Rate Stabilization and Supply Operations Reserves are projected to
be above what is needed for the risk assessment level.
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Figure 10: Electric Supply Operations Reserve Adequacy
28 | Page
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 2025. As shown in Figure 12, the Distribution Operations Reserve will stay within the
reserve guidelines over the course of the forecast period. The risk assessment includes the
revenue shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
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Table 11: Electric Distribution Fund Risk Assessment ($000)
FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Total non-commodity revenue $57,845 $61,683 $65,779 $69,494 $73,422
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $4,565 $4,868 $5,192 $5,485 $5,795
CIP Budget $19,333 $18,086 $19,426 $19,420 $19,298
CIP Contingency @10% $1,933 $1,809 $1,943 $1,942 $1,930
Total Risk Assessment value $6,499 $6,677 $7,134 $7,427 $7,725
Figure 12: Electric Distribution Operations Reserve Adequacy
The Electric Utility also has a Capital Improvement Program (CIP) Reserve that acts as a reserve
for short term capital contingencies or as a place to set aside funds for large, one-time projects
that the Utilities would otherwise need to debt-fund. In the future, staff would also like to use
this reserve to manage cash flow for capital projects on an ongoing basis as well, and as such staff
proposes modifications to the Electric Utility Reserves Management Practices. Specifically, the
modifications would set a new maximum CIP Reserve guideline level equal to the average annual
30 | Page
(12 month) CIP budget, for 48 months of budgeted CIP expense.7 Staff also proposes that the
Electric Utility Reserves Management Practices be amended to provide that if there are funds in
this reserve in excess of the maximum level, staff must propose in the next Financial Plan to
transfer these funds to another reserve, return the funds to ratepayers, or designate a specific
use of the funds for CIP investments that will be made by the end of the next Financial Planning
Period.
Figure 13 below reflects the new maximum and minimum CIP Reserve guideline levels, starting
in FY 2021. Because of the fluctuating annual dollar amounts and timing of CIP projects budgeted
to occur during the forecast period, as well as the potential for new ongoing projects to be
included in the CIP plan in later years, staff recommends that four years of budgeted CIP be used
to calculate the reserve maximum levels rather than the current four months (120 days) of
budgeted expenses. The new minimum CIP Reserve level is 20% of the maximum CIP Reserve
guideline level rather than two months (60 days) of expenses. This maximum in FY 2021 is $19
million and the minimum in FY 2021 is $3.8 million.
The 2021 Financial Plan anticipates funding the CIP Reserve from the Distribution Operations
Reserve by $7 million in FY 2020. In future years, the CIP Reserve will reflect actual fluctuations
in CIP expenditures (money spent on actual projects in a given year). CIP expenditures are
currently reflected in the Operations Reserve. Staff is anticipating, once the CIP Reserve has an
adequate ending balance in either FY 2021 or FY 2022, to annually fund the CIP reserve with an
amount based on average anticipated CIP spending for that year (currently estimated at $18 to
$19 million annually, but subject to change as new projects are added), and have any cost savings
or over-runs be reflected in the CIP Reserve instead of the Operations Reserve, as described
above. This will allow for better transparency and accounting of CIP related funds, will address
uneven annual funding associated with ongoing CIP projects, and offer a funding source for one-
time or immediately needed projects. Having the reserve guidelines in place will ensure the
reserve has sufficient funding for budgeted CIP as fluctuating annual amounts of capital
investment occur going forward.
Staff is currently requesting Council to approve the $7 million transfer from the Distribution
Operations Reserve to the CIP Reserve in FY 2020 and expects to request Council approval for
the other transfers to the CIP Reserve in the FY 2022 Electric Utility Financial Plan once the year-
end FY 2020 reserve balances are known.
Figure 13 shows the projected CIP Reserve balances and guideline levels for FY 2021 through FY
2025, as well as the current reserve and guidelines through FY 2020.
7 Each month is calculated based upon 1/12 of the annual budget.
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Figure 13: Electric CIP Reserve Adequacy
SECTION 5G: LONG-TERM OUTLOOK
This forecast covers the period from FY 2021 through FY 2025, but various long-term
developments may create new costs for the utility over the next 10 to 35 years. While it is
challenging to accurately forecast the impact these events will have on the utility’s costs, it is
32 | Page
worth noting them as future milestones and keeping them in mind for long-term planning
purposes.
For the supply portfolio, the 2020s will see a number of notable events. The contract with
Western for power from the CVP will expire in 2024. Determining the future relationship with
Western after 2024 will be important in the years leading up to the contract expiration, especially
because this resource represents nearly 40% of the electric portfolio, and is the utility’s largest
source of carbon-free electricity. The utility’s three earliest and lowest cost renewable contracts
will also begin expiring around that time, with the first contract expiring in 2021 and the last in
2028. These three contracts, plus one more expiring in 2030, currently provide 17% to 18% of the
energy for the utility’s supply portfolio at prices under $65 per megawatt-hour (MWh). It is
difficult to know what renewable energy prices will be when those contracts expire. Although
recent prices have been in that range (or even lower), and costs may decrease in the future,
current renewable projects also benefit from a wide range of tax 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
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some of the costs of these new lines and resources. CPAU is also currently investigating installing
a second transmission interconnection for Palo Alto, which could be funded by the Electric Special
Projects Reserve.
Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these factors
may begin to create notable increases in electric consumption and have a variety of impacts on
the distribution system. As housing stock is turned over, however, stricter building codes may
help to counteract load growth, as may increasing numbers of rooftop solar installations. The
utility has already started to take some of these factors into account in its long-term planning
processes, but will need to continue to incorporate them into its planning methodologies.
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.
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 FY2015 was 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.
34 | Page
Figure 14: Electricity Supply by Source
Figure 15 shows the historical and projected costs for the electric supply portfolio,8 as well as
average and actual hydroelectric generation.9 Electric supply costs increased in FY 2013, FY 2014,
and FY 2015 due to the drought, which reduced the amount of generation from hydroelectric
resources. Costs decreased slightly in FY 2016 due to better than expected market purchase
costs, and FY 2017 and FY 2018 had lower hydroelectric costs. Renewable energy costs assumed
a larger portion of cost as various renewable projects came online to fulfill the City’s carbon
neutral and RPS goals, although some of the older, higher priced contracts will start expiring as
early as FY 2022. The current market outlook is that newer renewables projects should come in
at lower costs. Transmission charges are also projected to increase as new transmission lines are
built throughout California to accommodate new renewable projects. In total, electric supply
costs are projected to increase to about $86 million by FY 2025, at which point all currently
contracted renewable projects will be online. Supply costs are only projected to change slightly
in subsequent years.
