HomeMy WebLinkAboutStaff Report 6857
City of Palo Alto (ID # 6857)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/17/2016
City of Palo Alto Page 1
Summary Title: Electric Utility Financial Plan and Rate Changes
Title: Utilities Advisory Commission Recommendation That the Finance
Committee Recommend the City Council Adopt: 1) Resolution Approving the
Fiscal Year 2017 Electric Financial Plan and Amending the Electric Utility
Reserves Management Practices, and 2) Resolution Increasing Electric Rates
by 11 Percent Effective July 1, 2016 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, and E-16 Rate Schedules, and Repealing
Rate Schedules E-18 and E-18-G
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission (UAC) recommend that the Finance Committee
recommend that the Council:
1. Adopt a resolution (Attachment A) amending the Electric Utility Reserve Management
Practices and approving the fiscal year (FY) 2017 Electric Financial Plan (Attachment B);
and
2. Adopt a resolution (Attachment D) amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Small Commercial Electric Service), E-2-G (Small Commercial Green Power
Electric Service), E-4 (Medium Commercial Electric Service), E-4-G (Medium Commercial
Green Power Electric Service), E-4 TOU (Medium Commercial Time of Use Electric
Service), E 7 (Large Commercial Electric Service), E-7-G (Large Commercial Green Power
Electric Service), E 7 TOU (Large Commercial Time of Use Electric Service), E-14 (Street
Lights), and E-16 (Unmetered Electrical Service) and Repealing Rate Schedules E-18
(Municipal Electric Service) and E-18-G (Municipal Green Power Electric Service).
Executive Summary
The FY 2017 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2023. Costs are projected to rise substantially for the next several years for several
reasons. First, costs for electric supply purchases are increasing as a result of new renewable
energy projects coming online. Increases in transmission costs are also projected. Substantial
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additional capital investment in the electric distribution system is planned for FY 2017 through
FY 2023, and operational costs are increasing.
To offset these rising costs, an increase in sales revenues is required. An 11% rate increase is
proposed for July 1, 2016, and another 10% increase is projected July 1, 2017. While staff would
normally attempt to spread these rate increases across more than two years to reduce the
single-year ratepayer impact, higher power supply purchase costs due to the drought have
reduced operational and other reserves substantially, making this infeasible. Staff proposes
various reserves transfers to limit the rate impact to 11%, as described later in this report.
While 11% is the overall increase in sales revenues, actual rate increases for each customer
class will differ as a result of rebalancing of the cost allocation between customer groups as
determined by the new cost of service analysis (COSA). In anticipation of the July 1, 2016 rate
change, staff hired EES Consulting to perform a COSA to determine the cost of service for
various customer classes and what revenues should be collected from each group. The analysis
showed that some customer groups are closer to cost of service than others, so some groups
will experience increases higher than 11%, while others will see lower increases. In addition,
customers with different consumption patterns will see different changes in their bills as a
result of a restructuring of the rate design for some customer classes.
In addition to the recommended rate and revenue changes, staff recommends a change to the
Electric Utility Reserves Management Practices to modify the minimum and maximum
guidelines for the CIP Reserve.
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. Staff occasionally proposes
amendments to these reserves as part of the Financial Plans.
When the Financial Plan reveals that operational costs are increasing beyond sales revenues,
staff typically recommends rate changes. These rates are designed to collect revenues equal to
the cost to serve each customer or customer group. It is industry practice to periodically
perform a COSA to ensure that a utility’s rates recover revenues equal to the costs to serve
customers. This is particularly important for the electric utility due to changes to the state
constitution that have taken place since the last time electric rates were changed on July 1,
2009. Since then, Proposition 26 (2010) amended the California Constitution, which defines all
government-imposed charges, including electric rates, as taxes requiring voter approval, unless
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certain exceptions are met. Cost-based electric rates may be adopted by the City Council. The
COSA helps the utility ensure that rates match the cost to serve customers.
Discussion
Summary of Proposed Actions
The two resolutions recommended for Council adoption will accomplish the following:
1. Increase overall electric rates by 11% effective July 1, 2016.
2. Align rates for individual rate classes with the attached COSA to ensure all ratepayers
are charged according to the cost of serving them;
3. Approve various reserves transfers for FY 2016 and FY 2017;
4. Add a minimum charge to all rate schedules to ensure that, at minimum, the direct
customer service costs are collected;
5. Modify the residential rate schedule to include two tiers instead of three;
6. Eliminate the municipal rate schedules, E-18 and E-18-G. All municipal customers will be
moved to the appropriate commercial rate schedule;
7. Update street light and traffic signal rate schedules to reflect lighting and signal
infrastructure currently installed, including LED lighting; and
8. Amend the Electric Utility Reserves Management Practices to modify the minimum and
maximum guidelines for the CIP Reserve.
Proposed and Projected Sales Revenue Requirement, FY 2017 through FY 2023
Table 1 shows the sales revenue increases needed to recover costs of operation over the
forecast period in the FY 2017 Electric Financial Plan.
Table 1: Projected Electric Rate Adjustments, FY 2017 to FY 2023
FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
11% 10% 2% 0% 1% 0% 0%
These sales revenue increases are for the utility as a whole, but the rate changes will differ for
individual customer classes. Proposed rate increases for each customer class are discussed
below.
Changes from Prior Financial Forecasts
This projection has changed since the FY 2016 Electric Utility Financial Plan presented last year.
Staff has projected future electric rate increases for many years. Table 2 compares current rate
projections to those projected in the last two year’s Financial Plans. As shown, the FY 2017 rate
projections are higher than projected the last two years when the ongoing drought was not
projected to be as long or severe as it has been, so the current rate increase projections are
generally higher than in prior years.
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Table 2: Projected Electric Rate Trajectory for FY 2017 to FY 2023
Projection FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Current
(FY 2017 Financial Plan) 11% 10% 2% 0% 1% 0% 0%
Last year
(FY 2016 Financial Plan) 6% 6% 1% 1% 0% 0% 2%
Two years ago
(FY 2015 Financial Plan) 3% 3% 2% N/A N/A N/A N/A
The original 6% rate increases were primarily related to increases in power supply purchase
costs resulting from increasing transmission costs and the cost of renewable projects coming
online. These same factors are driving the higher rate projections in the FY 2017 Electric Utility
Financial Plan, but some additional operational and capital costs have been added. One key
issue is the extent and duration of the ongoing drought, which has increased costs and drawn
down reserves more than anticipated. Additionally, substantial additional capital investment in
the electric distribution system is planned for FY 2017 through FY 2023, as is apparent in the FY
2017 Proposed Capital Budget. Operational costs are also increasing more than projected. This
is partially due to an increase in allocated administrative overhead costs and partially due to
deferred maintenance resulting from challenges in retaining staff in certain maintenance
classifications.
Even when large rate increases are needed, staff typically attempts to keep increases below
10% per year, but this is not possible for FY 2017 and FY 2018. The proposed rate increases for
FY 2017 and FY 2018 might have been phased in more gradually with adequate reserves, but
higher power supply purchase costs due to the drought have reduced operational and other
reserves substantially. Because of lower output from hydroelectric resources, the City has had
to purchase additional energy in the markets, and the cost of these market power purchases
have come from reserves. As a result, these reserves cannot be used to phase in the rate
increases over more years as they have served to insulate ratepayers from cost increases
experienced in the last two years.
This Financial Plan still contains some measures to mitigate the impact on ratepayers, however.
The July 1, 2016 rate increases would have to be substantially higher without a proposed
transfer from the Supply Rate Stabilization Reserve (see below). In addition, this Financial Plan
allows the Supply Operations Reserves to be up to $3.9 million below the minimum Supply
Operations Reserve level for FY 2017 through FY 2020. To keep the Supply Operations Reserve
above the minimum guideline, a 14% rate increase would be required in FY 2017. Staff
recommends allowing Supply Operations Reserves to temporarily go below minimums for two
reasons: first, due to the presence of a strong El Niño condition in the Pacific Ocean, spring
rains have improved the forecasted hydroelectric generation, which will likely result in higher
reserves at year-end FY 2016 than originally projected. Second, the presence of the $51 million
Electric Special Projects Reserve means that a relatively small temporary shortfall in the Supply
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Operations Reserve should not affect the Electric Utility’s bond ratings. In the event the drought
continues, staff will re-evaluate its projections for FY 2018 and may recommend additional rate
increases or the adoption of a hydroelectric rate adjuster. Note that the Financial Plan’s
Reserves Management Practices allow the Operations Reserve to fall below the minimum
guideline level as long as the plan provides for replenishing the reserve over time.
Rate Changes by Customer Class
Table 3 shows the sales revenue changes needed for each customer class. All recommended
sales revenue changes and the rates used to recover that revenue are based on the cost of
service methodology established in the attached “City of Palo Alto Electric Cost of Service and
Rate Study” by EES Consulting, Inc. (Attachment C), the COSA. As mentioned above, while total
sales revenue needs to increase 11% for FY 2017, the increase in sales revenue is different for
each customer class. This is a result of changes in consumption patterns since the last rate
change. The relationship between changes in consumption patterns and rate increases can be
counterintuitive. For a detailed discussion of the relationship between changing consumption
patterns and the rate increases for each customer class, see the section of the attached COSA
titled “Cost of Service Results,” page 25.
Table 3: Revenue Changes Required for Each Customer Class
Customer Class
Projected FY 2016-17
Revenues under Rates
Currently in Effect
FY 2016-17 Revenue
Requirement
Per COSA
Revenue
Increase
needed
E-1 (Residential) $18,406,003 $20,785,989 13%
E-2 (Small Non-Residential) 9,421,113 10,019,138 6%
E-4 (Medium Non-Residential) 38,382,821 42,680,642 11%
E-7 (Large Non-Residential) 41,216,279 42,441,354 3%
E-18 (Municipal) 3,044,789 4,463,490 47%1
E-14/E-16 (Street/Traffic Lights) 60,477 2,097,367 3368%2
Total Sales Revenue Requirement $110,531,481 $122,487,979 11%
Table 4 shows the rates that will be used to recover the sale revenues for each customer class
The Municipal (E-18) rate class, the Street Lighting (E-14) class, the Non-Metered Service (E-16)
class, and the E-4 and E-7 Time of Use (TOU) rates are not shown in the table, but can be seen
in the attached COSA (Attachment C). These three schedules are omitted for various reasons:
the Municipal class is recommended for repeal as of July 1, 2016, the E-14 and E-16 rate
schedules are not easy to summarize, and the E-4 and E-7 TOU rates are not easy to summarize
and are only used by one customer.
1 This rate class is recommended for repeal. Customers in this class will be moved to the E-2, E-4, and E-7 customer
classes.
2 This increase in revenue will primarily come from expanding the billing of street lights and traffic signals to cover
all lights and signals rather than through rate increases.
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Note that many of the components of the rate schedules are being realigned. For example, tiers
two and three of the E-1 residential rate schedule are being combined, and summer and winter
energy rates for non-residential customers are being realigned. This means that the rate
changes will have different effects on customers depending on their consumption patterns.
These realignments are needed to accurately collect the costs of serving these customer
groups. Both the tier structure and the amount of energy included in Tier 1 are changing. The
new Tier 1 allowance is based on the year-round baseload usage of the median customer. The
second tier represents peak consumption and the costs associated with that peak.
Another significant change to the rate schedules is the addition of a minimum charge. Palo
Alto’s current electric rates are very unusual among California utilities, since Palo Alto is one of
the only electric utilities without a fixed or a minimum charge. A minimum charge, unlike a
fixed charge, is only incurred when a customer’s bill falls below a minimum level, and it has less
of an impact on low and medium energy users than a fixed charge. A minimum charge ensures
the collection of revenue to cover the direct costs of operations that are incurred regardless of
how low usage is. This includes items like customer billing, meter reading, accounting, and
certain types of distribution costs. For E-1 customers, this charge is around $9.21/month, equal
to roughly 85 kWh of consumption per month. Roughly 7% of residential customers have bills
lower than 85 kWh at one time or another throughout the year, but only 2% of residential
customers have such low bills on an ongoing basis.
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Table 4: Electric Rates (Current and Proposed)
Current Rates
Proposed Rates
(7/1/16)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.09524 0.11029 0.01505 16%
Tier 2 Energy ($/kWh) 0.1302 0.16901 0.03881 30%
Tier 3 Energy ($/kWh) 0.17399 0.169011 (0.00498) -3%
Minimum Charge ($/day) - 0.3067 0.3067
E-2 (Small Non-Residential)
Summer Energy ($/kWh) 0.14045 0.16845 0.02800 20%
Winter Energy ($/kWh) 0.12661 0.11445 (0.01216) -10%
Minimum Charge ($/day) - 0.7657 0.7657
E-4 (Medium Non-Residential)
Summer Energy ($/kWh) 0.08171 0.10229 0.02058 25%
Winter Energy ($/kWh) 0.07318 0.08049 0.00731 10%
Summer Demand ($/kW) 20.54 19.68 (0.86) -4%
Winter Demand ($/kW) 13.84 14.04 0.20 1%
Minimum Charge ($/day) - 16.3216 16.3216
E-7 (Large Non-Residential)
Summer Energy ($/kWh) 0.07808 0.08749 0.00941 12%
Winter Energy ($/kWh) 0.07209 0.06242 (0.00967) -13%
Summer Demand ($/kW) 18.97 18.34 (0.63) -3%
Winter Demand ($/kW) 11.54 15.65 4.11 36%
Minimum Charge ($/day) - 48.5054 48.5054
1 Proposed E-1 Rates have two tiers
Table 5 shows the impact of the proposed July 1, 2016 rate changes (excluding any drought
surcharges) on the residential and non-residential bills for various consumption levels. While
the overall rate change for the residential class is roughly 13%, bills will increase more for
residents with lower electric usage than those with higher usage.
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Table 5: Impact of Proposed Electric Rate Changes on Customer Bills
Rate
Schedule Usage (kwh/mo)
Bill under
Current Rates
($/mo)
Bill Under Rates
Proposed 7/1/16
($/mo)
Change
$/mo %
E-1 300 28.57 33.09 4.51 16%
(Summer Median) 330 32.48 36.39 3.92 12%
(Winter Median) 453 48.49 57.18 8.69 18%
650 76.33 90.48 14.14 19%
1200 172.03 183.43 11.40 7%
E-2 1,000 134 142 8 6%
E-4 160,000 18,364 21,553 2,167 11%
E-7 500,000 43,319 43,862 1,318 3%
E-7 2,000,000 216,594 219,310 6,591 3%
Figure 1 shows an estimate of the impacts of the proposed rate changes on customers at
various income levels. Income is shown as a percentage of Palo Alto median income ($172,000
for a single-family customer and $133,000 for a multi-family customer).3 The estimate assumes
that customers in the lowest incomes levels4 are on the City’s Rate Assistance Program (RAP).
There are roughly 700 RAP customers in Palo Alto, 400 in multi-family dwellings and 300 in
single-family dwellings.
Currently the large majority of customers pay 1% or less of their income for electricity. These
rate increases and redesigns will increase that by roughly 15%-18% for most customer classes
(e.g. from 1% of income to 1.15% of income), and will not affect low-income customers
substantially differently than higher income customers even though, on average, customers in
the City’s RAP use less electricity than other customers. Customers in multi-family homes
mostly consume electricity in the first tier, and they will see a smaller rate increase than
customers in single-family homes because the first tier is increasing by a smaller percentage
than the second tier. This comparison holds true both for RAP customers and non-RAP
customers.
Even with these increases, Palo Alto still provides an economic electricity service to low-income
utility customers. In neighboring Mountain View, for example, which is served by PG&E, a single
family customer with an income level that would qualify them for RAP in Palo Alto (HUD Very
3 The median income for Palo Alto is based on the U.S. Census’s American Community Survey (ACS). This survey
does not break down income between single- and multi-family housing, but does break it down by income levels.
Therefore, this estimate assumes that income levels for customers in multi-family units roughly match the ACS
income levels for a two person household (the average household size for multi-family dwellings in Palo Alto),
while the single-family customers match the ACS income levels for a three person household.
4 Very Low ($42,550 /$47,850 for a two / three person household) or Extremely Low ($25,550 /$28,750 for a two /
three person household) under the Federal Department of Housing and Urban Development’s income guidelines
for Santa Clara County
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Low income) would pay 1.6% of their income for electric service5, as compared to 1.2% in Palo
Alto. In addition, Public Utilities Code 386 requires all publicly owned utilities (like Palo Alto) to
ensure that low-income families have access to affordable electricity. This requirement is
fulfilled through the City’s RAP and Residential Energy Assistance Program (REAP).
Figure 1: Impact of Rate Changes on Customers of Various Income Levels
Staff also analyzed the impacts of the proposed cost-based rate changes on existing solar
customers, particularly the impact of the minimum bill. The minimum bill would have some
impact on residential customers who have already installed solar and are on the City’s net
metering rate. For the majority of solar customers (57%) the annual impact would be less than
$30. For nearly 80% of customers the annual impact would be less than $80 per year. The
remaining customers pay little or nothing for their annual electric bill. These customers would
pay $81-$120 per year under the proposed rate structure.
Staff also analyzed the impacts of the minimum charge and rate changes on prospective solar
net energy metering customers. For the average customer in Palo Alto, the proposed rate
5 Calculated using PG&E E-1 CARE rate.
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changes actually reduce the payback period.6 This is because the increases in the Tier 1 and Tier
2 rates increased the bill savings for the average customer and reduced it for the highest users,
offsetting the impact of the minimum bill. For the highest use customers, the payback period
would increase. Customers would see substantial savings from installing solar even as they
contribute to their portion of the utility’s costs of serving them via the minimum bill and rate
changes, as shown in Table 6. Customers looking to optimize their return on investment
(shorten the payback period) might avoid oversizing their systems and may install systems that
generate a bit less than 100% of their annual usage. This is the strategy already undertaken by
the large majority of solar customers, so the minimum bill is unlikely to have a major impact on
new installations. With solar prices continuing to fall and future customers benefitting from the
recent extension of the Investment Tax Credit, staff is confident that the minimum bill will not
significantly affect the growth of rooftop solar in Palo Alto.
Table 6: Sample Solar Customer Bill Under Proposed Rates and Minimum Bill
Month
1. Total Energy
Consumption (kWh)
2. Solar Energy
Production (kWh)
3. Monthly Bill with
Solar Under NEM
4. Monthly Bill
Without Solar
January 700 327 $43 $99
February 602 314 $32 $82
March 531 519 $10 $70
April 459 610 $9 $58
May 442 704 $10 $55
June 441 659 $9 $55
July 465 711 $10 $59
August 447 582 $10 $56
September 465 551 $9 $59
October 471 467 $10 $60
November 477 348 $9 $61
December 592 299 $10 $81
Total: 6,092 6,092 $169 $796
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 attached “City of Palo Alto Electric Cost of Service and Rate Study” by EES
Consulting, Inc. (Attachment C). This section provides a brief overview of that methodology and
the resulting rate design changes. More detail is available in the report itself.
A typical COSA has three steps:
1. Establish the revenue requirement. This involves breaking the City’s costs into industry-
standard categories and calculating the amount of sales revenue to be recovered.
6 Payback period refers to the number of years until the savings from the solar installation equals the initial cost.
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2. Cost of service analysis. This step establishes the cost responsibility of each customer
class. Costs are allocated based on cost causation. For example, costs such as power
supply are driven by total annual energy consumption and are allocated to each
customer class based on that class’s annual energy use. Other costs are driven by peak
demand, number of customers, or other types of allocations. This step of the analysis
generated the customer class revenue requirements shown in Table 2, above.
3. Rate Study. In this step, rates are designed to recover the revenues for each customer
class calculated in Step 2. Most importantly in this step rates must be based on the cost
to serve customers, though staff has also attempted to take into account City policy
goals.
The design of the rates generated by the COSA and proposed for July 1, 2016 adoption is very
similar to the current rates. Residential rates are tiered, while non-residential rates are
seasonal, and larger non-residential customers are subject to demand charges. However, there
are a number of design changes that were needed to ensure rates matched the cost to serve
customers:
The E-1 residential rates have gone from three tiers to two. Two tiers are needed to
capture differences in commodity costs and seasonal capacity needs, but not three.
The Tier 1 allowance for the E-1 rate has gone from 10 kWh per day to 11 kWh per day.
This was based on an analysis of residential baseload energy use.
A minimum charge has been added to all rate classes. This ensures that at minimum the
direct costs of providing customer service, metering, and billing are recovered.
The E-18 (Municipal) rate class has been repealed. Customers in this class shared similar
characteristics to the E-2, E-4, and E-7 nonresidential classes, and will be moved to
those classes.
The E-14 (Street Lighting) rate schedule has been updated to apply to all street lights
served by the electric utility, and to reflect current street light inventories.
The E-16 (Unmetered Electric Service) rate schedule has been updated to remove traffic
signal rates. Since the City is the only customer these rates currently apply to, it is
simpler to bill the City directly for traffic signal maintenance rather than calculate
separate rates.
The COSA and rate study largely align with the “Design Guidelines for the 2015 (Phase One)
Electric Utility Cost of Service Analysis” adopted by the Council on September 15, 2015 (Staff
Report 6061). Some additional work may be required to fulfill some of the guidelines. Each
guideline is listed in Table 7 below, as well as the way in which the proposed rates align with
the guidelines.
Table 7: Implementation of COSA Design Guidelines
Guideline Implementation
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Table 7: Implementation of COSA Design Guidelines
Guideline Implementation
1. Rates must be based on the cost to serve
customers. This is the overriding principle for
the COSA; all other rate design considerations
are subsidiary to this basic premise.
The COSA and Rate Design study is based on the
cost to serve customers. The methodology used is
detailed in the report (Attachment C).
2. For this cost of service study, and to the
extent feasible, energy charges should be
based on existing rate structures. This includes:
a. A tiered rate design structure for residents
b. A flat general service rate for small non-
residential users
c. A flat demand and energy rate for large
non-residential users
Proposed residential rates are based on a two
tiered rate design structure. Small non-residential
rates are a flat seasonal rate. Large non-residential
rates have flat seasonal demand and energy
components.
3. The COSA should involve a review of all
existing rate schedules for inclusion in the
COSA or repeal.
All rate classes were reviewed except the voluntary
E-1 TOU schedule (also see note regarding E-15
schedule in Section 8, below). Analysis of the
voluntary E-1 TOU rate schedule will follow in the
fall. Only one adjustment was made to the other
rate classes: the E-18 (Municipal) and E-18-G
(Municipal Green) rates are recommended for
repeal.
4. The COSA should take into account the
impact of rate designs on electric vehicles and
electric heating customers, and should
investigate:
a. the extent to which these customers
have different load profiles from other
residential customers; and
b. the extent to which existing rate
designs should be adjusted for these
differing load profiles
Staff did not have enough time to complete this
analysis and still meet the July 1, 2016 rate
adoption goal. However, some of the concerns
behind this guideline centered on the impact of the
third tier on these types of customers. The
elimination of the third tier from the residential
rates and the increase in the first tier daily energy
allowance should alleviate these impacts.
5. The COSA should evaluate the need for a
minimum charge.
The proposed rate designs include a minimum
charge to ensure that the direct costs of customer
service, billing, meter reading, and some types of
distribution costs are collected from all customers.
6. A hydroelectric rate adjustment mechanism
should be evaluated.
Staff did not have enough time to complete this
analysis in time to have rates available for a July 1,
2016 rate adoption date, but intends to bring this
to the UAC and Council in the fall of 2016.
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Table 7: Implementation of COSA Design Guidelines
Guideline Implementation
7. The COSA should evaluate the impact of rate
designs on the economics of local solar for
current and future customers and should be
coordinated with an analysis of long-term solar
policies to be put into effect after the existing
net energy metering tariff reaches capacity.
See discussion earlier in this report for impacts on
existing and prospective net energy metering
customers. Staff is developing a successor to the
net energy metering program to take effect once
the net energy metering cap is reached. Staff has
established a set of guidelines for this analysis (see
Staff Report 6473), and will bring the results to the
Council in the spring of 2016. The economics of
solar under the proposed rates will be evaluated in
that report.
8. A connection fee study should be performed
and policies regarding residential transformer
upgrades should be reviewed, either as part of
the COSA or as part of a parallel analysis. The
COSA methodology should be coordinated with
any potential connection fee changes or policy
changes.
The E-15 Rate Schedule lists the City’s Connection
Fees. Staff did not have enough time to complete
this analysis in time to have rates available for a
July 1, 2016 rate adoption date, but intends to
bring this to the UAC and Council in the fall of
2016.
9. The impact of any proposed changes on low
income customers should be evaluated
Completed, see Figure 1.
Reserves Transfers, FY 2016 and FY 2017
The FY 2017 Electric Utility Financial Plan includes several proposed reserves transfers, shown
in Table 8. These reserves transfers have a variety of purposes, but overall they enable the
revenue trajectory projected in the Electric Utility Financial Plan. Without these transfers
additional rate increases would be required.
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Table 8: FY 2016 and FY 2017 Reserves Transfers
Fiscal
Year
Transfer
Amount
Transfer
From
Transfer
To Purpose
FY
2016
$5.6
million
Hydroelectric
Stabilization
Reserve
Supply
Operations
Reserve
Funds additional market energy purchases in FY 2016.
These purchases were required because hydroelectric
output was lower than average due to drought.
$2.0
million
Supply
Operations
Reserve
Distribution
Operations
Reserve
Ensures Distribution Operations Reserve is above
minimum guidelines at the end of FY 2016.
$5.6
million
CIP Reserve Distribution
Operations
Reserve
Minimum guidelines for the CIP Reserve are
recommended to be reduced, and some of the funds
used to fund additional FY 2016 capital investment.
FY
2017
$5.4
million
Supply Rate
Stabilization
Reserve
Supply
Operations
Reserve
This transfer allows the City to reduce the July 1, 2016
rate increases, delaying part of the rate increase to July
1, 2017.
Up to
$9.0
million
Hydroelectric
Stabilization
Reserve
Supply
Operations
Reserve
Funds additional market energy purchases that may be
needed if hydroelectric output is lower than average
due to continuing drought.
Up to
$4.5
million
Supply
Operations
Reserve
Distribution
Operations
Reserve
Keeps Distribution Operations Reserve above minimum
guidelines.
Proposed Changes to Electric Utility Reserves Management Practices
The proposed FY 2017 Electric Utility Financial Plan includes one change to the Electric Utility
Reserves Management Practices (see Appendix B of the Financial Plan). In the FY 2016 Electric
Utility Financial Plan, the CIP Reserve was modified to be the working capital reserve for the CIP
Program. This change was in response to modifications of the accounting process for the CIP
program that were made during the FY 2016 budget process. At the time, the minimum and
maximum guidelines were set at six months and one year of budgeted capital investment,
respectively. Staff is proposing to amend these guidelines, so the minimum guideline is 60 days
and the maximum 120 days. This is in line with the Government Finance Officer’s Association
guidelines for operational reserves and with the requirements for the electric utility’s other
operational reserves.
Electric Bill Comparison with Surrounding Cities
Table 9 compares electric bills under current rates as of February 1, 2016 for residential
customers to those in surrounding communities. Under current rates, CPAU’s customer bills are
far below PG&E’s and are lower than others for commercial customers, but slightly higher than
Santa Clara’s for higher using residential customers.
City of Palo Alto Page 15
Table 9: Residential Electric Bill Comparison ($/month)
As of February 1, 2016
Customers Usage (KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E
Santa
Clara Roseville
Residential
Customers
300 28.57 33.09 54.45 34.16 53.79
330 (Summer Median) 32.48 36.39 62.05 36.65 56.97
453 (Winter Median) 48.49 57.18 88.13 52.21 70.00
650 76.33 90.48 142.09 75.47 98.61
1200 172.03 183.43 333.61 140.38 185.21
Commercial
Customers
1,000 134 142 202 175 139
160,000 18,364 21,553 23,348 19,961 20,029
500,000 43,319 43,862 64,325 61,120 49,694
2,000,000 216,594 219,310 272,313 236,299 188,852
Commission Review and Recommendation
On April 12, 2016 the UAC reviewed the staff proposal and voted unanimously to approve it
after some in-depth discussion. Most of the discussion centered on two topics: first, whether
there were alternatives to Staff’s proposal for street lighting, and second, whether there was
any approach to the residential rate design that would preserve the current three tier system.
Staff stated they had not found any cost of service alternatives to the street lighting proposal,
and that the proposed two tier system was the cost of service proposal staff and the consultant
were able to develop that came closest to the existing three tier system.
The draft minutes from the UAC’s April 12, 2016 meeting are provided as Attachment F.
Timeline
If the Finance Committee recommends approval of the staff proposal, the City Council will
consider the recommendations with the FY 2017 budget.
Resource Impact
The proposed July 1, 2016 rate changes are projected to increase sales revenues by $12 million
per year over the forecast period.
The repeal of the E-18 (Municipal) rate schedule will increase the annual electricity costs to
enterprise funds by $253,000 (12% increase) and the cost to the General Fund by $361,000
(39% increase). The modifications to the E-14 (Street Lighting) schedule will increase costs to
the General Fund by $2.0 million, and the cost for traffic signal maintenance services will
increase costs to the General Fund by $233,000.
City of Palo Alto Page 16
Policy Implications
The proposed electric rate adjustments were developed using a cost of service study and
methodology. The attached Financial Plan includes amended Reserve Management Practices
that will modify Council policy with respect to the structure of the financial reserves of the
Electric Utility. These Reserve Management Practices replace the current Reserve Management
Practices, which were last adopted by Council in June 2015 (Resolution 9521).
Environmental Review
The Finance Committee’s review and recommendation to Council on the FY 2017 Electric
Financial Plans and rate adjustments does not meet the California Environmental Quality Act’s
definition of a project, pursuant to Public Resources Code Section 21065, thus no
environmental review is required.
Attachments:
Attachment A: Resolution of the Council of the City of Palo Alto Approving the FY 2016
Electric Utility Financial Plan and Amending the Electric Utility Reserves Management
Practices (PDF)
Attachment B: Proposed FY 2016 Electric Utility Financial Plan and Electric Utility
Reserves Management Practices (PDF)
Attachment C: Report from EES Consulting Titled “City of Palo Alto Electric Cost of
Service and Rate Study” (2016) (PDF)
Attachment D: Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending and Repealing Various Electric Rate Schedules (PDF)
Attachment E: Proposed Amendments to Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4
TOU, E-7, E-7-G, E-7 TOU, E-14, and E-16 (PDF)
Attachment F: Excerpted Draft UAC Minutes of April 12, 2016 (PDF)
Attachment A
NOT YET APPROVED
160330 jb 6053708
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2017 Electric Utility Financial Plan and Amending the Electric
Utility Reserves Management Practices
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. The City intends to make changes to its Electric Utility Reserves Management
Practices to amend the management practices of the Electric Utility’s Capital Improvement
Program (CIP) Reserve.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2017 Electric Utility Financial Plan,
including the amended Electric Utility Reserves Management Practices. These Reserves
Management Practices replace the Reserves Management Practices previously approved for
the Electric Utility as part of the FY 2016 Electric Utility Financial Plan (Resolution 9521).
SECTION 2. The Council hereby approves the transfer of $5.6 million in FY 2016 from
the Hydro Stabilization Reserve to the Supply Operations Reserve, $2.0 million in FY 2016 from
the Supply Operations Reserve to the Distribution Operations Reserve, the transfer of $5.6
million in FY 2016 from the CIP Reserve to the Distribution Operations Reserve, the transfer of
$5.4 million from the Supply Rate Stabilization Reserve to the Supply Operations Reserve in FY
2017, up to $9.0 million from the Hydroelectric Stabilization Reserve to the Supply Operations
Reserve in FY 2017, and up to $4.5 million from the Supply Operations Reserve to the
Distribution Operations Reserve in FY 2017, as described in the FY 2017 Electric Utility Financial
Plan approved via this resolution.
/ /
/ /
/ /
Attachment A
NOT YET APPROVED
160330 jb 6053708
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065, and therefore, no environmental assessment is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Senior Deputy City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2017 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2017 TO FY 2023
ATTACHMENT B
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FY 2017 ELECTRIC UTILITY
FINANCIAL PLAN
FY 2017 TO FY 2023
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2017 Rate and Reserves Proposals ....................................................... 7
Section 3A: Rate Design ............................................................................................................... 7
Section 3B: Current and Proposed Rates ..................................................................................... 7
Section 3C: Reserves Management Practices, Proposed Change ................................................ 7
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................. 10
Section 4A: Electric Utility History ............................................................................................. 11
Section 4B: Customer Base ........................................................................................................ 13
Section 4C: Distribution System ................................................................................................. 13
Section 4D: Cost Structure and Revenue Sources ...................................................................... 14
Section 4E: Reserves Structure ................................................................................................... 15
Section 4F: Competitiveness ...................................................................................................... 16
Section 5: Utility Financial Projections ................................................................................. 18
Section 5A: Load Forecast .......................................................................................................... 18
Section 5B: FY 2009 to FY 2015 Cost and Revenue Trends ........................................................ 19
Section 5C: FY 2015 Results ....................................................................................................... 20
Section 5D: FY 2016 Projections ................................................................................................ 20
Section 5E: FY 2017 – FY 2023 Projections ................................................................................ 21
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Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 23
Section 5G: Long-Term Outlook ................................................................................................. 27
Section 6: Details and Assumptions ..................................................................................... 30
Section 6A: Electricity Purchases ............................................................................................... 30
Section 6B: Operations .............................................................................................................. 32
Section 6C: Capital Improvement Program (CIP) ....................................................................... 33
Section 6D: Debt Service ............................................................................................................ 34
Section 6E: Equity Transfer ........................................................................................................ 35
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 36
Section 6G: Sales Revenues ....................................................................................................... 36
Section 7: Communications Plan .......................................................................................... 37
Appendices ......................................................................................................................... 38
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 39
Appendix B: Electric Utility Reserves Management Practices ................................................... 43
Appendix C: Description of Electric utility Operational Activities .............................................. 48
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 49
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SECTION 1: DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a
section of the distribution system operates. The transmission system operates at
115-500 kV, and this is lowered to 60 kV in the subtransmission section of the
Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution
system, and finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum
electricity demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Subtransmission System: The section of the Electric Utility’s distribution system that operates
at 60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115
kV or more. The voltage at the intersection of the Electric Utility’s distribution system
and PG&E’s transmission system is 115 kV. The Electric Utility does not own or
operate any transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
5 | P a g e
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Electric Utility for the next seven fiscal
years. This Financial Plan describes how revenues will cover the costs of operating the utility
safely over that time while adequately investing for the future. It also addresses the financial
risks facing the utility over the short term and long term, and includes measures to mitigate and
manage those risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
The Electric Utility’s costs will increase substantially over the next few years, as shown in Table
1. Most of the increases are related to electric supply costs, which are increasing due to
increased transmission costs and the cost of new renewable energy projects coming online.
There are also inflationary increases in Operations costs, and some additional capital
investment costs.
Table 1: Electric Utility Expenses for FY 2015 to FY 2023
Expenses
($000)
FY 2015
(actual)
FY 2016
(est.)
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
Power Supply
Purchases 80,022 75,705 86,378 88,524 89,131 90,304 89,637 88,543 89,919
Operations 47,611 52,170 52,923 53,922 54,579 55,277 56,076 56,898 58,696
Capital Projects 12,713 16,989 27,652 22,058 26,649 15,868 16,320 16,785 17,263
TOTAL 140,346 144,864 166,953 164,504 168,710 161,450 162,034 161,225 165,877
To cover these increases in costs, revenues (and therefore rates) need to increase over the next
several years to balance costs and revenues, as shown in Table 2. The table also compares
current rate projections to those projected in last year’s Financial Plan. The rate projections are
higher this year than last year primarily due to the continued drought that has required
additional electric supply purchases to replace hydroelectric supplies.
Table 2: Projected Electric Rate Trajectory for FY 2017 to FY 2023
Projection FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Current 11% 10% 3% 0% 1% 0% 2%
Last Year 6% 6% 1% 1% 0% 0% 2%
Table 3 shows the projected reserve transfers over the forecast period. The Supply Rate
Stabilization Reserve is projected to be drawn down entirely by the end of FY 2017. Funds are
projected to be transferred from the Electric Special Projects (ESP) Reserve to the Operations
Reserve to fund smart grid projects included in the long term CIP budget. Funds are projected
to be drawn from the Hydro Stabilization Reserve in FY 2017 and FY 2018 due to lower than
average hydroelectric generation, though this projection is subject to change with weather
conditions. It should be noted that the smart grid costs included in the forecast are
6 | P a g e
placeholders, as are the transfers from the ESP Reserve. Any transfers from the ESP Reserve
require Council approval.
Table 3: Reserves Transfers for FY 2016 to FY 2023 ($000)
Reserve FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 to FY 2023
Supply Reserves
Electric Special Projects (151) (333) (3,750) -
Hydro Stabilization (5,600) (9,000) (2,400) - -
Supply Rate Stabilization 9,000* (5,411) - - -
Supply Operations 3,600 14,562 2,733 3,750 -
Distribution Reserves
Capital Improvement Program (5,600)
Distribution Operations 7,700 - - - -
* A $9 million transfer from the Supply Rate Stabilization Reserve to the Supply Operations Reserve was
approved by Council when it adopted the FY 2016 Electric Utility Financial Plan
SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2016:
1. Complete the proposed FY 2016 reserves transfers described Section 3D: Proposed
Reserve Transfers.
Staff proposes the following actions for the Electric Utility in FY 2017:
1. Complete the proposed FY 2017 reserves transfers described in Section 3D: Proposed
Reserve Transfers.
2. Increase rates effective July 1, 2016 to generate an 11% increase in sales revenues.
3. Amend the Electric Utility Reserves Management Practices to modify the minimums and
maximums for the CIP Reserve.
Note that while the projected rate increases and reserves transfers in this FY 2017 Financial
Plan are adequate to recover costs over the forecast period, the Supply Operations Reserves
are projected to be as much as $3.9 million below the minimum Supply Operations Reserve
level for FY 2017 through FY 2020. Staff still recommends proceeding with this plan for two
reasons: first, due to the presence of a strong El Niño condition in the Pacific Ocean, there is a
chance of high spring rains that may change this forecast, resulting in higher reserves, and
second, the presence of the Electric Special Projects Reserve with a balance of $51 million
means that a small temporary shortfall in the Supply Operations Reserve should not affect the
Electric Utility’s financial health and bond ratings. In the event drought continues, staff will re-
evaluate its projections for FY 2018 and may recommend additional rate increases or the
adoption of a hydroelectric rate adjuster.
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SECTION 3: DETAIL OF FY 2017 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The Electric Utility’s current rate structure and methodology are consistent with the cost of
service analysis (COSA) update in 2007 by Boris Metrics. Staff is completing a new COSA with
revised rates to become effective July 1, 2016. The new COSA is based on design guidelines
adopted by Council on September 15, 2015 (Staff Report 6061).
SECTION 3B: CURRENT AND PROPOSED RATES
The current rates were adopted on July 1, 2009, when CPAU increased electric rates by 10%.
Table 4, below, summarizes the current rates for the four largest customer classes. The Electric
Utility also has specialty rates for smaller groups of customers. These include variations on its
primary rates, such as time of use rates, the PaloAltoGreen rates, and solar net metering.
Another specialty rate is the E-18 municipal electric rate.
Table 4: Current Electric Rates (Adopted July 1, 2009)
Rate Component Units
E-1
(Residential)
E-2 (Small
Commercial)
E-4 (Medium
Commercial)
E-7 (Large
Commercial)
Demand (Summer) $/kW N/A N/A 20.54 18.97
Demand (Winter) $/kW N/A N/A 13.84 11.54
Energy (Summer)
Tier 1 $/kWh 0.09524 0.14045 0.08171 0.07808
Tier 2 $/kWh 0.13020 N/A N/A N/A
Tier 3 $/kWh 0.17399 N/A N/A N/A
Energy (Winter)
Tier 1 $/kWh Same as
summer
energy
0.12661 0.07318 0.07209
Tier 2 $/kWh N/A N/A N/A
Tier 3 $/kWh N/A N/A N/A
Tier amounts:
Tier 1 kWh/day 0-10 N/A N/A N/A
Tier 2 kWh/day 11-20 N/A N/A N/A
Tier 3 kWh/day >20 N/A N/A N/A
Staff proposes an 11% overall increase in revenue along with changes in rate design and
changes in the allocation of costs between customer classes to ensure that the rates are based
on the cost of service for each customer group. These proposals are detailed in the consultant
report titled “City of Palo Alto Electric Cost of Service and Rate Study,” by EES Consulting (2016).