8 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
9 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.
35 | Page
Figure 15: Electric Supply Portfolio Costs, Historical and Projected
SECTION 6B: OPERATIONS
CPAU’s Electric Utility operations include the following activities:
• Administration, including financial management of charges allocated to the Electric Utility
for administrative services provided by the General Fund and for Utilities Department
administration, as well as debt service and other transfers. Additional detail on Electric
Utility debt service is provided in Section 6D (Debt Service)
• Customer Service
• Engineering work for maintenance activities (as opposed to capital activities)
• Operations and Maintenance of the distribution system; and
• Resource Management
Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 2014 to FY 2018, overall Operations costs have risen annually by about 3% on average.
Starting in FY 2020 and continuing for several years, Operations and Maintenance costs are
36 | Page
increased mainly due to the introduction of a contract line crew to help while the Utility is
understaffed. These costs may be reduced depending on how much work is needed, and may be
phased out as longer-term employees are gained.
Figure 16: Historical and Projected Electric Utility Operational Costs
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
Staff projects CIP spending for FY 2020 through FY 2025 to be consistent with last year’s forecast,
though there is a slight shift in the funding by project category. There will be a reduction in
funding for Undergrounding as current projects are completed; there will be an increase in
funding for Underground Rebuilding and 4/12kV Conversion as improvements are made to the
system in portions of the Crescent Park/Duveneck/St. Francis/Community Center/Leland
Manor/Garland neighborhoods to facilitate rebuild of the Hopkins Substation; there will be an
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, wildland fire mitigation, 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
37 | Page
and gas funds, but it might also be possible to use bond financing. That project has tentatively
slated to start in FY 2021 with an initial study, the main body of work tentatively slated to start
in FY 2024.
Excluding the one-time projects listed above, the CIP plan for FY 2020 to FY 2025 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 2021 Utilities
Capital Budget. Figure 17 shows the FY 2020 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 17: Electric Utility CIP Spending ($000)
SECTION 6D: DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently makes
payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax Credit
Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction costs
of solar demonstration projects at the Municipal Services Center, Baylands Interpretive Center,
and Cubberley Community Center. The capacity of these projects totaled 250 kW. In exchange
for funding part of the construction costs, the Electric Utility receives the RECs from these
projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are interest
free (the investors receive a tax credit from the federal government). This bond issuance is
secured by the net revenues of the Electric Utility. Debt service for this bond continues through
2021, and for the financial forecast period is as follows:
Table 12: Electric Utility Debt Service ($000)
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
2007 Clean Renewable
Energy Bonds 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.
Project Category
Current
Budget *
Spending,
Curr. Yr.
Remain.
Budget **Committed FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
One Time Projects 4,456 (310) 4,146 265 4,000 2,000 2,000 11,000 -
Reliability 3,531 (1,923) 1,609 1,042 4,020 5,690 4,040 3,000 2,563
Undergrounding 1,548 (35) 1,513 126 - 56 3,750 250 -
4/12 Kv Conversion 1,830 (7) 1,823 - 166 50 120 2,120 1,820
Underground Rebuild 4,955 (24) 4,931 17 2,110 250 400 4,050 461
Ongoing 3,766 (1,051) 2,715 1,169 5,830 4,445 3,805 3,605 3,672
Customer Connections 2,400 (1,515) 885 352 2,550 2,700 2,400 2,400 2,472
Total 22,486 (4,863) 17,623 2,971 18,676 15,191 16,515 26,425 10,987
* Includes unspent funds from previous years carried forward or re-appropriated into the current fiscal year.
** Equal to CIP Reserves (Reserve for Re-appropriations + Reserve for Commitments)
38 | Page
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 13: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Electric Utility’s:
Net Revenues Reserves
1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water $1,457 No Yes
*Net of Federal interest subsidy
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.10 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 one quarter
comes from other sources. Of these other sources, about 50 to 60% represents wholesale
revenues of surplus energy sales. These revenues may offset electric supply purchase costs,
smooth rate increases, or fund reserves or other costs. 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 2019 these sources represented roughly 24% of revenue from sources other than electricity
sales. The remaining FY 2019 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.
Connection fee revenues are collected to offset costs incurred in setting up new connections and
are pass-through in nature. Staff projects carbon allowance and interest income revenues to stay
relatively stable through the forecast period. However, both of these revenue sources are subject
10 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.
39 | Page
to some uncertainty. This forecast assumes the program State’s cap-and-trade program will
remain in place with similar program design following 2020, but that may not be the case. CARB
is in the process of establishing post-2020 rules.
The forecast for interest income assumes current interest rates continue and there are no major
reserve reductions aside from what is anticipated in this Financial Plan. If interest rates rise,
interest income could increase, and if reserves decrease (due to drought or a withdrawal from
the ESP reserve for a major project), interest income would decrease.
SECTION 6G: SALES REVENUES
The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7
provide the basis for sales revenue projections. As discussed in Section 5A, sales revenues for this
utility have been decreasing due to load reduction, but are helped by the mild climate in Palo
Alto. Palo Alto is a built out City, so the opportunities for increased load growth are limited to the
existing footprint of commercial structures and incremental growth in population. As utilization
of existing spaces changes, and energy efficiency measures continue, Palo Alto could see greater
load loss. Increased loads from electric vehicles and the electrification of households may
increase loads somewhat.
40 | Page
SECTION 7: COMMUNICATIONS PLAN
The fiscal year (FY) 2021 Electric Utility communications strategy covers these primary areas:
efficiency services and beneficial electrification; renewables and carbon neutral portfolio; capital
improvement, operations and maintenance for infrastructure safety and reliability; and utility
rates and cost containment measures. The City of Palo Alto Utilities (CPAU) communication
methods include use of the Utilities website, utility bill inserts, messaging on utility bills and
envelopes, email newsletters, print and digital ads in local publications, videos and participation
in community outreach events.
In FY 2021, CPAU is proposing a two (2) percent increase in electric utility rates. The percentage
increase is lower than originally anticipated, as the FY 2020 year-end Operations Reserves are
projected to be within guideline levels, and other reserve funds are projected to be healthier as
well at FY 2020 year-end. This will allow CPAU to begin payback of the $10 million loan from the
Special Projects Reserve and add $4 million to the Hydro Stabilization Reserve. CPAU’s goal is to
bring rates in line with costs, using reserves to smooth rate changes over the next few years.