SECTION 3C: RESERVES MANAGEMENT PRACTICES, PROPOSED CHANGE
Staff proposes one change to the Electric Utility Reserves Management Practices (See Appendix
B: Electric Utility Reserves Management Practices) in this Financial Plan. Staff recommends
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revising the CIP Reserve minimum to be 60 days of capital expenses, with a maximum of 120
days of expenses, which aligns with the Government Financial Officers of America rule of thumb
for operating reserves and the minimum and maximum guidelines for the Distribution
Operations Reserve. Staff recommends transferring $5.6 million from the CIP Reserve to the
Distribution Operations Reserve. Also see Section 3D: Proposed Reserve Transfers.
SECTION 3D: PROPOSED RESERVE TRANSFERS
In the FY 2016 Electric Financial Plan Council approved a $9 million transfer from the Supply
Rate Stabilization Reserve to the Supply Operations Reserve. Staff proposes the following
additional transfers in FY 2016:
Transfer $5.6 million from the Hydroelectric Stabilization Reserve fund to the Supply
Operations Reserve to cover additional costs associated with low hydroelectric
generation due to the drought.
Transfer $2.0 million from the Supply Operations Reserve to the Distribution Operations
Reserve to ensure reserve adequacy in the Distribution Operations Reserve.
Transfer $5.6 million from the CIP Reserve to the Distribution Operations Reserve as
part of the change to Reserves Management Practices described above.
For FY 2017, staff proposes the following transfers:
Transfer $5.4 million from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve. This transfer is to enable the City to spread necessary long term
rate increases over multiple years to reduce the short-term impact on ratepayers.
Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offset
potential costs associated with low hydroelectric generation. Some or all of this transfer
may be unnecessary if weather conditions change, but if drought continues, this
transfer will enable the City to fund the associated additional energy costs.
Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution
Operations Reserve if necessary to ensure reserve adequacy in the Distribution
Operations Reserve.
The impact of these transfers on reserves levels can be seen in Figure 8 (for Supply Fund
Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E: FY 2017 – FY 2023
Projections. Table 5 shows the projected balance of each of the Electric Utility reserves for the
period covered by this Financial Plan. The projected balances are also provided in. Appendix A:
Electric Utility Financial Forecast Detail
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Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2016 to FY 2023
Ending Reserve
Balance ($000) FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Reappropriations - - - - - - - -
Commitments 3,102 3,102 3,102 3,102 3,102 3,102 3,102 3,102
Underground Loan 730 730 730 730 730 730 730 730
Public Benefits 2,574 2,700 2,790 2,799 2,717 2,545 2,434 2,374
Special Projects 51,838 51,535 51,383 51,050 47,300 47,300 47,300 47,300
Hydro Stabilization 17,000 11,400 2,400 0 0 0 0 0
Capital 0 2,864 2,864 2,864 2,864 2,864 2,864 2,864
Rate Stabilization 14,411 5,411 0 0 0 0 0 0
Operations 22,498 22,734 22,015 22,281 24,814 27,033 30,783 34,269
Unassigned 0 0 0 0 0 0 0 0
TOTAL 112,153 100,476 85,284 82,827 81,528 83,574 87,214 90,639
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SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and
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Section 6: Details and Assumptions.
SECTION 4A: ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel
engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity
continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E
proved more economical than the diesel engines, and by the late 1920s CPAU was using its own
diesel engines only during peak demand periods. At that time CPAU owned 45 miles of
distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual
consumption. The diesel engines remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did
throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the
sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto,
which doubled the number of customers. Some was related to the proliferation of electric
appliances, as evidenced by the fact that residential customers were using three times more
electricity in 1970 than they had been in 1950. But the most notable factor was the growth of
industry in Palo Alto during that time. By 1970, commercial customers were using 20 times
more electricity per customer than they had been in 1950. These decades also saw several
other notable events, including:
1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of
Reclamation to purchase power from the Central Valley Project (CVP), a contract which
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement
program for its underground system in the early 1990s.
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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
Utility1 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 managing its supply portfolio. CPAU began
purchasing power from marketers and also investigated building a power plant in Palo Alto or
partnering in the development of a gas-fired power plant elsewhere. Climate change was also
becoming more of a concern to the community, and gradually CPAU shifted its focus to the
procurement of renewable energy. In 2002 CPAU adopted a goal of achieving 20% of its energy
supply from renewables by 2015. Subsequently CPAU signed its first contract for renewable
power, a contract for energy from a wind generator commencing deliveries in 2005. In 2011 the
renewable energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a
plan to make its electric supply 100% carbon neutral, which it achieves through the
combination of its carbon-free hydroelectric supplies, purchases of long-term renewable energy
supplies, and short-term renewable energy purchases (RECs) to meet the balance of its needs.
1 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
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Figure 1: Customer Base (FY 2015)
Residential
16%
Small
Comm
8%
Med
Comm
32%
Large
Comm
41%
Municipal
3%
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 29,300 customers
connected to the electric system,
26,400 (90%) of which are residential
and 2900 (10%) of which are non-
residential. Residential customers
consumed 173 gigawatt-hours (GWh)
in FY 2015, approximately 18% of the
electricity sold, while non-residential
customers consumed 82% or
763 GWh. Residential customers use
electricity primarily for lighting,
refrigeration, electronics, and air conditioning.2 Non-residential customers use the majority of
their electricity for cooling, ventilation, lighting, office equipment (offices), cooking
(restaurants), and refrigeration (grocery stores).3
As shown in Figure 1 large customer loads represent a larger proportion of sales for the Electric
Utility than they do for the City’s other utilities. The largest customers (the 66 customers on the
E-7 rate schedule) account for over 40% of CPAU’s sales. The next largest customer group (the
740 commercial customers on the E-4 rate schedule) represents another 32% of sales. In total,
that means that less than 3% of customers account for nearly three quarters of the electric
load.
SECTION 4C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 470 miles of
distribution lines, of which 223 miles (48%) are overhead lines and 245 miles (52%) are
underground. The Electric Utility also maintains six substations, roughly 2,000 overhead line
transformers, 1,075 underground and substation transformers, and the associated electric
services (which connect the distribution lines to the customers’ homes and businesses). These
lines, substations, transformers, and services, along with their associated poles, meters, and
2 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
3 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
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Figure 2: Cost Structure (FY 2015)
Figure 3: Hydroelectric Variability (FY 2016)
0%
20%
40%
60%
80%
100%
120%
140%
Low
Hydro
Average High
Hydro
Surplus
Hydro (sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 4: Revenue Structure (FY 2015)
other associated electric equipment, represent the vast majority of the infrastructure used to
deliver electricity in Palo Alto.
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric commodity
purchases accounted for roughly 55% of the
Electric Utility’s costs in FY 2015. Operational
costs represented roughly 31%, and capital
investment was responsible for the remaining
10%. CPAU’s non-hydro long-term
commodity supply is heavily dependent on
long-term contracts which have little
variability in price. On average, costs for
these long-term contracts are not predicted
to increase as quickly as operations and CIP
costs, and will steadily become a smaller
proportion of the Electric Utility’s costs. Commodity supply costs are projected to be roughly
47% of total costs in FY 2023.
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,
average, and low hydroelectric generation
scenarios. Additional costs associated with a
very low generation scenario can range from
$10-12 million per year. For the current
hydroelectric risk assessment see Section 5F:
Risk Assessment and Reserves Adequacy.
As shown in Figure 4 the Electric Utility
receives 87% of its revenue from sales of
electricity and the remainder from connection
fees, interest on reserves, cost recovery
transfers from other funds for shared services
provided by the electric utility, and other
sources. Some revenue sources are primarily
accounting entries that reflect things such as
CPAU’s participation in a pre-funding program
associated with its contract with WAPA, as well
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as accounting entries associated with occasional sales of surplus hydroelectric energy during
wet years. Without these entries sales revenues represent roughly 93% of total revenues.
Appendix A: Electric Utility Financial Forecast Detail
shows more detail on the utility’s cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 800 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 25% of the utility’s
revenue comes from peak demand charges on large commercial customers. Due to moderate
weather and the prevalence of natural gas heating, however, loads (and therefore revenues)
are very stable for this utility, without the large seasonal air conditioning or winter heating
loads seen at some other utilities.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of
contingencies. It also maintains two funds, the Supply Fund and the Distribution Fund, to
manage costs associated with electricity supply and electricity distribution, respectively. This
separation of supply and distribution costs was established as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) back in the late
1990s and early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues
to maintain separate funds to facilitate separation of supply and distribution costs in the rates.
This could be important in case California ever decides to reintroduce Direct Access, and may
also be useful for rate design as the nature of utility services evolves in response to higher
penetrations of distributed generation.
The various reserves are summarized below, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
Reserves for Commitments: Reserves equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
Reserves for Reappropriations: Reserves for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve. This is currently an important
reserve for all utility funds, but changes in budgeting practices will change that in future
years, as described in Section 3C (Reserves Management Practices, Proposed Change).
Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which was accumulated during deregulation of California’s electric system to
fund the stranded costs associated primarily with the Calaveras hydroelectric resource
and the California-Oregon Transmission Project. When that reserve was no longer
needed for that purpose, the reserve was renamed and the purpose was changed to
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fund projects with significant impact that provide demonstrable value to electric
ratepayers.
Hydroelectric Stabilization Reserve: This contingency reserve is used for managing
additional costs due to below average hydroelectric generation, or to hold surpluses
resulting from above average hydroelectric generation.
Underground Loan Reserve: This reserve is an accounting tool used to offset receivables
associated with loans made through the underground loan program. It is adjusted
according to principal payments made on those loans.
Public Benefits Reserve: CPAU’s electric rates include a separate charge called the
“Public Benefits Charge” which generates revenue to be used for energy efficiency,
demand-side renewable energy, research and development, and low-income energy
efficiency services. Any funds not expended in the current year are added to the Public
Benefits Reserve for use in future years.
Capital Improvement Program (CIP) Reserve: The CIP reserve is used to provide
working capital and contingency funds for the CIP program, as well as to accumulate
funds for major future one-time expenditures. This type of reserve is used in other
utility funds (Electric, Gas, and Wastewater Collection) as well.
Supply and Distribution Rate Stabilization Reserves: These reserves are intended to be
empty unless one or more large rate increases are anticipated in the forecast period. In
that case, funds can be accumulated to spread the impact of those future rate increases
across multiple years. This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
Supply and Distribution Operations Reserves: These are the primary contingency
reserves for the Electric Utility, and are used to manage yearly variances from budget
for operational costs and electric supply costs (aside from variances related to
hydroelectric generation). This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves
are for any financial resources not assigned to the other reserves and are normally
empty.
SECTION 4F: COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2015 was
$513.17 under current CPAU rates, 36% lower than the annual bill for a PG&E customer with
the same consumption and 9% lower 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 January 1, 2016. Note that rates for PG&E customers increased
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substantially on that date, and with rates currently in effect, the bill for the median residential
user is roughly 45% below PG&E’s rates.
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, 2016 rates.
However, even with the proposed rate increases, Palo Alto’s residential bills will remain
substantially below PG&E’s current rates, but slightly above Santa Clara’s.
Table 6: Residential Monthly Electric Bill Comparison (Effective 1/1/16, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(December)
300 28.57 54.45 34.16
(Median) 453 48.49 88.39 52.21
650 76.33 142.09 75.47
1200 172.03 333.61 140.38
Summer
(July)
300 28.57 54.45 34.16
(Median) 330 32.48 62.05 36.65
650 76.33 148.02 75.47
1200 172.03 339.84 140.38
Table 7 shows the average monthly electric bill for commercial customers for various usage
levels. Bills for small commercial customers in Palo Alto are 37% below what they would be in
PG&E territory and 20% below what they would be in Santa Clara (Silicon Valley Power). For
large commercial customers, rates are 30% to 35% below PG&E’s and are 4% to 10% lower than
Santa Clara’s. Even with the proposed rate increases, Palo Alto’s commercial bills will remain
substantially below PG&E’s, and below Santa Clara’s for most commercial customers.
Table 7: Commercial Monthly Electric Bill Comparison (1/1/16, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 134 212 167
160,000 18,364 27,221 19,228
500,000 43,319 66,152 47,913
2,000,000 216,594 311,640 234,322
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SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 5 shows a 40-year history of Palo Alto electricity consumption. Average electricity
consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then
electricity consumption has declined slowly as a result of a continuing focus on energy
efficiency, as well as the adoption of more stringent appliance efficiency standards and energy
standards in building codes.
Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2023, as well as what
electricity consumption would have been without energy efficiency rebates, appliance
efficiency standards, stricter building codes, and rooftop solar photovoltaic (PV) generation.
The forecast assumes that current trends continue and sales through the forecast period
decline slightly. As of the end of December 2015, net metered PV installations in Palo Alto
provided roughly 1% of the total electricity consumed in the City. The Council-adopted Local
Solar Plan’s goal is to increase the energy generated by local solar to 4% of the City’s needs by
2023.
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Figure 6: Forecasted Electricity Consumption
SECTION 5B: FY 2009 TO FY 2015 COST AND REVENUE TRENDS
The annual expenses for the Electric Utility declined between FY 2009 and FY 2012, as shown in
Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail
. These decreases were partly related to declines in electricity market prices due to the impact
of shale gas and partly due to above average output from hydroelectric resources. These
factors are discussed in more detail in Section 6A: Electricity Purchases. Since FY 2012, total
expenses for the utility have been increasing as renewable resources come online. In FY 2014
through FY 2015 costs were higher due to lower than average output from hydroelectric
resources.
Commodity costs are responsible for most of the changes in the utility’s expenses over the last
six years. Operational costs and capital investment increased at less than 1% per year over that
time.
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2015 and Projections through FY 2023
SECTION 5C: FY 2015 RESULTS
In spring of 2014 staff recommended no rate change for July 1, 2014, the start of FY 2015.
Although staff forecast a $5.7 million deficit for FY 2015 without a rate change, reserves were
adequate to absorb this deficit. However, drought conditions worsened in the spring of 2014
and continued through the winter of 2014/2015, resulting in a deficit of $17.0 million for FY
2015. The increased deficit was entirely related to the low output from hydroelectric resources,
which necessitated electricity market purchases to replace the lower than expected
hydroelectric energy.
SECTION 5D: FY 2016 PROJECTIONS
In spring of 2015, staff recommended (and Council approved) no rate change for July 1, 2015,
the start of FY 2016. Based on hydroelectric conditions at the time, staff forecasted a $10.3
million deficit for FY 2016. This deficit was primarily related to low hydroelectric output, and
was to be funded from the Operations and Hydroelectric Stabilization reserves. Staff’s current
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forecast for FY 2016 is for a deficit of $20.1 million, $9.8 million more than forecasted in spring
of 2015. This change is mainly related to two factors: 1) capital improvement program costs
have increased by roughly $7 million, and 2) energy costs have increased by roughly $3 million
due to continuing drought and resulting low hydroelectric generation.
The $7 million increase in CIP costs is largely related to the delay of projects from previous fiscal
years to FY 2016 rather than mid-year adjustments requesting new funding. Staff proposes
partially funding this portion of the deficit using a $5.6 million transfer from the CIP Reserve,
which contains $8.4 million collected in previous fiscal years to fund capital projects. The
additional $3 million related to energy costs would be funded from the Hydroelectric
Stabilization Reserve. These transfers are discussed in Section 3D: Proposed Reserve Transfers.
SECTION 5E: FY 2017 – FY 2023 PROJECTIONS
As shown in Figure 7 above, costs for the Electric Utility are projected to increase in FY 2017
and level off in subsequent years. Revenues will have to increase 11% in FY 2017 and another
10% in FY 2018 to keep up with these cost increases. The increases are primarily related to
electricity purchase costs, which have been increasing since FY 2013 and will continue to
increase through FY 2018 as new renewable projects come online to fulfill the City’s
environmental goals and as transmission costs increase. Operations costs are expected to
increase substantially in FY 2017 to begin catching up on deferred maintenance, but
subsequently are expected to increase at or below the inflation rate (2-3 %/year) through the
forecast period. Projected capital expenses for FY 2017 through FY 2023 are $30 million higher
than last year’s forecast due mostly to several large one-time projects, some customer driven,
but also due to an increase in spending on system improvements. The increased costs are
partially offset by $13.4 million in revenue from reimbursements associated with those
projects. Aside from those one-time costs, capital expenses are projected to increase in FY 2017
and then stay roughly level through the forecast period. This forecast also assumes that smart
grid costs are funded from the Electric Special Projects Reserves.
Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund
reserves) and Figure 9 (for Distribution Fund reserves), below. The Supply Rate Stabilization
Reserve is projected to be empty by the end of FY 2016. Assuming the projected increases in
revenue, the Distribution Operations reserve will remain adequate through the forecast period,
comfortably above minimum levels and adequate to meet all identified risks. The Supply
Operations Reserve, however, is forecasted to be below minimum levels. This is discussed in
more detail in Section 5F: Risk Assessment and Reserves Adequacy.
With respect to the Hydro Stabilization Reserve, these projections assume average rainfall next
winter, although hydro generation is still predicted to be below average due to low reservoir
levels. The current forecast does not take into account potential rainfall associated with El Niño
conditions in the spring of 2016, nor potential drought in the 2016/2017 year, which may follow
the El Niño conditions of 2016. This scenario may help reserves, hurt reserves, or have little net
effect depending on the associated rainfall levels.
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Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2015 and Projections through FY 2023
Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2015 and Projections through FY 2023
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SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two contingency reserves, the Supply Operations Reserve and
the Distribution Operations Reserve. This Financial Plan maintains reserves in excess of the
reserve minimum for the Distribution Operations Reserve throughout the forecast period.
Reserve levels also exceed the short-term risk assessment level for the Distribution Fund. The
Supply Operations Reserve, however, may end up below minimum levels and below the short-
term risk assessment level.
There are a variety of risks associated with the Supply Fund as are shown in Table 8. Because of
the high range of uncertainty in energy price predictions more than three years in the future,
this risk assessment is only performed for the first two fiscal years of the forecast period. It is
important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 8 is very low.
Table 8: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2017 FY 2018
1. Load Net Revenue 1.2 1.3 Revenue loss from load decreases (net of
reduction in energy purchases)
2. Production from Hydroelectric
Resources: Western & Calaveras 3.4 2.4 Lower than forecasted hydro
3. Renewable Production: Landfill &
Wind 0.5 2.1 Additional cost of renewable output that is
higher than forecasted
4. Carbon Neutral Cost 0.1 - Higher than forecasted market prices for RECs
5. Market Price (Energy) 1.1 0.5 Higher than forecasted market prices for
energy
6. Local Capacity 0.4 0.7 Higher than forecasted market prices for local
capacity
7. Transmission/CAISO 2.8 3.0 High-end transmission forecast scenario
8. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
9. Western Cost 3.0 3.5 Risk of rate adjustments from Western
Electric Supply Fund Risks $13.6
million
$14.3
million
Projected Supply Operations +
Hydro Stabilization Reserve Levels
$16.4
million
$12.8
million
Of the risks faced by the Electric Utility’s Supply Fund in FY 2016, the risk of a dry year with very
low hydroelectric output is normally the largest, accounting for nearly half the total cost of all
adverse outcomes. Since the utility’s costs for its hydroelectric resources are almost entirely
fixed, costs do not decline when the output of those resources are low, but the utility needs to
buy power to replace the lost output. The converse happens when hydroelectric output is
higher than average. However, for FY 2017 and FY 2018, lower than average hydroelectric
output is already expected, so the adverse risk is smaller than usual. Risks associated with
hydroelectric output account for $3.4 million (25%) of FY 2017 contingencies.
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Of the remaining risks for FY 2017, $2.8 million (20%) is related to the projected costs if
transmission cost increases are higher than staff’s current forecast. Another $3.0 million (22%)
is related to the possibility of drought-related changes to Western rates for CVP hydropower,
and $1.1 million (8%) is related to fluctuations in market prices for capacity, energy, and RECs.
As shown in Figure 10, the Supply Operations Reserve will drop below the minimum reserve
guidelines by as much as $3.9 million over the course of the forecast period. In addition, as
shown in Figure 11, the combined hydro stabilization and supply operations reserves will drop
below the risk assessment level. It is acceptable under the Electric Utility Reserves Management
Practices to drop below minimum reserve guidelines so long as Council approves the Financial
Plan. Staff recommends proceeding with this plan for two reasons: first, due to the presence of
a strong El Niño condition in the Pacific Ocean, there is a chance of high spring rains that may
change this forecast, resulting in higher reserves, and second, the presence of the $51 million
Electric Special Projects Reserve means that a small temporary shortfall in the Supply
Operations Reserve should not affect the Electric Utility’s bond ratings. In the event drought
continues, staff will re-evaluate its projections for FY 2018 and may recommend additional rate
increases or the adoption of a hydroelectric rate adjuster.
Figure 10: Electric Supply Operations Reserve Adequacy
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Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 9 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2021. As shown in Figure 12, the Distribution Operations Reserve will stay within the
reserve guidelines over the course of the forecast period. The risk assessment includes the
revenue shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 9: Electric Distribution Fund Risk Assessment ($000)
FY 2017 FY 2018 FY 2019 FY 2020 FY 2021
Total non-commodity revenue $49,651 $52,233 $52,275 $52,237 $53,804
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $3,919 $4,122 $4,126 $4,123 $4,246
CIP Budget $27,652 $22,058 $26,649 $15,868 $16,320
CIP Contingency @10% $2,765 $2,206 $2,665 $1,587 $1,632
Total Risk Assessment value $6,684 $6,328 $6,791 $5,710 $5,879
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Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, the CIP Reserve is projected to be well within the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels in later years, CIP Commitments are nearly impossible to project that far out,
and adjustments to the reserve can be made in future years.
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Figure 13: Electric Distribution Operations Reserve Adequacy
SECTION 5G: LONG-TERM OUTLOOK
This forecast covers the period from FY 2017 through FY 2023, but various long-term
developments may create new costs for the utility over the next 5 to 35 years. While it is
challenging to accurately forecast the impact these events will have on the utility’s costs, it is
worth noting them as future milestones and keeping them in mind for long-term planning
purposes.
For the supply portfolio, the 2020s will see a number of notable events. The contract with
Western for power from the CVP will expire in 2024. Determining the future relationship with
Western after 2024 will be important in the years leading up to the contract expiration,
especially because this resource represents nearly 40% of the electric portfolio, and is the
utility’s largest source of carbon-free electricity. The utility’s three earliest and lowest cost
renewable contracts will also begin expiring around that time, with the first contract expiring in
2021 and the last in 2028. These three contracts, plus one more expiring in 2030, currently
provide 17% to 18% of the energy for the utility’s supply portfolio at prices under $65 per
megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those
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contracts expire. Although recent prices have been in that range (or even lower), and costs
may decrease in the future, current renewable projects also benefit from a wide range of tax
and other incentives that may or may not be available in the 2020s and beyond. However, staff
is in the process of procuring a replacement for the contract expiring in 2021 at a lower price
than any of the City’s current renewable contracts.
The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs
dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032
(assuming no new debt is issued). The project will only be 40 years old at that time. Calaveras
debt service represents roughly 70% of the annual costs of that project (and nearly 7% of the
utility’s total costs), so when the debt is retired, the project could be a low-cost asset for the
utility, providing carbon-free energy equal to 13% of the Electric Utility’s supply needs in an
average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to 5 million per year in revenue from
allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to
pay for energy efficiency and to purchase renewable energy to support the utility’s Carbon
Neutral Plan. That revenue source is expected to continue through 2020, but there is no
provision for the continuation of these allocations past 2020. If the Electric Utility no longer
received these allowances, it would have to fund these programs from sales revenues.
Transmission costs are also continuing to rise. If the State continues to increase mandates or
incentives for renewable energy development, integrating these new projects into the
transmission grid will be an ever increasing challenge, some costs of which will be borne by Palo
Alto. The planned expansion of the CAISO to a larger regional grid control area may result in
additional transmission costs that could further increase CPAU’s transmission costs. In addition
to the costs of new transmission lines that will need to be built, flexible resources will be
required to balance rapid changes in wind or solar output throughout the day. Palo Alto will
likely bear some of the costs of these new lines and resources. CPAU is also currently
investigating installing a second transmission interconnection for Palo Alto, which could be
funded by the Electric Special Projects reserve.
Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these
factors may begin to create notable increases in electric consumption and have a variety of
impacts on the distribution system. As housing stock is turned over, however, stricter building
codes may help to counteract load growth, as may increasing numbers of rooftop solar
installations. The utility has already started to take some of these factors into account in its
long-term planning processes, but will need to continue to incorporate them into its planning
methodologies.
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Looking out toward 2050 and beyond, if the State were to adopt climate goals consistent with
Executive Orders S-3-05 and B-16-2012 (with a goal of reducing GHG emissions to 80 percent
below 1990 levels by 2050), or if similar (or more aggressive) local goals were adopted, it is
conceivable that electricity could replace natural gas and petroleum almost entirely. Many, if
not most, vehicles would use electricity, though hydrogen is another potential fuel source
under development and other technologies might be developed. Initial analysis of these types
of scenarios is being undertaken in the context of the Sustainability and Climate Action Plan
(S/CAP) development process. These types of scenarios require careful planning for the
associated load growth to make sure the distribution system did not end up overloaded, or
conversely, to avoid overinvestment.
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SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: ELECTRICITY PURCHASES
As shown in Figure 14 the utility gets roughly 50% of its energy from hydroelectric projects in a
normal year (FY 2014 and FY2015 were dry). Contracts with renewable sources made up just
over 20% of the portfolio in FY 2015, and are projected to rise to roughly 50% in FY 2017. The
remainder comes from unspecified market sources. Under the City’s Carbon Neutral Plan, CPAU
purchases RECs corresponding to the amount of market energy it purchases.
Figure 14: Electricity Supply by Source
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Figure 15 shows the historical and projected costs for the electric supply portfolio,4 as well as
average and actual hydroelectric generation.5 Electric supply costs decreased in FY 2010 and FY
2011 due to decreases in market prices related to shale gas. In addition, FY 2009 was a dry year
with low hydroelectric production, so FY 2010 and FY 2011 looked better by comparison. Costs
increased in FY 2013, FY 2014, and FY 2015 due to the drought, which reduced the amount of
generation from hydroelectric resources. Costs are projected to decrease slightly in FY 2016
due to slightly higher hydroelectric generation, and may decrease substantially depending on
rainfall. Even if hydroelectric generation returns to normal levels, costs will increase in FY 2017
due to increases in renewable energy costs as various renewable projects come online to fulfill
the City’s carbon neutral and RPS goals. Transmission charges are also projected to increase as
new transmission lines are built throughout California to accommodate new renewable
projects. In total, electric supply costs are projected to increase to $75.2 million by FY 2018, at
which point all currently contracted renewable projects will be online. Supply costs are only
projected to change slightly in subsequent years.
4 Costs are shown net of wholesale revenues, and cannot be directly compared with the electric supply purchase
figures shown in Appendix Error! Reference source not found. (Error! Reference source not found.).
5 Average hydroelectric generation increased in January of 2015 due to an increase in the utility’s contractual share
of the output of the CVP Federal hydropower project.
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Figure 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.
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From FY 2009 to FY 2015, Operations costs increased by $2.2 million, or less than 1% per year
on average. In 2013 there was a one-time increase in expenses associated with an adjustment
to the value of the City’s investment portfolio. Excluding debt service and transfers, which stay
relatively stable over time, costs increased roughly 2.5% per year over that time. In FY 2016,
however, Operations costs increased $4.5 million (9.6%). This was primarily due to increases in
overhead and salary and benefit costs. Operations costs are projected to increase by an
additional $1M per year starting in FY 2017 as work is done to begin catching up on deferred
maintenance that has accumulated due to difficulty filling certain maintenance positions. Aside
from those increases, costs are projected to increase with inflation over the remainder of the
forecast period.
Figure 16: Historical and Projected Electric Utility Operational Costs
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
CIP spending for FY 2017 through FY 2019 is projected to increase substantially, primarily due to
major one-time projects, including service connection upgrades for a few major customers,
pole replacements related to the Fiber to the Home project, and Smart Grid upgrades. Ongoing
capital investment in the electric distribution system is also increasing. The one-time projects
will mostly be funded by customer-specific fees and transfers from other funds. Only $3.4
million of the funding for the one-time projects is projected to come from utility rates. This
forecast assumes that smart grid projects are financed from the Electric Special Projects
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Reserve and with additional funding from the water and gas funds, but it would also be possible
to use bond financing.
Excluding the one-time projects listed above, the CIP plan for FY 2017 to FY 2023 is primarily
funded by utility rates, but other sources of funds include connection fees (for Customer
Connections), phone and cable companies (primarily for undergrounding), and other funds (for
smart grid). The details of the CIP budget will be available in the Proposed FY 2017 Utilities
Capital Budget. Figure 16 shows the adopted / proposed / projected capital budgets as well as
actual and projected capitalized administrative overhead associated with the program.
Figure 17: Electric Utility CIP Spending
SECTION 6D: DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently
makes payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax
Credit Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction
costs of solar demonstration projects at the Municipal Services Center, Baylands Interpretive
Center, and Cubberley Community Center. The capacity of these projects totaled 250 kW. In
exchange for funding part of the construction costs Electric Utility receives the RECs from these
35 | P a g e
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 10: Electric Utility Debt Service ($000)
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2007 Clean Renewable
Energy Bonds 100 100 100 100 100 100 - -
The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage
ratio of 125% of debt service. The current Financial Plan maintains compliance with these
covenants throughout the forecast period, as shown in Appendix C.
The Electric Utility’s reserves and net revenue are also pledged as security for the bond
issuances listed in Table 11, even though the Electric Utility is not responsible for the debt
service payments. The Electric Utility’s reserves or net revenues would only be called upon if
the responsible utilities are unable to make their debt service payments. Staff does not
currently foresee this occurring.
Table 11: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Electric Utility’s:
Net Revenues Reserves
1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water $1,457 No Yes
*Net of Federal interest subsidy
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since6. Each year it is calculated according
to the 2009 Council-adopted methodology, and does not require additional Council action.
6 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to equity transfer methodology.
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SECTION 6F: WHOLESALE REVENUES AND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 12% comes
from other sources. Of these other sources, about a third represent wholesale “revenues” that
is included solely for accounting purposes. These revenues have offsetting electric supply
purchase costs, and do not normally affect the utility’s net position. Of the remaining revenues,
the largest revenue sources are interest on reserves, connection fees for new or replacement
electric services, and carbon allowance revenues associated with the State’s cap-and-trade
program. In FY 2015 these sources represented roughly 50% of revenue from sources other
than electricity sales. The remaining FY 2015 revenues consisted of a variety of one-time
transfers.
Revenues from connection fees have more than doubled since FY 2009. Revenue from these
sources decreased slightly during the recession, but has increased substantially since then,
peaking in FY 2014. Staff is forecasting slightly lower revenue from this source in subsequent
years.
Carbon allowance revenues are projected to stay stable through the forecast period, as is
interest income. However, both of these revenue sources are subject to some uncertainty. The
State’s cap-and-trade program regulations only describe the program through 2020. This
forecast assumes the program will remain in place with similar program design following 2020,
but that may not be the case. CARB is in the process of establishing post-2020 rules.
The forecast for interest income assumes current interest rates continue and there are no
major reserve reductions aside from what is anticipated in this Financial Plan. If interest rates
rise, interest income could increase, and if reserves decreased (due to drought or a withdrawal
from the ESP reserve for a major project), interest income would decrease.
SECTION 6G: SALES REVENUES
Sales revenue projections are based on the load forecast in Section 5A: Load Forecast and the
projected rate changes shown in Figure 7. As discussed in Section 5A, sales revenues for this
utility stay relatively stable due to the mild climate in Palo Alto. In addition, Palo Alto is a built
out City, with incremental growth in population and relatively stable commercial customer
loads.
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SECTION 7: COMMUNICATIONS PLAN
CPAU communication methods include use of the Utilities website, utility bill inserts, messaging
on bills and envelopes, email newsletters, print ads in local publications, videos and
participation in community outreach events. The FY 2017 Electric Utility communications
strategy covers these primary areas: rates, drought impacts, efficiency, renewables, operations,
infrastructure and safety.
In FY 2017, CPAU is proposing an 11% increase in electric utility rates. Electric utility rates have
not increased since 2009, as the City has been drawing down reserves from the Electric Fund.
The rate increase is necessary this year, as these reserves are below the minimum reserve level.
Communications will focus on the reasons why a rate increase is necessary, and why the
percentage increase is higher than projected in past financial forecasts, particularly due to the
impact of the drought. Palo Alto purchases a significant portion of its electricity from
hydroelectric resources. Severe drought conditions over the past few years have reduced
available hydroelectric supplies, requiring the City to purchase more costly replacement electric
supplies.
Reliability and safety are primary concerns for CPAU and City Council has placed increasing
emphasis on capital improvement investments for utility infrastructure. In order to maintain
system integrity, continued capital improvement costs are necessary. Deferring such costs to
future years would not be prudent, as deferred investment in maintenance, operations and
capital improvement upgrades could potentially jeopardize the safety and reliability of the
electric utility system. Despite these costs and increasing rates, CPAU’s rates are far lower than
PG&E’s. Keeping costs low is one of the benefits CPAU offers its customers as a public utility
provider.
CPAU will continue to communicate about the City’s carbon neutral electric supply portfolio.
Outreach includes apprising the public of major renewable energy purchase agreements, which
contribute toward Palo Alto’s long-term energy security and commitment to sustainability.
Recent power purchase agreements have allowed CPAU to procure long-term renewable
electric supplies at low costs. CPAU will highlight these environmental attributes and value in
our communications.
Throughout the year, communications staff promotes CPAU’s electric efficiency services,
rebates and local renewable energy programs. Since January 2015, CPAU has been encouraging
community participation in the Georgetown University Energy Prize competition, a friendly,
national campaign for energy efficiency. This two-year campaign encourages the community to
reduce energy use and compete for a $5 million prize. Just recently, CPAU launched new
programs that will allow customers to better understand and manage their energy use. Such
programs include a free utility bill analysis service with option for a subsidized in-depth home
energy assessment, and an online utility portal for customers to view consumption history,
learn about efficiency tips and CPAU programs they can take advantage of for home energy
efficiency.