Communications will focus on electric supply and distribution cost drivers, such as increased
transmission charges, capital investment due to system age, and a substantial rise in construction
and contract labor costs. CPAU is actively working to make cost containment an ongoing priority
and part of an annual cycle, consistent with the newly approved Utilities Strategic Plan. Despite
some rising costs and this year’s proposed rate increase, CPAU’s electric utility rates remain lower
than the neighboring community average, including for municipal and investor-owned utilities
(PG&E). The average Palo Alto resident’s monthly electric bill is around 34% below the PG&E
average. Keeping costs low is one of the benefits CPAU offers its customers as a public utility
provider.
CPAU customers also benefit from local control and policy setting, and community values-driven
programs and services, including the decision to go carbon neutral in 2013. Palo Alto’s major
renewable energy purchase agreements contribute to our utility’s long-term energy security and
commitment to sustainability. Power purchase agreements in recent years have also allowed
CPAU to procure long-term renewable electric supplies at low costs. CPAU will highlight these
environmental attributes and value in our communications.
Programs such as the Home Efficiency Genie and commercial energy efficiency audits help
residents and businesses better understand energy usage, activities and/or upgrades they can
implement to improve efficiency and keep utility costs low. CPAU is exploring opportunities to
help customers electrify homes, buildings, and personal transportation. Rebates for residential
appliances such as heat pump water heaters and electric vehicle charging stations for multi-
family and non-profit facilities are incentivizing more and more customers to take action. Staff
are piloting programs to explore electrification technologies in other applications as well. These
efforts are in line with the City’s Sustainability and Climate Action Plan goals to reduce
greenhouse gas emissions. CPAU will also be launching an upgraded version of its online utility
41 | Page
account services portal this year, which can provide customers with direct access and more
information about utility account and consumption data.
42 | Page
APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
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APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
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1 FISCAL YEAR FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
2
3 ELECTRIC LOAD 162 164
4 Purchases (MWh)979,005 977,292 945,703 925,329 917,891 884,781 878,569 863,387 856,895 841,649 835,076
5 Sales (MWh)936,773 937,157 917,687 899,997 884,322 864,778 851,806 839,029 826,443 814,047 801,836
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1158$ 0.1156$ 0.1249$ 0.1413$ 0.1487$ 0.1624$ 0.1641$ 0.1665$ 0.1702$ 0.1743$ 0.1786$
9 Change in System Average Rate 0%0%10%13%5%9%1%1%2%2%2%
10 Change in Average Residential Bill -5%3%11%11%6%8%1%-1%4%2%2%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)- - - - - - - - - - -
14 Commitments (Non-CIP)3,164,000 3,102,055 3,777,205 2,970,955 3,725,000 3,910,695 3,910,695 3,910,695 3,910,695 3,910,695 3,910,695
15 Restricted for Debt Service - - - - - - - - - - -
16 Emergency Plant Replacement 1,000,000 - - - - - - - - - -
17 Low Carbon Fuel Standard (LCFS) Reserve 329,000 - - - - - 3,740,000 3,340,000 2,140,000 1,140,000 1,140,000
18 Underground Loan Reserve 734,000 730,000 729,000 730,147 730,147 726,659 726,659 726,659 726,659 726,659 726,659
19 Public Benefits Reserves 2,064,000 2,574,000 1,839,000 681,330 681,330 809,700 1,401,586 1,935,396 2,438,211 2,781,240 3,012,007
20 Electric Special Projects Reserve 51,838,000 51,837,855 51,837,855 51,837,855 41,837,855 41,664,855 46,664,855 49,664,855 49,664,855 49,664,855 39,664,855
21 Hydro Stabilization Reserve - 17,000,000 11,400,000 11,400,000 11,400,000 11,400,000 15,400,000 19,000,000 19,000,000 19,000,000 19,000,000
22 Capital Reserves - - - 879,964 879,964 879,964 7,879,964 11,879,964 11,879,964 11,879,964 11,879,964
23 Rate Stabilization Reserves 70,049,000 14,410,840 9,010,840 9,010,840 9,010,840 - - - - - -
24 Operations Reserves - 22,497,607 21,850,187 29,912,981 18,600,000 41,031,095 41,431,199 34,484,515 36,734,500 36,379,951 37,243,026
25 Unassigned - - - - 244,354 4,213,072 - - - - -
26 TOTAL STARTING RESERVES 129,178,000 112,152,357 100,444,086 107,424,072 87,109,490 104,636,040 121,154,958 124,942,084 126,494,885 125,483,364 116,577,206
27
28 REVENUES
29 Net Sales 108,873,377 108,312,917 114,624,726 127,172,308 131,471,245 140,433,750 139,772,776 139,710,860 140,684,833 141,884,202 143,211,537
30 Wholesale Revenues 6,267,000 4,301,366 16,188,920 18,106,327 21,060,071 21,725,571 23,377,736 24,639,974 23,997,227 25,061,025 24,788,013
31 Other Revenues and Transfers In 9,688,480 11,714,494 11,225,911 13,373,312 19,914,635 14,543,650 15,400,045 13,293,143 13,498,268 13,797,826 14,159,678
32 TOTAL REVENUES 124,828,858 124,328,776 142,039,557 158,651,947 172,445,951 176,702,971 178,550,557 177,643,977 178,180,327 180,743,053 182,159,227
33
34 EXPENSES
35 Electric Supply Purchases 80,022,010 75,705,000 80,467,136 94,629,654 89,625,027 90,210,407 95,627,883 97,955,786 97,645,266 97,137,601 100,815,346
36 Operating Expenses
37 Administration
38 Allocated Charges 4,511,222 4,934,195 3,990,822 6,374,241 4,568,027 4,675,023 4,732,003 4,944,893 5,059,013 5,165,543 5,284,513
39 Rent 4,147,742 4,997,101 5,121,102 5,284,977 5,454,097 5,617,719 6,741,263 6,916,536 7,096,366 7,280,872 7,470,174
40 Debt Service 9,037,000 8,885,994 8,953,893 8,867,395 8,464,883 8,473,276 8,439,378 8,447,315 9,280,490 8,914,853 4,898,677
41 Transfers and Other Adjustments 11,004,636 11,798,865 13,052,376 13,632,059 13,342,321 13,506,816 13,859,349 14,470,555 14,629,745 15,008,328 15,017,927
42 Subtotal, Administration 28,700,600 30,616,155 31,118,193 34,158,672 31,829,328 32,272,834 33,771,993 34,779,300 36,065,614 36,369,596 32,671,291
43 Resource Management 2,138,615 2,083,812 1,985,620 1,873,954 2,082,405 2,243,312 2,324,341 2,425,821 2,505,995 2,577,090 2,646,723
44 Demand Side Management 3,491,470 3,643,924 4,271,786 3,889,846 3,655,547 3,273,669 3,265,599 3,247,643 3,351,173 3,408,021 3,460,658
45 Operations and Mtc 10,716,881 11,523,881 11,811,016 11,528,747 11,606,585 15,000,000 15,455,400 16,135,128 16,629,670 17,072,186 17,517,087