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APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
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APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
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1 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2
3 ELECTRIC LOAD
4 Purchases (MWh)1,040,851 1,019,788 978,833 969,519 976,319 980,894 979,005 977,292 993,844 997,125 998,260 997,531 997,596 999,464 986,864
5 Sales (MWh)995,811 965,048 946,518 942,562 946,841 950,784 936,773 946,996 963,035 966,215 967,314 966,608 966,670 968,481 956,271
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1048$ 0.1155$ 0.1168$ 0.1156$ 0.1154$ 0.1164$ 0.1158$ 0.1158$ 0.1274$ 0.1398$ 0.1435$ 0.1435$ 0.1452$ 0.1452$ 0.1477$
9 Change in System Average Rate 10%1%-1%0%1%0%0%11%10%3%0%1%0%2%
10 Change in Average Residential Bill 11%-5%-1%-4%-1%-5%10%8%10%2%0%1%0%1%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)- - 2,760,000 343,000 1,886,000 305,000 - - - - - - - - -
14 Commitments (Non-CIP)2,241,000 1,916,000 1,463,000 1,593,000 2,737,000 3,528,000 3,164,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000
15 Restricted for Debt Service - - - - - - - - - - - - - - -
16 Emergency Plant Replacement 3,057,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - -
17 Central Valley Project Reserve 22,000 153,000 306,000 305,000 314,000 313,000 329,000 - - - - - - - -
18 Underground Loan Reserve 709,000 717,000 731,000 736,000 742,000 738,000 734,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000
19 Public Benefits Reserves 2,109,000 4,280,000 3,750,000 3,139,000 1,149,000 2,197,000 2,064,000 2,574,000 2,700,394 2,790,356 2,799,046 2,717,399 2,544,810 2,434,376 2,373,578
20 Electric Special Projects Reserve 70,397,000 64,535,000 59,865,000 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,534,944 51,383,460 51,050,127 47,300,127 47,300,127 47,300,127 47,300,127
21 Hydro Stabilization Reserve - - - - - - - 17,000,000 11,400,000 2,400,000 - - - - -
22 Capital Reserves - - - - - - - - 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000
23 Rate Stabilization Reserves 55,418,000 47,783,000 54,339,000 66,331,000 74,609,000 69,029,000 70,049,000 14,411,000 5,411,000 - - - - - -
24 Operations Reserves - - - - - - - 22,498,000 22,733,825 22,014,607 22,281,475 24,814,237 27,032,576 30,783,222 34,269,008
25 Unassigned - - - - - - - - - - 0 - - - -
26 TOTAL STARTING RESERVES 133,953,000 120,384,000 124,214,000 129,005,000 132,757,000 128,948,000 129,178,000 112,153,000 100,476,163 85,284,424 82,826,649 81,527,763 83,573,514 87,213,725 90,638,713
27
28 REVENUES
29 Net Sales 105,312,712 113,129,269 111,948,267 109,309,318 109,974,337 110,301,711 108,674,986 109,644,507 122,721,963 135,111,161 138,828,086 138,726,658 140,313,744 140,576,542 141,259,300
30 Wholesale Revenues 10,618,388 7,903,940 8,443,016 7,189,218 6,635,790 6,010,409 6,267,000 6,763,000 11,732,580 13,249,634 14,128,345 15,816,411 16,063,130 15,367,103 15,992,486
31 Other Revenues and Transfers In 11,744,330 8,458,392 6,374,799 6,316,048 8,736,976 9,772,185 8,379,507 8,315,879 17,306,372 13,685,157 16,104,331 8,952,387 9,297,064 9,706,437 10,042,027
32 TOTAL REVENUES 127,675,429 129,491,602 126,766,082 122,814,584 125,347,103 126,084,305 123,321,493 124,723,385 151,760,915 162,045,951 169,060,763 163,495,456 165,673,937 165,650,082 167,293,813
33
34 EXPENSES
35 Electric Supply Purchases 82,348,075 68,714,475 61,247,248 58,724,136 61,313,637 68,785,977 80,022,010 75,705,000 86,377,737 88,523,524 89,131,094 90,303,886 89,637,135 88,542,665 89,918,517
36 Operating Expenses
37 Administration
38 Allocated Charges 3,585,068 2,667,704 2,807,991 3,416,423 4,399,674 4,139,837 4,511,222 3,651,896 3,743,559 3,837,533 3,933,853 4,032,597 4,133,584 4,236,960 4,342,932
39 Rent 3,428,294 3,963,377 3,721,542 3,839,201 3,875,836 4,051,044 4,147,742 4,991,328 5,141,068 5,295,300 5,454,159 5,617,784 5,786,317 5,959,907 6,138,704
40 Debt Service 8,185,819 7,919,136 7,343,352 8,902,751 9,265,736 9,020,651 9,037,000 9,139,768 8,953,886 8,955,164 8,808,619 8,818,349 8,783,507 8,792,388 9,624,493
41 Transfers and Other Adjustments 13,282,668 10,860,269 13,056,927 11,603,695 16,797,054 11,385,421 10,789,119 11,778,415 11,781,400 11,784,460 11,787,597 11,790,812 11,794,107 11,797,485 11,800,947
42 Subtotal, Administration 28,481,848 25,410,486 26,929,812 27,762,069 34,338,299 28,596,953 28,485,082 29,561,407 29,619,914 29,872,457 29,984,228 30,259,541 30,497,516 30,786,740 31,907,076
43 Resource Management 2,062,511 3,033,428 2,380,313 2,654,024 3,024,268 3,541,524 2,138,615 2,966,005 3,071,752 3,182,092 3,295,330 3,413,039 3,513,915 3,605,059 3,699,533
44 Demand Side Management 3,336,356 4,048,114 3,490,676 4,541,531 3,529,529 3,187,875 3,491,470 4,476,424 3,612,447 3,694,961 3,558,989 3,275,399 3,213,446 3,169,620 3,251,901
45 Operations and Mtc 8,975,462 8,892,002 9,339,340 9,288,490 9,601,481 9,488,627 10,716,881 12,216,961 13,621,453 14,075,224 14,540,523 15,022,687 15,450,353 15,847,643 16,258,382
46 Engineering (Operating)879,303 1,094,766 1,070,441 1,057,783 1,114,945 1,102,008 1,230,160 1,929,843 1,981,771 2,035,192 2,089,931 2,146,191 2,201,598 2,257,007 2,313,920
47 Customer Service 1,650,731 1,896,956 1,881,881 1,908,493 2,007,322 2,032,231 1,548,851 2,348,349 2,436,928 2,529,629 2,624,844 2,724,064 2,806,984 2,880,302 2,956,458
48 Allowance for Unspent Budget - - - - - - - (1,328,747) (1,421,462) (1,467,484) (1,514,688) (1,563,571) (1,607,504) (1,648,717) (1,691,289)
49 Subtotal, Operating Expenses 45,386,213 44,375,751 45,092,464 47,212,389 53,615,844 47,949,218 47,611,059 52,170,242 52,922,803 53,922,071 54,579,157 55,277,350 56,076,307 56,897,655 58,695,982
50 Capital Program Contribution 13,510,141 12,571,376 15,635,370 13,126,059 14,226,622 9,119,111 12,713,425 16,988,980 27,652,114 22,058,131 26,649,398 15,868,470 16,320,285 16,784,774 17,262,590
51 TOTAL EXPENSES 141,244,429 125,661,602 121,975,082 119,062,584 129,156,103 125,854,305 140,346,493 144,864,222 166,952,654 164,503,726 170,359,649 161,449,705 162,033,726 162,225,093 165,877,088
52
53 ENDING RESERVES
54 Reappropriations (Non-CIP)- 2,760,000 343,000 1,886,000 305,000 - - - - - - - - - -
55 Commitments (Non-CIP)1,916,000 1,463,000 1,593,000 2,737,000 3,528,000 3,164,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000
56 Restricted for Debt Service - - - - - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - -
58 Central Valley Project Reserve 153,000 306,000 305,000 314,000 313,000 329,000 - - - - - - - - -
59 Underground Loan Reserve 717,000 731,000 736,000 742,000 738,000 734,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000
60 Public Benefits Reserves 4,280,000 3,750,000 3,139,000 1,149,000 2,197,000 2,064,000 2,574,000 2,700,394 2,790,356 2,799,046 2,717,399 2,544,810 2,434,376 2,373,578 2,191,308
61 Electric Special Projects Reserve 64,535,000 59,865,000 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,534,944 51,383,460 51,050,127 47,300,127 47,300,127 47,300,127 47,300,127 47,300,127
62 Hydro Stabilization Reserve - - - - - - 17,000,000 11,400,000 2,400,000 - - - - - -
58 Capital Reserve - - - - - - - 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000
59 Rate Stabilization Reserve 47,783,000 54,339,000 66,331,000 74,609,000 69,029,000 70,049,000 14,411,000 5,411,000 - - - - - - -
60 Operations Reserve - - - - - - 22,498,000 22,733,825 22,014,607 22,281,475 24,814,237 27,032,576 30,783,222 34,269,008 35,868,004
61 Unassigned - - - - - - - - - 0 - - - - -
62 TOTAL ENDING RESERVES 120,384,000 124,214,000 129,005,000 132,757,000 128,948,000 129,178,000 112,153,000 100,476,163 85,284,424 82,826,649 81,527,763 83,573,514 87,213,725 90,638,713 92,055,438
6053706
1 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2
3 REVENUES
4 Net Sales 82%87%88%89%88%87%88%88%81%83%82%85%85%85%84%
5 Other Revenues and Transfers In 18%13%12%11%12%13%12%12%19%17%18%15%15%15%16%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 56%54%46%47%46%54%56%51%46%46%45%47%47%47%46%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%2%2%3%3%3%3%3%2%2%2%2%3%3%3%
13 Rent 2%3%3%3%3%3%3%3%3%3%3%3%4%4%4%
14 Debt Service 6%6%6%7%7%7%6%6%5%5%5%5%5%5%6%
15 Transfers and Other Adjustments 9%9%11%10%13%9%8%8%7%7%7%7%7%7%7%
16 Subtotal, Administration 20%20%22%23%27%23%20%20%18%18%18%19%19%19%19%
17 Resource Management 1%2%2%2%2%3%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 6%7%8%8%7%8%8%8%8%9%9%9%10%10%10%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 1%2%2%2%2%2%1%2%1%2%2%2%2%2%2%
21 Allowance for Unspent Budget 0%0%0%0%0%0%0%-1%-1%-1%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 30%32%34%36%39%36%31%33%30%31%30%32%33%33%33%
23 Capital Program Contribution 10%10%13%11%11%7%9%12%17%13%16%10%10%10%10%
24 TOTAL EXPENSES 95%96%93%93%96%97%96%95%92%90%90%89%89%90%90%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
28 1. Load Net Revenue 77,428 652,853 1,208,477
29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 3,397,119
30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 539,073
31 4. Carbon Neutral Cost 331,630 303,022 114,983
32 5. Market Price 909,196 775,584 1,138,589
33 6. Local Capacity 475,962 408,388 446,695
34 7. Transmission/CAISO 4,555,915 3,741,647 2,806,120
35 8. Plant Outage 1,000,000 1,000,000 1,000,000
36 9. Western Cost 3,130,000 2,704,738 2,973,619
37 10. Regulatory & Legal - - -
38 11. Supplier Default - - -
39 TOTAL 20,170,708 19,380,490 13,624,674
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 196%176%179%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
44 Distribution Revenue Variance 3,240,845 3,290,258 3,918,697 4,122,469 4,163,694 4,160,651 4,285,471 4,293,497 4,422,302
45 10% CIP Program Contingency 1,271,343 1,698,898 2,765,211 2,205,813 2,664,940 1,586,847 1,632,028 1,678,477 1,726,259
46 Total Risk Asssessment Value 4,512,188 4,989,156 6,683,908 6,328,282 6,828,634 5,747,498 5,917,499 5,971,975 6,148,561
47 Projected Operations Reserve 22,498,000 22,733,825 22,014,607 22,281,475 24,814,237 27,032,576 30,783,222 34,269,008 35,868,004
48 Operations Reserve, % of Risk Value 499%456%329%352%363%470%520%574%583%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- - - - - - 8,339,587 6,424,305 6,557,102 6,698,857 6,808,081 6,897,553 7,013,278 7,126,792 7,248,481
46 Target (90 days of non-capital expenses)- - - - - - 10,338,923 9,636,457 9,835,653 10,048,285 10,212,121 10,346,329 10,519,917 10,690,188 10,872,721
47 Max (120 days of non-capital expenses)- - - - - - 12,338,259 12,848,609 13,114,204 13,397,714 13,616,162 13,795,105 14,026,555 14,253,584 14,496,961
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- - - - - - 8,339,587 6,424,305 6,557,102 6,698,857 6,808,081 6,897,553 7,013,278 7,126,792 7,248,481
51 Target (90 days of non-capital expenses)- - - - - - 10,338,923 9,636,457 9,835,653 10,048,285 10,212,121 10,346,329 10,519,917 10,690,188 10,872,721
52 Max (120 days of non-capital expenses)- - - - - - 12,338,259 12,848,609 13,114,204 13,397,714 13,616,162 13,795,105 14,026,555 14,253,584 14,496,961
53 Risk Assessment Value 4,512,188 4,989,156 6,683,908 6,328,282 6,828,634 5,747,498 5,917,499 5,971,975 6,148,561
ELECTRIC UTILITY FINANCIAL PLAN
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APPENDIX B: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
(This section includes the proposed amendments to this section. This section will be finalized
following Council adoption of the final amended version.)
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c) For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f) For operating contingencies, as described in Section 12 (Operations Reserves)
g) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserves for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c) As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d) To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
ELECTRIC UTILITY FINANCIAL PLAN
J u n e 1 6 , 2 0 1 4 44 | P a g e
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 14 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Commitments will be set to an amount equal to the total remaining spending
authority for all contracts in force for the Electric Supply Fund and Electric Distribution
Fund, respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Reappropriations will be set to an amount equal to the amount of all remaining
capital and non-capital budgets that will be reappropriated to the following fiscal year for
each Fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of
Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve
and Adoption of Electric Special Project Reserve Guidelines). These policies and timelines
are included from Resolution 9206 as amended to refer to the reserves structure set forth
in these Reserves Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) The preferred projects to be funded by the ESP Reserve must be identified by end of
FY 2015;
f) Any uncommitted funds remaining at the end of FY 2020 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed; and
g) Funds may be used for analysis and pilot projects which would be the basis for planned
large projects.
Section 7. Hydroelectric Stabilization Reserve
Supply cost savings and surplus energy sales revenue associated with higher than average
generation from hydroelectric resources may be added to the Electric Supply Fund’s
Hydroelectric Stabilization Reserve by action of the City Council and held to offset higher
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commodity supply costs during years of lower than average generation. Withdrawal of
funds from the Hydroelectric Stabilization Reserve requires action by the City Council.
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 60 days 6 months of budgeted CIP expense
Maximum Level 120 days 12 months of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve
for Commitments as a result of a change in contractual commitments related to CIP
projects. Any other additions to or withdrawals from the CIP reserve require Council
action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
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approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to d) above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
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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.
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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
City of Palo Alto
Prepared by:
570 Kirkland Way, Suite 100
Kirkland, Washington 98033
A registered professional engineering corporation with offices in
Kirkland, WA and Portland, OR
Telephone: (425) 889-2700 Facsimile: (425) 889-2725
City of Palo Alto
Electric Cost of Service and Rate Study
Draft
April 5, 2016
ATTACHMENT C
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY i
Contents
CONTENTS .............................................................................................................................................................. I
EXECUTIVE SUMMARY ........................................................................................................................................... 1
REVENUE REQUIREMENT ................................................................................................................................................. 1
COST OF SERVICE ANALYSIS.............................................................................................................................................. 2
RATE DESIGN OVERVIEW ................................................................................................................................................. 4
RECOMMENDATION ....................................................................................................................................................... 5
OVERVIEW OF RATE SETTING PRINCIPLES .............................................................................................................. 6
OVERVIEW AND ORGANIZATION OF REPORT ........................................................................................................................ 6
OVERVIEW OF THE ANALYSES ........................................................................................................................................... 6
OVERVIEW OF REVENUE REQUIREMENT METHODOLOGIES ..................................................................................................... 7
OVERVIEW OF COST ALLOCATION PROCEDURES ................................................................................................................... 7
RATE DESIGN AND ECONOMIC THEORY .............................................................................................................................. 7
DEVELOPMENT OF THE REVENUE REQUIREMENT .................................................................................................. 9
OVERVIEW OF CPA’S REVENUE REQUIREMENT METHODOLOGY ............................................................................................. 9
DEVELOPMENT OF POWER SUPPLY COSTS......................................................................................................................... 10
OTHER OPERATIONS AND MAINTENANCE EXPENSES ........................................................................................................... 10
GENERAL FUND TRANSFER ............................................................................................................................................. 11
RATE-FUNDED CAPITAL IMPROVEMENT PROGRAM (CIP) .................................................................................................... 11
MISCELLANEOUS REVENUES ........................................................................................................................................... 11
TRANSFERS FROM RESERVES .......................................................................................................................................... 11
SUMMARY OF REVENUE REQUIREMENT ............................................................................................................................ 11
RECOMMENDATION ..................................................................................................................................................... 12
COST OF SERVICE ANALYSIS ................................................................................................................................. 13
COSA DEFINITION AND GENERAL PRINCIPLES ................................................................................................................... 13
FUNCTIONALIZATION OF COSTS ....................................................................................................................................... 14
CLASSIFICATION AND ALLOCATION OF COSTS ..................................................................................................................... 15
COST OF SERVICE RESULTS ............................................................................................................................................. 23
REVIEW OF CUSTOMER CLASSES OF SERVICE ..................................................................................................................... 26
RATE DESIGN ....................................................................................................................................................... 27
RATE DESIGN – NON-COMMODITY ................................................................................................................................. 27
RATE DESIGN – COMMODITY ......................................................................................................................................... 28
PROPOSED RATE DESIGN ............................................................................................................................................... 28
MUNICIPAL E-18 ......................................................................................................................................................... 32
MINIMUM BILL ANALYSIS .............................................................................................................................................. 32
TIME OF USE RATE SCHEDULES ....................................................................................................................................... 32
PUBLIC BENEFITS CHARGE ............................................................................................................................................. 34
NET ENERGY METERING ................................................................................................................................................ 35
STREET LIGHTING AND TRAFFIC SIGNALS ........................................................................................................................... 36
TECHNICAL APPENDIX .......................................................................................................................................... 38
COST OF SERVICE MODEL
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 1
Executive Summary
The City of Palo Alto (CPA) retained EES Consulting, Inc. (EES Consulting) to perform an electric
cost of service analysis (COSA) and rate study as part of its ongoing efforts to maintain fiscally
prudent and fair, cost-based rates for its electric customers. The purpose of this report is to
discuss the data inputs, assumptions and results that were part of developing the rate study.
A comprehensive rate study generally consists of three separate, yet interrelated analyses.
These three analyses are the revenue requirement, the COSA, and the rate design.
Revenue Requirement
A revenue requirement analysis compares the overall revenues of the utility to its expenses and
helps determine whether an overall adjustment to rate levels is required. For this analysis, a
“cash basis” method was used for determining CPA’s revenue requirement. Recorded annual
operating expenses for fiscal year (FY) 2014-2015 as well as the FY 2016-17 budget forecast
provided by CPA were used to determine the revenue requirement.
A base case was defined to develop the COSA. This base case assumed the following:
Historic/recorded year is FY 2014-15 (July 2014 – June 2015).
Test year/allocation year is FY 2016-17.
Billing determinants were based on FY 2016-17 forecasts.
Expenses were based on forecasted FY 2016-17 expenses.
Transfers from reserves and budget savings of $17.9 million were assumed for FY 2016-17,
as assumed in the CPA financial forecasts.
If CPA’s rates currently in effect remain unchanged, FY 2016-17 revenues from all sources
would equal $118.9 million, while budgeted expenses are $148.7 million.1 After taking the
reserve transfers and budget savings into account, as well as other revenues, the revenue
requirement for FY 2016-17 is $122.5 million. This is the amount of revenue needed from rates
in FY 2016-17. With no rate change, forecasted sales revenues for FY 2016-17 are $110.5
million, as shown in Schedule 1.9. This means there remains a 10.1 percent shortfall in revenues
relative to costs. This translates into a 10.8 percent increase in the CPA’s system average retail
rate, as shown in Schedule 1.1, though the increase for individual customer classes of service
will vary, as discussed in the section on the COSA. A summary of the draft revenue requirement
is shown in Table 1. Additional detail can be found in Schedules 1.4 and 3.1.
1 Expenses exclude capital expenses reimbursed by connection fees or other direct reimbursement agreements.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 2
Table 1
Summary of the Revenue Requirement
FY: 2016-2017
Revenue Requirement
Production (Purchased Power) $90,065,328
Distribution $13,195,107
Customer Accounts and Services $5,946,916
Administration and General $13,931,304
Capital Projects from Rates $13,501,2502
General Fund Transfer $12,101,000
Total Expenses $148,740,905
Transfers from Reserves and Allowance for Unspent Budget $17,870,017
Other Revenues 8,382,909
Total Revenue Required from Rates (Revenue Requirement) $122,487,979
Revenues Based on Rates Currently in Effect $110,531,481
Additional Rate Revenue Needed $11,956,498
Total Required Rate Revenue Increase (Decrease) 10.8%
Cost of Service Analysis
A COSA is concerned with the equitable allocation of the revenue requirement to the various
customer classes of service. As is standard procedure for COSAs, the revenue requirement
shown in Table 1 for CPA was functionalized, classified and allocated. This process is described
in detail in the section below titled “Cost of Service Analysis.”
Table 2 shows the results of the COSA. It shows the revenues that would be realized in
FY 2016-17 without any rate changes (i.e. keeping the rates currently in effect), the share of the
FY 2016-17 revenue requirement that should be allocated to each rate class as determined by
the COSA, and the deficiency in revenue if current rates are left unchanged. Without a rate
change, FY 2016-17 revenues will be less than allocated FY 2016-17 costs for every class of
service. In addition, the variance between revenues and costs is greater for some classes than
others. The last column of Table 2 shows the increase in revenue required for each rate class.
For most classes this increase will be achieved by increasing rates.
The results of the COSA are summarized in Table 2. More detail is presented in Schedules 1.1,
1.2, and 1.4, and the COSA methodology is described in more detail below in the “Cost of
Service Analysis” section of this report.
2 Excludes capital expenses reimbursed by connection fees or other direct reimbursement agreements.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 3
Table 2
Summary of Cost of Service Analysis for FY 2016-17 Test Year
Projected
FY 2016-17
Revenues under
Rates Currently in
Effect
Net Revenue
Requirement
Projected Deficiency
in FY 2016-17
Revenue Based on
Rates Currently in
Effect
Revenue
Increase
needed3
Residential E-1 $18,406,003 $20,785,989 ($2,379,986) 12.9%
Small Non-residential E-2 9,421,113 10,019,138 (598,025) 6.3%
Medium Non-residential E-4 38,382,821 42,680,642 (4,297,821) 11.2%
Large Non-residential E-7 41,216,279 42,441,354 (1,225,074) 3.0%
City Accounts E-18 3,044,789 4,463,490 (1,418,701) 46.6%
Street/Traffic Lights 60,477 2,097,367 (2,036,890) 3368.1%4
TOTAL $110,531,481 $122,487,979 ($11,956,498) 10.8%
Overall CPA needs a 10.8 percent revenue increase for FY 2016-17. The results show that while
customers on Rate Schedule E-7 are paying close to cost of service already, most of the rate
classes will need a significant rate increase. The E-1 rate class and the E-4 rate class show the
largest increases. This is a result of significant changes in customer usage characteristics since
the last COSA and rate redesign. In the last few years some rate classes have increased energy
consumption or peak demand, while others have decreased consumption or demand.
As is typical with most rate schedules, particularly those without large fixed charges, when
energy consumption increases or decreases significantly, a COSA may reveal the need for
realignment of revenue collection among classes of service. Classes whose consumption and
demand have decreased since the last COSA will typically see higher rate increases so they are
paying their share of fixed system costs, while classes with increasing consumption and demand
will see lower rate increases.
As part of the COSA, the composition of each rate class was reviewed to determine whether
classes should be combined or additional classes created. Each rate class was found to have
distinct consumption characteristics that indicated those customers should be grouped
together under a single rate schedule, except for the E-18 (Municipal) rate class. The customers
in the E-18 class have similar consumption characteristics to the E-2 (Small Non-Residential), E-4
(Medium Non-Residential), and E-7 (Large Non-Residential) rate classes, and are recommended
to be merged into those other rate classes.
3 Projected FY 2016-17 revenue deficiency divided by projected FY 2016-17 revenue based on rates currently in
effect.
4 This increase in revenue will primarily come from charging all City customers for lighting service rather than
through rate increases to the general public.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 4
Rate Design Overview
The rates for the residential and non-residential customers are designed to take into account
differences in energy costs for various generating resources as well as the impacts seasonal
changes in energy use and peak demand have on the utility’s distribution capacity needs. The
E-1 (Residential) rate class is fairly homogenous compared to the other rate classes, and these
varying costs are best captured in a tiered energy rate design. For the non-residential classes, E-
2 (Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential),
these costs are best captured by a seasonal rate structure. Note that while these
methodologies capture seasonal variations in cost, they do not capture hourly cost variations.
This requires time of use rates, which require more advanced metering that is only available to
a small subset of Palo Alto customers. Optional time of use rates are made available to these
customers, and reflect both seasonal and hourly capacity needs and energy consumed.
Rate Design - Non-Commodity
The allocation of distribution costs is based on an analysis of the base and excess monthly
energy and capacity costs associated with that rate class, the Average and Excess method. The
Average and Excess method compares the baseline capacity and energy used (the “average,” or
“baseline”) against the maximum capacity and energy used on a seasonal basis (the “excess”).
This captures the level of system capacity required to serve the customer during peak times as
opposed to average times. The rate design for the E-1 (Residential) class is tiered, with the first
tier reflecting the baseline usage, which is defined as energy usage below 11 kWh per day. This
is the median summer usage, since this customer class’s peak usage is in the winter. This is
reversed for the E-2 (Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large
Non-Residential) customer classes, with the baseline consumption in the winter season and the
peak in the summer.
Costs associated with demand-related system costs (such as transformers or lines) were
separated into tier or season using the average and excess demand information from the COSA.
The methodology assigns costs associated with baseload demand to all tiers or seasons, while
costs related to the distribution capacity required to serve peak demands is allocated to Tier 2
(for the residential class) or the summer season (for the non-residential classes). Customer-
related costs are allocated equally to each tier or season based on the energy billing
determinants.
Rate Design - Commodity
The commodity component of the rate design is based on differences in the cost of energy from
the utility’s various sources of supply, as well as the impact of peak demand on capacity costs.
For the E-1 (Residential) class, lower-cost resources are allocated to Tier 1 usage, while higher
cost resources are allocated to Tier 2. Because this rate class is winter peaking, generating
capacity costs were not reflected differently in each tier. This is because generating capacity
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 5
requirements are driven by the system peak demand rather than the customer class peak
demand, and the system peak demand occurs in the summer, when residential use is lower.
In order to develop commodity rates for rate classes E-2 (Small Non-Residential), E-4 (Medium
Non-Residential), and E-7 (Large Non-Residential), the costs for each generating resource were
assigned to the season in which the costs were incurred. Demand rates were calculated by
allocating baseload capacity costs to both summer and winter rates, while the remainder of the
capacity-related costs were allocated to the summer (peak demand) period.
Recommendation
Based on the projected revenue requirement and COSA analysis, the following observations can
be made for CPA:
CPA will need to increase overall revenues by 10.8 percent for FY 2016-17 in order to
recover sufficient revenues to meet costs.
Revenues for each rate class should be aligned with the costs allocated to that rate class.
Customers under rate schedule E-18 (Municipal Electric Use) should be moved to the E-2,
E-4, and E-7 rate schedules as appropriate and the E-18 rate schedule should be retired.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 6
Overview of Rate Setting Principles
EES Consulting, Inc. (EES Consulting) was retained by the City of Palo Alto (CPA) to perform a
comprehensive electric cost of service and rate study. Performing an electric rate study is
necessary to assure that CPA’s rates are structured to be fair, equitable and based on the cost
of providing service to all City customers.
In conducting a cost of service and rate study, three inter-related analyses are performed:
1. Revenue Requirement Analysis: This analysis examines the various sources and uses of
funds for the utility and determines the overall revenue required to operate the utility.
2. Cost of Service Analysis (COSA): The COSA is used to determine the fair and equitable
allocation of the total revenue requirement to the various customer classes of service (e.g.
residential, small non-residential, medium non-residential, etc.). This analysis provides a
determination of the level of revenue responsibility of each class of service and the
adjustments from current revenues required to meet the cost of service.
3. Rate Design Analysis: The third analysis involves evaluating the rate design options
available and designing rate schedules that can be applied to each rate class to equitably
collect revenues that match the cost to serve each customer in that class.
Overview and Organization of Report
This report is divided into sections that follow these three analyses. This first section is a
generic discussion of the theory and financial principles behind setting rates. This is followed
by a section discussing the development of the revenue requirement analysis for CPA. The next
section discusses the COSA. Finally, rate design options are presented in the fourth and final
section. A technical appendix is attached at the end of this report that provides details of the
various analyses. The schedules contained in the technical appendix are referenced throughout
the report.
The purpose of this section of the report is to provide a brief overview of the fundamentals of
cost identification and allocation for purposes of developing electric rates. From this base-level
of knowledge, more insight and understanding can be obtained from the following sections of
the report that discuss the specifics of the Revenue Requirement, Cost of Service, and Rate
Design analyses mentioned above.
Overview of the Analyses
All electric utility rate cost allocation methodologies share the same basic framework. That is,
in allocating electric costs multiple separate yet interrelated analyses (revenue requirement
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 7
analysis, COSA, and rate design analysis) are performed. A variety of reasonable methodologies
exist within each of these separate analyses.
Overview of Revenue Requirement Methodologies
For this study, a cash basis was used to determine CPA’s electric utility’s revenue requirement.
The cash basis methodology aligns well to most Publicly Owned Utility (POU) budgetary
processes and is more easily understood by POU managers and policy makers.
Overview of Cost Allocation Procedures
After the total revenue requirement has been determined, it is allocated to the various
customer classes of service based upon a cost-based methodology that reflects cost causation
and cost-causal relationships between customer characteristics and the production and delivery
of the services. This analytical exercise usually takes the form of a COSA. A COSA begins by
assigning each cost in a utility’s revenue requirement into major categories that reflect the
utility’s capital investment and services provided to customers, such as power supply,
transmission, distribution and customer. This is called “functionalization.” Next, the
functionalized costs are linked to categories (such as demand-, energy-, and customer-related
costs) and a direct assignment category. This is called “classification.” Allocation factors are
then used to allocate each cost to each class of service. At that point the revenue requirement
has been allocated to each class of service and a determination of the necessary revenue
adjustments between classes of service can be made.
Rate Design and Economic Theory
The final step in the rate study process is to design rates for each class of service. Rates can be
structured in many ways, but ultimately they should reflect the types of costs that the utility
incurs to serve the customer (e.g. demand-, energy- and customer-related costs), and should
collect the required level of revenues to safely and reliably operate the utility. Traditional rate
designs use time-of-day, seasonal or marginal cost-based utility rates to provide accurate, cost-
based price signals for the cost of power supply and to equitably allocate the cost of providing
distribution service. The utility, in designing power supply rates, will need to take into
consideration the characteristics of the power supply it acquires, as well as the characteristics
of the customer to whom the utility will sell. POUs are subject to a wide variety of state statutes
and regulations on topics including renewable portfolio mandates, cap and trade, energy
efficiency programs, public goods charges and net metering, each presenting compliance costs.
Particularly relevant to the rates studied by this COSA are the following:
Article XIII C of the California Constitution amended by Proposition 26 (2010), which defines
all imposed government charges, including electric rates, as taxes requiring voter approval
unless certain exceptions are met; and
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 8
Public Utilities Code Section 385-387.8, which requires all POUs to have a public benefits
charge built in to their rates to be used for a variety of programs, including: 1) demand side-
management services to promote efficiency and conservation, 2) new investment in
renewable energy and technologies, 3) research and development programs for the public
interest, and 4) services and discounts for low income electricity customers.
Public Utilities Code Section 2827, which sets out requirements that POUs offer net
metering rates for certain types of customer-owned generators until the number of
customer taking that rate reaches a specified limit.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 9
Development of the Revenue Requirement
This section of the report presents the development of the electric revenue requirement for
CPA. Simply stated, a revenue requirement analysis compares the overall revenues of the
utility to its expenses and determines the overall adjustment to rate levels that is required.
Overview of CPA’s Revenue Requirement Methodology
As discussed in the previous section of the report, CPA utilizes the “cash basis” approach for
determining its revenue requirement. In summary form, CPA’s components to its revenue
requirement include the elements shown in Table 4.
Table 4
Elements of a Cash Basis Revenue Requirement
+ Operation and Maintenance Expenses (O&M)
Power Supply Expense
Distribution Expense
Customer Accounting Expenses
Administrative and General Expense
+ Capital Improvements funded from Rates
+ General Fund Transfer
= Total Revenue Requirement
- Transfers from Reserves
- Miscellaneous Revenue Sources
= Net Revenues Required From Rates
From this basic analytical framework, the next step in determining the revenue requirement
methodology is to select a time period over which to review revenue and expenses. In the case
of CPA, a fiscal year test period was utilized (July through June) rather than a calendar year test
period. The test period may either be a past fiscal year or a future fiscal year. The former is
appropriate when costs do not change significantly from year to year, while the latter is more
appropriate when costs are expected to change significantly. Various costs for CPA are
projected to increase in the FY 2016-17 fiscal year (July 2016 through June 2017), so this fiscal
year was chosen as the test period for the COSA. CPA provided budgeted costs for FY 2016-17.
The next step in the analysis was to translate the CPA budgeted costs into the system used by
the Federal Electric Regulatory Commission (FERC), the FERC System of Accounts. The FERC
System of Accounts provides a set of industry-standard methodologies for classification of
electric costs and allocating to classes of service. For example, costs associated with the
secondary distribution system (lines and customer transformers) are traditionally allocated
primarily using customer peak demand, regardless of what time of day that occurs (called “non-
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 10
coincident peak demand”). These methodologies will be discussed in the “Cost of Service
Analysis” section later in this report, but it is important when reviewing the schedules in the
technical appendix to be aware that all costs are categorized by FERC Accounts. A summary of
the FY 2016-17 revenue requirement (using the FERC System of Accounts) is provided in
Schedule 1.4, and the detail is shown in Schedule 3.1.
Development of Power Supply Costs
As with most electric utilities, the major expense associated with operating the utility is power
supply. Approximately $90 million or 69 percent of the FY 2016-17 total revenue requirement
of the utility is power supply costs, as shown in Schedule 3.1. Power supply costs include costs
from renewable and non-renewable resources, including Western Area Power Administration
(WAPA), Northern California Power Agency (NCPA) resources and power purchase agreements.
In addition, power supply costs include California Independent System Operator (CAISO)
transmission and ancillary charges. CPA’s proposed FY 2016-17 Operating Budget was used for
the derivation of power supply costs.
Other Operations and Maintenance Expenses
CPA’s proposed FY 2016-17 Operating Budget was also used for the derivation of all other
operations and maintenance (O&M) expenses. Total FY 2016-17 O&M expenses (excluding
power supply) are projected to be $33 million. As shown in Schedules 1.4 and 3.1, this is made
up of the following:
Distribution expenses of $13.2 million. These costs include maintenance of distribution
system infrastructure such as lines, transformers, meters, and substations.
Customer Service related costs of $5.9 million. These costs include meter reading, billing,
key account representatives and general customer service.
Administrative and general costs of $13.9 million. These costs include functions like
accounting, benefit overhead, insurance, and other types of administrative overhead.
FY 2016-17 O&M and Power Supply costs together total $123.1 million, as shown in Schedules
1.4 and 3.1.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 11
General Fund Transfer
CPA calculates the equity transfer from its Electric Utility based on a methodology adopted by
Council in 2009,5 which has remained unchanged since then. The General Fund Transfer will be
$12.1 million in FY 2016-17, as shown in Schedule 3.1.
Rate-Funded Capital Improvement Program (CIP)
For FY 2016-17, the budgeted CIP is $13.5 million, as shown in Schedules 1.4 and 3.1. This
excludes any capital expenses reimbursed by customers through connection fees or other
reimbursement agreements.
Miscellaneous Revenues
CPA receives additional operating and non-operating revenues and contributions. These come
in the form of interest revenues, miscellaneous service revenues, rents and other revenue.
Interest revenues represent interest on the utility’s reserves. Miscellaneous service revenues
include minor revenue sources like pole attachment fees for other utilities such as
telecommunications, transfers from other City-owned utilities for shared services, and charges
for damaged utility property. Rents represent rent paid to the General Fund for the use of City-
owned property for utility purposes. Other revenues include wholesale sales of surplus energy.
For FY 2016-17 the projection for such revenues and contributions is $8.4 million, as shown in
Schedules 1.4 and 3.1.
Transfers from Reserves
In its FY 2016-17 Electric Utility Financial Plan, CPA is anticipating that $15.1 million will be
withdrawn from reserves in FY 2016-17 for rate stabilization. In addition, CPA estimates that
roughly $2.8 million in budgeted operational and capital expenses remain unspent each year in
the normal course of business. These savings and reserves withdrawals are included in the line
titled “Transfers from Reserves and Allowance for Unspent Budget” in Schedules 1.4 and 3.1.
Summary of Revenue Requirement
Once all of the components of the cash basis revenue requirement have been determined, the
parts can be summed to equal the total revenue requirement. CPA’s revenue requirement for
5 City of Palo Alto City Manager’s Report (CMR) 280:09, “Adoption of an Ordinance Adopting the Fiscal Years 2010
and 2011 Budget, Including the Fiscal Year 2010 Capital Improvement Program, Changes to the Municipal Fee
Schedule, Utility Rates and Charges, Equity Transfer Methodology Change and Changes to Compensation Plans,”
June 15, 2009 and CMR 260:09, “Recommendation to City Council to Change the Methodology Used to Calculate
the Equity Transfer from Utilities Funds to the General Fund,” May 26, 2009.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 12
the FY 2016-17 test period is summarized in Table 5. More detail on the individual components
of the revenue requirement can be found in Schedules 1.4 and 3.1.
Table 5
Summary of the Revenue Requirement
FY: 2016-2017
Revenue Requirement
Production (Purchased Power) $90,065,328
Distribution $13,195,107
Customer Accounts and Services $5,946,916
Administration and General $13,931,304
Capital Improvement Projects from Rates $13,501,2506
General Fund Transfer $12,101,000
Total Expenses $148,740,905
Transfers from Reserves and Allowance for Unspent Budget ($17,870,017)
Other Revenues ($8,382,909)
Total Revenue Required from Rates (Revenue Requirement) $122,487,909
Revenues Based on Rates Currently in Effect $110,531,481
Additional Rate Revenue Needed $11,956,498
Total Required Rate Revenue Increase (Decrease) 10.8%
Recommendation
CPA’s revenues are not sufficient to cover its cost obligations in FY 2016-17 using current rates.
It is important to note that CPA’s revenue-to-cost balance needs to be continually monitored.
Both short and longer term supply and operating cost considerations will need to be evaluated
and analyzed as CPA’s management and the City Council pursue CPA’s operating and financial
objectives.
6 Excludes capital expenses reimbursed by connection fees or other direct reimbursement agreements.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 13
Cost of Service Analysis
The objective of the cost of service analysis (COSA) is to allocate the costs in the revenue
requirement to each customer class of service to determine the cost to serve those customers.
An essential principle of cost allocation is the concept of cost-causation. Cost-causation
evaluates which customer or group of customers causes the utility to incur certain costs by
linking system facility investments and the operating costs to serve certain facilities to the way
customers use those facilities and services. This section of the report will discuss the general
approach used to apportion the CPA’s costs, and will provide a summary of the results.
COSA Definition and General Principles
A COSA study allocates the costs of providing utility service to the various customer classes
served by the utility based upon the cost-causal relationship associated with specific expense
items. This approach is taken to develop a fair and equitable designation of costs to each class
of service. Because the majority of costs are not incurred by any one type of customer, the
COSA allocates joint and common costs among the various classes using factors appropriate to
each type of expense. The COSA is the second step in a traditional three-step process for
developing electric service rates, after development of the revenue requirement but before
designing rates.
A COSA study can be performed using embedded costs or marginal costs. Embedded costs
generally reflect the actual costs incurred by the utility and closely track the costs kept in its
accounting records. Marginal costs reflect the cost associated with adding a new customer, and
are based on costs of facilities and services if incurred at the present time. This study uses an
embedded COSA as its standard methodology, however it uses some marginal concepts, (for
example, the examination of the relative cost of new meters in determining cost allocation
between rate classes).
There are three basic steps to follow in developing a COSA, namely:
Functionalization
Classification
Allocation
Functionalization separates costs into major categories that reflect the different services
provided to customers and the types of assets used to provide those services. The primary
functional categories for CPA are production (power supply) and distribution. Shared services
(overhead) to be allocated across multiple functional categories are also identified in this
phase.
Classification determines the portion of each cost that is related to specific cost-causal factors,
or “classifiers.” These classifiers might be demand-related (related to the class of service’s peak
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 14
energy usage over a given period), energy-related (related to the total energy used by the class
of service over a given period), or customer-related (costs incurred as a result of receiving
service, regardless of the energy use or peak demand). Production (Power Supply) costs are
related to generating and supplying power to customers on the system, and are often demand-
or energy-related. The distribution system is designed to extend service to all customers
attached to the system and to meet the peak demand requirement of each customer, meaning
that costs are often demand-related. Some operational costs, such as billing, are generally
customer-related. Costs can also be classified based on system revenues or directly assigned to
a customer or group of customers if appropriate (for example, for street lighting customers).
Allocation of costs to specific classes of service happens after those costs have been classified.
Allocation factors are chosen to allocate the costs assigned to each classification, and the share
of costs allocated to each class of service are based on the class’s contribution to the specific
allocation factor selected. For example, certain production (power supply) costs might be
classified as partially demand-related and partially energy-related. The demand-related power
supply costs would be allocated to the classes of service using each class’s contribution to the
annual system peak demand (the highest demand for the system as a whole at any time during
the year), while the energy-related costs would be allocated to classes based on their annual
energy usage. In this example, the allocation factors are 1) each class of service’s contribution
to the annual system peak demand and 2) the annual energy usage of each class of service. An
analysis of customer requirements, loads, and usage characteristics is completed to develop
allocation factors reflecting each of the classifiers employed within the COSA.
Functionalization of Costs
As discussed above, the first step in the COSA process following finalization of the revenue
requirement is to functionalize the revenue requirement.
Certain types of costs in the revenue requirement (primarily O&M costs associated with various
types of capital assets) are allocated based on the use of the underlying capital assets by
customer class. To determine this, the underlying capital assets of the utility (the “rate base”)
are functionalized into cost categories and allocated to customer classes. The functionalization,
classification, and allocation of the rate base will be used as a basis for functionalization,
classification, and allocation of certain types of operating expenses in the revenue requirement,
such as maintenance of the capital assets included in the rate base.
In CPA’s case, the rate base and revenue requirement are functionalized into Production
(Power Supply), Distribution, and Shared Services categories. Schedule 3.1 shows the functional
category for each cost in the revenue requirement, while Schedule 3.3 shows the results of the
functionalization and classification of each cost. Schedules 4.1 and 4.2 show the same
information for the rate base. The functional categories are described in more detail below:
Production (Power Supply). The power supply function category includes all power-related
services that are obtained by the utility through generation and direct purchase. CPA does
not produce power itself, but instead purchases power from a variety of renewable and
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 15
hydroelectric generating sources, as well as purchasing power in the energy markets. The
transmission services that CPA must acquire to deliver the purchased power supply to the
service area are included in purchased power costs.
Distribution. Distribution services include all services required to move the electricity from
the point of interconnection between the transmission system and the distribution system
to the end user of the power. These include substations, primary and secondary poles and
conductors, line transformers, services and meters as well as customer costs and any direct
assignment items.
Shared Services. Shared services include assets used across multiple functions or costs that
apply across multiple functions, such as facilities used for general management of the
operation or insurance or benefits costs. Assets and costs in the shared services category
are not shown in the attached schedules as a separate functional category. Instead, they are
allocated across the Production and Distribution functions as overhead.
Classification and Allocation of Costs
The next step in performing a COSA is to classify and allocate the functionalized expenses. The
classifications and allocations are directly related to specific consumption behavior or system
configuration measurements such as coincident peak (CP) or non-coincident peak (NCP)7
demand, energy consumption, or number of customers. Each cost in the revenue requirement
will be classified into one or more categories, and will then be allocated to customer classes of
service based on a specific allocator. For example, 7% of the costs associated with the Calaveras
hydroelectric generating resource were classified into the demand classification and 93% were
classified into the energy classification, with the demand classifier allocated to classes of service
based on each class’s CP demand, and the energy portion of the cost allocated based on each
class’s annual energy consumption.
The classification and allocation factors used for each component of the rate base and revenue
requirement are shown in Tables 6 and 7 and are discussed in more detail below. Descriptions
of each factor are included in Table 8.
The following are the specific classifiers used in CPA’s COSA within the Production and
Distribution functions. As noted earlier, the Shared Services function is spread across the
Production and Distribution functions as overhead, so it does not have its own classifiers:
7 Coincident peak represents the customer class’s contribution to the system peak demand (i.e. its demand coincident
with, or at the time of, the system peak), while non-coincident peak represents the customer class’s peak demand
regardless of when it occurs. A customer class’s demand at the time of the system peak demand may be lower than
its peak demand, which may occur at some other time of the year.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 16
Production (Power Supply) Function
Within this study, power supply costs are classified to demand and energy based on
discussion with CPA staff related to cost causation. The specific classifiers used for the
power supply function include:
Energy. Energy-related costs are those that vary with the total amount of electricity
consumed by a customer. Electricity usage measured in kWh is used in this portion of
the analysis. Energy costs are the costs of consumption over a specified period of time,
such as a month or year.
Demand. Demand-related costs are those that vary with the maximum demand or the
maximum rates of power supply to classes of service. Customer and system demands
for this analysis were measured in kW. Demand costs are generally related to the size
(capacity) of facilities needed to meet a customer’s maximum demand at any point in
time.
In order to classify power supply costs, each resource or type of cost was evaluated based
on how CPA is charged and whether the resource provides energy or capacity8 to CPA.