46 Engineering (Operating)1,230,160 1,592,024 1,656,522 1,790,942 1,838,799 1,898,965 1,929,956 2,016,341 2,066,346 2,112,467 2,162,574
47 Customer Service 1,548,851 1,540,884 2,190,993 2,291,246 2,180,400 2,371,839 2,468,610 2,575,748 2,665,899 2,745,343 2,821,663
48 Allowance for Unspent Budget - - - - - (2,403,372) (1,413,087) (1,130,696) (1,163,650) (1,193,344) (1,223,737)
49 Subtotal, Operating Expenses 47,826,576 51,000,680 53,034,130 55,533,407 53,193,063 54,657,248 57,802,811 60,049,284 62,121,047 63,091,359 60,056,259
50 Capital Program Contribution 14,005,915 9,331,367 11,558,306 18,803,467 10,770,456 15,316,399 21,332,737 18,086,106 19,425,535 29,420,251 19,297,949
51 TOTAL EXPENSES 141,854,501 136,037,047 145,059,572 168,966,528 153,588,546 160,184,054 174,763,431 176,091,176 179,191,848 189,649,211 180,169,554
52
53 ENDING RESERVES
54 Reappropriations (Non-CIP)- - - 9,063,000 - - - - - - -
55 Commitments (Non-CIP)3,102,055 3,777,205 2,970,955 8,637,000 3,910,695 3,910,695 3,910,695 3,910,695 3,910,695 3,910,695 3,910,695
56 Restricted for Debt Service - - - - - - - - - - -
57 Emergency Plant Replacement - - - - - - - - - - -
58 Low Carbon Fuel Standard (LCFS) Reserve - - - - - 3,740,000 3,340,000 2,140,000 1,140,000 1,140,000 1,140,000
59 Underground Loan Reserve 730,000 729,000 730,147 730,147 726,659 726,659 726,659 726,659 726,659 726,659 726,659
60 Public Benefits Reserves 2,574,000 1,839,000 681,330 681,330 809,700 1,401,586 1,935,396 2,438,211 2,781,240 3,012,007 3,135,555
61 Electric Special Projects Reserve 51,837,855 51,837,855 51,837,855 41,837,855 41,664,855 46,664,855 49,664,855 49,664,855 49,664,855 39,664,855 39,664,855
62 Hydro Stabilization Reserve 17,000,000 11,400,000 11,400,000 11,400,000 11,400,000 15,400,000 19,000,000 19,000,000 19,000,000 19,000,000 19,000,000
58 Capital Reserve - - 879,964 879,964 879,964 7,879,964 11,879,964 11,879,964 11,879,964 11,879,964 11,879,964
59 Rate Stabilization Reserve 14,410,840 9,010,840 9,010,840 9,010,840 - - - - - - -
60 Operations Reserve 22,497,607 21,850,187 29,912,981 18,600,000 41,031,095 41,431,199 34,484,515 36,734,500 36,379,951 37,243,026 39,109,150
61 Unassigned - - - 244,354 4,213,072 - - - - - -
62 TOTAL ENDING RESERVES 112,152,357 100,444,086 107,424,072 101,084,490 104,636,040 121,154,958 124,942,084 126,494,885 125,483,364 116,577,206 118,566,879
63
64 OPERATIONS RESERVE
65 Min (60 days of non-capital expenses)23,548,140 23,011,890 25,227,248 25,849,452 24,700,922 25,092,161 26,485,076 27,295,868 27,644,901 27,738,659 27,931,890
66 Target (90 days of non-capital expenses)33,151,752 32,456,285 35,127,156 37,071,179 35,342,766 35,888,942 37,956,693 39,093,225 39,573,934 39,674,602 39,919,863
67 Max (120 days of non-capital expenses)42,755,364 41,900,681 45,027,065 48,292,905 45,984,610 46,685,723 49,428,310 50,890,583 51,502,967 51,610,544 51,907,837
68 Risk Assessment Value 4,645,297 4,193,350 4,338,548 5,622,455 4,992,321 5,979,427 6,494,144 6,649,374 7,008,251 7,293,835 7,584,126
6053706
1 FISCAL YEAR FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
2
3 REVENUES
4 Net Sales 87%87%81%80%76%79%78%79%79%79%79%
5 Other Revenues and Transfers In 13%13%19%20%24%21%22%21%21%21%21%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 55%54%42%50%53%46%48%49%47%46%48%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%4%3%4%3%3%3%3%3%3%3%
13 Rent 3%4%4%3%4%4%4%4%4%4%4%
14 Debt Service 6%7%6%5%6%5%5%5%5%5%3%
15 Transfers and Other Adjustments 8%9%9%8%9%8%8%8%8%8%8%
16 Subtotal, Administration 20%23%21%20%21%20%20%20%20%20%18%
17 Resource Management 2%2%1%1%1%1%1%1%1%1%1%
18 Operations and Mtc 8%8%8%7%7%9%9%9%9%10%10%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 1%1%2%1%1%2%1%2%2%2%2%
21 Allowance for Unspent Budget 0%0%0%0%0%-1%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 31%35%34%31%32%32%32%32%33%33%31%
23 Capital Program Contribution 10%7%8%11%7%10%11%10%11%11%11%
24 TOTAL EXPENSES 96%96%83%91%93%88%91%91%91%90%90%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
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 & 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 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
44 Distribution Revenue Variance 3,244,706 3,260,213 3,182,718 3,742,109 3,915,276 4,447,787 4,565,391 4,868,311 5,191,564 5,484,785 5,794,823
45 10% CIP Program Contingency 1,400,592 933,137 1,155,831 1,880,347 1,077,046 1,531,640 1,933,274 1,808,611 1,942,554 1,942,025 1,929,795
46 Total Risk Asssessment Value 4,645,297 4,193,350 4,338,548 5,622,455 4,992,321 5,979,427 6,498,665 6,676,921 7,134,117 7,426,810 7,724,618
47 Projected Operations Reserve 22,497,607 21,850,187 29,912,981 18,600,000 41,213,012 44,035,135 39,848,445 40,803,204 38,585,767 38,428,294 39,114,164
48 Operations Reserve, % of Risk Value 484% 521% 689% 331% 826% 736% 613% 611% 541% 517% 506%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)15,208,552 14,498,215 15,472,236 17,841,143 16,852,824 16,875,687 17,780,492 18,194,567 18,316,974 18,191,684 18,155,030
46 Target (90 days of non-capital expenses)22,812,829 21,747,322 23,208,354 26,761,715 25,279,235 25,313,531 26,670,738 27,291,850 27,475,461 27,287,526 27,232,546
47 Max (120 days of non-capital expenses)30,417,105 28,996,429 30,944,472 35,682,287 33,705,647 33,751,375 35,560,984 36,389,134 36,633,948 36,383,368 36,310,061
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)8,339,587 8,513,675 9,755,012 8,008,309 7,867,287 8,211,434 8,699,450 9,095,386 9,321,858 9,540,765 9,770,499
51 Target (90 days of non-capital expenses)10,338,923 10,708,963 11,918,803 10,309,464 10,092,313 10,567,853 11,278,255 11,792,502 12,089,369 12,377,761 12,677,777
52 Max (120 days of non-capital expenses)12,338,259 12,904,252 14,082,593 12,610,618 12,317,339 12,924,271 13,857,059 14,489,618 14,856,880 15,214,756 15,585,055
53 Risk Assessment Value 4,645,297 4,193,350 4,338,548 5,622,455 4,992,321 5,979,427 6,498,665 6,676,921 7,134,117 7,426,810 7,724,618
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1315%1326%1391%1593%1538%1610%1718%1770%1622%1697%3184%
57 Available Reserves (5x Debt Service)*12.1 10.9 11.7 9.4 11.6 13.9 14.6 14.7 13.2 13.8 25.2
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 mee
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 47 | 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)
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).