Power purchase agreements for the output from the Western Area Power Administration
(WAPA) and Calaveras hydroelectric generating resources and all renewable resources
provide both energy and capacity, and so were classified according to the relative market
value of the energy and capacity provided by each resource. An analysis of the amount of
capacity and energy provided by each resources was done, and the market value of each of
those was calculated based on historical energy and capacity prices. The ratio of energy to
capacity value was used to classify the cost of the resource. Costs associated with services
provided to CPA by Northern California Power Agency (NCPA) (such as scheduling
generating resources and interacting with the California Independent System Operator
(CAISO) on CPA’s behalf) are classified as energy costs because these services are
necessitated by City’s energy purchases. Purchases of energy from marketers9 are classified
as energy-related costs, while purchases of capacity are classified as demand-related
costs.10 CAISO transmission costs are classified as energy-related costs, as this is the way
those costs are allocated to distribution utilities by the CAISO and the CAISO transmission
costs therefore vary with the total CPA system energy.
8 When referring to a generating resource, “capacity” refers to its potential generating capacity regardless of
whether it is actually generating energy. Capacity must be held to meet customer peak demand, regardless of
whether it is used to generate energy at all times of the year. Capacity costs are usually assigned to the demand
classifier.
9 CPA purchases energy and capacity from various marketers and other agencies (BP Energy Company, Cargill
Power Markets, Exelon Generation Co., Iberdrola Renewables, Nextera Energy Marketing, Pacificorp, Powerex,
Shell Energy North America, and Turlock Irrigation District) through its Electric Master Agreements.
10 Energy purchases require that energy is delivered to the system during some specified period of time, while
capacity purchases enable CPA to count generating capacity from a specific generating unit owned by another
agency or marketer toward the generating capacity requirements imposed on it by the CAISO.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 17
Distribution Function
Distribution services include all services required to get energy supply from the point of
interconnection between the transmission system and the utility’s service area to the end
user of the power. Most distribution costs are split between demand and customer
components. The demand component is the cost of facilities like distribution substations,
lines, or line transformers built to serve a particular peak demand. The customer
component is the cost of facilities that varies with the number of customers, such as
meters. The following are the specific classifiers used for CPA’s distribution function:
Demand. Demand-related costs are those that vary with the maximum demand or the
maximum rates of power supply to classes of service. Customer and system demands
for this analysis are measured in kW. Demand costs are generally related to the size of
facilities needed to meet a customer’s maximum demand at any point in time.
Customer. Customer-related costs are those that vary with the number of customers.
Customer costs may be weighted to account for differences in the cost of providing
services to those customers. For example, the service drop and metering associated
with serving a large commercial customer is more costly and requires substantially more
work and material than the service and meter for a small residential customer.
Direct Assignment. Some costs are directly assigned to specific classes of service. Costs
associated with providing account representatives to large customers are allocated
directly to those classes of service. Direct maintenance costs associated with street
lights and traffic signals are directly allocated to the street light / traffic signal class.
Schedules 3.5 and 4.4 provide the background information for all directly assigned costs
associated with the revenue requirement and rate base.
The methodology for functionalization, classification, and allocation of CPA’s rate base is
summarized in Table 6 and in Technical Appendix Schedule 4.1. The results of the process for
the rate base can be found in Schedule 4.2. The same information for the revenue requirement
can be found in Table 7, Schedule 3.1, and Schedule 3.3. More detail on the classification and
allocation factor codes used in the classification and allocation process can be found in Table 8.
Schedule 6.1 shows how each code is used to separate costs into functions (production and
distribution) and classifications (demand, energy, customer, and direct assignment). Schedule
6.2 shows the way each code then allocates the costs within each classification across classes of
service.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 18
Table 6
Rate Base11 Functionalization, Classification, and Allocation
FERC
Account Asset Description Functionalization
Category
Classification and Allocation
Factor Code12
Distribution Plant
361.0 Structures and Improvements Distribution NCPP
362.0 Station Equipment –
Distribution
Distribution NCPP
364.0 Poles, Towers & Fixtures Distribution 100% DP
365.0 Overhead Conductor & Devices Distribution 100% DC
366.0 Underground Conduit Distribution 100% DC
367.0 Underground Conductors Distribution 100% DC
368.0 Line Transformers Distribution 100% DT
369.0 Services Distribution SERV
370.0 Meters Distribution CUSTW
373.0 Street Lighting Systems Distribution DA1
General Plant
394.0 Tools, Shop & Garage
Equipment Shared Services GPLT
397.0 Communication Equipment Shared Services GPLT
398.0 Miscellaneous Equipment Shared Services GPLT
Accumulated Depreciation
Distribution Plant Distribution RBD-ST
Working Capital
90 days O&M Shared Services OMWOP
90 days Purchased Power
Supply Cost Production OMP
90 days Purchased
Transmission Charges Production OMPT
Construction Work in Progress
Construction Work in Progress Distribution RBD
11 Rate base as of June 30, 2015, the most recent year for which capitalized asset data is available.
12 See Table 8 for more detail and fully spelled-out acronyms
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 19
Table 7
Revenue Requirement Functionalization, Classification, and Allocation
FERC
Account Plant Description Functionalization
Category
Classification and
Allocation Factor Code13
Power Purchases
555.70 Western Power Purchases Power Supply WEST
555.72 NCPA Pooling Power Supply kWh
555.73 NCPA Facilities Power Supply kWh
555.74 Local Capacity Purchase Power Supply CP12
555.76 Renewable Energy Power Supply REN
555.77 Carbon Neutral Purchases (RECs) Power Supply kWh
555.78 Market Power Purchases Power Supply kWh
555.50 Demand-Side Renewable Energy Power Supply DSRE
XXXX Calaveras O&M and Debt Service Power Supply CALA
XXXX Transmission Costs Power Supply kWh
Other
555.20 Salaries & Benefits - Resource Mgmt. Power Supply kWh
555.30 Carbon Allowance Revenues Power Supply kWh
555.40 General Expense (Resource Mgmt.) Power Supply kWh
555.45 Allocated Administrative/General Costs Power Supply kWh
Distribution
580.0 Operations Supervision and Engineering Distribution RBD-NoDA
585.0 Street Lighting Distribution DA1
588.0 Miscellaneous Distribution Distribution RBD-NoDA
589.0 Rents Distribution RBD-NoDA
590.0 Maintenance Supervision and
Engineering
Distribution RBD-NoDA
593.0 Overhead Lines Distribution RBOH
596.0 Street Lighting Distribution DA1
598.1 Communication O&M Distribution RBD-NoDA
Customer Service, Accounts & Sales
901.0 Supervision Distribution CUSTW
902.0 Meter Reading Expenses Distribution CUSTMR
903.0 Cust. Records Collection Expense Distribution CREDIT
904.0 Uncollectable Accounts Distribution CREDIT
906.0 Customer Service & Information Distribution CUST SERV
906.1 Key Accounts Distribution DA2
906.2 Energy Efficiency & Demand-Side
Management (DSM)
Power Supply DSMEE
916.0 Misc. Sales Expense Distribution CUST SERV
Administrative and General (A&G) Expenses
920.0 Salaries Shared Services OMAG
921.0 Office Supplies and Expense Shared Services OMAG
923.0 Outside Services Shared Services OMAG
925.0 Injuries and Damages Shared Services OMAG
926.0 Employee Pension and Benefits Shared Services OMAG
13 See Table 8 for more detail.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 20
Table 7
Revenue Requirement Functionalization, Classification, and Allocation
FERC
Account Plant Description Functionalization
Category
Classification and
Allocation Factor Code13
930.2 Miscellaneous General Expense Shared Services OMAG
930.3 Environmental Fees Shared Services OMAG
931.0 Rents Shared Services OMAG
Capital Projects From Rates
Distribution Distribution RBD-NoDA
Other Contributions
General Fund Transfer Shared Services NETPLT
Misc. & Other Revenues and Income
454.0 Rent, Electric Properties Shared Services OMAG
456.0 Other Misc. Electric Revenue Shared Services OMAG
458.0 Low Hydro Transfers Shared Services kWh
415/416 Income from Equity Investments Shared Services OMAG
421.0 Traffic Signal Transfer from General Fund Distribution DA 3
446.0 Green Power (Palo Alto Green) Power Supply kWh
XXXX Surplus Energy Revenues Power Supply kWh
XXXX Transfers from Reserves and Allowance
for Unspent Budget
Shared Services OM
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 21
Table 8
Classification and Allocation Factors
Factor
Code
Factor
Name Classification Allocation Basis
Rate Base Classification and Allocation Factors
NCPP Non-coincident Peak -
Primary
100% Demand The total peak kW demand, regardless of
when it occurs.
100% DP 100% Demand (Poles,
Towers, Fixtures)
100% Demand The total peak kW demand, regardless of
when it occurs.
100% DC 100% Demand
(Overhead and
Underground Conduit)
100% Demand The total peak kW demand, regardless of
when it occurs.
100% DT 100% Demand
(Transformers)
100% Demand The total peak kW demand, regardless of
when it occurs.
SERV Services14 100% Customer # customers weighted for the cost of
installing and replacing services
CUSTW Customers weighted
for accounting /
metering
100% Customer # customers weighted for cost of installing,
maintaining and reading meters, billing,
and account management
DA1 Street Light Rate Base
Assignment
100% Direct
Assignment
Street lighting assets allocated directly to
street light customer class of service
GPLT General Plant 73.5% Demand,
18.4% Customer
8.1% Direct Assignment
Shared services assets15 that are the rate
base equivalent of administrative
overhead. Allocated to classes of service
according to the other operational assets
(e.g. lines and transformers) allocated to
each class.
RBD-ST Rate Base:
Distribution Adjusted
for Street Light Direct
Assignments(
64.7% Demand,
23.3% Customer
12.0% Direct
Assignment
Classified and allocated to classes of service
based on the value of all operational and
shared services assets assigned to each
class of service. Used for accumulated
depreciation
OMWOP O&M without Power
Supply
48.7% Demand,
31.5% Customer
7.2% Direct Assignment
Allocated based on O&M without Power
Supply costs
OMP O&M: Purchase Power 48.7% Demand,
31.5% Customer
7.2% Direct Assignment
Allocated based on Purchased Power costs
OMPT O&M: Purchased
Transmission
48.7% Demand,
31.5% Customer
7.2% Direct Assignment
Allocated based on Purchased Transmission
costs
RBD Rate Base:
Distribution
73.5% Demand,
18.4% Customer
8.1% Direct Assignment
Classified and allocated to classes of service
based on the net book value of all shared
services assets and other capital assets
assigned to each class of service
14 This is a technical term referring to the connection from the line transformer to the customer’s electrical panel.
15 Facilities used for administration and other general utility management functions.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 22
Table 8
Classification and Allocation Factors
Factor
Code
Factor
Name Classification Allocation Basis
Revenue Requirement Classification and Allocation Factors
WEST Western Base
Resource allocation
16% Demand,
84% Energy
Western Base Resource costs. Classified
according to the relative market value of
the capacity and energy provided by the
resource, and allocated to classes of service
based on each class’s energy consumption
and coincident peak demand.
kWh Energy consumption
(kWh)
100% Energy
Energy consumption of each class of service
in kWh
CP12 12-month Coincident
Peak
100% Demand
Customer class of service’s contribution to
the utility’s annual system peak demand
CALA Calaveras
Hydroelectric
Resource allocation
7% Demand,
93% Energy
Calaveras hydroelectric resource costs.
Classified according to the relative market
value of the capacity and energy provided
by the resource, and allocated to classes of
service based on each class’s energy
consumption and coincident peak demand.
REN Renewable Power
Purchase Agreements
3% Demand,
97% Energy
Renewable Power Purchase Agreement
costs. Classified according to the relative
market value of the capacity and energy
provided by the resource, and allocated to
classes of service based on each class’s
energy consumption and coincident peak
demand.
RBD-NoDA Distribution Rate Base
Excluding Street
Lighting and Traffic
Signals
73.5% Demand,
26.5% Customer
Used for allocation of most distribution
system infrastructure O&M costs other
than street light/traffic signal maintenance.
Classified and allocated to classes of service
based on the net book value of all shared
services assets and other capital assets
assigned to each class of service, excluding
street lighting and traffic signals.
DA1 Street Light and Traffic
Signal Direct
Assignment
100% Direct
Assignment
Costs associated with operating and
maintaining street light and traffic signal
assets
RBOH Rate Base (Overhead
Lines)
100% Demand Used for allocation of maintenance costs
for overhead lines. Classified and allocated
to classes of service based on the net book
value of overhead lines assigned to each
class of service.
CUSTW Customers weighted
for accounting /
metering
100% Customer # customers weighted for cost of installing,
maintaining and reading meters, billing,
and account management
CUSTMR Customers weighted
for meter reading
100% Customer # customers weighted for cost of reading
meters
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 23
Table 8
Classification and Allocation Factors
Factor
Code
Factor
Name Classification Allocation Basis
CREDIT Credit and Collections 100% Customer # customers weighted for credit and
collections costs
CUST SERV Customer Service 100% Customer # customers weighted for customer service
costs
DA2 Direct Assignment for
Key Account costs
100% Direct
Assignment
Direct assignment of key account costs to
large non-residential classes of service
CUST Actual Customers 100% Customer Actual (unweighted) customer count
OMAG O&M omitting A&G
and Power Supply
Shared Services On the basis of all other O&M costs
allocated to each class of service excluding
A&G and Power Supply. Allocated to
Production Function (12.6% Energy) and
Distribution Function (48.7% Demand,
31.5% Customer, 7.2% Direct Assignment)
OM All O&M Shared Services Allocated on the basis of all other O&M
costs in the revenue requirement.
Allocated to Production Function (4.9%
Demand, 12.6% Energy) and Distribution
Function (48.7% Demand, 31.5% Customer,
7.2% Direct Assignment)
DSRE Demand-Side
Renewable Energy
Allocator
Power Supply Allocated based on PV Partners solar
rebate budget allocation
DSMEE DSM / EE Allocator Power Supply Based on historical residential / non-
residential program expenditures.
Residential direct assignment, non-
residential based on annual kWh. No
allocation to Street/Traffic Lights
DA3 Direct Assignment for
Traffic Lights revenues
100% Direct
Assignment
Direct assignment of General Fund
Transfers of Traffic Light revenues.
NETPLT Net Plant 80.5% Demand,
14.5% Customer,
5.1% Direct Assignment
Allocated on the basis of the net book
value of all capital assets (initial cost less
accumulated depreciation) assigned to
each class of service.
Cost of Service Results
Given the key assumptions listed above, the COSA was completed. Schedules 3.4 and 4.3 in the
appendix show the functionalized and classified rate base and revenue requirement allocated
to each class of service. These schedules are calculated by multiplying the applicable
classification and allocation factors to each cost in the revenue requirement or rate base.
Given the above assumptions regarding the COSA, the various costs were classified and
allocated to the customer classes of service. Table 9 provides the COSA results. Summary data
and additional detail is presented in Schedules 1.1 and 1.2.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 24
Table 9
Summary of Cost of Service Analysis for FY 2016-17 Test Year
Projected
FY 2016-17
Revenues under
Rates Currently in
Effect
Net Revenue
Requirement
Projected Deficiency
in FY 2016-17
Revenue Based on
Rates Currently in
Effect
Revenue
Increase
needed16
Residential E-1 $18,406,003 $20,785,989 ($2,379,986) 12.9%
Small Non-residential E-2 9,421,113 10,019,138 (598,025) 6.3%
Medium Non-residential E-4 38,382,821 42,680,642 (4,297,821) 11.2%
Large Non-residential E-7 41,216,279 42,441,354 (1,225,074) 3.0%
City Accounts E-18 3,044,789 4,463,490 (1,418,701) 46.6%
Street/Traffic Lights 60,477 2,097,367 (2,036,890) 3368.1%17
TOTAL $110,531,481 $122,487,979 ($11,956,498) 10.8%
The results show that with present rates, CPA will not collect sufficient revenues to meet
FY 2016-17 costs. As discussed previously in the report, the amount of additional revenue
required varies by class of service. While customers on Rate Schedule E-7 are paying close to
cost of service already, most of the rate classes will need a significant rate increase. The E-1
rate class and the E-4 rate class show the largest increases. The varying rate changes are a
result of significant changes in customer usage characteristics since the last COSA and rate
redesign. In the last few years some rate classes have increased energy consumption or peak
demand, while others have decreased consumption or demand. These changing consumption
patterns affect usage of the system and the way costs are allocated among customers.
As described throughout this section, costs are allocated to customers based on their
consumption patterns, particularly energy consumption and peak demand. As customer
consumption patterns change, some of the utility’s costs change as well, but others are fixed
over the short term. For example, some charges to the utility, like market energy purchases, are
directly related to energy consumption. These costs decrease as customer energy consumption
decreases, usually in real-time. If a customer class uses less energy, fewer of these costs will be
allocated to them and their revenue requirement will decrease. Other costs only change slowly
over time, such as the amount of distribution capacity the utility builds and maintains. These
costs are largely fixed, and change over the long term with changes in peak demand or energy
use. The majority of the City of Palo Alto’s cost change slowly over the long term.
Rates for each customer class are set based on the energy and peak demand patterns over the
study period. If energy use and peak demand decrease or increase after the rate study is
completed, costs that change only over the long term might not change. When a subsequent
16 Projected FY 2016-17 revenue deficiency divided by projected FY 2016-17 revenue based on rates currently in
effect. Numbers rounded to the nearest tenth of a percent.
17 This increase in revenue will primarily come from charging all City customers for service rather than through rate
increases to the general public.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 25
COSA is performed, different revenue adjustments may need to be made for each customer
class. The impacts to each class required as a result of the analysis done in the COSA are
described below:
Energy consumption and demand has decreased for the E-1 (Residential)18 class of service.
The share of costs allocated to this customer class decreased as a result. The decrease in
energy consumption, however, means that the existing rates do not collect adequate
revenue to fund certain types of fixed costs. The latter factor means that revenues need to
increase more than average for this class of service.
Small Non-residential (E-2) energy consumption and demand has increased. The share of
costs allocated to this customer class increased as a result. The increase in energy
consumption, however, means that the existing rates collect close to the amount of
revenue needed to fund fixed costs. The latter factor means that revenues need to increase
less than average for this class of service.
Medium Non-residential (E-4) energy consumption has decreased, but demand has
increased. The share of energy-related costs allocated to this customer class increased,
while the share of demand-related costs decreased. These factors roughly offset each other,
and revenue increases needed roughly match the average increase for the city as a whole.
Large Non-residential (E-7) energy consumption and demand has increased. The share of
costs allocated to this class increased as a result. However, revenue from existing rates also
increased substantially as a result of the increased consumption and demand. Existing
revenue collection is close to the amount of revenue needed based on the COSA, so the
necessary revenue increase from this customer class is small.
The energy consumption for the E-18 class of service has stayed roughly the same, but the
demand has increased. The share of costs allocated to this customer class increased as a
result. The unchanged energy consumption, in light of the increased demand, however,
means that the existing rates did not collect adequate revenue to fund fixed costs.
The street light and traffic signal class reflects additional revenues associated with charging
for maintenance and operation of City-owned street lighting, which was not included in
previous rate schedules.
When examining the results, it is important to note that the inter-class cost allocation is based
on load data estimates and usage pattern assumptions. Since these can vary from year to year,
the results of applying this COSA may deviate from these allocations over time. To avoid these
deviations, the COSA model built for CPA can be updated when necessitated by significant
changes to customer consumption patterns or the CPA’s costs.
18 While this class of service is named “Residential Electric Service,” it does not include 100% of residential use.
Some master-metered multi-family residential buildings take service under other rate schedules.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 26
Review of Customer Classes of Service
Customer classes of service refer to the arrangement of customers into groups that reflect
common usage characteristics or facility requirement. The classes of service used within this
study were as follows:
Residential E-1
Small Non-Residential E-2
Medium Non-Residential E-3
Large Non-Residential E-7
Municipal Electric Service E-18
Street and Traffic Lights
Rate schedule E-18 (Municipal Electric Service) was modeled separately in the COSA, but the
analysis showed that the customer characteristics of municipal service accounts are not
significantly different from the characteristics of other non-residential customers. Municipal
accounts should be moved to the appropriate non-residential rate schedule based on energy
consumption and peak demand.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 27
Rate Design
The final step in the rate study process is to design rates for each class of service. In California,
local governments are subject to Article XIII C of the California Constitution, amended by
Proposition 26 (2010). As a result, CPA has set rates to match the COSA results for each class. It
is important to note that the results of the revenue requirement and COSA study are based on
forecasted load data estimates and usage pattern assumptions. Actual load and usage patterns
may differ from forecast. For this study, rates are developed based on the forecast loads and
observed historical usage patterns for each rate class.
The rates for the residential and non-residential customers are designed to take into account
differences in energy costs for various generating resources as well as the impacts seasonal
changes in energy use and peak demand have on the utility’s distribution capacity needs. The
E-1 (Residential) rate class is fairly homogenous compared to the other rate classes, and these
varying costs can be captured in a tiered energy rate design. For the non-residential classes, E-2
(Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential), these
costs are captured in a seasonal rate. Note that while these methodologies capture seasonal
variations in cost, they do not capture hourly cost variations. This requires time of use rates,
which require more advanced metering that is only available to a smaller subset of Palo Alto
customers. Optional time of use rates are made available to these customers, and reflect both
seasonal and hourly capacity needs and energy consumed.
Rate Design – Non-Commodity
The allocation of distribution costs is based on an analysis of the base and excess monthly
energy and capacity costs associated with that rate class, also known as the Average and Excess
method. The Average and Excess method compares the baseline capacity and energy used (the
“average,” or “baseline”) against the maximum capacity and energy used on a seasonal basis
(the “excess”). This captures the level of system capacity required to serve the customer during
peak times as opposed to average times. The rate design for the E-1 (Residential) class is tiered,
with the first tier reflecting the baseline usage, which is defined as energy usage below 11 kWh
per day. This was calculated by analyzing the median summer usage for the class. Summer was
chosen as the year-round baseline rather than winter because the residential customer class’s
peak usage is in the winter, unlike the other customer classes. This is reversed for the E-2 (Small
Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential) customer
classes, with the baseline consumption in the winter season and the peak in the summer.
Costs associated with demand-related system costs (such as transformers or lines) were
separated into tier or season using the average and excess demand information from the COSA.
The methodology assigns costs associated with baseload demand to all tiers or seasons, while
costs related to the distribution capacity required to serve peak demands is allocated to Tier 2
(for the residential class) or the summer season (for the non-residential classes). Customer-
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 28
related costs are allocated equally to each tier or season based on the energy billing
determinants.
Rate Design – Commodity
The commodity component of the rate design is based on differences in the cost of energy from
the utility’s various sources of supply, as well as the impact of peak demand on capacity costs.
For the E-1 (Residential) class, lower-cost resources are allocated to Tier 1 usage, while higher
cost resources are allocated to Tier 2. Because this rate class is winter peaking, generating
capacity costs were not reflected differently in each tier. This is because generating capacity
costs are determined based on the Palo Alto’s system peak, which is in the summer. That
means that the residential peak usage, which is in the winter, does not impact capacity costs in
the same way the peak usage for other customer classes does.
In order to develop commodity rates for rate classes E-2 (Small Non-Residential), E-4 (Medium
Non-Residential), and E-7 (Large Non-Residential), the costs for each generating resource were
assigned to the season in which the costs were incurred. Demand rates were calculated by
allocating baseload capacity costs to both summer and winter rates, while the remainder of the
capacity-related costs were allocated to the summer (peak demand) period.
Proposed Rate Design
This section of the report will review the present rate structures for CPA and will provide a
comparison with the proposed rates based on this cost of service study.
Residential E-1
The present Residential rate design is composed of a three tier energy rate for commodity,
distribution and Public Benefit Charges, which are charges the utility is required by State Law to
impose to fund energy efficiency and other programs (as discussed earlier in the “Overview of
Rate Setting” section). Tier 1 energy is based on an average of 10 kWh per day (or 300 kWh per
month), while Tier 2 applies to usage between 300 and 600 kWh per month. Finally, Tier 3
rates apply to usage above 600 kWh per month.
The proposed rate structure for the Residential Schedule E-1 consists of two tiers. As discussed
earlier, the first tier represents the lower cost energy, as well as the distribution capacity
required to serve customers year-round. The second tier represents the higher cost energy, as
well as the distribution capacity required to serve customers during the winter (peak) season. In
the commodity portion of the rates, only the costs for generating resources differ across tiers.
Other power supply costs (such as transmission and energy scheduling services) are distributed
uniformly across both tiers of the commodity rate on a per-kWh basis. For distribution rates,
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 29
only physical infrastructure costs are distributed differently between tiers. Customer-related
costs are allocated uniformly to both tiers on a per-kWh basis.
After reviewing the median daily consumption during summer months for E-1 customers, the
Tier 1 usage was increased from 10 kWh per day to 11 kWh per day or 330 kWh per month.
This represents the year-round, baseload usage for the median residential customer. Tier 2
rates are then applied to any usage above 330 kWh per month.
Presented below, in Table 10, are the present and proposed rates for the Residential E-1
customers.
Table 10
Comparison of Proposed Rates to Current –Residential E-1
Residential Commodity Distribution Public Benefits
Charge Total Rate
Current Energy Charge
($/kWh)
Tier 1: First 300 kWh $0.05448 $0.03755 $0.00321 $0.09524
Tier 2: 301-600 kWh $0.07654 $0.05045 $0.00321 $0.13020
Tier 3: > 600 kWh $0.10349 $0.06729 $0.00321 $0.17399
Proposed Energy Charge
($/kWh)
Tier 1: First 330 kWh $0.05883 $0.04795 $0.00351 $0.11029
Tier 2: > 330 kWh $0.09728 $0.06822 $0.00351 $0.16901
Overall Rate Change 12.9%
Small Non-Residential E-2
The present Small Non-Residential E-2 rate design is composed of a summer and winter energy
rate for commodity, distribution and Public Benefit Charges. The proposed rate structure for
the Small Non-Residential Schedule E-2 is the same, though the summer and winter rates have
been updated to properly reflect the difference in the cost of serving this class in both seasons.
Consumption for this class peaks in the summer, and the costs of the additional distribution
capacity associated with serving this higher summer load have been allocated to the summer
energy rate component. Costs for energy from generating resources are assigned to summer
and winter rates based on the season in which those costs are incurred by the utility. All other
costs are assigned uniformly across both rate components.
Presented below, in Table 11, are the present and proposed rates for the Small Non-Residential
E-2 customers.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 30
Table 11
Comparison of Proposed Rates to Current –Small Non-Residential E-2
Small Non-Residential Commodity Distribution PBC Total Rate
Current Energy Charge ($/kWh)
E-2 Summer $0.08219 $0.05505 $0.00321 $0.14045
E-2 Winter $0.07406 $0.04934 $0.00321 $0.12661
Proposed Energy Charge ($/kWh)
E-2 Summer $0.09094 $0.07400 $0.00351 $0.16845
E-2 Winter $0.06417 $0.04677 $0.00351 $0.11445
Overall Rate Change 6.3%
Medium Non-Residential E-4
The present Medium Non-Residential E-4 rate design is composed of a summer and winter
energy and demand rate for commodity, distribution and Public Benefit Charges. The proposed
rate structure for the Medium Non-Residential Schedule E-4 is the same. As for the E-2 rate, the
summer and winter components of the rate have been updated to reflect current costs and
consumption patterns. However, unlike for the E-2 customer class, all of the demand-related
distribution system costs are captured in a demand charge,19 while customer-related costs are
captured in the energy component of the distribution charges. This is feasible for E-4 and E-7
customers but not for E-2 customers due to the limitations of the metering technology
currently deployed in Palo Alto. Costs for energy from generating resources are assigned to
summer and winter rate components based on the time of year those costs are incurred by the
utility. Generating capacity costs are collected through a commodity demand charge. All other
costs are assigned uniformly across both rate components.
Presented below, in Table 12, are the present and proposed rates for the Medium Non-
Residential E-4 customers.
Table 12
Comparison of Proposed Rates to Current –Medium Non-Residential E-4
Medium Non-Residential Commodity Distribution PBC Total Rate
Current Energy Charge ($/kWh)
E-4 Summer $0.06083 $0.01767 $0.00351 $0.08171
E-4 Winter $0.05281 $0.01716 $0.00351 $0.07318
19 A demand charge is a charge based on the highest power consumption in a specified period of time, and is
measured in kW. The E-4 and E-7 demand charges are based on the usage in the highest 15-minute period over the
course of the billing period, roughly one month. This is in contrast to an energy charge, which is measured in kWh,
and represents the total energy consumption over the entire month.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 31
Current Demand Charge ($/kWh)
E-4 Summer $2.31 $15.23 $20.54
E-4 Winter $4.80 $9.04 $13.84
Proposed Energy Charge ($/kWh)
E-4 Summer $0.08218 $0.01661 $0.00351 $0.10229
E-4 Winter $0.06037 $0.01661 $0.00351 $0.08049
Proposed Demand Charge ($/kWh)
E-4 Summer $2.53 $17.14 $19.68
E-4 Winter $1.55 $12.49 $14.04
Overall Rate Change 11.2%
Large Non-Residential E-7
The present Large Non-Residential E-7 rate design is composed of a summer and winter energy
and demand rate for commodity, distribution and Public Benefit Charges. The proposed rate
structure for the Large Non-Residential Schedule E-7 is the same. The rate design and
methodology for allocating costs to rates is the same as for the E-4 rate schedule. The two rate
classes are distinct, however, due to the different consumption patterns of the E-4 and E-7
customer classes. The E-7 customer class has a higher load factor (a measure of the ratio of
peak demand to annual energy use). The higher a class’s load factor, the more efficiently it
makes use of the capacity dedicated to serving it. A customer class with a higher load factor will
have a lower share of the demand-related system costs allocated to it than a low load factor
customer class that uses the same amount of energy, so it is best to distinguish the two as
separate customer classes.
Presented below, in Table 13, are the present and proposed rates for the Large Non-Residential
E-7 customers.
Table 13
Comparison of Proposed Rates to Current –Large Non-Residential E-7
Large Non-Residential Commodity Distribution PBC Total Rate
Current Energy Charge ($/kWh)
E-7 Summer $0.05662 $0.01825 $0.00321 $0.07808
E-7 Winter $0.04990 $0.01898 $0.00321 $0.07209
Current Demand Charge ($/kWh)
E-7 Summer $6.42 $12.55 $18.97
E-7 Winter $5.50 $6.04 $11.54
Proposed Energy Charge ($/kWh)
E-7 Summer $0.08311 $0.00087 $0.00351 $0.08749
E-7 Winter $0.05804 $0.00087 $0.00351 $0.06242
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 32
Proposed Demand Charge ($/kWh)
E-7 Summer $2.50 $15.85 $18.34
E-7 Winter $1.53 $14.11 $15.65
Overall Rate Change 3.0%
Municipal E-18
As discussed previously, the E-18 rate schedule is recommended for retirement. Customers in
this rate class share characteristics with the E-2, E-4, and E-7 rate classes, and should be
allocated to those classes.
Minimum Bill Analysis
To ensure the collection of monthly meter reading, billing and customer service costs from all
customers, a minimum bill charge for all rate schedules should be implemented. Meter reading,
billing, customer service, and some distribution system O&M cost elements in the COSA are
divided by the number of customers for each rate class to generate the minimum bill for each
class.
The minimum bill mechanism is a new approach to determining a customer’s electricity bill for
CPA, but is used frequently in the electric utility industry. The monthly bill would be calculated
in the following manner under the minimum bill mechanism:
1. Calculate the customer’s monthly bill based on usage
2. If the calculated bill is less than the minimum bill amount, the customer pays the
minimum bill charge for the month.
The proposed minimum bill was developed by determining the customer-related distribution,
CIP and customer service costs in the COSA. These are the costs that should be collected from
all customers regardless of usage. Based on the cost of service study, the following minimum
bill charges are proposed:
Residential E-1: $0.3067 per day
Small Non-Residential E-2: $0.7657 per day
Medium Non-Residential E-4: $16.3216 per day
Large Non-Residential E-7: $48.5054 per day
Time of Use Rate Schedules
CPA also offers optional time of use (TOU) rates to its E-1, E-4, and E-7 customers. A TOU rate
applies different charges to customer usage during different time periods. These time periods
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 33
correspond to times of day with differing energy costs. The peak time period (summer weekday
afternoons) corresponds to the time of highest demand on the system. Capacity requirements
are set based on system peaks during this time period. The off-peak period represents
nighttime periods when energy costs are lower. Mid-peak periods represent all other hours.
The E-1 TOU rate is a voluntary pilot rate currently limited to customers participating in the
City’s CustomerConnect advanced metering pilot program. It differs from the E-4 TOU and E-7
TOU rates in that it is designed as a modifier that adds to or subtracts from the underlying E-1
rate schedule, based on the customer’s hourly usage. In contrast, the E-4 TOU and E-7 TOU rate
schedules are standalone rate schedules. The E-1 TOU rate schedule will be updated in a
subsequent analysis.
The E-4 TOU and E-7 TOU rates are offered on a voluntary basis to all E-4 and E-7 customers,
but only one customer is currently on one of these rate schedules. The E-4 TOU and E-7 TOU
rate designs allocate costs seasonally or to tiers using the same methodology as the underlying
non-TOU rate designs, but they also take into account hourly variations in energy prices. Most
generating capacity costs are allocated to the summer peak periods, since CPA’s system peak
demand occurs during that time. Most of CPA’s resource adequacy (generating capacity) costs
result from requirements imposed by the CAISO based on the CPA annual system peak demand.
Resource Adequacy costs are allocated to the peak periods based on the impact peak demand
has on those costs.
Distribution costs are not allocated on an hourly basis since inadequate data exists at this time
to separate costs associated with the primary (sub-transmission) system from costs associated
with the secondary system. The former serves all customers and can benefit when some
customers use energy in off-peak rather than peak periods. The latter serves individual
customers or small groups of customers, and is therefore affected by customer peak demand
regardless of when that peak demand occurs.
The Time-of-Use rates developed for E-4 and E-7 are provided in Table 14.
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 34
Table 14
Present and Proposed E-4 and E-7 Time-of-Use Rates
Existing Rates Proposed Rates
Commodity Distribution PBC Total Commodity Distribution PBC Total
E-4 Summer Energy
Peak $0.10963 $0.03242 $0.00321 $0.14526 $0.08819 $0.01661 $0.00351 $0.10830
Mid-Peak $0.05617 $0.01623 $0.00321 $0.07561 $0.08367 $0.01661 $0.00351 $0.10378
Off-Peak $0.04298 $0.01218 $0.00321 $0.05837 $0.07332 $0.01661 $0.00351 $0.09344
E-4 Winter Energy
Peak $0.07003 $0.02296 $0.00321 $0.09620 $0.06566 $0.01661 $0.00351 $0.08577
Off-Peak $0.04088 $0.01313 $0.00321 $0.05722 $0.06167 $0.01661 $0.00351 $0.08178
E-4 Summer Demand
Peak $3.12 $8.96 $12.08 $1.52 $5.91 $7.42
Mid-Peak $1.99 $5.65 $7.64 $0.54 $5.91 $6.44
Off-Peak $1.13 $3.26 $4.39 $0.54 $5.91 $6.44
E-4 Winter Demand
Peak $2.77 $5.10 $7.87 $0.87 $6.96 $7.83
Off-Peak $1.49 $2.94 $4.43 $0.87 $6.96 $7.83
E-7 Summer Energy
Peak $0.07029 $0.02296 $0.00321 $0.09646 $0.09267 $0.00087 $0.00351 $0.09705
Mid-Peak $0.05867 $0.01901 $0.00321 $0.08089 $0.08792 $0.00087 $0.00351 $0.09230
Off-Peak $0.04870 $0.01567 $0.00321 $0.06758 $0.07705 $0.00087 $0.00351 $0.08143
E-7 Winter Energy
Peak $0.05617 $0.02142 $0.00321 $0.08080 $0.06009 $0.00087 $0.00351 $0.06447
Off-Peak $0.04663 $0.01767 $0.00321 $0.06751 $0.05643 $0.00087 $0.00351 $0.06081
E-7 Summer Demand
Peak $4.24 $8.25 $12.49 $1.48 $5.33 $6.80
Mid-Peak $2.06 $4.13 $6.19 $0.51 $5.33 $5.84
Off-Peak $1.17 $2.06 $3.23 $0.51 $5.33 $5.84
E-7 Winter Demand
Peak $3.04 $3.38 $6.42 $0.78 $7.15 $7.92
Off-Peak $1,59 $1.68 $3.27 $0.78 $7.15 $7.92
Public Benefits Charge
Public Utilities Code Section 385 requires all POUs to have a public benefits charge built in to
their rates. The rate must recover revenue equal to a set percentage of all other sales revenue
based on a formula in that law. Most California POUs have interpreted this formula to require
collection of an additional 2.85% of sales revenue for this purpose, as has CPA. The revenue
collected must be spent on a specified set of energy efficiency and other demand-side
measures, including: 1) demand side-management services to promote efficiency and
conservation, 2) new investment in renewable energy and technologies, 3) research and
development programs for the public interest, and 4) services and discounts for low income
electricity customers.
The public benefits charge is collected as a flat charge assessed on every kWh that results in the
revenue level described above. The COSA analysis confirmed that all customer classes received
benefits greater than or equal to the Public Benefits Charge revenues collected from them. The
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 35
results of this analysis are shown in Table 15 below. Public benefit program costs not directly
funded by PBC revenues are funded by other sales revenues, which complies with the CPA-
adopted Long Term Energy Acquisition Plan and Public Utilities Code Section 9615, which
requires local publicly owned utilities to fund cost-effective energy efficiency measures before
funding new energy supply purchases.
Table 15
Public Benefit Charge Expenses and Revenues
Total
Residential
E-1
Small Non-
Residential
E-2
Medium
Non-
Residential
E-4
Large Non-
Residential
E-7
City
Accounts
E-18
Street/
Traffic
Lights
906.20 Energy
Efficiency & DSM
$2,723,852 $418,856 $203,104 $875,794 $1,142,094 $84,004 $0
555.50 Demand-
Side Renewable
Energy
$1,555,878 $324,484 $114,004 $491,591 $528,951 $96,847 $0
Total PBC
Expenses
$4,279,730 $743,341 $317,108 $1,367,385 $1,671,045 $180,851 $0
Total PBC
Revenues
$3,399,398 $537,721 $251,223 $1,083,285 $1,412,677 $103,905 $0
Net Energy Metering
Public Utilities Code Section 2827 requires that utilities, including POUs, offer net energy
metering (NEM) for certain types of customer-owned generators until the installed capacity of
NEM customers’ generation reaches a specified limit, or cap. PUC 2827(g) also requires POUs
to offer identical rates to both eligible NEM customers taking service under the cap, and to non-
NEM customers in the same rate class. New or additional charges that might otherwise be
imposed solely upon NEM customers to fully recover the utility’s cost of serving them (such as
the costs of maintaining the distribution system) are prohibited.
Until the cap is reached, CPA offers NEM under terms and conditions compliant with PUC 2827
under CPA Rule and Regulation 29. Once the cap is reached, utilities are not obligated to
provide NEM to new customers (PUC 2827(C)(4)(A)), although CPA plans to continue offering
NEM under a NEM successor program currently being developed. In CPA’s service territory,
customers have only taken advantage of Rule 29 using solar systems; no other types of eligible
generators have been installed and applied for NEM.
Table 16 shows the expenses and revenues for NEM customers under the proposed E-1 and E-2
Rate Schedules. NEM program expenses are comprised of the revenues that would be received
from the relevant customer group without NEM, less the value of the surplus energy provided
by all customers’ solar systems on an hourly basis. The regulatory compliance cost of offering
NEM to customers under PUC 2827 is roughly $62,911 per year for the 725 customers in the
NEM program as of this report. Commercial rate classes with larger customers and demand
charges (E-4 and E-7) have solar system outputs that coincide well with customer consumption
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 36
patterns because their installed solar systems are smaller relative to the customer load. These
customers are omitted from Table 16 because revenues from E-4 and E-7 NEM customers
match the cost of service. In the E-1 (Residential) and E-2 (Small Non-Residential) classes,
consumption does not coincide as well with solar system output and so the customer meter
runs backwards more frequently (creating “surplus generation”) and offsetting a larger
percentage of customer consumption during the non-solar producing hours.
Table 16
NEM Program Expenses and Revenues
E-1 E-2 TOTAL
NEM Expenses
Revenue without NEM $708,113 $113,517 $821,630
Value of Surplus Energy Generated $106,833 $8,218 $115,051
Net Cost $601,280 $105,299 $706,579
Revenue
Monthly Revenue with NEM $583,240 $99,025 $682,625
Bill Credits for Monthly Net Surplus Energy $32,613 $98 $32,711
Payments for Annual Net Surplus Energy $5,885 $0 $5,885
Total Revenue Received $544,742 $98,926 $643,668
Net Program Expense $56,538 $6,373 $62,911
Street Lighting and Traffic Signals
CPA’s electric utility also provides lighting and traffic signal maintenance services, which are
captured in the E-14 (Street Lighting) and E-16 (Unmetered Electric Service) rate schedules.
These services are primarily provided to CPA itself, but also to a few other governmental
agencies. These rate schedules were modeled combined and then separated based on
estimated usage.
Street lighting costs are equal to $2.1 million, and are provided to several agencies, including
CPA, while traffic signal costs are equal to $234,000 and are only provided to CPA. Given that
CPA is the only customer for traffic signal maintenance services, it is recommended that CPA bill
itself using an internal transfer rather than a rate schedule. Traffic signal rates are
recommended to be removed from the E-16 rate schedule. The E-14 rate schedule, on the
other hand, which is used to bill agencies other than CPA, was updated to reflect CPA’s current
lighting inventory and the inventory of lighting it maintains for other agencies. Actual street
lighting rates are calculated by assigning the costs of street lighting O&M across all street lights,
then allocating the costs of energy consumption based on actual energy use (calculated using
lamp wattages).
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 37
Table 17
Schedule E-14 Proposed Rates
Device
Number
Maintenance Service
Provided Bulb
Current Rate
$/mo.
Proposed Rate
$/mo.
1 Yes HPS 70W $11.85 $28.61
2 Yes HPS 100W $15.48 $30.79
3 Yes HPS 150W $18.43 $34.43
4 Yes HPS 200W $20.55 $0.00
5 Yes HPS 250W $23.32 $41.70
6 Yes HPS 310W $27.32 $0.00
7 Yes HPS 400W $33.47 $0.00
8 Yes LED 70W-EQ $0.00 $23.79
9 Yes LED 100W-EQ $0.00 $25.44
10 Yes LED 150W-EQ $0.00 $26.96
11 Yes LED 250W-EQ $0.00 $31.12
12 Yes Mercury-Vapor 100W $13.56 $0.00
13 Yes Mercury-Vapor 175W $16.31 $0.00
14 Yes Mercury-Vapor 250W $20.32 $0.00
15 Yes Mercury-Vapor 400W $30.29 $0.00
16 Yes Incandescent 2500L $14.41 $0.00
17 Yes Incandescent 4000L $18.43 $0.00
18 Yes Fluorescent 40W $5.30 $0.00
19 Yes Fluorescent 60W $6.36 $0.00
20 No HPS 100W $15.48 $8.59
22 No HPS 200W $20.55 $15.87
23 No HPS 250W $23.32 $19.50
24 No HPS 310W $27.32 $24.13
25 No HPS 400W $33.47 $31.07
26 Yes Mercury-Vapor 400W $20.32 $32.58
CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 38
Technical Appendix
Date:March 10, 2016
Version:Final Draft
Test Period:FY 2017
570 Kirkland Way, Suite 100
Kirkland, Washington 98033
Telephone: 425 889‐2700
Facsimile: 425 889‐2725
A registered professional engineering corporation with offices in the Seattle and Portland areas.
City of Palo Alto
Cost of Service Schedules
Consulting, Inc. EES
Prepared By EES Consulting, Inc.City of Palo Alto
Name of Schedule Worksheet Schedule No.
SUMMARY
SUMMARY OF PRESENT AND PROPOSED RATE REVENUE Summary 1.1
FUNCTIONALIZATION AND CLASSIFICATION OF REVENUE REQUIREMENT Summary 1.2
FUNCTIONALIZATION AND CLASSIFICATION OF RATE BASE SUMMARY Summary 1.3
SUMMARY OF REVENUE REQUIREMENT COST ALLOCATION Summary 1.4
SUMMARY OF RATE BASE COST ALLOCATIONS Summary 1.5
SUMMARY OF HISTORIC LOAD DATA Summary 1.6
SUMMARY OF FORECAST LOAD DATA Summary 1.7
SUMMARY OF POWER SUPPLY COSTS Summary 1.8
UNIT COST
SUMMARY OF REVENUE REQUIREMENT UNIT COSTS Unit Cost 2.1
SUMMARY OF RATE BASE UNIT COST Unit Cost 2.2
REVENUE REQUIREMENT
INPUT REVENUE REQUIREMENT Rev Req 3.1
PROJECTED REVENUE REQUIREMENTS Rev Req 3.2
REVENUE REQUIREMENT COST ALLOCATION FUNCTIONALIZATION AND
CLASSIFICATION Rev Req 3.3
REVENUE REQUIREMENT COST ALLOCATION CLASSIFICATION BY
CUSTOMER Rev Req 3.4
REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY
CUSTOMER Rev Req 3.5
RATE BASE
INPUT RATE BASE Rate Base 4.1
RATE BASE FOR COST ALLOCATION FUNCTIONALIZATION AND
CLASSIFICATION Rate Base 4.2
RATE BASE COST ALLOCATION CLASSIFICATION BY CUSTOMER Rate Base 4.3
RATE BASE COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Rate Base 4.4
TABLE OF CONTENTS
Last Updated: 3/10/2016 1:15 PM Table Of Contents Page 1 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
TABLE OF CONTENTS
POWER SUPPLY
SUMMARY OF POWER SUPPLY COSTS Power Supply 5.1
FUNCTIONALIZATION, CLASSIFICATION AND ALLOCATION
CLASSIFICATION AND ALLOCATION BY FUNCTION C&A by Funct 6.1
CLASSIFICATION AND ALLOCATION BY CUSTOMER C&A by Cust 6.2
COINCIDENT PEAK DEMAND ALLOCATION C&A Calculations 6.3
NON‐COINCIDENT PEAK DEMAND ALLOCATION C&A Calculations 6.4
CLASSIFICATION AND ALLOCATION OF DIRECT ASSIGNMENT BY CUSTOMER C&A Calculations 6.5
REVENUES FROM RATES
FORECAST OF REVENUES FROM CURRENT RATES Revenues 7.1
LOAD DATA
FORECAST CUSTOMERS AND ENERGY SALES Load Summary 8.1
FORECAST CUSTOMER DEMAND Load Summary 8.2
FORECAST kWh AT INPUT Load Summary 8.3
RECORDED CUSTOMERS AND ENERGY SALES Load Summary 8.4
RECORDED CUSTOMER DEMAND Load Summary 8.5
RECORDED kWh AT INPUT Load Summary 8.6
Last Updated: 3/10/2016 1:15 PM Table Of Contents Page 2 of 2
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Forecast Year: 2017 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts
E‐18
Street/Traffic
Lights
Revenues Based on Rates Currently in Effect $110,531,481 $18,406,003 $9,421,113 $38,382,821 $41,216,279 $3,044,789 $60,477
Less Allocated Revenue Requirement $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367
Difference ‐$11,956,498 ‐$2,379,986 ‐$598,025 ‐$4,297,821 ‐$1,225,074 ‐$1,418,701 ‐$2,036,890
Revenue To Cost Ratio 90.2% 88.6% 94.0% 89.9% 97.1% 68.2% 2.9%
% Increase in Rates to Needed to Meet Revenue Requirement 10.8% 12.9% 6.3% 11.2% 3.0% 46.6% 3368.1%
Unit Cost Summary
Unit Cost: Rates Currently in Effect ($/kWh) $0.1140 $0.1203 $0.1337 $0.1196 $0.1045 $0.1042 $0.0319
Unit Cost: COSA Rates ($/kWh) $0.1263 $0.1358 $0.1422 $0.1330 $0.1076 $0.1527 $1.1054
Difference from Present Rates 10.8% 12.9% 6.3% 11.2% 3.0% 46.6% 3368.1%
SUMMARY OF PRESENT AND PROPOSED RATE REVENUE
BY CUSTOMER CLASS
Schedule 1.1
Last Updated: 3/10/2016 1:15 PM Schedule 1.1 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Forecast Year: 2017 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts
E‐18
Street/Traffic
Lights
Production
Demand (PD) $4,205,945 $497,669 $409,908 $1,605,067 $1,528,121 $159,647 $5,534
Energy (PE) $69,412,241 $11,064,767 $5,080,769 $23,048,647 $27,943,724 $2,148,631 $125,704
Direct Assignment (PDA)
Distribution
Demand (DD) $32,680,740 $4,943,138 $3,208,606 $11,570,988 $11,242,417 $1,619,102 $96,489
Energy (DE)
Customer (DC) $13,828,371 $4,280,415 $1,319,855 $6,259,437 $1,432,336 $536,110 $217
Direct Assignment (DDA) $2,360,683 $196,504 $294,755 $1,869,424
Total $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367
Total Cost / Function
Production $73,618,185 $11,562,435 $5,490,676 $24,653,713 $29,471,845 $2,308,278 $131,237
Distribution $48,869,794 $9,223,553 $4,528,462 $18,026,928 $12,969,508 $2,155,212 $1,966,130
Total Cost / Function $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367
Total Cost / Classifier
Demand $36,886,684 $5,440,807 $3,618,514 $13,176,055 $12,770,538 $1,778,749 $102,022
Energy $69,412,241 $11,064,767 $5,080,769 $23,048,647 $27,943,724 $2,148,631 $125,704
Customer $13,828,371 $4,280,415 $1,319,855 $6,259,437 $1,432,336 $536,110 $217
Direct Assignment $2,360,683 $196,504 $294,755 $1,869,424
Total Cost / Classifier $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367
FUNCTIONALIZATION AND CLASSIFICATION OF REVENUE REQUIREMENT SUMMARY
BY CUSTOMER CLASS
Schedule 1.2
Last Updated: 3/10/2016 1:15 PM Schedule 1.2 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Historic Year: 2015 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts
E‐18
Street/Traffic
Lights
Production
Demand (PD) $1,254,278 $148,413 $122,241 $478,656 $455,710 $47,609 $1,650
Energy (PE) $22,114,052 $3,524,837 $1,618,382 $7,345,860 $8,900,881 $683,593 $40,498
Direct Assignment (PDA)
Distribution
Demand (DD) $146,046,015 $22,089,558 $14,338,402 $51,707,642 $50,243,901 $7,235,331 $431,182
Energy (DE)
Customer (DC) $28,537,688 $6,707,376 $1,279,106 $15,356,854 $3,751,894 $1,442,359 $99
Direct Assignment (DDA) $9,909,699 $53,302 $79,953 $9,776,444
Total $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874
Total Cost / Function
Production $23,368,330 $3,673,250 $1,740,623 $7,824,516 $9,356,591 $731,202 $42,148
Distribution $184,493,403 $28,796,934 $15,617,507 $67,117,798 $54,075,748 $8,677,690 $10,207,725
Total Cost / Function $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874
Total Cost / Classifier
Demand $147,300,294 $22,237,971 $14,460,642 $52,186,298 $50,699,611 $7,282,940 $432,832
Energy $22,114,052 $3,524,837 $1,618,382 $7,345,860 $8,900,881 $683,593 $40,498
Customer $28,537,688 $6,707,376 $1,279,106 $15,356,854 $3,751,894 $1,442,359 $99
Direct Assignment $9,909,699 $53,302 $79,953 $9,776,444
Total Cost / Classifier $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874
FUNCTIONALIZATION AND CLASSIFICATION OF RATE BASE SUMMARY
BY CUSTOMER CLASS
Schedule 1.3
Last Updated: 3/10/2016 1:15 PM Schedule 1.3 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Forecast Year: 2017 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts
E‐18
Street/Traffic
Lights
Power Purchases $76,183,327 $11,969,000 $5,693,446 $25,595,699 $30,382,353 $2,399,225 $143,604
Transmission/Ancillary Services Purchases $13,957,173 $2,216,312 $1,020,323 $4,648,913 $5,620,799 $423,347 $27,479
Other ‐$75,172 ‐$11,937 ‐$5,495 ‐$25,039 ‐$30,273 ‐$2,280 ‐$148
Total Production $90,065,328 $14,173,375 $6,708,273 $30,219,573 $35,972,879 $2,820,292 $170,935
Total Distribution $13,195,107 $2,038,394 $1,019,065 $4,848,242 $3,585,597 $608,679 $1,095,130
Total Operation & Maintenance $103,260,435 $16,211,769 $7,727,338 $35,067,816 $39,558,477 $3,428,970 $1,266,066
Total O&M w/o Purchased Power Supply & A&G $19,142,024 $3,863,685 $1,843,484 $6,586,454 $5,027,527 $725,614 $1,095,259
Total Customer Service, Accounts & Sales $5,946,916 $1,825,291 $824,420 $1,738,212 $1,441,929 $116,935 $129
Total Administrative & General $13,931,304 $2,811,937 $1,341,663 $4,793,532 $3,658,965 $528,092 $797,115
Total O&M plus A&G $123,138,655 $20,848,997 $9,893,420 $41,599,559 $44,659,372 $4,073,998 $2,063,309
Total Capital Projects Funded From Rates $13,501,250 $2,301,482 $1,107,223 $5,484,931 $3,899,486 $678,825 $29,304
Total General Fund Transfer $12,101,000 $1,864,587 $1,021,317 $4,412,352 $3,588,443 $574,072 $640,229
Revenue Requirement Before Reserve Transfers and Other Revenues $148,740,905 $25,015,066 $12,021,959 $51,496,843 $52,147,301 $5,326,895 $2,732,842
Revenue Req. Before Taxes, Reserve Transfers and Other Revenues $148,740,905 $25,015,066 $12,021,959 $51,496,843 $52,147,301 $5,326,895 $2,732,842
Total Transfers from Reserves and Allowances for Unspent Budget ‐$17,870,017 ‐$2,805,572 ‐$1,337,276 ‐$6,068,757 ‐$6,845,900 ‐$593,410 ‐$219,102
Total Other Revenues $8,382,909 $1,423,505 $665,546 $2,747,444 $2,860,047 $269,995 $416,373
REVENUE REQUIREMENT for COST ALLOCATION $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367
SUMMARY OF REVENUE REQUIREMENT COST ALLOCATION
Schedule 1.4
Last Updated: 3/10/2016 1:15 PM Schedule 1.4 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Historic Year: 2015 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts
E‐18
Street/Traffic
Lights
Total Distribution Plant $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962
Total General Plant $23,436,856 $3,569,196 $1,851,291 $8,472,309 $6,510,824 $1,078,770 $1,954,465
Total Plant Before General Plant & Intangible $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962
Total Gross Plant in Service $297,800,603 $45,352,022 $23,523,450 $107,653,467 $82,729,835 $13,707,402 $24,834,427
Total Accumulated Depreciation $131,788,193 $19,771,944 $9,512,109 $47,120,845 $33,500,340 $5,831,760 $16,051,195
Total Net Plant $166,012,410 $25,580,078 $14,011,342 $60,532,622 $49,229,494 $7,875,642 $8,783,232
Total Working Capital $30,362,956 $5,140,849 $2,439,473 $10,257,426 $11,011,900 $1,004,547 $508,761
TOTAL RATE BASE $196,375,366 $30,720,927 $16,450,815 $70,790,048 $60,241,394 $8,880,189 $9,291,993
Total Construction Work In Progress $11,486,367 $1,749,258 $907,315 $4,152,266 $3,190,945 $528,704 $957,880
TOTAL RATE BASE plus Construction Work In Progress $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874
SUMMARY OF RATE BASE COST ALLOCATIONS
Schedule 1.5
Last Updated: 3/10/2016 1:15 PM Schedule 1.5 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Historic Year: 2015 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts
E‐18
Street/Traffic
Lights
Recorded Load Data
Energy Sales (kWh)952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346
Total Billing Capacity (kVa)1,521,344 773,606 747,738
Avg. Monthly Billing Capacity (kVa)126,779 64,467 62,312
Number of Customers 29,339 25,341 3,073 736 66 123 1
Ratio of NCP to Avg. Billing Capacity 99% 99%
Rate Classes NCP Demand at Meter 177,573 27,808 17,374 63,599 61,411 6,775 607
Estimates Based on Recorded Data
Annual NCP Load Factor 61% 62% 46% 55% 74% 49% 36%
Rate Classes CP Demand at Input Voltage 169,623 21,594 17,963 62,227 61,674 5,712 454
Annual CP Load Factor 64% 80% 45% 56% 73% 58% 48%
Average On‐Peak kWh as a % of Total kWh 66% 66% 66% 66% 66% 66%
Average Off‐Peak kWh as a % of Total kWh 34% 34% 34% 34% 34% 34%
SUMMARY OF HISTORIC LOAD DATA
Schedule 1.6
Last Updated: 3/10/2016 1:15 PM Schedule 1.6 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Forecast Year: 2017 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts
E‐18
Street/Traffic
Lights
Forecast Load Data
Energy Sales (kWh)969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346
Total Billing Capacity (kVa)1,521,344 773,606 747,738
Avg. Monthly Billing Capacity (kVa)126,779 64,467 62,312
Number of Customers 29,339 25,341 3,073 736 66 123 1
Ratio of NCP to Avg. Billing 197% 99% 99%
Rate Classes NCP Demand at Meter 181,222 27,600 18,470 63,599 61,411 9,534 607
Forecast Based on Recorded and Forecast Data
Annual NCP Load Factor 61% 63% 44% 58% 73% 35% 36%
Rate Classes CP Demand at Input Voltage 168,329 21,188 18,821 62,227 61,674 3,980 439
Annual CP Load Factor 66% 82% 43% 59% 73% 84% 49%
Schedule 1.7
SUMMARY OF FORECAST LOAD DATA
Last Updated: 3/10/2016 1:15 PM Schedule 1.7 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Forecast Year: 2017 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts
E‐18
Street/Traffic
Lights
Western Power Purchases $12,806,834 $1,950,721 $986,135 $4,365,205 $5,076,817 $404,080 $23,876
NCPA Pooling $2,472,030 $392,543 $180,715 $823,394 $995,530 $74,981 $4,867
NCPA Facilities $2,721,836 $432,211 $198,977 $906,601 $1,096,131 $82,558 $5,359
Local Capacity Purchase $1,055,340 $124,873 $102,853 $402,737 $383,430 $40,058 $1,388
Load Advance
Renewable Energy $36,272,543 $5,713,498 $2,679,559 $12,137,404 $14,562,469 $1,108,948 $70,665
Carbon Neutral Purchases (REC)$229,965 $36,517 $16,811 $76,598 $92,611 $6,975 $453
Market Power Purchases $7,112,993 $1,129,499 $519,987 $2,369,225 $2,864,528 $215,750 $14,004
Demand Side Renewable Energy $1,555,878 $324,484 $114,004 $491,591 $528,951 $96,847
Calaveras O&M $11,955,908 $1,864,655 $894,406 $4,022,943 $4,781,886 $369,027 $22,992
Transmission/Ancillary Services Purchases
Transmission Costs $13,957,173 $2,216,312 $1,020,323 $4,648,913 $5,620,799 $423,347 $27,479
Salaries & Benefits ‐ Resource Mgmt $2,073,843 $329,313 $151,606 $690,764 $835,173 $62,903 $4,083
Carbon Allowance Revenues ‐$4,296,000 ‐$682,178 ‐$314,054 ‐$1,430,930 ‐$1,730,075 ‐$130,306 ‐$8,458
General Expense (Resource Mgmt)$796,548 $126,487 $58,231 $265,318 $320,784 $24,161 $1,568
Allocated G&A $1,350,437 $214,441 $98,722 $449,809 $543,845 $40,961 $2,659
Total Power Supply $90,065,328 $14,173,375 $6,708,273 $30,219,573 $35,972,879 $2,820,292 $170,935
SUMMARY OF POWER SUPPLY COSTS
Schedule 1.8
Last Updated: 3/10/2016 1:15 PM Schedule 1.8 Page 1 of 1
Prepared By EES Consulting, Inc.
Last Updated: 3/10/2016 1:15 PM Schedule 1.9 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Forecast Year: 2017 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7City Accounts E‐18 Street/Traffic Lights
Billing Determinants
Total kVa 1,521,344 773,606 747,738
Total Demand (kW) 2,098,690 304,102 190,983 773,606 747,738 76,890 5,371
Total Energy (kWh) 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346
Average Monthly Customers 29,339 25,341 3,073 736 66 123 1
Functional Cost Total Cost Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7City Accounts E‐18 Street/Traffic Lights
Production
Demand (PD)$4,205,945 $497,669 $409,908 $1,605,067 $1,528,121 $159,647 $5,534
$/kW $1.64 $2.15 $2.07 $2.04 $2.08 $1.03
or $/kVa $2.07 $2.04
Energy (PE)$69,412,241 $11,064,767 $5,080,769 $23,048,647 $27,943,724 $2,148,631 $125,704
$/kWh $0.072 $0.072 $0.072 $0.071 $0.074 $0.066
Distribution
Demand (DD)$32,680,740 $4,943,138 $3,208,606 $11,570,988 $11,242,417 $1,619,102 $96,489
$/kW $16.25 $16.80 $14.96 $15.04 $21.06 $17.96
or $/kVa $14.96 $15.04
Customer (DC)$13,828,371 $4,280,415 $1,319,855 $6,259,437 $1,432,336 $536,110 $217
$/Customer/Month $14 $36 $709 $1,811 $365 $18
Direct Assignment (DDA)$2,360,683 $196,504 $294,755 $1,869,424
$/kW $0.25 $0.39 $348.06
$/kVa $0.25 $0.39
$/kWh $0.001 $0.001 $0.985
Total $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367
Total
$/kW $17.89 $18.95 $17.29 $17.47 $23.13 $367.06
$/kWh $0.07230 $0.072 $0.072 $0.072 $0.074 $1.052
$/Customer/Month $14.08 $35.79 $708.80 $1,810.79 $364.70 $18.12
SUMMARY OF REVENUE REQUIREMENT UNIT COSTS
BY CUSTOMER CLASS
Schedule 2.1
Last Updated: 3/10/2016 1:15 PM Schedule 2.1 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand
Forecast Year: 2016 Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7City Accounts E‐18 Street/Traffic Lights
Billing Determinants
Total kVa 1,521,344 773,606 747,738
Total Demand (kW) 2,098,690 304,102 190,983 773,606 747,738 76,890 5,371
Total Energy (kWh) 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346
Average Monthly Customers 29,339 25,341 3,073 736 66 123 1
Functional Cost Total Cost Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7City Accounts E‐18 Street/Traffic Lights
Production
Demand (PD)$1,254,278 $148,413 $122,241 $478,656 $455,710 $47,609 $1,650
$/kW $0.49 $0.64 $0.62 $0.61 $0.62 $0.31
Energy (PE)$22,114,052 $3,524,837 $1,618,382 $7,345,860 $8,900,881 $683,593 $40,498
$/kWh $0.023 $0.023 $0.023 $0.023 $0.023 $0.023 $0.021
Distribution
Demand (DD)$146,046,015 $22,089,558 $14,338,402 $51,707,642 $50,243,901 $7,235,331 $431,182
$/kW $72.64 $75.08 $66.84 $67.19 $94.10 $80.28
Customer (DC)$28,537,688 $6,707,376 $1,279,106 $15,356,854 $3,751,894 $1,442,359 $99
$/Customer/Month $22 $35 $1,739 $4,743 $981 $8
Direct Assignment (DDA)$9,909,699 $53,302 $79,953 $9,776,444
$/kW $0.07 $0.11 $1,820.25
$/kWh $0.000 $0.000 $5.153
Total $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874
SUMMARY OF RATE BASE UNIT COST
BY CUSTOMER CLASS
Schedule 2.2
Last Updated: 3/10/2016 1:15 PM Schedule 2.2 Page 1 of 1
Prepared By EES Consulting, Inc.
City of Palo Alto
INPUT REVENUE REQUIREMENT
Schedule 3.1
Year Classification
2017 & Allocation
Cost, $FunctionFactor Classification & Allocation Method
FERC Account Operation & Maintenance Expense
Power Purchases
555.70 Western Power Purchases $12,806,834 PWESTWestern Cost (84% E, 16% D)
555.71 Contra Surplus Energy PkWhAnnual Energy (kWh)
555.72 NCPA Pooling $2,472,030 PkWhAnnual Energy (kWh)
555.73 NCPA Facilities $2,721,836 PkWhAnnual Energy (kWh)
555.74 Local Capacity Purchase $1,055,340 PCP1212 Coincident Utility Peak
555.75 Load Advance PkWhAnnual Energy (kWh)
555.76 Renewable Energy $36,272,543 PRENRenewable (92% E, 3% D)
555.77 Carbon Neutral Purchases (REC)$229,965 PkWhAnnual Energy (kWh)
555.78 Market Power Purchases $7,112,993 PkWhAnnual Energy (kWh)
OTHER RESOURCES
555.50 Demand Side Renewable Energy $1,555,878 PDSREDemand‐Side Renewable Energy Allocator
555.60 Alt Resources Renewable Energy DSM PkWhAnnual Energy (kWh)
XXXX Calaveras O&M $11,955,908 PCALACalaveras Cost (93% E, 7% D)
Transmission/Ancillary Services Purchases
XXXX Transmission Costs $13,957,173 PkWhAnnual Energy (kWh)
Other
555.20 Salaries & Benefits ‐ Resource Mgmt $2,073,843 PkWhAnnual Energy (kWh)
555.30 Carbon Allowance Revenues ‐$4,296,000 PkWhAnnual Energy (kWh)
555.40 General Expense (Resource Mgmt)$796,548 PkWhAnnual Energy (kWh)
555.45 Allocated G&A $1,350,437 PKWhAnnual Energy (kWh)
Total Purchased Power $90,065,328
Total Production $90,065,328
Distribution
580.00 Op. Supervision & Engineering $3,314,847 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting
581.00 Load Dispatching DRBSEOn the Basis of Station Equipment Rate Base
582.00 Line and Station Expenses DRBSEOn the Basis of Station Equipment Rate Base
583.00 Overhead Lines DRBOHOn the Basis of all Overhead Rate Base
584.00 Underground Lines DRBUGOn the Basis of all Underground Rate Base
585.00 Street Lighting & Signal System $869,624 DDA1Direct Assignment for Streetlights
586.00 Meters DCUSTWCustomers Weighted for Accounting/Metering
587.00 Customer Installations DCUSTWCustomers Weighted for Accounting/Metering
588.00 Misc. Distribution $3,537,760 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting
589.00 Rents $318,470 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting
590.00 Maint. Supervision & Engineering $3,092,997 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting
591.00 Maint. of Structures DRBSEOn the Basis of Station Equipment Rate Base
592.00 Maint. of Station Equipment DRBSEOn the Basis of Station Equipment Rate Base
592.10 Maint. of Structures and Equipment DRBSEOn the Basis of Station Equipment Rate Base
593.00 Maint. of Overhead Lines $1,510,766 DRBOHOn the Basis of all Overhead Rate Base
594.00 Maint. Of Underground Lines DRBUGOn the Basis of all Underground Rate Base
594.10 Maint. of Lines DRBUGOn the Basis of all Underground Rate Base
Last Updated: 3/10/2016 1:15 PM Schedule 3.1 Page 1 of 3
Prepared By EES Consulting, Inc.
City of Palo Alto
INPUT REVENUE REQUIREMENT
Schedule 3.1
Year Classification
2017 & Allocation
Cost, $FunctionFactor Classification & Allocation Method
595.00 Maint. of Line Transformers DRBTROn the Basis of all Transformer Rate Base
595.00 Maint. of Line Transformers ‐ Underground DRBTROn the Basis of all Transformer Rate Base
596.00 Maint. of Street Lighting & Signal System $198,001 DDA1Direct Assignment for Streetlights
597.00 Maint. of Meters DCUSTMCustomers Weighted for Meters and Services
598.00 Maint. of Misc. Distribution Plant DRBD‐NoDA As Distribution Ratebase without DA Street Lighting
598.10 Communication O&M $352,642 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting
XXXX Other DRBD‐NoDA As Distribution Ratebase without DA Street Lighting
XXXX Other DRBD‐NoDA As Distribution Ratebase without DA Street Lighting
Total Distribution $13,195,107
Total Operation & Maintenance $103,260,435
Customer Service, Accounts, & Sales
901/907/911 Supervision $718,334 DCUSTWCustomers Weighted for Accounting/Metering
902.00 Meter Reading $390,328 DCUSTMRCustomers Weighted for Meter Reading
903.00 Customer Records Collection $487,803 DCREDITCredit & Collections (35% Residential)
904.00 Uncollectable Accounts $141,023 DCREDITCredit & Collections (35% Residential)
905.00 Misc. Customer Accounts DCUSTActual Customers
906.00 Customer Service & Information $176,793 DCUST SERV Customer Service (60% Residential)
907.00 Customer Communication & Education DCUSTActual Customers
908.00 Customer Assistance DCUSTActual Customers
910.00 Misc. Customer Service & Information DCUSTActual Customers
912.00 Demonstrating & Selling DCUSTActual Customers
913.00 Advertising DCUSTActual Customers
916.00 Misc. Sales Expenses $996,000 DCUST SERV Customer Service (60% Residential)
917.00 Sales Expenses DOMOn the Basis of All O&M
906.10 Key Accounts $312,784 DDA2Direct Assignment for Key Accounts
906.20 Energy Efficiency & DSM $2,417,900 PDSMEEDSM / EE Allocator:
906.30 Low Income Residential Energy Assistance Program $305,952 PDSMEEDSM / EE Allocator:
Total Customer Service, Accounts & Sales $5,946,916
Total O&M w/o Purchased Power Supply & A&G $19,142,024
Administrative & General
920.00 Administrative & General Salaries $5,245,712 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
921.00 Office Supplies $36,700 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
922.00 Administrative Transfer ‐ Credit SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
923.00 Outside Services $487,748 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
924.00 Property Insurance SS NETPLT On the Basis of Net Plant
925.00 Injuries and Damages $10,864 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
926.00 Employee Pension & Benefits $1,142,543 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
927.00 Franchise Requirements SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
928.00 Regulatory Expense SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
929.00 Duplicate Charge ‐ Credit SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
930.10 General Advertising SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
930.20 Misc. General Expense $1,934,446 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
930.30 Environmental $77,118 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
931.00 Rents $4,996,173 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
Last Updated: 3/10/2016 1:15 PM Schedule 3.1 Page 2 of 3
Prepared By EES Consulting, Inc.
City of Palo Alto
INPUT REVENUE REQUIREMENT
Schedule 3.1
Year Classification
2017 & Allocation
Cost, $FunctionFactor Classification & Allocation Method
932.00 Maint. of General Plant & Communication Equipment SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
933.00 Transportation SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
935.00 Maintenance of General Plant SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
Total Administrative & General $13,931,304
Total O&M plus A&G $123,138,655
Taxes
408.00 Property Tax SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
Total Taxes
Capital Projects Funded From Rates
Production PRBGOn the Basis of Generation Rate Base
Transmission TRBTOn the Basis of Transmission Rate Base
Distribution $13,501,250 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting
General SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
Total Capital Projects Funded From Rates $13,501,250
Revenue Requirement Before Transfers and Other Revenues
Other Contributions
Transfers from Reserves and Allowances for Unspent Budget ‐$17,870,017 SS OM On the Basis of All O&M
General Fund Transfer $12,101,000 SS NETPLT On the Basis of Net Plant
Total Other Contributions ‐$5,769,017
Revenue Requirement Before Reserve Transfers and Other Revenues $148,740,905
Revenue Req. Before Taxes, Reserve Transfers and Other Revenues $148,740,905
Other Revenues
450.00 Forfeited Deposits SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
451.00 Misc. Service Revenues $167,200 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
454.00 Rent ‐ Electric Properties SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
456.00 Misc. Revenue (Other)$2,507,700 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
457.00 Transfer Credits $135,386 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
458.00 Low Hydro Transfers PkwhAnnual Energy (kWh)
419&424 Dividends from Affiliates, Interest SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
449.00 Other Revenue SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
415&416 Income (Loss) from Equity Investments $198,500 SS OMAG On the Basis of O&M (w/o Power Supply and A&G)
444.20 Street Light Revenue DCUSTMCustomers Weighted for Meters and Services
421&429 Traffic Signal Transfer from General Fund $233,984 DDA1Direct Assignment for Streetlights
446.00 Green Power $45,085 PkWhAnnual Energy (kWh)
XXXX Surplus Energy Revenues $5,084,054 PkWhAnnual Energy (kWh)
Total Other Revenues $8,382,909
REVENUE REQUIREMENT for COST ALLOCATION $122,487,979
Last Updated: 3/10/2016 1:15 PM Schedule 3.1 Page 3 of 3
Prepared By EES Consulting, Inc.
FERC Account
555.70
555.71
555.72
555.73
555.74
555.75
555.76
555.77
555.78
555.50
555.60
XXXX
XXXX
555.20
555.30
555.40
555.45
580.00
581.00
582.00
583.00
584.00
585.00
City of Palo Alto
Total
2015
Expenses 2016 2017 2018 2019 2020
Operation & Maintenance Expense
Power Purchases
Western Power Purchases $11,251,000 $11,521,895 $12,806,834 $12,806,834 $12,806,834 $12,806,834
Contra Surplus Energy
NCPA Pooling $2,609,000 $2,489,570 $2,472,030 $2,472,030 $2,472,030 $2,472,030
NCPA Facilities $1,958,000 $3,799,711 $2,721,836 $2,721,836 $2,721,836 $2,721,836
Local Capacity Purchase $1,383,000 $1,059,322 $1,055,340 $1,055,340 $1,055,340 $1,055,340
Load Advance
Renewable Energy $16,361,000 $22,711,901 $36,272,543 $36,272,543 $36,272,543 $36,272,543
Carbon Neutral Purchases (REC)$542,000 $606,088 $229,965 $229,965 $229,965 $229,965
Market Power Purchases $14,249,000 $12,952,695 $7,112,993 $7,112,993 $7,112,993 $7,112,993
OTHER RESOURCES
Demand Side Renewable Energy $2,250,171 $2,256,075 $1,555,878 $1,555,878 $1,555,878 $1,555,878
Alt Resources Renewable Energy DSM
Calaveras O&M $11,756,000 $12,151,449 $11,955,908 $11,955,908 $11,955,908 $11,955,908
Transmission/Ancillary Services Purchases
Transmission Costs $14,850,000 $12,005,787 $13,957,173 $13,957,173 $13,957,173 $13,957,173
Other
Salaries & Benefits ‐ Resource Mgmt $1,454,687 $2,066,695 $2,073,843 $2,073,843 $2,073,843 $2,073,843
Carbon Allowance Revenues ‐$4,296,000 ‐$4,296,000 ‐$4,296,000 ‐$4,296,000 ‐$4,296,000 ‐$4,296,000
General Expense (Resource Mgmt)$710,740 $729,232 $796,548 $796,548 $796,548 $796,548
Allocated G&A $1,254,368 $1,350,437 $1,350,437 $1,350,437 $1,350,437 $1,350,437
Total Purchased Power $76,332,966 $81,404,857 $90,065,328 $90,065,328 $90,065,328 $90,065,328
Total Production $76,332,966 $81,404,857 $90,065,328 $90,065,328 $90,065,328 $90,065,328
Distribution
Op. Supervision & Engineering $2,749,336 $3,315,025 $3,314,847 $3,381,144 $3,448,767 $3,517,743
Load Dispatching
Line and Station Expenses
Overhead Lines
Underground Lines
Street Lighting & Signal System $860,619 $843,545 $869,624 $887,016 $904,757 $922,852
PROJECTED REVENUE REQUIREMENTS
Schedule 3.2
Last Updated: 3/10/2016 1:16 PM Schedule 3.2 Page 1 of 4
Prepared By EES Consulting, Inc.
586.00
587.00
588.00
589.00
590.00
591.00
592.00
592.10
593.00
594.00
594.10
595.00
595.00
596.00
597.00
598.00
598.10
XXXX
XXXX
901/907/911
902.00
903.00
904.00
905.00
906.00
907.00
908.00
910.00
912.00
City of Palo Alto
Total
2015
Expenses 2016 2017 2018 2019 2020
PROJECTED REVENUE REQUIREMENTS
Schedule 3.2
Meters
Customer Installations
Misc. Distribution $2,299,091 $2,304,516 $3,537,760 $3,608,515 $3,680,686 $3,754,299
Rents $214,400 $310,400 $318,470 $324,839 $331,336 $337,963
Maint. Supervision & Engineering $2,697,138 $3,093,886 $3,092,997 $3,154,857 $3,217,954 $3,282,314
Maint. of Structures
Maint. of Station Equipment
Maint. of Structures and Equipment
Maint. of Overhead Lines $1,479,858 $1,502,814 $1,510,766 $1,540,981 $1,571,801 $1,603,237
Maint. Of Underground Lines
Maint. of Lines
Maint. of Line Transformers
Maint. of Line Transformers ‐ Underground
Maint. of Street Lighting & Signal System $185,979 $198,001 $198,001 $201,961 $206,000 $210,120
Maint. of Meters
Maint. of Misc. Distribution Plant
Communication O&M $318,092 $338,641 $352,642 $337,177 $343,539 $349,901
Other
Other
Total Distribution $10,804,513 $11,906,828 $13,195,107 $13,436,492 $13,704,840 $13,978,428
Total Operation & Maintenance $87,137,479 $93,311,685 $103,260,435 $103,501,819 $103,770,167 $104,043,755
Customer Service, Accounts, & Sales
Supervision $664,307 $724,258 $718,334 $732,701 $747,355 $762,302
Meter Reading $298,424 $373,288 $390,328 $398,135 $406,097 $414,219
Customer Records Collection $547,945 $487,803 $487,803 $497,560 $507,511 $517,661
Uncollectable Accounts $135,704 $141,644 $141,023 $143,843 $146,720 $149,654
Misc. Customer Accounts
Customer Service & Information $190,513 $176,793 $176,793 $180,329 $183,935 $187,614
Customer Communication & Education
Customer Assistance
Misc. Customer Service & Information
Demonstrating & Selling
Last Updated: 3/10/2016 1:16 PM Schedule 3.2 Page 2 of 4
Prepared By EES Consulting, Inc.
913.00
916.00
917.00
906.10
906.20
906.30
920.00
921.00
922.00
923.00
924.00
925.00
926.00
927.00
928.00
929.00
930.10
930.20
930.30
931.00
932.00
933.00
935.00
408.00
City of Palo Alto
Total
2015
Expenses 2016 2017 2018 2019 2020
PROJECTED REVENUE REQUIREMENTS
Schedule 3.2
Advertising
Misc. Sales Expenses $996,000 $996,000 $996,000 $1,015,920 $1,036,238 $1,056,963
Sales Expenses
Key Accounts $299,195 $313,752 $312,784 $319,039 $325,420 $331,928
Energy Efficiency & DSM $2,115,545 $2,245,302 $2,417,900 $2,466,258 $2,515,583 $2,565,894
Low Income Residential Energy Assistance Program $292,243 $305,952 $305,952 $312,071 $318,313 $324,679
Total Customer Service, Accounts & Sales $5,539,876 $5,764,791 $5,946,916 $6,065,855 $6,187,172 $6,310,915
Total O&M w/o Purchased Power Supply & A&G $16,344,389 $17,671,620 $19,142,024 $19,502,346 $19,892,012 $13,978,428
Administrative & General
Administrative & General Salaries $4,781,200 $5,245,712 $5,245,712 $5,350,626 $5,457,639 $5,566,792
Office Supplies $40,000 $36,700 $36,700 $37,434 $38,183 $38,946
Administrative Transfer ‐ Credit
Outside Services $30,000 $487,748 $487,748 $497,503 $507,453 $517,602
Property Insurance
Injuries and Damages $5,794 $10,864 $10,864 $11,081 $11,303 $11,529
Employee Pension & Benefits $1,004,817 $1,142,543 $1,142,543 $1,165,394 $1,188,702 $1,212,476
Franchise Requirements
Regulatory Expense
Duplicate Charge ‐ Credit
General Advertising
Misc. General Expense $1,874,081 $1,935,081 $1,934,446 $1,973,135 $2,012,598 $2,052,850
Environmental $77,118 $77,118 $77,118 $78,660 $80,234 $81,838
Rents $3,850,594 $4,869,565 $4,996,173 $5,096,096 $5,198,018 $5,301,979
Maint. of General Plant & Communication Equipment
Transportation
Maintenance of General Plant
Total Administrative & General $11,663,603 $13,805,331 $13,931,304 $14,209,930 $14,494,128 $14,784,011
Total O&M plus A&G $104,340,959 $112,881,807 $123,138,655 $123,777,604 $124,451,468 $125,138,682
Taxes
Property Tax
Total Taxes
Capital Projects Funded From Rates
Last Updated: 3/10/2016 1:16 PM Schedule 3.2 Page 3 of 4
Prepared By EES Consulting, Inc.