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June 2018 48 | Page
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.
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
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 49 | Page
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 and approved by Council
resolution.
Minimum Level 20% of the maximum CIP Reserve guideline
level
Maximum Level Average annual (12 month)11 CIP budget, for
48 months of budgeted CIP expenses12
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) 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.
11 Each month is calculated based upon 1/12 of the annual budget.
12 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual
average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use
to derive the annual average would be FY 2022 through FY 2025 etc.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 50 | Page
d) Maximum Level: If there are funds in this reserve in excess of the maximum level staff
must propose in the next Financial Plan to transfer these funds to another reserve or
return them to ratepayers in the funds to ratepayers, or designate a specific use of funds
for CIP investments that will be made by the end of the next Financial Planning period.
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. The Council may approve exceptions
to this requirement, when proposed by staff to provide greater rate stabilization to
customers.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to d) above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 51 | Page
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.
Section 15. Low Carbon Fuel Standard (LCFS) Reserve
This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the
California Air Resources Board to the City, as well as expenses incurred, in accordance with
California’s Low Caron Fuel Standard program. At the end of each fiscal year, the LCFS
Reserve will be adjusted by the net of revenues and expenses associated with California’s
LCFS program.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 52 | 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
Attachment C
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.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) Any funds not included in the other reserves will be considered Unassigned Reserves and shall be
returned to ratepayers or assigned a specific purpose as described in Section 14 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves for
Commitments will be set to an amount equal to the total remaining spending authority for all contracts in
force for the Electric Supply Fund and Electric Distribution Fund, respectively, at that time.
Section 5. Reserves for Reappropriations
Attachment C
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.
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
Attachment C
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 and approved by Council resolution.
Minimum Level 20% of the maximum CIP Reserve guideline
level
Maximum Level Average annual (12 month)1 CIP budget, for
48 months of budgeted CIP expenses2
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) 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 there are funds in this reserve in excess of the maximum level staff must propose in
the next Financial Plan to transfer these funds to another reserve or return them to ratepayers in the
funds to ratepayers, or designate a specific use of funds for CIP investments that will be made by the
end of the next Financial Planning period. 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. The Council may
approve exceptions to this requirement, when proposed by staff to provide greater rate stabilization to
customers.
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:
1 Each month is calculated based upon 1/12 of the annual budget.
2 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual average is FY
2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use to derive the annual average
would be FY 2022 through FY 2025 etc.
Attachment C
a) The following guideline levels are set forth for the Electric Supply Fund Operations Reserve. These
guideline levels are calculated for each fiscal year of the Financial Planning Period based on the levels
of Operations and Maintenance (O&M) and commodity expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
b) The following guideline levels are set forth for the Electric Distribution Fund Operations Reserve.
These guideline levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of O&M expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund or Distribution
Fund’s Operations Reserve are lower than the minimum level set forth above, staff shall present a plan
to the City Council to replenish the reserve. The plan shall be delivered within six months of the end of
the fiscal year, and shall, at a minimum, result in the reserve reaching its minimum level by the end of
the following fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its minimum level
by June 30, 2015. In addition, staff may present an alternative plan that takes longer than one year to
replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or lower than the
target level, any Financial Plan created for the Electric Utility shall be 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.
Section 15. Low Carbon Fuel Standard (LCFS) Reserve
At the end of each fiscal year, the LCFS Reserve will be adjusted by the net of revenues and expenses
associated with California’s LCFS program.
RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-1-1 Sheet No E-1-1
dated 7-1-20198 Effective 7-1-202019
A. APPLICABILITY: This Rate Schedule applies to separately metered single-family residential dwellings receiving Electric Service from the City of Palo Alto Utilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Tier 1 usage
$0.0892233
9
$0.04702971
$0.0046347
$0.140873757
Tier 2 usage Any usage over Tier 1
0.12223156
9
0.069237351
0.0044763
0.19609367
Minimum Bill ($/day) 0.3344283
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Calculation of Usage Tiers Tier 1 Electricity usage shall be calculated and billed based upon a level of 11 kWh per
day, prorated by Meter reading days of Service. As an example, for a 30-day bill, the Tier 1 level would be 330 kWh. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. {End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-1 Sheet No E-2-1
dated 7-1-201918 Effective 7-1-201920
A. APPLICABILITY: This Rate Schedule applies to the following Customers receiving Electric Service from the City
of Palo Alto Utilities: 1. Small non-residential Customers receiving Non-Demand Metered Electric Service; and 2. Customers with Accounts at Master-Metered multi-family facilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period $0.128361855 $0.08131551 $0.0046347 $0.214300853
Winter Period 0.08848502 0.05481675 0.0044763 0.14792624 Minimum Bill ($/day) 0.8536359
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-2 Sheet No E-2-2
dated 7-1-201918 Effective 7-1-201920
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option. The billing Demand to be used in computing charges under this schedule will be the actual maximum Demand in kilowatts for the current month. An exception is that the billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on weekdays. {End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-G-1 Sheet No E-2-G-1
dated 7-1-201918 Effective 7-1-202019
A. APPLICABILITY: This Rate Schedule applies to the following Customers receiving Electric Service from the City of Palo Alto Utilities under the Palo Alto Green Program: 1. Small non-residential Customers receiving Non-Demand Metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
$0.128361855 $0.08131551
$0.0046347 $0.0020
$0.21630053
Winter Period 0.08848502 0.05481675 0.0046347 0.0020
$0.149928
24
Minimum Bill ($/day) 0.8536359 2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period $0.11855 $0.08551 $0.00447 $0.20853
Winter Period 0.08502 0.05675 0.00447 0.14624
Minimum Bill ($/day)
0.8359
Palo Alto Green Charge (per 1000 kWh block) $2.00
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-G-2 Sheet No E-2-G-2
dated 7-1-201918 Effective 7-1-202019
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer and Winter Periods, usage will be prorated based upon the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewable
sources, and create a transparent and sustainable market that encourages new development of wind and solar power. Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-G-3 Sheet No E-2-G-3
dated 7-1-201918 Effective 7-1-202019
4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer-s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option. The billing Demand to be used in computing charges under this schedule will be the actual maximum Demand in kilowatts for the current month. An exception is that the billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on weekdays. {End}
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-1 Sheet No E-4-1
dated 7-1-20189 Effective 7-1-201920
A. APPLICABILITY: This Rate Schedule applies to Demand metered Secondary Electric Service for Customers with a maximum Demand below 1,000 kilowatts. This Rate Schedule applies to three-phase Electric Service and may include Service to master-metered multi-family facilities or other facilities requiring Demand-metered Service, as determined by the City.
B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $6.064.41 $22.084.50 $28.1491
Energy Charge (per kWh)
0.110240536 0.023051865 0.0046347 0.137922848
Winter Period
Demand Charge (per kW) $2.8075 $11.846.22 $14.648.97
Energy Charge (per kWh) 0.07919634 0.023051865 0.0046347 0.1068709946
Minimum Bill ($/day) 17.43462742 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-2 Sheet No E-4-2
dated 7-1-20189 Effective 7-1-201920
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a Maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed. The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays. 4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has been below 200 kilowatts for four consecutive months. When such metering is installed, the monthly Electric bill will include a “Power Factor
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-3 Sheet No E-4-3
dated 7-1-20189 Effective 7-1-201920
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to the computation of any primary voltage discount. The Power Factor Adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent (0.25%) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt hours to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand.
5. Changing Rate Schedules Customers may request a rate schedule change at any time to any City of Palo Alto full-service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage
profile. 6. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-4 Sheet No E-4-4
dated 7-1-20189 Effective 7-1-201920
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director. {End}
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-1 Sheet No E-4-G-1
dated 7-1-201918 Effective 7-1-202019
A. APPLICABILITY: This Rate Schedule applies to Demand metered Secondary Electric Service for Customers with a maximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green Program. This Rate Schedule applies to three-phase Electric Service and may include Service to Master-metered multi-family facilities or other facilities requiring Demand metered Service, as
determined by the City. B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge (per kW) $6.064.41 $22.084.50 $28.1491
Energy Charge (per kWh) 0.110240536 0.023051865 0.0046347 0.0020
0.13992048
Winter Period
Demand Charge (per kW) $2.8075 $11.846.22
$14.648.97
Energy Charge (per kWh) 0.07919634 0.023051865 0.0046347 0.0020
0.10887146
Minimum Bill ($/day) 17.43462742
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-2 Sheet No E-4-G-2
dated 7-1-201918 Effective 7-1-202019
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $6.064.41 $22.084.50 $28.1491
Energy Charge (per kWh) 0.110240536 0.023051865 0.0046347 0.137922848
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $2.8075 $11.846.22 $14.648.97
Energy Charge (per kWh) 0.07919634 0.023051865 0.0046347 0.0106879946
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 17.43462742 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the
option of the City, it may be removed.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-3 Sheet No E-4-G-3
dated 7-1-201918 Effective 7-1-202019
The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter, which does not reset after a definite time interval, may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays. 4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four consecutive months. When such Metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to the computation of any primary voltage discount. The Power Factor Adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-hours to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand.
5. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full-service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-4 Sheet No E-4-G-4
dated 7-1-201918 Effective 7-1-202019
6. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the production of renewable energy, increase the financial value of power from renewal sources, and creates a transparent and sustainable market that encourages new development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program application provided by the Customer Service Center. Customers may request at any time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program.
7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change the system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-5 Sheet No E-4-G-5
dated 7-1-201918 Effective 7-1-202019
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters: A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit: (1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-1 Sheet No E-4-TOU-1
dated 7-1-201918 Effective 7-1-202019
A. APPLICABILITY: This voluntary Rate Schedule applies to Demand metered Secondary Electric Service for Customers with Demand between 500 and 1,000 kilowatts per month and who have sustained this level of usage for at least three consecutive months during the most recent 12 month period. This Rate Schedule applies to three-phase Electric Service and may include Service to Master-
Metered multi-family facilities or other facilities requiring Demand-metered Service, as determined by the City. In addition, this Rate Schedule is applicable for Customers who did not pay power factor adjustments during the last 12 months. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $4.232.61 $7.618.44 $11.8405
Mid-Peak 0.975 7.618.44 8.589.39
Off-Peak 0.975 7.618.44 8.589.39
Energy Charge (per kWh)
Peak $0.089789642 $0.023051864 $0.0046347 $0.11747954
Mid-Peak 0.113052142 0.023051864 0.0046347 0.14074453
Off-Peak 0.069387451 0.023051864 0.0046347 0.0970663
Winter Period
Demand Charge (per kW)
Peak $1.563 $6.609.04 $8.1610.57
Off-Peak 1.563 6.609.04 8.1610.57
Energy Charge (per kWh)
Peak $0.140161781 $0.023051864 $0.0046347 $0.167844092
Off-Peak 0.120320113 0.023051864 $0.0044763 0.148002425
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-2 Sheet No E-4-TOU-2
dated 7-1-201918 Effective 7-1-202019
Commodity Distribution Public Benefits Total
Minimum Bill ($/day) 17.43462742
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
SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and the Winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Demand Meter will be installed as promptly as is practicable and
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-3 Sheet No E-4-TOU-3
dated 7-1-201918 Effective 7-1-202019
thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the
designated time periods as defined under Section D.2. 4. Power Factor Adjustment Time of Use Customers must not have had a power factor adjustment assessed on their
Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt-ampere hours consumed during the month, and must not have fallen below 95% to avoid the power factor adjustment. Should the City of Palo Alto Utilities Department find that the Customer’s Service should
be subject to power factor adjustments, the Customer will be removed from the E-4-TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 5. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said Rate 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 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.