450.00
451.00
454.00
456.00
457.00
458.00
419&424
449.00
415&416
444.20
421&429
446.00
XXXX
City of Palo Alto
Total
2015
Expenses 2016 2017 2018 2019 2020
PROJECTED REVENUE REQUIREMENTS
Schedule 3.2
Production
Transmission
Distribution $7,781,000 $14,666,639 $13,501,250 $16,306,888 $20,477,804 $10,735,893
General
Total Capital Projects Funded From Rates $7,781,000 $14,666,639 $13,501,250 $16,306,888 $20,477,804 $10,735,893
Revenue Requirement Before Transfers and Other Revenu
Other Contributions
Transfers from Reserves and Allowances for Unspent Budget ‐$17,870,017 ‐$9,245,124 ‐$7,849,878 $909,000
General Fund Transfer $11,397,790 $11,725,000 $12,101,000 $12,343,020 $12,589,880 $12,841,678
Total Other Contributions $11,397,790 $11,725,000 ‐$5,769,017 $3,097,896 $4,740,002 $13,750,678
Revenue Requirement Before Reserve Transfers and Other $123,519,749 $139,273,446 $148,740,905 $152,427,512 $157,519,152 $148,716,253
Revenue Req. Before Taxes, Reserve Transfers and Other R $123,519,749 $139,273,446 $148,740,905 $152,427,512 $157,519,152 $148,716,253
Other Revenues
Forfeited Deposits
Misc. Service Revenues $167,200 $167,200 $167,200 $170,544 $173,955 $177,434
Rent ‐ Electric Properties
Misc. Revenue (Other)$11,000 $11,000 $2,507,700 $2,557,854 $2,609,011 $2,661,191
Transfer Credits $666,667 $135,386 $135,386
Low Hydro Transfers $15,000,000
Dividends from Affiliates, Interest
Other Revenue $300,676 $198,500
Income (Loss) from Equity Investments $198,500 $202,470 $206,519 $210,650
Street Light Revenue
Traffic Signal Transfer from General Fund $233,984 $233,984 $233,984 $233,984 $233,984
Green Power $165,900 $56,000 $45,085 $45,987 $46,906 $47,845
Surplus Energy Revenues $2,316,000 $3,684,054 $5,084,054 $5,084,054 $5,084,054 $5,084,054
Total Other Revenues $6,325,543 $21,993,824 $8,382,909 $8,306,113 $8,365,874 $8,426,831
REVENUE REQUIREMENT for COST ALLOCATION $117,194,206 $117,279,622 $122,487,979 $134,876,275 $141,303,399 $141,198,422
Last Updated: 3/10/2016 1:16 PM Schedule 3.2 Page 4 of 4
Prepared By EES Consulting, Inc.
FERC Account
555.70
555.71
555.72
555.73
555.74
555.75
555.76
555.77
555.78
555.50
555.60
XXXX
XXXX
555.20
555.30
555.40
555.45
580.00
581.00
582.00
583.00
584.00
585.00
586.00
587.00
588.00
589.00
590.00
591.00
592.00
592.10
593.00
594.00
594.10
595.00
595.00
596.00
597.00
598.00
Allocation Date
2017 Direct Direct
Total Demand Energy Demand Energy Assignment Demand Customer Assignment
Expenses PD PE TD TE TDA DD DC DDA Total Check
Operation & Maintenance Expense
Power Purchases
Western Power Purchases $12,806,834 $2,049,093 $10,757,741
Contra Surplus Energy
NCPA Pooling $2,472,030 $2,472,030
NCPA Facilities $2,721,836 $2,721,836
Local Capacity Purchase $1,055,340 $1,055,340
Load Advance
Renewable Energy $36,272,543 $1,145,449 $35,127,094
Carbon Neutral Purchases (REC) $229,965 $229,965
Market Power Purchases $7,112,993 $7,112,993
OTHER RESOURCES
Demand Side Renewable Energy $1,555,878 $1,555,878
Alt Resources Renewable Energy DSM
Calaveras O&M $11,955,908 $836,914 $11,118,995
Transmission/Ancillary Services Purchases
Transmission Costs $13,957,173 $13,957,173
Other
Salaries & Benefits ‐ Resource Mgmt $2,073,843 $2,073,843
Carbon Allowance Revenues ‐$4,296,000 ‐$4,296,000
General Expense (Resource Mgmt) $796,548 $796,548
Allocated G&A $1,350,437 $1,350,437
Total Purchased Power $90,065,328 $5,086,796 $84,978,532
Total Production $90,065,328 $5,086,796 $84,978,532
Distribution
Op. Supervision & Engineering $3,314,847 $2,436,476 $878,372
Load Dispatching
Line and Station Expenses
Overhead Lines
Underground Lines
Street Lighting & Signal System $869,624 $869,624
Meters
Customer Installations
Misc. Distribution $3,537,760 $2,600,321 $937,439
Rents $318,470 $234,082 $84,388
Maint. Supervision & Engineering $3,092,997 $2,273,412 $819,585
Maint. of Structures
Maint. of Station Equipment
Maint. of Structures and Equipment
Maint. of Overhead Lines $1,510,766 $1,510,766
Maint. Of Underground Lines
Maint. of Lines
Maint. of Line Transformers
Maint. of Line Transformers ‐ Underground
Maint. of Street Lighting & Signal System $198,001 $198,001
Maint. of Meters
Maint. of Misc. Distribution Plant
Production Transmission Distribution
FUNCTIONALIZATION AND CLASSIFICATION
Schedule 3.3
REVENUE REQUIREMENT COST ALLOCATION
Last Updated: 3/10/2016 1:16 PM Schedule 3.3 Page 1 of 3
Prepared By EES Consulting, Inc.
598.10
XXXX
XXXX
901/907/911
902.00
903.00
904.00
905.00
906.00
907.00
908.00
910.00
912.00
913.00
916.00
917.00
906.10
906.20
906.30
920.00
921.00
922.00
923.00
924.00
925.00
926.00
927.00
928.00
929.00
930.10
930.20
930.30
931.00
932.00
933.00
935.00
408.00
Allocation Date
2017 Direct Direct
Total Demand Energy Demand Energy Assignment Demand Customer Assignment
Expenses PD PE TD TE TDA DD DC DDA Total Check
Production Transmission Distribution
FUNCTIONALIZATION AND CLASSIFICATION
Schedule 3.3
REVENUE REQUIREMENT COST ALLOCATION
Communication O&M $352,642 $259,199 $93,443
Other
Other
Total Distribution $13,195,107 $9,314,255 $2,813,228 $1,067,625
Total Operation & Maintenance $103,260,435 $5,086,796 $84,978,532 $9,314,255 $2,813,228 $1,067,625
Customer Service, Accounts, & Sales
Supervision $718,334 $718,334
Meter Reading $390,328 $390,328
Customer Records Collection $487,803 $487,803
Uncollectable Accounts $141,023 $141,023
Misc. Customer Accounts
Customer Service & Information $176,793 $176,793
Customer Communication & Education
Customer Assistance
Misc. Customer Service & Information
Demonstrating & Selling
Advertising
Misc. Sales Expenses $996,000 $996,000
Sales Expenses
Key Accounts $312,784 $312,784
Energy Efficiency & DSM $2,417,900 $2,417,900
Low Income Residential Energy Assistance Program $305,952 $305,952
Total Customer Service, Accounts & Sales $5,946,916 $2,723,852 $2,910,281 $312,784
Total O&M w/o Purchased Power Supply & A&G $19,142,024 $2,723,852 $9,314,255 $5,723,509 $1,380,408
Administrative & General
Administrative & General Salaries $5,245,712 $746,449 $2,552,494 $1,568,480 $378,289
Office Supplies $36,700 $5,222 $17,858 $10,973 $2,647
Administrative Transfer ‐ Credit
Outside Services $487,748 $69,405 $237,332 $145,838 $35,173
Property Insurance
Injuries and Damages $10,864 $1,546 $5,286 $3,248 $783
Employee Pension & Benefits $1,142,543 $162,580 $555,946 $341,623 $82,393
Franchise Requirements
Regulatory Expense
Duplicate Charge ‐ Credit
General Advertising
Misc. General Expense $1,934,446 $275,266 $941,276 $578,404 $139,501
Environmental $77,118 $10,974 $37,525 $23,058 $5,561
Rents $4,996,173 $710,940 $2,431,071 $1,493,867 $360,294
Maint. of General Plant & Communication Equipment
Transportation
Maintenance of General Plant
Total Administrative & General $13,931,304 $1,982,382 $6,778,788 $4,165,492 $1,004,642
Total O&M plus A&G $123,138,655 $5,086,796 $89,684,766 $16,093,042 $9,889,001 $2,385,050
Taxes
Property Tax
Total Taxes
Capital Projects Funded From Rates
Last Updated: 3/10/2016 1:16 PM Schedule 3.3 Page 2 of 3
Prepared By EES Consulting, Inc.
450.00
451.00
454.00
456.00
457.00
458.00
419&424
449.00
415&416
444.20
421&429
446.00
XXXX
Allocation Date
2017 Direct Direct
Total Demand Energy Demand Energy Assignment Demand Customer Assignment
Expenses PD PE TD TE TDA DD DC DDA Total Check
Production Transmission Distribution
FUNCTIONALIZATION AND CLASSIFICATION
Schedule 3.3
REVENUE REQUIREMENT COST ALLOCATION
Production
Transmission
Distribution $13,501,250 $9,923,675 $3,577,575
General
Total Capital Projects Funded From Rates $13,501,250 $9,923,675 $3,577,575
Revenue Requirement Before Transfers and Other Revenu
Other Contributions
Transfers from Reserves and Allowances for Unspent Budge ‐$17,870,017 ‐$880,309 ‐$14,706,192 ‐$1,611,904 ‐$486,851 ‐$184,761
General Fund Transfer $12,101,000 $9,740,954 $1,748,579 $611,467
Total Other Contributions ‐$5,769,017 ‐$880,309 ‐$14,706,192 $8,129,050 $1,261,729 $426,706
Revenue Requirement Before Reserve Transfers and Othe $148,740,905 $5,086,796 $89,684,766 $35,757,671 $15,215,155 $2,996,517
Revenue Req. Before Taxes, Reserve Transfers and Other R $148,740,905 $5,086,796 $89,684,766 $35,757,671 $15,215,155 $2,996,517
Other Revenues
Forfeited Deposits
Misc. Service Revenues $167,200 $23,792 $81,357 $49,993 $12,057
Rent ‐ Electric Properties
Misc. Revenue (Other) $2,507,700 $356,838 $1,220,214 $749,808 $180,840
Transfer Credits $135,386 $19,265 $65,877 $40,481 $9,763
Low Hydro Transfers
Dividends from Affiliates, Interest
Other Revenue
Income (Loss) from Equity Investments $198,500 $28,246 $96,587 $59,352 $14,315
Street Light Revenue
Traffic Signal Transfer from General Fund $233,984 $233,984
Green Power $45,085 $45,085
Surplus Energy Revenues $5,084,054 $5,084,054
Total Other Revenues $8,382,909 $542 $5,566,333 $1,465,028 $899,934 $451,074
REVENUE REQUIREMENT for COST ALLOCATION $122,487,979 $4,205,945 $69,412,241 $32,680,740 $13,828,371 $2,360,683
Last Updated: 3/10/2016 1:16 PM Schedule 3.3 Page 3 of 3
Prepared By EES Consulting, Inc.
FERC Account
555.70
555.71
555.72
555.73
555.74
555.75
555.76
555.77
555.78
555.50
555.60
XXXX
XXXX
555.20
555.30
555.40
555.45
580.00
581.00
582.00
583.00
584.00
585.00
586.00
587.00
588.00
589.00
590.00
591.00
592.00
592.10
593.00
594.00
City of Palo Alto ‐ 100% Demand
Allocation Date
2017
Total
Expenses
Operation & Maintenance Expense Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7City Accounts E‐18
Street/Traffic
Lights Total Check
Power Purchases
Western Power Purchases $12,806,834 $1,950,721 $986,135 $4,365,205 $5,076,817 $404,080 $23,876
Contra Surplus Energy
NCPA Pooling $2,472,030 $392,543 $180,715 $823,394 $995,530 $74,981 $4,867
NCPA Facilities $2,721,836 $432,211 $198,977 $906,601 $1,096,131 $82,558 $5,359
Local Capacity Purchase $1,055,340 $124,873 $102,853 $402,737 $383,430 $40,058 $1,388
Load Advance
Renewable Energy $36,272,543 $5,713,498 $2,679,559 $12,137,404 $14,562,469 $1,108,948 $70,665
Carbon Neutral Purchases (REC) $229,965 $36,517 $16,811 $76,598 $92,611 $6,975 $453
Market Power Purchases $7,112,993 $1,129,499 $519,987 $2,369,225 $2,864,528 $215,750 $14,004
OTHER RESOURCES
Demand Side Renewable Energy $1,555,878 $324,484 $114,004 $491,591 $528,951 $96,847
Alt Resources Renewable Energy DSM
Calaveras O&M $11,955,908 $1,864,655 $894,406 $4,022,943 $4,781,886 $369,027 $22,992
Transmission/Ancillary Services Purchases
Transmission Costs $13,957,173 $2,216,312 $1,020,323 $4,648,913 $5,620,799 $423,347 $27,479
Other
Salaries & Benefits ‐ Resource Mgmt $2,073,843 $329,313 $151,606 $690,764 $835,173 $62,903 $4,083
Carbon Allowance Revenues ‐$4,296,000 ‐$682,178 ‐$314,054 ‐$1,430,930 ‐$1,730,075 ‐$130,306 ‐$8,458
General Expense (Resource Mgmt) $796,548 $126,487 $58,231 $265,318 $320,784 $24,161 $1,568
Allocated G&A $1,350,437 $214,441 $98,722 $449,809 $543,845 $40,961 $2,659
Total Purchased Power $90,065,328 $14,173,375 $6,708,273 $30,219,573 $35,972,879 $2,820,292 $170,935
Total Production $90,065,328 $14,173,375 $6,708,273 $30,219,573 $35,972,879 $2,820,292 $170,935
Distribution
Op. Supervision & Engineering $3,314,847 $565,063 $271,847 $1,346,669 $957,408 $166,666 $7,195
Load Dispatching
Line and Station Expenses
Overhead Lines
Underground Lines
Street Lighting & Signal System $869,624 $869,624
Meters
Customer Installations
Misc. Distribution $3,537,760 $603,062 $290,128 $1,437,228 $1,021,790 $177,874 $7,679
Rents $318,470 $54,288 $26,117 $129,380 $91,982 $16,012 $691
Maint. Supervision & Engineering $3,092,997 $527,246 $253,653 $1,256,541 $893,332 $155,512 $6,713
Maint. of Structures
Maint. of Station Equipment
Maint. of Structures and Equipment
Maint. of Overhead Lines $1,510,766 $228,622 $148,399 $535,163 $519,234 $74,884 $4,463
Maint. Of Underground Lines
REVENUE REQUIREMENT COST ALLOCATION
BY CUSTOMER
Schedule 3.4
Last Updated: 3/10/2016 1:16 PM Schedule 3.4 Page 1 of 4
Prepared By EES Consulting, Inc.
FERC Account
594.10
595.00
595.00
596.00
597.00
598.00
598.10
XXXX
XXXX
901/907/911
902.00
903.00
904.00
905.00
906.00
907.00
908.00
910.00
912.00
913.00
916.00
917.00
906.10
906.20
906.30
920.00
921.00
922.00
923.00
924.00
925.00
926.00
927.00
928.00
City of Palo Alto ‐ 100% Demand
Allocation Date
2017
Total
Expenses
Operation & Maintenance Expense Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7City Accounts E‐18
Street/Traffic
Lights Total Check
REVENUE REQUIREMENT COST ALLOCATION
BY CUSTOMER
Schedule 3.4
Maint. of Lines
Maint. of Line Transformers
Maint. of Line Transformers ‐ Underground
Maint. of Street Lighting & Signal System $198,001 $198,001
Maint. of Meters
Maint. of Misc. Distribution Plant
Communication O&M $352,642 $60,113 $28,920 $143,262 $101,852 $17,730 $765
Other
Other
Total Distribution $13,195,107 $2,038,394 $1,019,065 $4,848,242 $3,585,597 $608,679 $1,095,130
Total Operation & Maintenance $103,260,435 $16,211,769 $7,727,338 $35,067,816 $39,558,477 $3,428,970 $1,266,066
Customer Service, Accounts, & Sales
Supervision $718,334 $312,734 $113,769 $245,213 $39,047 $7,559 $12
Meter Reading $390,328 $169,936 $61,821 $133,246 $21,218 $4,107
Customer Records Collection $487,803 $170,731 $243,691 $58,360 $5,227 $9,715 $79
Uncollectable Accounts $141,023 $49,358 $70,450 $16,872 $1,511 $2,808 $23
Misc. Customer Accounts
Customer Service & Information $176,793 $106,076 $19,836 $42,753 $6,808 $1,318 $2
Customer Communication & Education
Customer Assistance
Misc. Customer Service & Information
Demonstrating & Selling
Advertising
Misc. Sales Expenses $996,000 $597,600 $111,749 $240,860 $38,354 $7,425 $12
Sales Expenses
Key Accounts $312,784 $125,113 $187,670
Energy Efficiency & DSM $2,417,900 $371,809 $180,291 $777,422 $1,013,810 $74,568
Low Income Residential Energy Assistance Program $305,952 $47,047 $22,813 $98,372 $128,284 $9,436
Total Customer Service, Accounts & Sales $5,946,916 $1,825,291 $824,420 $1,738,212 $1,441,929 $116,935 $129
Total O&M w/o Purchased Power Supply & A&G $19,142,024 $3,863,685 $1,843,484 $6,586,454 $5,027,527 $725,614 $1,095,259
Administrative & General
Administrative & General Salaries $5,245,712 $1,058,811 $505,191 $1,804,963 $1,377,752 $198,848 $300,147
Office Supplies $36,700 $7,408 $3,534 $12,628 $9,639 $1,391 $2,100
Administrative Transfer ‐ Credit
Outside Services $487,748 $98,449 $46,973 $167,826 $128,104 $18,489 $27,908
Property Insurance
Injuries and Damages $10,864 $2,193 $1,046 $3,738 $2,853 $412 $622
Employee Pension & Benefits $1,142,543 $230,614 $110,033 $393,130 $300,081 $43,310 $65,373
Franchise Requirements
Regulatory Expense
Last Updated: 3/10/2016 1:16 PM Schedule 3.4 Page 2 of 4
Prepared By EES Consulting, Inc.
FERC Account
929.00
930.10
930.20
930.30
931.00
932.00
933.00
935.00
408.00
450.00
451.00
454.00
456.00
457.00
458.00
419&424
449.00
415&416
444.20
City of Palo Alto ‐ 100% Demand
Allocation Date
2017
Total
Expenses
Operation & Maintenance Expense Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7City Accounts E‐18
Street/Traffic
Lights Total Check
REVENUE REQUIREMENT COST ALLOCATION
BY CUSTOMER
Schedule 3.4
Duplicate Charge ‐ Credit
General Advertising
Misc. General Expense $1,934,446 $390,455 $186,298 $665,611 $508,070 $73,329 $110,684
Environmental $77,118 $15,566 $7,427 $26,535 $20,255 $2,923 $4,413
Rents $4,996,173 $1,008,443 $481,159 $1,719,101 $1,312,212 $189,389 $285,869
Maint. of General Plant & Communication Equipment
Transportation
Maintenance of General Plant
Total Administrative & General $13,931,304 $2,811,937 $1,341,663 $4,793,532 $3,658,965 $528,092 $797,115
Total O&M plus A&G $123,138,655 $20,848,997 $9,893,420 $41,599,559 $44,659,372 $4,073,998 $2,063,309
Taxes
Property Tax
Total Taxes
Capital Projects Funded From Rates
Production
Transmission
Distribution $13,501,250 $2,301,482 $1,107,223 $5,484,931 $3,899,486 $678,825 $29,304
General
Total Capital Projects Funded From Rates $13,501,250 $2,301,482 $1,107,223 $5,484,931 $3,899,486 $678,825 $29,304
Revenue Requirement Before Transfers and Other Revenue
Other Contributions
Transfers from Reserves and Allowances for Unspent Budget ‐$17,870,017 ‐$2,805,572 ‐$1,337,276 ‐$6,068,757 ‐$6,845,900 ‐$593,410 ‐$219,102
General Fund Transfer $12,101,000 $1,864,587 $1,021,317 $4,412,352 $3,588,443 $574,072 $640,229
Total Other Contributions ‐$5,769,017 ‐$940,985 ‐$315,959 ‐$1,656,404 ‐$3,257,457 ‐$19,337 $421,126
Revenue Requirement Before Reserve Transfers and Other $148,740,905 $25,015,066 $12,021,959 $51,496,843 $52,147,301 $5,326,895 $2,732,842
Revenue Req. Before Taxes, Reserve Transfers and Other R $148,740,905 $25,015,066 $12,021,959 $51,496,843 $52,147,301 $5,326,895 $2,732,842
Other Revenues
Forfeited Deposits
Misc. Service Revenues $167,200 $33,748 $16,102 $57,531 $43,914 $6,338 $9,567
Rent ‐ Electric Properties
Misc. Revenue (Other) $2,507,700 $506,162 $241,506 $862,858 $658,631 $95,059 $143,484
Transfer Credits $135,386 $27,327 $13,038 $46,584 $35,558 $5,132 $7,746
Low Hydro Transfers
Dividends from Affiliates, Interest
Other Revenue
Income (Loss) from Equity Investments $198,500 $40,066 $19,117 $68,301 $52,135 $7,525 $11,358
Street Light Revenue
Last Updated: 3/10/2016 1:16 PM Schedule 3.4 Page 3 of 4
Prepared By EES Consulting, Inc.
FERC Account
421&429
446.00
XXXX
City of Palo Alto ‐ 100% Demand
Allocation Date
2017
Total
Expenses
Operation & Maintenance Expense Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7City Accounts E‐18
Street/Traffic
Lights Total Check
REVENUE REQUIREMENT COST ALLOCATION
BY CUSTOMER
Schedule 3.4
Traffic Signal Transfer from General Fund $233,984 $233,984
Green Power $45,085 $7,159 $3,296 $15,017 $18,157 $1,368 $89
Surplus Energy Revenues $5,084,054 $807,316 $371,664 $1,693,418 $2,047,438 $154,209 $10,010
Total Other Revenues $8,382,909 $1,423,505 $665,546 $2,747,444 $2,860,047 $269,995 $416,373
REVENUE REQUIREMENT for COST ALLOCATION $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367
Last Updated: 3/10/2016 1:16 PM Schedule 3.4 Page 4 of 4
Prepared By EES Consulting, Inc.
FERC Account
555.70
555.71
555.72
555.73
555.74
555.75
555.76
555.77
555.78
555.50
555.60
XXXX
XXXX
555.20
555.30
555.40
555.45
580.00
581.00
582.00
583.00
584.00
585.00
586.00
587.00
588.00
589.00
590.00
591.00
592.00
City of Palo Alto ‐ 100% Demand
Allocation Date
2016
Total
Expenses
Operation & Maintenance Expense Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7 City Accounts E‐18
Street/Traffic
Lights Total Check
Power Purchases
Western Power Purchases
Contra Surplus Energy
NCPA Pooling
NCPA Facilities
Local Capacity Purchase
Load Advance
Renewable Energy
Carbon Neutral Purchases (REC)
Market Power Purchases
OTHER RESOURCES
Demand Side Renewable Energy
Alt Resources Renewable Energy DSM
Calaveras O&M
Transmission/Ancillary Services Purchases
Transmission Costs
Other
Salaries & Benefits ‐ Resource Mgmt
Carbon Allowance Revenues
General Expense (Resource Mgmt)
Allocated G&A
Total Purchased Power
Total Production
Distribution
Op. Supervision & Engineering
Load Dispatching
Line and Station Expenses
Overhead Lines
Underground Lines
Street Lighting & Signal System $869,624 $869,624
Meters
Customer Installations
Misc. Distribution
Rents
Maint. Supervision & Engineering
Maint. of Structures
Maint. of Station Equipment
REVENUE REQUIREMENT COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 3.5
Last Updated: 3/10/2016 1:16 PM Schedule 3.5 Page 1 of 4
Prepared By EES Consulting, Inc.
FERC Account
592.10
593.00
594.00
594.10
595.00
595.00
596.00
597.00
598.00
598.10
XXXX
XXXX
901/907/911
902.00
903.00
904.00
905.00
906.00
907.00
908.00
910.00
912.00
913.00
916.00
917.00
906.10
906.20
906.30
920.00
921.00
922.00
City of Palo Alto ‐ 100% Demand
Allocation Date
2016
Total
Expenses
Operation & Maintenance Expense Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7 City Accounts E‐18
Street/Traffic
Lights Total Check
REVENUE REQUIREMENT COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 3.5
Maint. of Structures and Equipment
Maint. of Overhead Lines
Maint. Of Underground Lines
Maint. of Lines
Maint. of Line Transformers
Maint. of Line Transformers ‐ Underground
Maint. of Street Lighting & Signal System $198,001 $198,001
Maint. of Meters
Maint. of Misc. Distribution Plant
Communication O&M
Other
Other
Total Distribution $1,067,625 $1,067,625
Total Operation & Maintenance $1,067,625 $1,067,625
Customer Service, Accounts, & Sales
Supervision
Meter Reading
Customer Records Collection
Uncollectable Accounts
Misc. Customer Accounts
Customer Service & Information
Customer Communication & Education
Customer Assistance
Misc. Customer Service & Information
Demonstrating & Selling
Advertising
Misc. Sales Expenses
Sales Expenses
Key Accounts $312,784 $125,113 $187,670
Energy Efficiency & DSM
Low Income Residential Energy Assistance Program
Total Customer Service, Accounts & Sales $312,784 $125,113 $187,670
Total O&M w/o Purchased Power Supply & A&G $1,380,408 $125,113 $187,670 $1,067,625
Administrative & General
Administrative & General Salaries $378,289 $34,286 $51,429 $292,574
Office Supplies $2,647 $240 $360 $2,047
Administrative Transfer ‐ Credit
Last Updated: 3/10/2016 1:16 PM Schedule 3.5 Page 2 of 4
Prepared By EES Consulting, Inc.
FERC Account
923.00
924.00
925.00
926.00
927.00
928.00
929.00
930.10
930.20
930.30
931.00
932.00
933.00
935.00
408.00
450.00
451.00
City of Palo Alto ‐ 100% Demand
Allocation Date
2016
Total
Expenses
Operation & Maintenance Expense Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7 City Accounts E‐18
Street/Traffic
Lights Total Check
REVENUE REQUIREMENT COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 3.5
Outside Services $35,173 $3,188 $4,782 $27,204
Property Insurance
Injuries and Damages $783 $71 $107 $606
Employee Pension & Benefits $82,393 $7,468 $11,202 $63,724
Franchise Requirements
Regulatory Expense
Duplicate Charge ‐ Credit
General Advertising
Misc. General Expense $139,501 $12,644 $18,965 $107,892
Environmental $5,561 $504 $756 $4,301
Rents $360,294 $32,655 $48,983 $278,656
Maint. of General Plant & Communication Equipment
Transportation
Maintenance of General Plant
Total Administrative & General $1,004,642 $91,056 $136,584 $777,003
Total O&M plus A&G $2,385,050 $216,169 $324,254 $1,844,627
Taxes
Property Tax
Total Taxes
Capital Projects Funded From Rates
Production
Transmission
Distribution
General
Total Capital Projects Funded From Rates
Revenue Requirement Before Transfers and Other Revenue
Other Contributions
Transfers from Reserves and Allowances for Unspent Budget ‐$184,761 ‐$184,761
General Fund Transfer $611,467 $611,467
Total Other Contributions $426,706 $426,706
Revenue Requirement Before Reserve Transfers and Other $2,996,517 $216,169 $324,254 $2,456,094
Revenue Req. Before Taxes, Reserve Transfers and Other Re $2,996,517 $216,169 $324,254 $2,456,094
Other Revenues
Forfeited Deposits
Misc. Service Revenues $12,057 $1,093 $1,639 $9,325
Last Updated: 3/10/2016 1:16 PM Schedule 3.5 Page 3 of 4
Prepared By EES Consulting, Inc.
FERC Account
454.00
456.00
457.00
458.00
419&424
449.00
415&416
444.20
421&429
446.00
XXXX
City of Palo Alto ‐ 100% Demand
Allocation Date
2016
Total
Expenses
Operation & Maintenance Expense Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7 City Accounts E‐18
Street/Traffic
Lights Total Check
REVENUE REQUIREMENT COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 3.5
Rent ‐ Electric Properties
Misc. Revenue (Other)$180,840 $16,390 $24,586 $139,864
Transfer Credits $9,763 $885 $1,327 $7,551
Low Hydro Transfers
Dividends from Affiliates, Interest
Other Revenue
Income (Loss) from Equity Investments $14,315 $1,297 $1,946 $11,071
Street Light Revenue
Traffic Signal Transfer from General Fund $233,984 $233,984
Green Power
Surplus Energy Revenues
Total Other Revenues $451,074 $19,666 $29,498 $401,910
REVENUE REQUIREMENT for COST ALLOCATION $2,360,683 $196,504 $294,755 $1,869,424
Last Updated: 3/10/2016 1:16 PM Schedule 3.5 Page 4 of 4
Prepared By EES Consulting, Inc.City of Palo Alto
INPUT RATE BASE
Schedule 4.1
Year Classification
2015 & Allocation
Cost, $ Function Factor Classification & Allocation Method
FERC Account
Intangible Plant
301.00 Organization SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
302.00 Franchise and Consents SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
303.00 Miscellaneous Intangible Plant SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
Total Intangible Plant
Distribution Plant
360.00 Land & Rights DNCPPNon‐Coincident Peak ‐ Primary
361.00 Structures & Improvements $4,384,759 D NCPP Non‐Coincident Peak ‐ Primary
362.00 Station Equipment ‐ Distribution $40,394,851 D NCPP Non‐Coincident Peak ‐ Primary
363.00 Storage & Battery Equipment DNCPPNon‐Coincident Peak ‐ Primary
364.00 Poles, Towers, & Fixtures $29,237,542 D 100%DP Demand Only ‐ Poles, Towers & Fixtures (100% Demand)
365.00 Overhead Conductors & Devices $18,614,589 D 100%DC Demand Only ‐ Overhead and Underground Conduit (100% Demand)
366.00 Underground Conduit $28,600,165 D 100%DC Demand Only ‐ Overhead and Underground Conduit (100% Demand)
367.00 Underground Conductors & Devices $61,209,198 D 100%DC Demand Only ‐ Overhead and Underground Conduit (100% Demand)
368.00 Line Transformers $19,221,468 D 100%DT Demand Only‐ Transformers (100% Demand)
369.00 Services $45,628,911 D SERV Services
370.00 Meters $4,787,766 D CUSTW Customers Weighted for Accounting/Metering
371.00 Installation on Customer Premises DCUSTMCustomers Weighted for Meters and Services
372.00 Leased Property on Cust. Premises DCUSTMCustomers Weighted for Meters and Services
373.00 Street Lights and Signal Systems $22,284,499 D DA1 Direct Assignment for Streetlights
Total Distribution Plant $274,363,748
Total Transmission & Distribution $274,363,748
General Plant
389.00 Land & Land Rights SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
390.00 Structures & Improvements SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
391.00 Office Furniture & Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
392.00 Transportation Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
393.00 Stores Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
394.00 Tools, Shop, & Garage Equipment $2,593,795 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
395.00 Laboratory Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
396.00 Power Operated Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
397.00 Communication Equipment $1,865,281 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
398.00 Misc. Equipment $18,977,780 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
399.00 Other Tangible Property SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
Total General Plant $23,436,856
Total Plant Before General Plant & Intangible $274,363,748
Total Gross Plant in Service $297,800,603
Last Updated: 3/10/2016 1:16 PM Schedule 4.1 Page 1 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
INPUT RATE BASE
Schedule 4.1
Year Classification
2015 & Allocation
Cost, $ Function Factor Classification & Allocation Method
Less: Accumulated Depreciation
Intangible Plant PRBIGOn the Basis of Intangible Plant Rate Base
Distribution Plant $131,788,193 D RBD‐ST As Distribution Ratebase DA Street Lighting
General Plant SS RBGP On the Basis of General Plant Rate Base
Misc. Plant SS RBGP On the Basis of General Plant Rate Base
Total Accumulated Depreciation $131,788,193
Total Net Plant $166,012,410
Working Capital
90 Days of Non Power Supply O&M $8,155,067 SS OMWOP On the Basis of O&M (w/o Purch. Power Supply)
90 Days of Power Supply Cost $22,207,889 POMPOn the Basis of Purchased Power O&M
Total Working Capital $30,362,956
TOTAL RATE BASE $196,375,366
Construction Work In Progress (CWIP)
Distribution Plant $11,486,367 D RBD On the Basis of Distribution Rate Base
Services DRBDOn the Basis of Distribution Rate Base
General Plant SS RBGP On the Basis of General Plant Rate Base
Other SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
Total Construction Work In Progress $11,486,367
TOTAL RATE BASE plus Construction Work In Progress $207,861,733
Last Updated: 3/10/2016 1:16 PM Schedule 4.1 Page 2 of 2
Prepared By EES Consulting, Inc.
FERC Account
301.00
302.00
303.00
360.00
361.00
362.00
363.00
364.00
365.00
366.00
367.00
368.00
369.00
370.00
371.00
372.00
373.00
389.00
390.00
391.00
392.00
393.00
394.00
395.00
396.00
397.00
398.00
399.00
City of Palo Alto ‐ 100% Demand
Direct Direct
Total Demand Energy Demand Energy Assignment Demand Customer Assignment
Account Description Rate Base PD PE TD TE TDA DD DC DDA Total Check
Intangible Plant
Organization
Franchise and Consents
Miscellaneous Intangible Plant
Total Intangible Plant
Distribution Plant
Land & Rights
Structures & Improvements $4,384,759 $4,384,759
Station Equipment ‐ Distribution $40,394,851 $40,394,851
Storage & Battery Equipment
Poles, Towers, & Fixtures $29,237,542 $29,237,542
Overhead Conductors & Devices $18,614,589 $18,614,589
Underground Conduit $28,600,165 $28,600,165
Underground Conductors & Devices $61,209,198 $61,209,198
Line Transformers $19,221,468 $19,221,468
Services $45,628,911 $45,628,911
Meters $4,787,766 $4,787,766
Installation on Customer Premises
Leased Property on Cust. Premises
Street Lights and Signal Systems $22,284,499 $22,284,499
Total Distribution Plant $274,363,748 $201,662,571 $50,416,678 $22,284,499
Total Transmission & Distribution $274,363,748 $201,662,571 $50,416,678 $22,284,499
General Plant
Land & Land Rights
Structures & Improvements
Office Furniture & Equipment
Transportation Equipment
Stores Equipment
Tools, Shop, & Garage Equipment $2,593,795 $1,906,488 $476,632 $210,674
Laboratory Equipment
Power Operated Equipment
Communication Equipment $1,865,281 $1,371,017 $342,761 $151,503
Misc. Equipment $18,977,780 $13,949,029 $3,487,329 $1,541,422
Other Tangible Property
Total General Plant $23,436,856 $17,226,534 $4,306,722 $1,903,599
Total Plant Before General Plant & Intangible $274,363,748 $201,662,571 $50,416,678 $22,284,499
Total Gross Plant in Service $297,800,603 $218,889,106 $54,723,400 $24,188,098
Less: Accumulated Depreciation
Intangible Plant
Distribution Plant $131,788,193 $85,253,936 $30,734,813 $15,799,444
RATE BASE FOR COST ALLOCATION
DistributionProduction Transmission
FUNCTIONALIZATION AND CLASSIFICATION
Schedule 4.2
Last Updated: 3/10/2016 1:16 PM Schedule 4.2 Page 1 of 2
Prepared By EES Consulting, Inc.
City of Palo Alto ‐ 100% Demand
Direct Direct
Total Demand Energy Demand Energy Assignment Demand Customer Assignment
Account Description Rate Base PD PE TD TE TDA DD DC DDA Total Check
RATE BASE FOR COST ALLOCATION
DistributionProduction Transmission
FUNCTIONALIZATION AND CLASSIFICATION
Schedule 4.2
General Plant
Misc. Plant
Total Accumulated Depreciation $131,788,193 $85,253,936 $30,734,813 $15,799,444
Total Net Plant $166,012,410 $133,635,170 $23,988,587 $8,388,654
Working Capital
90 Days of Non Power Supply O&M $8,155,067 $1,160,441 $3,968,147 $2,438,384 $588,095
90 Days of Power Supply Cost $22,207,889 $1,254,278 $20,953,611
Total Working Capital $30,362,956 $1,254,278 $22,114,052 $3,968,147 $2,438,384 $588,095
TOTAL RATE BASE $196,375,366 $1,254,278 $22,114,052 $137,603,317 $26,426,971 $8,976,748
Construction Work In Progress (CWIP)
Distribution Plant $11,486,367 $8,442,698 $2,110,718 $932,951
Services
General Plant
Other
Total Construction Work In Progress $11,486,367 $8,442,698 $2,110,718 $932,951
TOTAL RATE BASE plus Construction Work In Progress $207,861,733 $1,254,278 $22,114,052 $146,046,015 $28,537,688 $9,909,699
Last Updated: 3/10/2016 1:16 PM Schedule 4.2 Page 2 of 2
Prepared By EES Consulting, Inc.
FERC Account
301.00
302.00
303.00
360.00
361.00
362.00
363.00
364.00
365.00
366.00
367.00
368.00
369.00
370.00
371.00
372.00
373.00
389.00
390.00
391.00
392.00
393.00
394.00
395.00
396.00
397.00
398.00
399.00
City of Palo Alto ‐ 100% Demand
Account Description Total Rate Base Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights Total Check
Intangible Plant
Organization
Franchise and Consents
Miscellaneous Intangible Plant
Total Intangible Plant
Distribution Plant
Land & Rights
Structures & Improvements $4,384,759 $663,540 $430,706 $1,553,226 $1,506,995 $217,339 $12,952
Station Equipment ‐ Distribution $40,394,851 $6,112,901 $3,967,903 $14,309,190 $13,883,284 $2,002,252 $119,322
Storage & Battery Equipment
Poles, Towers, & Fixtures $29,237,542 $4,424,479 $2,871,944 $10,356,902 $10,048,634 $1,449,217 $86,365
Overhead Conductors & Devices $18,614,589 $2,816,922 $1,828,473 $6,593,902 $6,397,638 $922,669 $54,985
Underground Conduit $28,600,165 $4,328,026 $2,809,335 $10,131,122 $9,829,575 $1,417,625 $84,482
Underground Conductors & Devices $61,209,198 $9,262,709 $6,012,453 $21,682,318 $21,036,955 $3,033,957 $180,805
Line Transformers $19,221,468 $2,892,953 $1,877,825 $6,771,878 $6,674,768 $947,573 $56,470
Services $45,628,911 $9,196,894 $1,115,240 $26,148,249 $6,580,910 $2,587,618
Meters $4,787,766 $2,084,402 $758,280 $1,634,369 $260,252 $50,381 $82
Installation on Customer Premises
Leased Property on Cust. Premises
Street Lights and Signal Systems $22,284,499 $22,284,499
Total Distribution Plant $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962
Total Transmission & Distribution $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962
General Plant
Land & Land Rights
Structures & Improvements
Office Furniture & Equipment
Transportation Equipment
Stores Equipment
Tools, Shop, & Garage Equipment $2,593,795 $395,009 $204,885 $937,644 $720,563 $119,389 $216,304
Laboratory Equipment
Power Operated Equipment
Communication Equipment $1,865,281 $284,063 $147,340 $674,290 $518,180 $85,857 $155,551
Misc. Equipment $18,977,780 $2,890,124 $1,499,066 $6,860,375 $5,272,080 $873,524 $1,582,610
Other Tangible Property
RATE BASE COST ALLOCATION
CLASSIFICATION BY CUSTOMER
Schedule 4.3
Last Updated: 3/10/2016 1:16 PM Schedule 4.3 Page 1 of 2
Prepared By EES Consulting, Inc.
FERC Account
City of Palo Alto ‐ 100% Demand
Account Description Total Rate Base Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights Total Check
RATE BASE COST ALLOCATION
CLASSIFICATION BY CUSTOMER
Schedule 4.3
Total General Plant $23,436,856 $3,569,196 $1,851,291 $8,472,309 $6,510,824 $1,078,770 $1,954,465
Total Plant Before General Plant & Intangible $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962
Total Gross Plant in Service $297,800,603 $45,352,022 $23,523,450 $107,653,467 $82,729,835 $13,707,402 $24,834,427
Less: Accumulated Depreciation
Intangible Plant
Distribution Plant $131,788,193 $19,771,944 $9,512,109 $47,120,845 $33,500,340 $5,831,760 $16,051,195
General Plant
Misc. Plant
Total Accumulated Depreciation $131,788,193 $19,771,944 $9,512,109 $47,120,845 $33,500,340 $5,831,760 $16,051,195
Total Net Plant $166,012,410 $25,580,078 $14,011,342 $60,532,622 $49,229,494 $7,875,642 $8,783,232
Working Capital
90 Days of Non Power Supply O&M $8,155,067 $1,646,044 $785,379 $2,806,024 $2,141,875 $309,133 $466,613
90 Days of Power Supply Cost $22,207,889 $3,494,805 $1,654,095 $7,451,402 $8,870,025 $695,414 $42,148
Total Working Capital $30,362,956 $5,140,849 $2,439,473 $10,257,426 $11,011,900 $1,004,547 $508,761
TOTAL RATE BASE $196,375,366 $30,720,927 $16,450,815 $70,790,048 $60,241,394 $8,880,189 $9,291,993
Construction Work In Progress (CWIP)
Distribution Plant $11,486,367 $1,749,258 $907,315 $4,152,266 $3,190,945 $528,704 $957,880
Services
General Plant
Other
Total Construction Work In Progress $11,486,367 $1,749,258 $907,315 $4,152,266 $3,190,945 $528,704 $957,880
TOTAL RATE BASE plus Construction Work In Progress $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874
Last Updated: 3/10/2016 1:16 PM Schedule 4.3 Page 2 of 2
Prepared By EES Consulting, Inc.
FERC Account
301.00
302.00
303.00
360.00
361.00
362.00
363.00
364.00
365.00
366.00
367.00
368.00
369.00
370.00
371.00
372.00
373.00
389.00
390.00
391.00
392.00
393.00
394.00
395.00
396.00
397.00
398.00
399.00
City of Palo Alto ‐ 100% Demand
Account Description Total Rate Base Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights Total Check
Intangible Plant
Organization
Franchise and Consents
Miscellaneous Intangible Plant
Total Intangible Plant
Distribution Plant
Land & Rights
Structures & Improvements
Station Equipment ‐ Distribution
Storage & Battery Equipment
Poles, Towers, & Fixtures
Overhead Conductors & Devices
Underground Conduit
Underground Conductors & Devices
Line Transformers
Services
Meters
Installation on Customer Premises
Leased Property on Cust. Premises
Street Lights and Signal Systems $22,284,499 $22,284,499
Total Distribution Plant $22,284,499 $22,284,499
Total Transmission & Distribution $22,284,499 $22,284,499
General Plant
Land & Land Rights
Structures & Improvements
Office Furniture & Equipment
Transportation Equipment
Stores Equipment
Tools, Shop, & Garage Equipment $210,674 $210,674
Laboratory Equipment
Power Operated Equipment
Communication Equipment $151,503 $151,503
Misc. Equipment $1,541,422 $1,541,422
Other Tangible Property
RATE BASE COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 4.4
Last Updated: 3/10/2016 1:16 PM Schedule 4.4 Page 1 of 2
Prepared By EES Consulting, Inc.
FERC Account
City of Palo Alto ‐ 100% Demand
Account Description Total Rate Base Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights Total Check
RATE BASE COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 4.4
Total General Plant $1,903,599 $1,903,599
Total Plant Before General Plant & Intangible $22,284,499 $22,284,499
Total Gross Plant in Service $24,188,098 $24,188,098
Less: Accumulated Depreciation
Intangible Plant
Distribution Plant $15,799,444 $15,799,444
General Plant
Misc. Plant
Total Accumulated Depreciation $15,799,444 $15,799,444
Total Net Plant $8,388,654 $8,388,654
Working Capital
90 Days of Non Power Supply O&M $588,095 $53,302 $79,953 $454,840
90 Days of Power Supply Cost
Total Working Capital $588,095 $53,302 $79,953 $454,840
TOTAL RATE BASE $8,976,748 $53,302 $79,953 $8,843,493
Construction Work In Progress (CWIP)
Distribution Plant $932,951 $932,951
Services
General Plant
Other
Total Construction Work In Progress $932,951 $932,951
TOTAL RATE BASE plus Construction Work In Progress $9,909,699 $53,302 $79,953 $9,776,444
Last Updated: 3/10/2016 1:16 PM Schedule 4.4 Page 2 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Classification Factors
Total %
Allocated
Demand Energy
Direct
Assignment Demand Energy
Direct
Assignment Demand Energy Customer
Direct
Assignment
PD PE PDA TD TE TDA DD DE DC DDA
CP12 100.0% 100.0% 100.0%100.0%
NCPP 100.0% 100.0% 100.0%100.0%
NCPS 100.0% 100.0% 100.0%100.0%
kWh 100.0% 100.0% 100.0%100.0%
CUST 100.0%100.0%
CUSTW 100.0%100.0%
CUSTM 100.0%100.0%
CUSTMR 100.0%100.0%
100%DP 100.0%100.0%
100%DC 100.0%100.0%
100%DT 100.0%100.0%
DA1 100.0% 100.0%
DA2 100.0% 100.0%
RBG
RBD 73.5% 18.4% 8.1%100.0%
RBGP 73.5% 18.4% 8.1%100.0%
RBGP‐P 73.5% 18.4% 8.1%100.0%
RBGP‐T 73.5% 18.4% 8.1%100.0%
RBGP‐D 73.5% 18.4% 8.1%100.0%
RBSE 100.0%100.0%
RBOH 100.0%100.0%
RBUG 100.0%100.0%
RBTR 100.0%100.0%
OM 4.9% 82.3% 9.0% 2.7% 1.0%100.0%
OM‐P 4.9% 82.3% 9.0% 2.7% 1.0%100.0%
OM‐T 4.9% 82.3% 9.0% 2.7% 1.0%100.0%
OM‐D 4.9% 82.3% 9.0% 2.7% 1.0%100.0%
OMAG 14.2% 48.7% 29.9% 7.2%100.0%
OMAG‐P 14.2% 48.7% 29.9% 7.2%100.0%
OMAG‐T 14.2% 48.7% 29.9% 7.2%100.0%
OMAG‐D 14.2% 48.7% 29.9% 7.2%100.0%
GPLT 73.5% 18.4% 8.1%100.0%
GPLT‐P 73.5% 18.4% 8.1%100.0%
GPLT‐T 73.5% 18.4% 8.1%100.0%
Production Transmission Distribution
CLASSIFICATION and ALLOCATION BY FUNCTION
Schedule 6.1
Last Updated: 3/10/2016 1:16 PM Schedule 6.1 Page 1 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Classification Factors
Total %
Allocated
Demand Energy
Direct
Assignment Demand Energy
Direct
Assignment Demand Energy Customer
Direct
Assignment
PD PE PDA TD TE TDA DD DE DC DDA
Production Transmission Distribution
CLASSIFICATION and ALLOCATION BY FUNCTION
Schedule 6.1
GPLT‐D 73.5% 18.4% 8.1%100.0%
NETPLT 80.5% 14.4% 5.1%100.0%
NETPLT‐P 80.5% 14.4% 5.1%100.0%
NETPLT‐T 80.5% 14.4% 5.1%100.0%
NETPLT‐D 80.5% 14.4% 5.1%100.0%
OMP 5.6% 94.4%100.0%
OMWOP 14.2% 48.7% 29.9% 7.2%100.0%
OMWOP‐P 14.2% 48.7% 29.9% 7.2%100.0%
OMWOP‐T 14.2% 48.7% 29.9% 7.2%100.0%
OMWOP‐D 14.2% 48.7% 29.9% 7.2%100.0%
WEST 16.0% 84.0%100.0%
REN 3.2% 96.8%100.0%
CALA 7.0% 93.0%100.0%
CREDIT 100.0% 100.0%
CUST SERV 100.0% 100.0%
SERV 100.0% 100.0%
RBD‐ST 64.7% 23.3% 12.0% 100.0%
RBD‐NoDA 73.5% 26.5% 100.0%
DSRE 100.0%100.0%
DSMEE 100.0%100.0%
Last Updated: 3/10/2016 1:16 PM Schedule 6.1 Page 2 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Test Year: 2016
Classification Factors Total Allocated Residential E‐1
Small Non‐residential
E‐2
Medium Non‐
residential E‐4
Large Non‐residential
E‐7City Accounts E‐18 Street/Traffic Lights
CP12 100% 11.8% 9.7% 38.2% 36.3% 3.8% 0.1%
NCPP 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
NCPS 100% 15.1% 9.8% 35.2% 34.7% 4.9% 0.3%
kWh
CUST
CUSTW
CUSTM
CUSTMR
100%DP 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
100%DC 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
100%DT 100% 15.1% 9.8% 35.2% 34.7% 4.9% 0.3%
DA1
DA2
RBG
RBD 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
RBGP 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
RBGP‐P
RBGP‐T
RBGP‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
RBSE 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
RBOH 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
RBUG 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
RBTR 100% 15.1% 9.8% 35.2% 34.7% 4.9% 0.3%
OM 100% 14.0% 9.8% 36.4% 35.1% 4.5% 0.2%
OM‐P 100% 11.8% 9.7% 38.2% 36.3% 3.8% 0.1%
OM‐T
OM‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
OMAG 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
OMAG‐P
OMAG‐T
OMAG‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
GPLT 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
GPLT‐P
GPLT‐T
GPLT‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
NETPLT 100.0000% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
NETPLT‐P
NETPLT‐T
NETPLT‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
OMP 100% 11.8% 9.7% 38.2% 36.3% 3.8% 0.1%
CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ DEMAND
Schedule 6.2
Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Demand) Page 1 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Test Year: 2016
Classification Factors Total Allocated Residential E‐1
Small Non‐residential
E‐2
Medium Non‐
residential E‐4
Large Non‐residential
E‐7City Accounts E‐18 Street/Traffic Lights
CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ DEMAND
Schedule 6.2
OMWOP 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
OMWOP‐P
OMWOP‐T
OMWOP‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
WEST 100%11.8% 9.7% 38.2% 36.3% 3.8% 0.1%
REN 100%11.8% 9.7% 38.2% 36.3% 3.8% 0.1%
CALA 100%11.8% 9.7% 38.2% 36.3% 3.8% 0.1%
CREDIT
CUST SERV
SERV
RBD‐ST 100%15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
RBD‐NoDA 100%15.1% 9.8% 35.4% 34.4% 5.0% 0.3%
DSRE
DSMEE
Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Demand) Page 2 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Test Year: 2016
Classification Factors Total Allocated Residential E‐1
Small Non‐residential
E‐2
Medium Non‐
residential E‐4
Large Non‐residential
E‐7City Accounts E‐18 Street/Traffic Lights
CP1
NCPP
NCPS
kWh 100% 15.9% 7.3% 33.3% 40.3% 3.0% 0.2%
CUST
CUSTW
CUSTM
CUSTMR
100%DP
100%DC
100%DT
DA1
DA2
RBG
RBD
RBGP
RBGP‐P
RBGP‐T
RBGP‐D
RBSE
RBOH
RBUG
RBTR
OM 100% 16.0% 7.3% 33.3% 40.2% 3.1% 0.2%
OM‐P 100% 16.0% 7.3% 33.3% 40.2% 3.1% 0.2%
OM‐T
OM‐D
OMAG 100% 15.4% 7.5% 32.2% 41.9% 3.1%
OMAG‐P 100% 15.4% 7.5% 32.2% 41.9% 3.1%
OMAG‐T
OMAG‐D
GPLT
CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ ENERGY
Schedule 6.2
Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Energy) Page 1 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Test Year: 2016
Classification Factors Total Allocated Residential E‐1
Small Non‐residential
E‐2
Medium Non‐
residential E‐4
Large Non‐residential
E‐7City Accounts E‐18 Street/Traffic Lights
CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ ENERGY
Schedule 6.2
GPLT‐P
GPLT‐T
GPLT‐D
NETPLT
NETPLT‐P
NETPLT‐T
NETPLT‐D
OMP 100% 16.0% 7.3% 33.3% 40.2% 3.1% 0.2%
OMWOP 100% 15.4% 7.5% 32.2% 41.9% 3.1%
OMWOP‐P 100% 15.4% 7.5% 32.2% 41.9% 3.1%
OMWOP‐T
OMWOP‐D
WEST 100%15.9% 7.3% 33.3% 40.3% 3.0% 0.2%
REN 100%15.9% 7.3% 33.3% 40.3% 3.0% 0.2%
CALA 100%15.9% 7.3% 33.3% 40.3% 3.0% 0.2%
CREDIT
CUST SERV
SERV
RBD‐ST
RBD‐NoDA
DSRE 100%20.9% 7.3% 31.6% 34.0% 6.2%
DSMEE 100%15.4% 7.5% 32.2% 41.9% 3.1%
Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Energy) Page 2 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Test Year: 2016
Classification Factors Total Allocated Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7 City Accounts E‐18 Street/Traffic Lights
CP1
NCPP
NCPS
kWh
CUST 100% 86.4% 10.5% 2.5% 0.2% 0.4% 0.0%
CUSTW 100% 43.5% 15.8% 34.1% 5.4% 1.1% 0.0%
CUSTM 100% 84.2% 10.2% 4.1% 1.0% 0.4%
CUSTMR 100% 43.5% 15.8% 34.1% 5.4% 1.1%
100%DP
100%DC
100%DT
DA1
DA2
RBG
RBD 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0%
RBGP 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0%
RBGP‐P
RBGP‐T
RBGP‐D
RBSE
RBOH
RBUG
RBTR
OM 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0%
OM‐P
OM‐T
CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ CUSTOMER
Schedule 6.2
Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Customer) Page 1 of 3
Prepared By EES Consulting, Inc.City of Palo Alto
Test Year: 2016
Classification Factors Total Allocated Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7 City Accounts E‐18 Street/Traffic Lights
CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ CUSTOMER
Schedule 6.2
OM‐D
OMAG 100% 35.6% 12.7% 40.0% 8.6% 3.1% 0.0%
OMAG‐P
OMAG‐T
OMAG‐D
GPLT 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0%
GPLT‐P
GPLT‐T
GPLT‐D
NETPLT 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0%
NETPLT‐P
NETPLT‐T
NETPLT‐D
OMP
OMWOP 100% 35.6% 12.7% 40.0% 8.6% 3.1% 0.0%
OMWOP‐P
OMWOP‐T
OMWOP‐D
WEST
REN
CALA
CREDIT 100%35.0% 50.0% 12.0% 1.1% 2.0% 0.0%
CUST SERV 100%60.0% 11.2% 24.2% 3.9% 0.7% 0.0%
SERV 100%20.2% 2.4% 57.3% 14.4% 5.7%
RBD‐ST 100%22.4% 3.7% 55.1% 13.6% 5.2% 0.0%
RBD‐NoDA 100%22.4% 3.7% 55.1% 13.6% 5.2% 0.0%
DSRE
Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Customer) Page 2 of 3
Prepared By EES Consulting, Inc.City of Palo Alto
Test Year: 2016
Classification Factors Total Allocated Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7 City Accounts E‐18 Street/Traffic Lights
CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ CUSTOMER
Schedule 6.2
DSMEE
Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Customer) Page 3 of 3
Prepared By EES Consulting, Inc.City of Palo Alto
Test Year: 2016
Classification Factors Total Allocated Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7 City Accounts E‐18 Street/Traffic Lights
CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ DIRECT ASSIGNMENT
Schedule 6.2
CP12
NCPP
NCPS
kWh
CUST
CUSTW
CUSTM
CUSTMR
100%DP
100%DC
100%DT
DA1 100.0%100.0%
DA2 100.0%40.0% 60.0%
RBG
RBD 100.0%100.0%
RBGP 100.0%100.0%
RBGP‐P
RBGP‐T
RBGP‐D 100.0%100.0%
RBSE
RBOH
RBUG
RBTR
OM 100.0%100.0%
OM‐P
OM‐T
OM‐D 100.0%100.0%
OMAG 100.0% 9.1% 13.6% 77.3%
OMAG‐P
OMAG‐T
Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (DA) Page 1 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Test Year: 2016
Classification Factors Total Allocated Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7 City Accounts E‐18 Street/Traffic Lights
CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ DIRECT ASSIGNMENT
Schedule 6.2
OMAG‐D 100.0% 9.1% 13.6% 77.3%
GPLT 100.0%100.0%
GPLT‐P
GPLT‐T
GPLT‐D 100.0%100.0%
NETPLT 100.0%100.0%
NETPLT‐P
NETPLT‐T
NETPLT‐D 100.0%100.0%
OMP
OMWOP 100.0% 9.1% 13.6% 77.3%
OMWOP‐P
OMWOP‐T
OMWOP‐D 100.0% 9.1% 13.6% 77.3%
WEST
REN
CALA
CREDIT
CUST SERV
SERV
RBD‐ST 100.0%100.0%
RBD‐NoDA
DSRE
DSMEE
Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (DA) Page 2 of 2
Prepared By EES Consulting, Inc.
Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Number of Customers
Jul‐16 29,547 25,565 3,057 742 60 122 1
Aug‐16 29,529 25,535 3,060 743 67 123 1
Sep‐16 28,949 24,968 3,049 741 68 122 1
Oct‐16 29,679 25,666 3,083 741 67 121 1
Nov‐16 28,235 24,269 3,043 733 67 122 1
Dec‐16 29,346 25,359 3,060 741 67 118 1
Jan‐17 29,667 25,656 3,077 742 67 124 1
Feb‐17 29,562 25,555 3,074 740 67 125 1
Mar‐17 29,628 25,625 3,077 738 63 124 1
Apr‐17 29,575 25,562 3,097 724 67 124 1
May‐17 29,109 25,109 3,088 726 64 121 1
Jun‐17 29,245 25,223 3,110 720 67 124 1
Total / Average 29,339 25,341 3,073 736 66 123 1
Customer Charge Revenues Rate: $/Month
Jul‐16
Aug‐16
Sep‐16
Oct‐16
Nov‐16
Dec‐16
Jan‐17
Feb‐17
Mar‐17
Apr‐17
May‐17
Jun‐17
Total
Forecast kWh $34,224,095 $152,705,600 $192,576,637 $15,152,723
Jul‐16 81,963,781 11,794,741 6,137,168 28,465,870 33,062,440 2,345,450 158,112
Aug‐16 82,988,623 11,610,462 6,180,235 29,183,253 33,393,107 2,463,453 158,112
Sep‐16 86,437,570 11,622,595 6,368,684 30,123,313 35,387,793 2,777,073 158,112
Oct‐16 80,883,590 12,244,921 5,947,833 27,818,985 33,033,747 1,679,991 158,112
Nov‐16 83,139,914 11,477,370 5,800,156 27,654,416 34,904,226 3,145,634 158,112
Dec‐16 83,571,051 15,245,758 5,692,051 25,691,547 34,342,286 2,441,297 158,112
Jan‐17 81,058,191 17,174,759 5,896,626 25,403,178 30,208,921 2,216,594 158,112
Feb‐17 76,493,499 14,137,692 5,626,886 24,544,236 29,927,066 2,099,507 158,112
Mar‐17 76,431,249 13,215,351 5,440,633 23,829,508 31,789,551 1,998,094 158,112
Apr‐17 78,235,599 12,070,845 5,767,744 25,582,716 31,404,586 3,251,596 158,112
May‐17 77,298,181 11,257,471 5,828,133 26,002,776 31,644,326 2,407,363 158,112
Jun‐17 81,424,554 11,178,348 5,764,361 26,695,073 35,223,773 2,404,886 158,112
Total / Average 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346
Energy Rates
Flat Rate: Flat Rate $/kWh
Seasonal Rate:Jul $/kWh $0.14045 $0.08171 $0.07808 $0.11479
Aug $/kWh $0.14045 $0.08171 $0.07808 $0.11479
Sep $/kWh $0.14045 $0.08171 $0.07808 $0.11479
Oct $/kWh $0.14045 $0.08171 $0.07808 $0.11479
Nov $/kWh $0.12661 $0.07318 $0.07209 $0.09429
FORECAST OF REVENUES FROM CURRENT RATES
Schedule 7.1
Last Updated: 3/10/2016 1:16 PM Schedule 7.1 Page 1 of 3
Prepared By EES Consulting, Inc.
Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
FORECAST OF REVENUES FROM CURRENT RATES
Schedule 7.1
Dec $/kWh $0.12661 $0.07318 $0.07209 $0.09429
Jan $/kWh $0.12661 $0.07318 $0.07209 $0.09429
Feb $/kWh $0.12661 $0.07318 $0.07209 $0.09429
Mar $/kWh $0.12661 $0.07318 $0.07209 $0.09429
Apr $/kWh $0.12661 $0.07318 $0.07209 $0.09429
May $/kWh $0.14045 $0.08171 $0.07808 $0.11479
Jun $/kWh $0.14045 $0.08171 $0.07808 $0.115
Distribution Charge for $/kWh:
Block Rate:1st Block kWh %54% 100% 100% 100% 100%
2nd Block kWh %25%
3rd Block kWh %21%
4th Block kWh %
1st Block $/kWh $0.09524
2nd Block $/kWh $0.13020
3rd Block $/kWh $0.17399
4th Block $/kWh
Energy Revenues
Jul‐16 $7,457,295 $1,418,634 $861,965 $2,325,946 $2,581,515 $269,234
Aug‐16 $7,539,161 $1,396,470 $868,014 $2,384,564 $2,607,334 $282,780
Sep‐16 $7,835,646 $1,397,929 $894,482 $2,461,376 $2,763,079 $318,780
Oct‐16 $7,353,364 $1,472,780 $835,373 $2,273,089 $2,579,275 $192,846
Nov‐16 $6,951,417 $1,380,462 $734,358 $2,023,750 $2,516,246 $296,602
Dec‐16 $7,140,415 $1,833,712 $720,671 $1,880,107 $2,475,735 $230,190
Jan‐17 $7,058,066 $2,065,726 $746,572 $1,859,005 $2,177,761 $209,003
Feb‐17 $6,564,409 $1,700,437 $712,420 $1,796,147 $2,157,442 $197,963
Mar‐17 $6,502,292 $1,589,501 $688,839 $1,743,843 $2,291,709 $188,400
Apr‐17 $6,624,790 $1,451,843 $730,254 $1,872,143 $2,263,957 $306,593
May‐17 $7,044,391 $1,354,013 $818,561 $2,124,687 $2,470,789 $276,341
Jun‐17 $7,361,684 $1,344,496 $809,605 $2,181,254 $2,750,272 $276,057
Subtotal $85,432,931 $18,406,003 $9,421,113 $24,925,912 $29,635,114 $3,044,789
Surcharge
Total $85,432,931 $18,406,003 $9,421,113 $24,925,912 $29,635,114 $3,044,789
Demand kVa or kW
Jul‐16 183,197 23,739 14,809 70,573 67,108 6,360 607
Aug‐16 182,882 22,903 16,421 70,808 66,460 5,758 531
Sep‐16 175,133 23,449 16,689 68,874 58,881 6,752 488
Oct‐16 186,783 23,195 19,162 69,274 70,362 4,365 425
Nov‐16 178,554 22,134 19,442 66,391 61,535 8,652 399
Dec‐16 173,216 28,614 14,197 60,673 63,551 5,827 354
Jan‐17 161,171 31,766 12,193 58,366 53,142 5,377 327
Feb‐17 158,353 29,053 15,224 57,248 50,947 5,489 392
Mar‐17 171,252 24,715 14,149 58,641 68,420 4,939 386
Apr‐17 168,043 26,611 16,348 61,809 52,799 10,036 439
May‐17 176,488 23,278 15,667 64,005 67,154 5,912 472
Jun‐17 183,618 24,644 16,679 66,944 67,380 7,422 549
Total / Average
Total 2,098,690 304,102 190,983 773,606 747,738 76,890 5,371
Demand Revenues Rate: $/kVa
Last Updated: 3/10/2016 1:16 PM Schedule 7.1 Page 2 of 3
Prepared By EES Consulting, Inc.
Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
FORECAST OF REVENUES FROM CURRENT RATES
Schedule 7.1
Rate: $/kW
Jul‐16 $20.54 $18.97
Aug‐16 $20.54 $18.97
Sep‐16 $20.54 $18.97
Oct‐16 $20.54 $18.97
Nov‐16 $13.84 $11.54
Dec‐16 $13.84 $11.54
Jan‐17 $13.84 $11.54
Feb‐17 $13.84 $11.54
Mar‐17 $13.84 $11.54
Apr‐17 $13.84 $11.54
May‐17 $20.54 $18.97
Jun‐17 $20.54 $18.97
Jul‐16 $2,722,615 $1,449,570 $1,273,045
Aug‐16 $2,715,151 $1,454,405 $1,260,746
Sep‐16 $2,531,627 $1,414,663 $1,116,963
Oct‐16 $2,757,661 $1,422,893 $1,334,768
Nov‐16 $1,628,969 $918,858 $710,112
Dec‐16 $1,573,085 $839,710 $733,375
Jan‐17 $1,421,046 $807,791 $613,255
Feb‐17 $1,380,242 $792,312 $587,930
Mar‐17 $1,601,160 $811,592 $789,568
Apr‐17 $1,464,740 $855,434 $609,306
May‐17 $2,588,557 $1,314,653 $1,273,904
Jun‐17 $2,653,220 $1,375,027 $1,278,194
Total $25,038,074 $13,456,909 $11,581,165
Total Revenues Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 $10,179,910 $1,418,634 $861,965 $3,775,517 $3,854,560 $269,234
Aug‐16 $10,254,312 $1,396,470 $868,014 $3,838,969 $3,868,080 $282,780
Sep‐16 $10,367,272 $1,397,929 $894,482 $3,876,039 $3,880,042 $318,780
Oct‐16 $10,111,025 $1,472,780 $835,373 $3,695,982 $3,914,043 $192,846
Nov‐16 $8,580,387 $1,380,462 $734,358 $2,942,608 $3,226,357 $296,602
Dec‐16 $8,713,500 $1,833,712 $720,671 $2,719,818 $3,209,110 $230,190
Jan‐17 $8,479,112 $2,065,726 $746,572 $2,666,796 $2,791,016 $209,003
Feb‐17 $7,944,651 $1,700,437 $712,420 $2,588,459 $2,745,372 $197,963
Mar‐17 $8,103,452 $1,589,501 $688,839 $2,555,435 $3,081,277 $188,400
Apr‐17 $8,089,530 $1,451,843 $730,254 $2,727,577 $2,873,263 $306,593
May‐17 $9,632,949 $1,354,013 $818,561 $3,439,340 $3,744,693 $276,341
Jun‐17 $10,014,905 $1,344,496 $809,605 $3,556,281 $4,028,466 $276,057
Subtotal $110,471,004 $18,406,003 $9,421,113 $38,382,821 $41,216,279 $3,044,789
Surcharge $60,477 $60,477
Total $110,531,481 $18,406,003 $9,421,113 $38,382,821 $41,216,279 $3,044,789 $60,477
Actual Revenue 2015 $110,687,581.09 $18,318,169 $9,422,028 $37,253,029 $42,605,849 $3,028,030 $60,477
difference 0.1% 0.5% 0.0% 2.9%‐3.4% 0.6%
Last Updated: 3/10/2016 1:16 PM Schedule 7.1 Page 3 of 3
Prepared By EES Consulting, Inc.City of Palo Alto
Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Current kWh Forecast:
2014 952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346
Forecast Year: 2016 953,615,752 152,522,421 70,565,310 321,517,940 377,834,163 29,278,572 1,897,346
Forecast Year: 2017 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346
Forecast Year: 2018 972,609,590 153,080,810 70,473,757 321,100,795 396,816,297 29,240,585 1,897,346
Forecast Year: 2019 973,106,669 152,786,206 70,338,130 320,482,834 398,417,843 29,184,311 1,897,346
Forecast Year: 2020 971,881,787 152,593,513 70,249,420 320,078,644 397,915,361 29,147,504 1,897,346
Current Customer Forecast:
2014 29,339 25,341 3,073 736 66 123 1
Forecast Year: 2016 29,356 25,358 3,073 736 66 123 1
Forecast Year: 2017 29,319 25,321 3,073 736 66 123 1
Forecast Year: 2018 29,339 25,341 3,073 736 66 123 1
Forecast Year: 2019 29,339 25,341 3,073 736 66 123 1
Forecast Year: 2020 29,339 25,341 3,073 736 66 123 1
Forecast Rate Class Customer Count Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 29,547 25,565 3,057 742 60 122 1
Aug‐16 29,529 25,535 3,060 743 67 123 1
Sep‐16 28,949 24,968 3,049 741 68 122 1
Oct‐16 29,679 25,666 3,083 741 67 121 1
Nov‐16 28,235 24,269 3,043 733 67 122 1
Dec‐16 29,346 25,359 3,060 741 67 118 1
Jan‐17 29,667 25,656 3,077 742 67 124 1
Feb‐17 29,562 25,555 3,074 740 67 125 1
Mar‐17 29,628 25,625 3,077 738 63 124 1
Apr‐17 29,575 25,562 3,097 724 67 124 1
May‐17 29,109 25,109 3,088 726 64 121 1
Jun‐17 29,245 25,223 3,110 720 67 124 1
Total Average Forecast Customers 29,339 25,341 3,073 736 66 123 1
Schedule 8.1
FORECAST CUSTOMERS AND ENERGY SALES
Last Updated: 3/10/2016 1:16 PM Schedule 8.1 Page 1 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Schedule 8.1
FORECAST CUSTOMERS AND ENERGY SALES
Customer Information Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Weighting Factors for:
Customers Meters & Services 994.00$994.00$1,672.00$4,698.00$ 994.00$‐$
Customer Billing and Collection 1.00 3.00 27.00 48.00 5.00 1.00
Customer Meter Reading 1.00 3.00 27.00 48.00 5.00
Weighted Number of Customers
Customers Meters & Services 29,905,327 25,188,954 3,054,479 1,230,453 309,677 121,765 ‐
Customer Billing and Collection 58,207 25,341 9,219 19,870 3,164 613 1
Customer Meter Reading 58,206 25,341 9,219 19,870 3,164 613 ‐
Provided Services
Power Purchased from Utility*111 1 1 1
Reg & Shaping from Utility*111 1 1 1
Uses Utility Transmission*111 1 1 1
Uses Primary Distribution*111 1 1 1
Uses Secondary Distribution*111 1 1 1
Test Date Forecast Rate Class Sales kWh Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 77,965,899 11,789,582 5,880,488 26,024,709 31,803,107 2,309,901 158,112
Aug‐14 82,987,201 11,330,498 5,895,458 27,361,945 35,773,165 2,468,023 158,112
Sep‐14 87,503,059 11,560,737 6,386,405 29,269,602 37,406,835 2,721,368 158,112
Oct‐14 78,632,817 12,077,193 5,493,428 25,803,870 32,767,071 2,333,143 158,112
Nov‐14 79,700,792 11,607,795 5,456,028 24,942,299 34,971,656 2,564,902 158,112
Dec‐14 80,199,169 15,092,762 5,446,408 24,598,609 32,572,571 2,330,707 158,112
Jan‐15 80,513,170 17,342,158 5,951,986 24,061,704 30,479,098 2,520,112 158,112
Feb‐15 81,389,444 14,606,393 5,799,412 24,244,688 34,041,901 2,538,938 158,112
Mar‐15 71,512,256 12,097,303 5,333,019 22,956,678 28,761,884 2,205,260 158,112
Apr‐15 77,355,465 11,477,709 5,894,120 23,923,508 33,608,313 2,293,703 158,112
May‐15 76,149,464 11,077,484 6,431,015 25,223,376 30,780,866 2,478,611 158,112
Jun‐15 78,772,748 10,806,575 6,516,748 25,521,556 33,382,123 2,387,634 158,112
Total Sales 952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346
Forecast Rate Class Sales kWh Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 81,963,781 11,794,741 6,137,168 28,465,870 33,062,440 2,345,450 158,112
Aug‐16 82,988,623 11,610,462 6,180,235 29,183,253 33,393,107 2,463,453 158,112
Sep‐16 86,437,570 11,622,595 6,368,684 30,123,313 35,387,793 2,777,073 158,112
Oct‐16 80,883,590 12,244,921 5,947,833 27,818,985 33,033,747 1,679,991 158,112
Nov‐16 83,139,914 11,477,370 5,800,156 27,654,416 34,904,226 3,145,634 158,112
Dec‐16 83,571,051 15,245,758 5,692,051 25,691,547 34,342,286 2,441,297 158,112
Jan‐17 81,058,191 17,174,759 5,896,626 25,403,178 30,208,921 2,216,594 158,112
Feb‐17 76,493,499 14,137,692 5,626,886 24,544,236 29,927,066 2,099,507 158,112
Mar‐17 76,431,249 13,215,351 5,440,633 23,829,508 31,789,551 1,998,094 158,112
Apr‐17 78,235,599 12,070,845 5,767,744 25,582,716 31,404,586 3,251,596 158,112
May‐17 77,298,181 11,257,471 5,828,133 26,002,776 31,644,326 2,407,363 158,112
Jun‐17 81,424,554 11,178,348 5,764,361 26,695,073 35,223,773 2,404,886 158,112
Total Sales 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346
Last Updated: 3/10/2016 1:16 PM Schedule 8.1 Page 2 of 2
Prepared By EES Consulting, Inc.City of Palo Alto
Billing Demand ‐ kVa Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 137,681 70,573 67,108
Aug‐16 137,268 70,808 66,460
Sep‐16 127,754 68,874 58,881
Oct‐16 139,636 69,274 70,362
Nov‐16 127,926 66,391 61,535
Dec‐16 124,223 60,673 63,551
Jan‐17 111,508 58,366 53,142
Feb‐17 108,195 57,248 50,947
Mar‐17 127,061 58,641 68,420
Apr‐17 114,608 61,809 52,799
May‐17 131,158 64,005 67,154
Jun‐17 134,324 66,944 67,380
Total 1,521,344 773,606 747,738
Individual Load Factor Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 67% 56% 50% 64% 50% 35%
Aug‐16 68% 51% 58% 80% 58% 40%
Sep‐16 69% 53% 57% 85% 57% 45%
Oct‐16 71% 42% 52% 65% 52% 50%
Nov‐16 72% 41% 50% 76% 50% 55%
Dec‐16 72% 54% 56% 71% 56% 60%
Jan‐17 73% 65% 55% 77% 55% 65%
Feb‐17 72% 55% 57% 90% 57% 60%
Mar‐17 72% 52% 54% 58% 54% 55%
Apr‐17 63% 49% 52% 86% 45% 50%
May‐17 65% 50% 55% 64% 55% 45%
Jun‐17 63% 48% 51% 67% 45% 40%
Individual NCP (kW) Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 183,197 23,739 14,809 70,573 67,108 6,360 607
Aug‐16 182,882 22,903 16,421 70,808 66,460 5,758 531
Sep‐16 175,133 23,449 16,689 68,874 58,881 6,752 488
Oct‐16 186,783 23,195 19,162 69,274 70,362 4,365 425
Nov‐16 178,554 22,134 19,442 66,391 61,535 8,652 399
Dec‐16 173,216 28,614 14,197 60,673 63,551 5,827 354
Jan‐17 161,171 31,766 12,193 58,366 53,142 5,377 327
Feb‐17 158,353 29,053 15,224 57,248 50,947 5,489 392
Mar‐17 171,252 24,715 14,149 58,641 68,420 4,939 386
Apr‐17 168,043 26,611 16,348 61,809 52,799 10,036 439
May‐17 176,488 23,278 15,667 64,005 67,154 5,912 472
Jun‐17 183,618 24,644 16,679 66,944 67,380 7,422 549
Maximum 186,783 31,766 19,442 70,808 70,362 10,036 607
5,371
FORECAST CUSTOMER DEMAND
Schedule 8.2
Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 1 of 5
Prepared By EES Consulting, Inc.City of Palo Alto FORECAST CUSTOMER DEMAND
Schedule 8.2
Group Coincidence Factor Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 95% 95% 85% 91% 90% 100%
Aug‐16 85% 85% 90% 92% 80% 100%
Sep‐16 95% 95% 89% 90% 90% 100%
Oct‐16 95% 95% 87% 86% 90% 100%
Nov‐16 95% 95% 88% 85% 90% 100%
Dec‐16 95% 95% 83% 84% 90% 100%
Jan‐17 85% 85% 83% 89% 80% 100%
Feb‐17 95% 95% 82% 85% 90% 100%
Mar‐17 85% 85% 87% 80% 80% 100%
Apr‐17 95% 95% 86% 82% 95% 100%
May‐17 95% 95% 85% 84% 90% 100%
Jun‐17 95% 95% 86% 84% 95% 100%
Rate Class NCP @ Meter (kW) Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 164,373 22,552 14,069 60,018 61,403 5,724 607
Aug‐16 163,574 19,468 13,958 63,599 61,411 4,606 531
Sep‐16 158,817 22,276 15,855 61,012 53,109 6,077 488
Oct‐16 165,377 22,035 18,204 60,186 60,599 3,928 425
Nov‐16 158,676 21,028 18,470 58,652 52,341 7,787 399
Dec‐16 149,774 27,183 13,487 50,353 53,152 5,245 354
Jan‐17 137,978 27,001 10,364 48,640 47,344 4,301 327
Feb‐17 137,967 27,600 14,463 47,228 43,344 4,940 392
Mar‐17 143,230 21,008 12,027 50,965 54,892 3,951 386
Apr‐17 147,176 25,281 15,531 53,007 43,384 9,534 439
May‐17 153,295 22,115 14,884 54,247 56,257 5,320 472
Jun‐17 160,837 23,411 15,845 57,599 56,381 7,051 549
Maximum 165,377 27,600 18,470 63,599 61,411 9,534 607
Rate Class NCP @ Meter (kW) ‐ Winter Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 164,373 22,552 14,069 60,018 61,403 5,724 607
Aug‐16 163,574 19,468 13,958 63,599 61,411 4,606 531
Sep‐16 158,817 22,276 15,855 61,012 53,109 6,077 488
Oct‐16
Nov‐16
Dec‐16
Jan‐17
Feb‐17
Mar‐17
Apr‐17 147,176 25,281 15,531 53,007 43,384 9,534 439
May‐17 153,295 22,115 14,884 54,247 56,257 5,320 472
Jun‐17 160,837 23,411 15,845 57,599 56,381 7,051 549
Maximum 164,373 25,281 15,855 63,599 61,411 9,534 607
Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 2 of 5
Prepared By EES Consulting, Inc.City of Palo Alto FORECAST CUSTOMER DEMAND
Schedule 8.2
Rate Class NCP @ Meter (kW) ‐ Summer Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16
Aug‐16
Sep‐16
Oct‐16 165,377 22,035 18,204 60,186 60,599 3,928 425
Nov‐16 158,676 21,028 18,470 58,652 52,341 7,787 399
Dec‐16 149,774 27,183 13,487 50,353 53,152 5,245 354
Jan‐17 137,978 27,001 10,364 48,640 47,344 4,301 327
Feb‐17 137,967 27,600 14,463 47,228 43,344 4,940 392
Mar‐17 143,230 21,008 12,027 50,965 54,892 3,951 386
Apr‐17
May‐17
Jun‐17
Maximum 165,377 27,600 18,470 60,186 60,599 7,787 425
Rate Class NCP @ Primary Voltage (kW) Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Line Losses:2.50% 2.50% 2.50% 0.95% 2.50% 2.50%
Jul‐16 167,602 23,130 14,429 61,557 61,992 5,871 623
Aug‐16 166,782 19,967 14,316 65,230 62,000 4,725 545
Sep‐16 162,037 22,847 16,261 62,576 53,619 6,233 501
Oct‐16 168,645 22,600 18,671 61,729 61,180 4,029 436
Nov‐16 161,905 21,567 18,944 60,155 52,843 7,987 410
Dec‐16 152,761 27,880 13,833 51,644 53,662 5,379 363
Jan‐17 140,756 27,694 10,630 49,887 47,798 4,412 335
Feb‐17 140,809 28,308 14,834 48,439 43,760 5,066 402
Mar‐17 146,021 21,547 12,335 52,272 55,418 4,053 396
Apr‐17 150,253 25,929 15,929 54,366 43,800 9,778 450
May‐17 156,323 22,682 15,265 55,638 56,797 5,457 484
Jun‐17 164,056 24,012 16,252 59,076 56,922 7,232 563