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-4 Sheet No E-4-TOU-4
dated 7-1-201918 Effective 7-1-202019
7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-
utility generation source. b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67 c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the
Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the
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.
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-TOU-5 Sheet No E-4-TOU-5
dated 7-1-201918 Effective 7-1-202019
(3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End}
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-1 Sheet No E-7-1
dated 7-1-20198 Effective 7-1-202019
A. APPLICABILITY: This Rate Schedule applies to Demand Metered Service for large non-residential Customers
with a Maximum Demand of at least 1,000KW per month per site, who have sustained this
Demand level at least 3 consecutive months during the last twelve months. B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (kW) $6.695.03 $21.655.66 $28.3430.69
Energy Charge (kWh) 0.112150932 0.0001153 0.0046347 0.11689432
Winter Period
Demand Charge (kW) $3.052.89 $14.136 $17.1805
Energy Charge (kWh) 0.07785238 0.0001153 0.0046347 0.082597738
Minimum Bill ($/day) 42.79949.1139 D. SPECIAL NOTES:
1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-2 Sheet No E-7-2
dated 7-1-20198 Effective 7-1-202019
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Request for Service Qualifying Customers may request Service under this schedule for more than one Account or one Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule, consists of one or more Accounts which cover contiguous parcels of land with
no intervening public right-of-ways (e.g. streets) and which have a common billing
address. 4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the
City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-3 Sheet No E-7-3
dated 7-1-20198 Effective 7-1-202019
5. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option to install applicable
Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has been below 200 kilowatts for four consecutive months. When such metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The power factor adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent (0.25%) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile. 7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kVA size limitation.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-4 Sheet No E-7-4
dated 7-1-20198 Effective 7-1-202019
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76 c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand (as defined in Section D.4) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-5 Sheet No E-7-5
dated 7-1-20198 Effective 7-1-202019
Section 2827(b)(4) , as amended. (3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-1 Sheet No E-7-TOU-1
dated 7-1-201918 Effective 7-1-202019
A. APPLICABILITY: This voluntary Rate Schedule applies to Demand Metered Service for non-residential
Customers with a Maximum Demand of at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months. In addition, this Rate Schedule is applicable for Customers who did not pay power factor adjustments during the last 12 months.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $4.663.11 $7.278.62 $11.9473
Mid-Peak 1.020.97 7.278.62 8.309.60
Off-Peak 1.020.97 7.278.62 8.309.60
Energy Charge (per kWh)
Peak $0.125961356 $0.0001153 $0.0046347 $0.130701856
Mid-Peak 0.158604299 0.0001153 0.0046347 0.163344799
Off-Peak 0.097338776 0.0001153 0.0046347 0.1020709276
Winter Period
Demand Charge (per kW)
Peak $1.5447 $7.157 $8.7063
Off-Peak 1.5447 7.157 8.7063
Energy Charge (per kWh)
Peak $0.088607619 $0.0001153 $0.0046347 $0.093348119
Off-Peak 0.076066540 0.0001153 0.0046347 0.080807040
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-2 Sheet No E-7-TOU-2
dated 7-1-201918 Effective 7-1-202019
Minimum Bill ($/day) 42.79949.1139 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
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. Request for Service Qualifying Customers may request Service under this schedule for more than one Account or one
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-3 Sheet No E-7-TOU-3
dated 7-1-201918 Effective 7-1-202019
Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule, consists of one or more Accounts which cover contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and which have a common billing address. 4. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time periods as defined under Section D.2. 5. Power Factor Adjustment
Time of Use Customers must not have had a power factor adjustment assessed on their Service
for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt-ampere hours consumed during the month, and must not have fallen below 95% to avoid the power factor adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be
subject to power factor adjustments, the Customer will be removed from the E-7-TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage.
6. Changing Rate Schedules Customers electing to be served under E-7 TOU must remain on said Rate 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.
7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-4 Sheet No E-7-TOU-4
dated 7-1-201918 Effective 7-1-202019
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's
electrical requirements, as determined in the City’s sole discretion. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size
limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source. b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76 c. Meters. A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum
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
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-TOU-5 Sheet No E-7-TOU-5
dated 7-1-201918 Effective 7-1-202019
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 GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-1 Sheet No E-7-G-1
dated 7-1-201918 Effective 7-1-202019
A. APPLICABILITY: This Rate Schedule applies to Demand metered Service for large non-residential Customers who choose Service under the Palo Alto Green Program. A Customer may qualify for this Rate Schedule if the Customer’s Maximum Demand is at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months. B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge ( per kW) $6.695.03 $21.655.66 $28.3430.69
Energy Charge (per kWh) 0.112150932 0.0001153 0.0046347 0.0020 0.11889632
Winter Period
Demand Charge (per kW) $3.052.89 $14.136 $17.1805
Energy Charge (per kWh) 0.07785238 0.0001153 0.0044763 0.0020 0.084597938
Minimum Bill ($/day) 42.79949.1139
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-2 Sheet No E-7-G-2
dated 7-1-201918 Effective 7-1-202019
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $6.695.03 $21.655.66 $28.3430.69
Energy Charge (per kWh) 0.112150932 0.0001153 0.0046347 0.11689432
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $3.052.89 $14.1316 $17.1805
Energy Charge (per kWh) 0.07785238 0.0001153 0.0046347 0.082597738
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 42.79949.1139 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C. 2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-3 Sheet No E-7-G-3
dated 7-1-201918 Effective 7-1-202019
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, for the purposes of this Rate
Schedule, consists of one or more Accounts which cover contiguous parcels of land with
no intervening public right-of-ways (e.g. streets) and which have a common billing address. 5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to the computation of any primary voltage discount. The power factor adjustment is applied
by increasing the total energy and Demand charges for any month by 0.25 percent or
(1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-4 Sheet No E-7-G-4
dated 7-1-201918 Effective 7-1-202019
hours to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand.
6. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile
7. 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
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-5 Sheet No E-7-G-5
dated 7-1-201918 Effective 7-1-202019
a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76 c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit: (1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director.
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-6 Sheet No E-7-G-6
dated 7-1-201918 Effective 7-1-202019
{End}
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-14-1 Sheet No. E-14-1
dated 7-1-20198 Effective 7-1-202019
A. APPLICABILITY: This Rate Schedule applies to all street and highway lighting installations, which CPAU elects to
operate and maintain.
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: CPAU supplies electricity and switching service
only.
Lamp Rating: High Pressure Sodium Vapor Lamps 100 watts 12.475.91
200 watts 23.0310.91
250 watts 28.3113.41 310 watts 35.0216.59 400 watts 45.1021.36
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-14-2 Sheet No. E-14-2
dated 7-1-20198 Effective 7-1-202019
Per Lamp Per Month – Class C: CPAU supplies electricity and switching and
maintains lighting system,
including lamps and glassware. Lamp Rating: Mercury-Vapor Lamps
400 watts 37.7934.12
High Pressure Sodium Vapor Lamps 70 watts 32.031.40 100 watts 35.202.90
150 watts 40.4835.40
250 watts 51.0340.40 Light Emitting Diode (LED) Lamps 70 watts-equivalent 25.038.08
100 watts-equivalent 27.439.22
150 watts-equivalent 29.6330.26 250 watts 35.6833.12
D. SPECIAL CONDITIONS: 1. Type of Service: This Rate Schedule applies to series, multiple, and single lamp street lighting systems to which CPAU delivers Service at secondary voltage. Unless a variation is
approved by CPAU in its sole discretion, Service to street lighting systems will be delivered
at 120/240 volts, three-wire, single-phase or 120/208 volt three-wire, single phase from star-connected poly-phase lines. Single phase service from 480-volt sources will be available in certain areas at CPAU’s discretion. All voltages stated herein are nominal, and reasonable variations may occur. New lights will normally be installed as multiple lamp systems with a
single Service point or single lamp with and individual Service point.
2. Point of Delivery: Delivery will be made to the Customer's system at a Service point or at points designated by CPAU. CPAU will furnish the Service connection to one point for each
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-14-3 Sheet No. E-14-3
dated 7-1-20198 Effective 7-1-202019
lamp or group of lamps, provided the Customer has designed the system to include the minimum number of delivery points. CPAU will make all underground connections to CPAU’s system at the Customer's expense.
3. Switching: CPAU will perform switching (on CPAU's side of the points of delivery) at no Charge, 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 Rate Schedule or not. An extra charge of $2.50 per month will be made for each circuit separately switched unless
such switching installation is made for CPAU's convenience.
4. Annual Burning Schedule: The rates in this Rate Schedule apply to lamps which will be turned on and off once each night in accordance with a regular burning schedule approved by CPAU and not exceeding 4,100 hours per year. 5. Maintenance: The Class C rates in this Rate Schedule include all labor necessary for
replacement of glassware, including inspection and cleaning. Maintenance of glassware by CPAU is limited to standard glassware that is commonly used and manufactured in reasonably large quantities, as determined by CPAU in its sole discretion. The Class C 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 as determined by CPAU.
CPAU in its sole discretion may decline to grant Class C rates for maintenance of systems with non-standard glassware, or inadequate circuitry and equipment. 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 determined by CPAU to be needed to maintain good appearance.
Maintenance does not include replacement of posts damaged by third parties or acts of
nature. 6. System Owned In-Part by CPAU: If CPAU agrees to a Customer’s request for CPAU to install, own, or maintain any portion of the lighting fixtures, supports, and/or interconnecting
circuits, the Customer shall be responsible for an extra monthly Charge of one and one-fourth
percent of CPAU's contribution to the cost of the street lighting system. 7. Rates For Lamps Not on this Rate Schedule: In the event a Customer installs a lamp which is not represented on this Rate Schedule, CPAU will prepare an interim rate reflecting CPAU's
estimated costs associated with the specific lamp. This interim rate will serve as the effective
rate for billing purposes until the new lamp rating is added to Rate Schedule E-14. {End}
EXPORT ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-EEC-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council Supersedes Sheet No. E-EEC-1 Sheet No.E-EEC-1
dated 7-1-20196 Effective 7-1-202019
A. APPLICABILITY: This Rate Schedule applies in conjunction with the otherwise applicable Rate Schedules for each Customer class. This Rate Schedule may not apply in conjunction with any time-of-use Rate Schedule. This Rate Schedule applies to Customer-Generators as defined in Rule and Regulation 2 who are either not eligible for Net Energy Metering or who are eligible for Net Energy metering but elect to take Service under this Rate Schedule. B. TERRITORY: Applies to locations within the service area of the City of Palo Alto. C. RATE: The following buyback rate shall apply to all electricity exported to the grid. Per kWh Export electricity compensation rate $0.103609 D. SPECIAL CONDITIONS 1. Metering equipment: Electricity delivered by CPAU to the Customer-Generator or received by CPAU from the Customer-Generator shall be measured using a Meter capable of registering the flow of electricity in two directions (aka “bidirectional meter”). The electrical power measurements will be used for billing the Customer-Generator. CPAU shall furnish, install and own the appropriate Meter. 2. Billing: a. CPAU shall measure during the billing period, in kilowatt-hours, the electricity delivered and received after the Customer-Generator serves its own instantaneous load. b. CPAU shall bill the Customer-Generator consumption charges for the electricity delivered by CPAU to the Customer-Generator based on the Customer-Generator’s applicable Rate Schedule. c. In the event the electricity generated exceeds the electricity consumed and therefore is received by CPAU, the Customer will receive a credit for all electricity received by CPAU at the buyback Rate designated in section C above. {End}
NET METERING NET SURPLUS ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-NSE-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-NSE-1 Sheet No.E-NSE-1
dated 07-01-20169 Effective 7-1-201920
A. APPLICABILITY: This Rate Schedule applies to eligible residential and small commercial Net Energy Metering Customers who, at the end of an annual settlement period, as described in Rule 29, are Net Surplus Customer-Generators of electricity who elect to receive monetary compensation as such preference is indicated on the net surplus electricity election form. This Rate Schedule only applies to Customers who participate in Net Energy Metering, and does not apply to Customers that take service under the City’s Net Energy Metering Successor Rate, as each of these terms are defined in Rule and Regulation 2. B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides electric service. C. RATES: Per kWh Net Surplus Electricity Compensation rate $0.09398771 D. SPECIAL CONDITIONS 1. Net Surplus Electricity Compensation Rate eligibility shall be determined as specified in Rule 29. Net surplus electricity, as specified in Rule 29, if applicable, will be multiplied by the above compensation rate to determine the Customer’s annual net surplus electricity compensation stated in dollars. 2. Additional terms, conditions and definitions govern Net Energy Metering Service and Interconnection, as described in Rule 29. {End}