Maximum 168,645 28,308 18,944 65,230 62,000 9,778 623
NCP @ Primary Voltage (kW) ‐ Winter Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 167,602 23,130 14,429 61,557 61,992 5,871 623
Aug‐16 166,782 19,967 14,316 65,230 62,000 4,725 545
Sep‐16 162,037 22,847 16,261 62,576 53,619 6,233 501
Oct‐16
Nov‐16
Dec‐16
Jan‐17
Feb‐17
Mar‐17
Apr‐17 150,253 25,929 15,929 54,366 43,800 9,778 450
May‐17 156,323 22,682 15,265 55,638 56,797 5,457 484
Jun‐17 164,056 24,012 16,252 59,076 56,922 7,232 563
Maximum 167,602 25,929 16,261 65,230 62,000 9,778 623
Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 3 of 5
Prepared By EES Consulting, Inc.City of Palo Alto FORECAST CUSTOMER DEMAND
Schedule 8.2
NCP @ Primary Voltage (kW) ‐ Summer Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16
Aug‐16
Sep‐16
Oct‐16 168,645 22,600 18,671 61,729 61,180 4,029 436
Nov‐16 161,905 21,567 18,944 60,155 52,843 7,987 410
Dec‐16 152,761 27,880 13,833 51,644 53,662 5,379 363
Jan‐17 140,756 27,694 10,630 49,887 47,798 4,412 335
Feb‐17 140,809 28,308 14,834 48,439 43,760 5,066 402
Mar‐17 146,021 21,547 12,335 52,272 55,418 4,053 396
Apr‐17
May‐17
Jun‐17
Maximum 168,645 28,308 18,944 61,729 61,180 7,987 436
Rate Class NCP @ Input Voltage (kW) Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Line Losses:0.80% 0.80% 0.80% 0.80% 0.80% 0.80%
Jul‐16 168,954 23,317 14,546 62,054 62,492 5,918 628
Aug‐16 168,127 20,128 14,431 65,756 62,500 4,763 549
Sep‐16 163,344 23,032 16,393 63,081 54,051 6,283 505
Oct‐16 170,005 22,783 18,821 62,227 61,674 4,061 439
Nov‐16 163,210 21,741 19,097 60,641 53,269 8,051 413
Dec‐16 153,993 28,105 13,944 52,061 54,094 5,422 366
Jan‐17 141,891 27,917 10,716 50,289 48,184 4,447 338
Feb‐17 141,944 28,536 14,954 48,829 44,112 5,107 405
Mar‐17 147,199 21,720 12,435 52,693 55,865 4,085 399
Apr‐17 151,465 26,138 16,058 54,804 44,154 9,857 454
May‐17 157,584 22,865 15,388 56,087 57,255 5,501 488
Jun‐17 165,380 24,205 16,383 59,552 57,381 7,290 568
Maximum 170,005 28,536 19,097 65,756 62,500 9,857 628
NCP @ Input Voltage (kW) ‐ Winter Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 168,954 23,317 14,546 62,054 62,492 5,918 628
Aug‐16 168,127 20,128 14,431 65,756 62,500 4,763 549
Sep‐16 163,344 23,032 16,393 63,081 54,051 6,283 505
Oct‐16
Nov‐16
Dec‐16
Jan‐17
Feb‐17
Mar‐17
Apr‐17 151,465 26,138 16,058 54,804 44,154 9,857 454
May‐17 157,584 22,865 15,388 56,087 57,255 5,501 488
Jun‐17 165,380 24,205 16,383 59,552 57,381 7,290 568
Maximum 168,954 26,138 16,393 65,756 62,500 9,857 628
Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 4 of 5
Prepared By EES Consulting, Inc.City of Palo Alto FORECAST CUSTOMER DEMAND
Schedule 8.2
NCP @ Input Voltage (kW) ‐ Summer Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16
Aug‐16
Sep‐16
Oct‐16 170,005 22,783 18,821 62,227 61,674 4,061 439
Nov‐16 163,210 21,741 19,097 60,641 53,269 8,051 413
Dec‐16 153,993 28,105 13,944 52,061 54,094 5,422 366
Jan‐17 141,891 27,917 10,716 50,289 48,184 4,447 338
Feb‐17 141,944 28,536 14,954 48,829 44,112 5,107 405
Mar‐17 147,199 21,720 12,435 52,693 55,865 4,085 399
Apr‐17
May‐17
Jun‐17
Maximum 170,005 28,536 19,097 62,227 61,674 8,051 439
System Coincidence Factor Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 58% 90% 100% 100% 97%
Aug‐16 59% 90% 97% 97% 97%
Sep‐16 50% 97% 98% 98% 97%
Oct‐16 93% 100% 100% 100% 98% 100%
Nov‐16 50% 90% 100% 100% 90% 100%
Dec‐16 58% 90% 100% 100% 90% 100%
Jan‐17 90% 100% 100% 100% 96% 100%
Feb‐17 83% 98% 100% 100% 95% 100%
Mar‐17 60% 90% 100% 100% 97% 100%
Apr‐17 93% 100% 100% 100% 100%
May‐17 76% 100% 100% 100% 97%
Jun‐17 98% 100% 100% 100% 100%
Coincident Peak (CP) @ Input (kW) Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 156,901 13,524 13,091 62,054 62,492 5,741
Aug‐16 153,892 11,875 12,988 63,783 60,625 4,620
Sep‐16 148,481 11,516 15,901 61,945 53,024 6,095
Oct‐16 168,329 21,188 18,821 62,227 61,674 3,980 439
Nov‐16 149,625 10,870 17,187 60,641 53,269 7,246 413
Dec‐16 140,252 16,301 12,550 52,061 54,094 4,880 366
Jan‐17 138,921 25,125 10,716 50,289 48,184 4,269 338
Feb‐17 136,396 23,543 14,654 48,829 44,112 4,852 405
Mar‐17 137,145 13,032 11,191 52,693 55,865 3,963 399
Apr‐17 149,181 24,308 16,058 54,804 44,154 9,857
May‐17 151,443 17,377 15,388 56,087 57,255 5,336
Jun‐17 164,328 23,721 16,383 59,552 57,381 7,290
Total CP Demand ‐ Bottom Up 1,794,894 212,381 174,929 684,965 652,128 68,130 2,361
Peak Month 168,329 21,188 18,821 62,227 61,674 3,980 439
Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 5 of 5
Prepared By EES Consulting, Inc.City of Palo Alto
kWh @ Input Voltage Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 84,221,494 12,197,250 6,346,606 29,437,301 33,651,339 2,425,491 163,508
Aug‐16 85,275,915 12,006,683 6,391,143 30,179,165 33,987,895 2,547,522 163,508
Sep‐16 88,810,020 12,019,229 6,586,023 31,151,306 36,018,110 2,871,844 163,508
Oct‐16 83,104,909 12,662,793 6,150,810 28,768,341 33,622,134 1,737,323 163,508
Nov‐16 85,407,717 11,869,049 5,998,093 28,598,155 35,525,930 3,252,982 163,508
Dec‐16 85,862,734 15,766,037 5,886,299 26,568,301 34,953,981 2,524,609 163,508
Jan‐17 83,331,554 17,760,868 6,097,855 26,270,091 30,746,994 2,292,238 163,508
Feb‐17 78,615,685 14,620,157 5,818,910 25,381,836 30,460,118 2,171,155 163,508
Mar‐17 78,520,925 13,666,341 5,626,301 24,642,717 32,355,777 2,066,281 163,508
Apr‐17 80,393,131 12,482,777 5,964,575 26,455,756 31,963,956 3,362,561 163,508
May‐17 79,419,811 11,641,645 6,027,025 26,890,151 32,207,966 2,489,517 163,508
Jun‐17 83,628,605 11,559,822 5,961,077 27,606,074 35,851,168 2,486,956 163,508
Total Purchases ‐ bottom up 996,592,500 158,252,650 72,854,715 331,949,194 401,345,367 30,228,479 1,962,095
growth in Purchases against Recorded (bottom‐up) 1% 0% 6%‐1% 0%
On‐Peak Energy Use by Percentage Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 66%66% 66% 66% 66% 66% 66%
Aug‐16 66%66% 66% 66% 66% 66% 66%
Sep‐16 66%66% 66% 66% 66% 66% 66%
Oct‐16 66%66% 66% 66% 66% 66% 66%
Nov‐16 66%66% 66% 66% 66% 66% 66%
Dec‐16 66%66% 66% 66% 66% 66% 66%
Jan‐17 66%66% 66% 66% 66% 66% 66%
Feb‐17 66%66% 66% 66% 66% 66% 66%
Mar‐17 66%66% 66% 66% 66% 66% 66%
Apr‐17 66%66% 66% 66% 66% 66% 66%
May‐17 66%66% 66% 66% 66% 66% 66%
Jun‐17 66%66% 66% 66% 66% 66% 66%
Total 66% 66% 66% 66% 66% 66% 66%
On‐Peak kWh @ Input Voltage Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 55,586,186 8,050,185 4,188,760 19,428,619 22,209,884 1,600,824 107,915
Aug‐16 56,282,104 7,924,411 4,218,154 19,918,249 22,432,011 1,681,364 107,915
Sep‐16 58,614,613 7,932,691 4,346,775 20,559,862 23,771,953 1,895,417 107,915
Oct‐16 54,849,240 8,357,443 4,059,535 18,987,105 22,190,609 1,146,633 107,915
Nov‐16 56,369,093 7,833,572 3,958,741 18,874,782 23,447,114 2,146,968 107,915
Dec‐16 56,669,405 10,405,585 3,884,957 17,535,079 23,069,627 1,666,242 107,915
Jan‐17 54,998,825 11,722,173 4,024,584 17,338,260 20,293,016 1,512,877 107,915
Feb‐17 51,886,352 9,649,304 3,840,480 16,752,012 20,103,678 1,432,963 107,915
Mar‐17 51,823,811 9,019,785 3,713,359 16,264,193 21,354,813 1,363,746 107,915
Apr‐17 53,059,467 8,238,633 3,936,619 17,460,799 21,096,211 2,219,290 107,915
May‐17 52,417,075 7,683,486 3,977,836 17,747,499 21,257,257 1,643,081 107,915
Jun‐17 55,194,879 7,629,482 3,934,311 18,220,009 23,661,771 1,641,391 107,915
Total 657,751,050 104,446,749 48,084,112 219,086,468 264,887,943 19,950,796 1,294,983
FORECAST kWh AT INPUT
Schedule 8.3
Last Updated: 3/10/2016 1:16 PM Schedule 8.3 Page 1 of 3
Prepared By EES Consulting, Inc.City of Palo Alto FORECAST kWh AT INPUT
Schedule 8.3
Off‐Peak Energy Use by Percentage Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 34% 34% 34% 34% 34% 34% 34%
Aug‐16 34% 34% 34% 34% 34% 34% 34%
Sep‐16 34% 34% 34% 34% 34% 34% 34%
Oct‐16 34% 34% 34% 34% 34% 34% 34%
Nov‐16 34% 34% 34% 34% 34% 34% 34%
Dec‐16 34% 34% 34% 34% 34% 34% 34%
Jan‐17 34% 34% 34% 34% 34% 34% 34%
Feb‐17 34% 34% 34% 34% 34% 34% 34%
Mar‐17 34% 34% 34% 34% 34% 34% 34%
Apr‐17 34% 34% 34% 34% 34% 34% 34%
May‐17 34% 34% 34% 34% 34% 34% 34%
Jun‐17 34% 34% 34% 34% 34% 34% 34%
Total 34% 34% 34% 34% 34% 34% 34%
Off‐Peak kWh @ Input Voltage Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 28,635,308 4,147,065 2,157,846 10,008,682 11,441,455 824,667 55,593
Aug‐16 28,993,811 4,082,272 2,172,989 10,260,916 11,555,884 866,157 55,593
Sep‐16 30,195,407 4,086,538 2,239,248 10,591,444 12,246,157 976,427 55,593
Oct‐16 28,255,669 4,305,350 2,091,275 9,781,236 11,431,526 590,690 55,593
Nov‐16 29,038,624 4,035,477 2,039,352 9,723,373 12,078,816 1,106,014 55,593
Dec‐16 29,193,330 5,360,453 2,001,342 9,033,222 11,884,353 858,367 55,593
Jan‐17 28,332,728 6,038,695 2,073,271 8,931,831 10,453,978 779,361 55,593
Feb‐17 26,729,333 4,970,853 1,978,429 8,629,824 10,356,440 738,193 55,593
Mar‐17 26,697,115 4,646,556 1,912,942 8,378,524 11,000,964 702,536 55,593
Apr‐17 27,333,665 4,244,144 2,027,955 8,994,957 10,867,745 1,143,271 55,593
May‐17 27,002,736 3,958,159 2,049,188 9,142,651 10,950,708 846,436 55,593
Jun‐17 28,433,726 3,930,339 2,026,766 9,386,065 12,189,397 845,565 55,593
Total Off‐Peak Energy 338,841,450 53,805,901 24,770,603 112,862,726 136,457,425 10,277,683 667,112
Summary of Future Test Period Seasonal Load Data
Power Supply
‐ System kWh @ Input Voltage‐ Winter Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 84,221,494 12,197,250 6,346,606 29,437,301 33,651,339 2,425,491 163,508
Aug‐16 85,275,915 12,006,683 6,391,143 30,179,165 33,987,895 2,547,522 163,508
Sep‐16 88,810,020 12,019,229 6,586,023 31,151,306 36,018,110 2,871,844 163,508
Oct‐16
Nov‐16
Dec‐16
Jan‐17
Feb‐17
Mar‐17
Apr‐17 80,393,131 12,482,777 5,964,575 26,455,756 31,963,956 3,362,561 163,508
May‐17 79,419,811 11,641,645 6,027,025 26,890,151 32,207,966 2,489,517 163,508
Jun‐17 83,628,605 11,559,822 5,961,077 27,606,074 35,851,168 2,486,956 163,508
Total Winter 501,748,976 71,907,405 37,276,447 171,719,752 203,680,433 16,183,890 981,048
Last Updated: 3/10/2016 1:16 PM Schedule 8.3 Page 2 of 3
Prepared By EES Consulting, Inc.City of Palo Alto FORECAST kWh AT INPUT
Schedule 8.3
‐System kWh @ Input Voltage‐ Summer Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16
Aug‐16
Sep‐16
Oct‐16 83,104,909 12,662,793 6,150,810 28,768,341 33,622,134 1,737,323 163,508
Nov‐16 85,407,717 11,869,049 5,998,093 28,598,155 35,525,930 3,252,982 163,508
Dec‐16 85,862,734 15,766,037 5,886,299 26,568,301 34,953,981 2,524,609 163,508
Jan‐17 83,331,554 17,760,868 6,097,855 26,270,091 30,746,994 2,292,238 163,508
Feb‐17 78,615,685 14,620,157 5,818,910 25,381,836 30,460,118 2,171,155 163,508
Mar‐17 78,520,925 13,666,341 5,626,301 24,642,717 32,355,777 2,066,281 163,508
Apr‐17
May‐17
Jun‐17
Total Summer 494,843,524 86,345,245 35,578,267 160,229,442 197,664,934 14,044,589 981,048
CP @ Input Voltage‐ Winter Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16 156,901 13,524 13,091 62,054 62,492 5,741
Aug‐16 153,892 11,875 12,988 63,783 60,625 4,620
Sep‐16 148,481 11,516 15,901 61,945 53,024 6,095
Oct‐16
Nov‐16
Dec‐16
Jan‐17
Feb‐17
Mar‐17
Apr‐17 149,181 24,308 16,058 54,804 44,154 9,857
May‐17 151,443 17,377 15,388 56,087 57,255 5,336
Jun‐17 164,328 23,721 16,383 59,552 57,381 7,290
Total Winter 924,225 102,322 89,809 358,225 334,930 38,939
CP @ Input Voltage‐ Summer Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐16
Aug‐16
Sep‐16
Oct‐16 168,329 21,188 18,821 62,227 61,674 3,980 439
Nov‐16 149,625 10,870 17,187 60,641 53,269 7,246 413
Dec‐16 140,252 16,301 12,550 52,061 54,094 4,880 366
Jan‐17 138,921 25,125 10,716 50,289 48,184 4,269 338
Feb‐17 136,396 23,543 14,654 48,829 44,112 4,852 405
Mar‐17 137,145 13,032 11,191 52,693 55,865 3,963 399
Apr‐17
May‐17
Jun‐17
Total Summer 870,669 110,059 85,120 326,740 317,198 29,190 2,361
Last Updated: 3/10/2016 1:16 PM Schedule 8.3 Page 3 of 3
Prepared By EES Consulting, Inc.City of Palo Alto
Number of Customers / Services Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 29,547 25,565 3,057 742 60 122 1
Aug‐14 29,529 25,535 3,060 743 67 123 1
Sep‐14 28,949 24,968 3,049 741 68 122 1
Oct‐14 29,679 25,666 3,083 741 67 121 1
Nov‐14 28,235 24,269 3,043 733 67 122 1
Dec‐14 29,346 25,359 3,060 741 67 118 1
Jan‐15 29,667 25,656 3,077 742 67 124 1
Feb‐15 29,562 25,555 3,074 740 67 125 1
Mar‐15 29,628 25,625 3,077 738 63 124 1
Apr‐15 29,575 25,562 3,097 724 67 124 1
May‐15 29,109 25,109 3,088 726 64 121 1
Jun‐15 29,245 25,223 3,110 720 67 124 1
Total Average 29,339 25,341 3,073 736 66 123 1
Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Input Recorded Data
Energy Sales (kWh) 952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346
Total Billing Capacity (kVa) 1,521,344 773,606 747,738
Avg. Monthly Billing Capacity (kVa) 126,779 64,467 62,312
Number of Customers 29,339 25,341 3,073 736 66 123 1
Ratio of NCP to Avg. Billing Capacity 11
Rate Classes NCP Demand at Meter 177,573 27,808 17,374 63,599 61,411 6,775 607
Estimated Based on Recorded Data
Annual NCP Load Factor 61% 62% 46% 55% 74% 49% 36%
Rate Classes CP Demand at Input Voltage 169,623 21,594 17,963 62,227 61,674 5,712 454
Annual CP Load Factor 64% 80% 45% 56% 73% 58% 48%
Average On‐Peak kWh as a % of Total kWh 66% 66% 66% 66% 66% 66%
Average Off‐Peak kWh as a % of Total kWh 34% 34% 34% 34% 34% 34%
kWh Sales at the Meter Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 77,965,899 11,789,582 5,880,488 26,024,709 31,803,107 2,309,901 158,112
Aug‐14 82,987,201 11,330,498 5,895,458 27,361,945 35,773,165 2,468,023 158,112
Sep‐14 87,503,059 11,560,737 6,386,405 29,269,602 37,406,835 2,721,368 158,112
Oct‐14 78,632,817 12,077,193 5,493,428 25,803,870 32,767,071 2,333,143 158,112
Nov‐14 79,700,792 11,607,795 5,456,028 24,942,299 34,971,656 2,564,902 158,112
Dec‐14 80,199,169 15,092,762 5,446,408 24,598,609 32,572,571 2,330,707 158,112
Jan‐15 80,513,170 17,342,158 5,951,986 24,061,704 30,479,098 2,520,112 158,112
Feb‐15 81,389,444 14,606,393 5,799,412 24,244,688 34,041,901 2,538,938 158,112
Mar‐15 71,512,256 12,097,303 5,333,019 22,956,678 28,761,884 2,205,260 158,112
Apr‐15 77,355,465 11,477,709 5,894,120 23,923,508 33,608,313 2,293,703 158,112
May‐15 76,149,464 11,077,484 6,431,015 25,223,376 30,780,866 2,478,611 158,112
Jun‐15 78,772,748 10,806,575 6,516,748 25,521,556 33,382,123 2,387,634 158,112
Total Sales 952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346
Load Data And Customer Sales
‐‐ Recorded Year ‐‐
Historic Energy, Demand And Customer Count
RECORDED CUSTOMERS AND ENERGY SALES
Schedule 8.4
Historic Year
By Rate Class
Last Updated: 3/10/2016 1:16 PM Schedule 8.4 Page 1 of 1
Prepared By EES Consulting, Inc.City of Palo Alto
Metered Demand ‐ kVA Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 137,681 70,573 67,108
Aug‐14 137,268 70,808 66,460
Sep‐14 127,754 68,874 58,881
Oct‐14 139,636 69,274 70,362
Nov‐14 127,926 66,391 61,535
Dec‐14 124,223 60,673 63,551
Jan‐15 111,508 58,366 53,142
Feb‐15 108,195 57,248 50,947
Mar‐15 127,061 58,641 68,420
Apr‐15 114,608 61,809 52,799
May‐15 131,158 64,005 67,154
Jun‐15 134,324 66,944 67,380
Total 1,521,344 773,606 747,738
Individual Load Factor Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 66.78% 55.70% 49.56% 63.70% 49.56% 35.00%
Aug‐14 68.14% 50.59% 57.50% 80.10% 57.50% 40.00%
Sep‐14 68.84% 53.00% 57.12% 85.39% 57.12% 45.00%
Oct‐14 70.96% 41.72% 51.73% 64.68% 51.73% 50.00%
Nov‐14 72.02% 41.43% 50.50% 76.39% 50.50% 55.00%
Dec‐14 71.61% 53.89% 56.31% 71.19% 56.31% 60.00%
Jan‐15 72.67% 65.00% 55.41% 77.09% 55.41% 65.00%
Feb‐15 72.41% 55.00% 56.92% 89.81% 56.92% 60.00%
Mar‐15 71.87% 51.68% 54.37% 58.38% 54.37% 55.00%
Apr‐15 63.00% 49.00% 52.02% 85.55% 45.00% 50.00%
May‐15 65.00% 50.00% 54.73% 63.66% 54.73% 45.00%
Jun‐15 63.00% 48.00% 51.24% 66.59% 45.00% 40.00%
Individual NCP (kW) Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Power Factor:100% 100%
Jul‐14 182,471 23,729 14,190 70,573 67,108 6,264 607
Aug‐14 186,332 24,746 17,343 70,808 66,460 6,387 588
Sep‐14 173,397 22,571 16,196 68,874 58,881 6,404 472
Oct‐14 188,267 23,640 18,288 69,274 70,362 6,264 439
Nov‐14 174,503 21,664 17,699 66,391 61,535 6,827 386
Dec‐14 173,646 29,271 14,037 60,673 63,551 5,749 366
Jan‐15 162,332 32,076 12,308 58,366 53,142 6,113 327
Feb‐15 155,828 27,111 14,173 57,248 50,947 5,995 354
Mar‐15 170,804 23,378 14,332 58,641 68,420 5,633 399
Apr‐15 162,539 24,487 16,168 61,809 52,799 6,851 425
May‐15 179,469 23,670 17,864 64,005 67,154 6,289 488
Jun‐15 183,290 23,056 18,248 66,944 67,380 7,132 531
Maximum 188,267 32,076 18,288 70,808 70,362 7,132 607
RECORDED CUSTOMER DEMAND
Schedule 8.5
Last Updated: 3/10/2016 1:16 PM Schedule 8.5 Page 1 of 3
Prepared By EES Consulting, Inc.City of Palo Alto RECORDED CUSTOMER DEMAND
Schedule 8.5
Group Coincidence Factor Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 95.00% 95.00% 85.04% 91.50% 90.00% 100.00%
Aug‐14 85.00% 85.00% 89.82% 92.40% 80.00% 100.00%
Sep‐14 95.00% 95.00% 88.58% 90.20% 90.00% 100.00%
Oct‐14 95.00% 95.00% 86.88% 86.12% 90.00% 100.00%
Nov‐14 95.00% 95.00% 88.34% 85.06% 90.00% 100.00%
Dec‐14 95.00% 95.00% 82.99% 83.64% 90.00% 100.00%
Jan‐15 85.00% 85.00% 83.33% 89.09% 80.00% 100.00%
Feb‐15 95.00% 95.00% 82.50% 85.08% 90.00% 100.00%
Mar‐15 85.00% 85.00% 86.91% 80.23% 80.00% 100.00%
Apr‐15 95.00% 95.00% 85.76% 82.17% 95.00% 100.00%
May‐15 95.00% 95.00% 84.76% 83.77% 90.00% 100.00%
Jun‐15 95.00% 95.00% 86.04% 83.68% 95.00% 100.00%
Rate Class NCP @ Meter (kW)Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 163,688 22,542 13,480 60,018 61,403 5,638 607
Aug‐14 166,483 21,034 14,742 63,599 61,411 5,109 588
Sep‐14 157,185 21,443 15,386 61,012 53,109 5,763 472
Oct‐14 166,693 22,458 17,374 60,186 60,599 5,637 439
Nov‐14 154,918 20,581 16,814 58,652 52,341 6,145 386
Dec‐14 150,187 27,808 13,335 50,353 53,152 5,174 366
Jan‐15 138,927 27,264 10,462 48,640 47,344 4,890 327
Feb‐15 135,541 25,756 13,464 47,228 43,344 5,396 354
Mar‐15 142,816 19,872 12,182 50,965 54,892 4,507 399
Apr‐15 141,947 23,263 15,359 53,007 43,384 6,508 425
May‐15 156,110 22,486 16,971 54,247 56,257 5,661 488
Jun‐15 160,525 21,903 17,336 57,599 56,381 6,775 531
Maximum 166,693 27,808 17,374 63,599 61,411 6,775 607
Rate Class NCP @ Primary Voltage (kW)Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Line Losses:2.50% 2.50% 2.50% 0.95% 2.50% 2.50%
Jul‐14 166,900 23,120 13,826 61,557 61,992 5,782 623
Aug‐14 169,766 21,573 15,119 65,230 62,000 5,240 603
Sep‐14 160,363 21,993 15,781 62,576 53,619 5,911 484
Oct‐14 169,994 23,034 17,819 61,729 61,180 5,782 450
Nov‐14 158,050 21,108 17,245 60,155 52,843 6,302 396
Dec‐14 153,185 28,521 13,677 51,644 53,662 5,307 375
Jan‐15 141,730 27,964 10,730 49,887 47,798 5,016 335
Feb‐15 138,321 26,416 13,809 48,439 43,760 5,534 363
Mar‐15 145,597 20,381 12,494 52,272 55,418 4,622 410
Apr‐15 144,890 23,859 15,753 54,366 43,800 6,675 436
May‐15 159,210 23,063 17,406 55,638 56,797 5,806 501
Jun‐15 163,736 22,464 17,780 59,076 56,922 6,949 545
Maximum 169,994 28,521 17,819 65,230 62,000 6,949 623
Last Updated: 3/10/2016 1:16 PM Schedule 8.5 Page 2 of 3
Prepared By EES Consulting, Inc.City of Palo Alto RECORDED CUSTOMER DEMAND
Schedule 8.5
Rate Class NCP @ Input Voltage (kW)Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Line Losses:0.80% 0.80% 0.80% 0.80% 0.80% 0.80%
Jul‐14 168,246 23,307 13,937 62,054 62,492 5,829 628
Aug‐14 171,135 21,747 15,241 65,756 62,500 5,283 608
Sep‐14 161,656 22,170 15,908 63,081 54,051 5,959 488
Oct‐14 171,365 23,220 17,963 62,227 61,674 5,828 454
Nov‐14 159,324 21,278 17,384 60,641 53,269 6,353 399
Dec‐14 154,421 28,751 13,787 52,061 54,094 5,349 378
Jan‐15 142,873 28,189 10,816 50,289 48,184 5,056 338
Feb‐15 139,436 26,629 13,921 48,829 44,112 5,579 366
Mar‐15 146,771 20,546 12,595 52,693 55,865 4,659 413
Apr‐15 146,058 24,052 15,880 54,804 44,154 6,729 439
May‐15 160,494 23,249 17,546 56,087 57,255 5,853 505
Jun‐15 165,056 22,645 17,924 59,552 57,381 7,005 549
Maximum 171,365 28,751 17,963 65,756 62,500 7,005 628
System Coincidence Factor Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 58.00% 90.00% 100.00% 100.00% 97.00%
Aug‐14 59.00% 90.00% 97.00% 97.00% 97.00%
Sep‐14 50.00% 97.00% 98.20% 98.10% 97.00%
Oct‐14 93.00% 100.00% 100.00% 100.00% 98.00% 100.00%
Nov‐14 50.00% 90.00% 100.00% 100.00% 90.00% 100.00%
Dec‐14 58.00% 90.00% 100.00% 100.00% 90.00% 100.00%
Jan‐15 90.00% 100.00% 100.00% 100.00% 96.00% 100.00%
Feb‐15 82.50% 98.00% 100.00% 100.00% 95.00% 100.00%
Mar‐15 60.00% 90.00% 100.00% 100.00% 97.00% 100.00%
Apr‐15 93.00% 100.00% 100.00% 100.00% 100.00%
May‐15 76.00% 100.00% 100.00% 100.00% 97.00%
Jun‐15 98.00% 100.00% 100.00% 100.00% 100.00%
Coincident Peak (CP) @ Input (kW) Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 156,261 13,518 12,544 62,054 62,492 5,654
Aug‐14 156,081 12,831 13,717 63,783 60,625 5,124
Sep‐14 147,265 11,085 15,431 61,945 53,024 5,780
Oct‐14 169,623 21,594 17,963 62,227 61,674 5,712 454
Nov‐14 146,311 10,639 15,646 60,641 53,269 5,718 399
Dec‐14 140,432 16,675 12,409 52,061 54,094 4,814 378
Jan‐15 139,851 25,370 10,816 50,289 48,184 4,854 338
Feb‐15 134,219 21,969 13,642 48,829 44,112 5,300 366
Mar‐15 137,154 12,327 11,336 52,693 55,865 4,520 413
Apr‐15 143,935 22,368 15,880 54,804 44,154 6,729
May‐15 154,234 17,669 17,546 56,087 57,255 5,677
Jun‐15 164,054 22,193 17,924 59,552 57,381 7,005
Total 1,789,420 208,239 174,853 684,965 652,128 66,886 2,349
Peak Month 169,623 21,594 17,963 62,227 61,674 5,712 454
Last Updated: 3/10/2016 1:16 PM Schedule 8.5 Page 3 of 3
Prepared By EES Consulting, Inc.City of Palo Alto
kWh @ Input Voltage Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 80,107,726 12,191,915 6,081,166 26,912,832 32,369,575 2,388,729 163,508
Aug‐14 85,235,616 11,717,164 6,096,647 28,295,703 36,410,346 2,552,247 163,508
Sep‐14 89,878,931 11,955,261 6,604,349 30,268,461 38,073,115 2,814,238 163,508
Oct‐14 80,781,677 12,489,341 5,680,898 26,684,457 33,350,708 2,412,764 163,508
Nov‐14 81,850,131 12,003,925 5,642,221 25,793,484 35,594,561 2,652,432 163,508
Dec‐14 82,404,655 15,607,820 5,632,273 25,438,065 33,152,744 2,410,245 163,508
Jan‐15 82,763,526 17,933,979 6,155,104 24,882,838 31,021,983 2,606,114 163,508
Feb‐15 83,611,578 15,104,853 5,997,324 25,072,066 34,648,245 2,625,582 163,508
Mar‐15 73,483,461 12,510,138 5,515,014 23,740,101 29,274,182 2,280,517 163,508
Apr‐15 79,447,009 11,869,399 6,095,264 24,739,926 34,206,934 2,371,978 163,508
May‐15 78,245,980 11,455,516 6,650,481 26,084,153 31,329,126 2,563,196 163,508
Jun‐15 80,916,349 11,175,362 6,739,140 26,392,509 33,976,716 2,469,115 163,508
Total Purchases ‐ Bottom Up 978,726,637 156,014,673 72,889,881 314,304,596 403,408,234 30,147,158 1,962,095
Historic Load Reconciliation Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Secondary Line Losses 2.50% 2.50% 2.50% 0.95% 2.50% 2.50%
Primary Line Losses 0.80% 0.80% 0.80% 0.80% 0.80% 0.80%
Total Jul‐14 Aug‐14 Sep‐14 Oct‐14 Nov‐14 Dec‐14
Recorded Energy Purchases kWh 980,893,955 85,616,647 86,907,303 83,078,225 82,724,711 79,300,007 83,420,214
Bottom‐Up Energy Purchases kWh 978,726,637 80,107,726 85,235,616 89,878,931 80,781,677 81,850,131 82,404,655
% Difference 0.22% 7% 2%‐8% 2%‐3% 1%
Measured System Demand kW 1,821,704 156,272 156,120 147,279 170,079 146,691 140,814
CP @ Input Demand kW 1,789,420 156,261 156,081 147,265 169,623 146,311 140,432
% Difference 1.8% 0.0% 0.0% 0.0% 0.3% 0.3% 0.3%
On‐Peak Energy Use by Percentage Average Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 66% 66% 66% 66% 66% 66% 66%
Aug‐14 66% 66% 66% 66% 66% 66% 66%
Sep‐14 66% 66% 66% 66% 66% 66% 66%
Oct‐14 66% 66% 66% 66% 66% 66% 66%
Nov‐14 66% 66% 66% 66% 66% 66% 66%
Dec‐14 66% 66% 66% 66% 66% 66% 66%
Jan‐15 66% 66% 66% 66% 66% 66% 66%
Feb‐15 66% 66% 66% 66% 66% 66% 66%
Mar‐15 66% 66% 66% 66% 66% 66% 66%
Apr‐15 66% 66% 66% 66% 66% 66% 66%
May‐15 66% 66% 66% 66% 66% 66% 66%
Jun‐15 66% 66% 66% 66% 66% 66% 66%
Total (Derived)66%66% 66% 66% 66% 66% 66%
RECORDED kWh AT INPUT
Schedule 8.6
Last Updated: 3/10/2016 1:16 PM Schedule 8.6 Page 1 of 2
Prepared By EES Consulting, Inc.City of Palo Alto RECORDED kWh AT INPUT
Schedule 8.6
On‐Peak kWh @ Input Voltage Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 52,871,099 8,046,664 4,013,570 17,762,469 21,363,919 1,576,561 107,915
Aug‐14 56,255,507 7,733,329 4,023,787 18,675,164 24,030,828 1,684,483 107,915
Sep‐14 59,320,094 7,890,472 4,358,870 19,977,184 25,128,256 1,857,397 107,915
Oct‐14 53,315,906 8,242,965 3,749,392 17,611,742 22,011,468 1,592,424 107,915
Nov‐14 54,021,086 7,922,590 3,723,866 17,023,699 23,492,410 1,750,605 107,915
Dec‐14 54,387,072 10,301,161 3,717,300 16,789,123 21,880,811 1,590,762 107,915
Jan‐15 54,623,927 11,836,426 4,062,369 16,422,673 20,474,509 1,720,035 107,915
Feb‐15 55,183,642 9,969,203 3,958,234 16,547,564 22,867,842 1,732,884 107,915
Mar‐15 48,499,084 8,256,691 3,639,910 15,668,467 19,320,960 1,505,141 107,915
Apr‐15 52,435,026 7,833,803 4,022,874 16,328,351 22,576,577 1,565,506 107,915
May‐15 51,642,347 7,560,641 4,389,317 17,215,541 20,677,223 1,691,710 107,915
Jun‐15 53,404,790 7,375,739 4,447,832 17,419,056 22,424,632 1,629,616 107,915
Total On‐Peak Energy ‐ Bottom‐Up 645,959,581 102,969,684 48,107,322 207,441,033 266,249,435 19,897,124 1,294,983
Off‐Peak Energy Use by Percentage Average Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 34% 34% 34% 34% 34% 34% 34%
Aug‐14 34% 34% 34% 34% 34% 34% 34%
Sep‐14 34% 34% 34% 34% 34% 34% 34%
Oct‐14 34% 34% 34% 34% 34% 34% 34%
Nov‐14 34% 34% 34% 34% 34% 34% 34%
Dec‐14 34% 34% 34% 34% 34% 34% 34%
Jan‐15 34% 34% 34% 34% 34% 34% 34%
Feb‐15 34% 34% 34% 34% 34% 34% 34%
Mar‐15 34% 34% 34% 34% 34% 34% 34%
Apr‐15 34% 34% 34% 34% 34% 34% 34%
May‐15 34% 34% 34% 34% 34% 34% 34%
Jun‐15 34% 34% 34% 34% 34% 34% 34%
Total (Derived) 34%34% 34% 34% 34% 34% 34%
Off‐Peak kWh @ Input Voltage Total Residential E‐1
Small Non‐
residential E‐2
Medium Non‐
residential E‐4
Large Non‐
residential E‐7
City Accounts E‐
18
Street/Traffic
Lights
Jul‐14 27,236,627 4,145,251 2,067,597 9,150,363 11,005,655 812,168 55,593
Aug‐14 28,980,109 3,983,836 2,072,860 9,620,539 12,379,518 867,764 55,593
Sep‐14 30,558,836 4,064,789 2,245,478 10,291,277 12,944,859 956,841 55,593
Oct‐14 27,465,770 4,246,376 1,931,505 9,072,715 11,339,241 820,340 55,593
Nov‐14 27,829,044 4,081,334 1,918,355 8,769,785 12,102,151 901,827 55,593
Dec‐14 28,017,583 5,306,659 1,914,973 8,648,942 11,271,933 819,483 55,593
Jan‐15 28,139,599 6,097,553 2,092,736 8,460,165 10,547,474 886,079 55,593
Feb‐15 28,427,937 5,135,650 2,039,090 8,524,503 11,780,403 892,698 55,593
Mar‐15 24,984,377 4,253,447 1,875,105 8,071,634 9,953,222 775,376 55,593
Apr‐15 27,011,983 4,035,596 2,072,390 8,411,575 11,630,358 806,473 55,593
May‐15 26,603,633 3,894,875 2,261,163 8,868,612 10,651,903 871,487 55,593
Jun‐15 27,511,559 3,799,623 2,291,307 8,973,453 11,552,083 839,499 55,593
Total Off‐Peak Energy ‐ Bottom‐Up 332,767,057 53,044,989 24,782,560 106,863,563 137,158,800 10,250,034 667,112
Last Updated: 3/10/2016 1:16 PM Schedule 8.6 Page 2 of 2
Attachment D
NOT YET APPROVED
160330 jb 6053723
Resolution No. _________
Resolution of the Council of the City of Palo Alto Adopting an Electric Rate
Increase and Amending Rate Schedules E-1 (Residential Electric Service), E-2
(Small Commercial Electric Service), E-2-G (Small Commercial Green Power
Electric Service), E-4 (Medium Commercial Electric Service), E-4-G (Medium
Commercial Green Power Electric Service), E-4 TOU (Medium Commercial Time
of Use Electric Service), E 7 (Large Commercial Electric Service), E-7-G (Large
Commercial Green Power Electric Service), E 7 TOU (Large Commercial Time of
Use Electric Service), E-14 (Street Lights), and E-16 (Unmetered Electrical
Service) and Repealing Rate Schedules E-18 (Municipal Electric Service) and E-
18-G (Municipal Green Power Electric Service)
R E C I T A L S
A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
B. On ____, 2016, the City Council heard and approved the proposed rate increase
at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule 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, 2016.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2 (Small Commercial Electric Service) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-2, as amended, shall become effective July 1, 2016.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2-G (Small Commercial Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-2-G, as amended, shall become
effective July 1, 2016.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Commercial Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2016.
Attachment D
NOT YET APPROVED
160330 jb 6053723
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Commercial Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall become
effective July 1, 2016.
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Commercial Time of Use Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended, shall become
effective July 1, 2016.
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Commercial Electric Service) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-7, as amended, shall become effective July 1, 2016.
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Commercial Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7, as amended, shall become
effective July 1, 2016.
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Commercial Time of Use Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become
effective July 1, 2016.
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated.
Utility Rate Schedule E-14, as amended, shall become effective July 1, 2016.
SECTION 11. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-16 (Unmetered Electrical Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-16, as amended, shall become effective July 1, 2016.
SECTION 12. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-18 (Municipal Electric Service) is hereby repealed effective July 1, 2016.
SECTION 13. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-18-G (Municipal Green Power Electric Service) is hereby repealed effective
July 1, 2016.
SECTION 14. The City Council finds as follows:
a. Revenue derived from the electric rates approved by this resolution does not
exceed the funds required to provide electric service.
Attachment D
NOT YET APPROVED
160330 jb 6053723
b. 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.
c. 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 15. The adoption of this resolution changing electric rates to meet operating
expenses, purchase supplies and materials, meet financial reserve needs and obtain funds for
capital improvements necessary to maintain service is not subject to the California
Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec.
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a).
After reviewing the staff report and all attachments presented to Council, the Council
incorporates these documents herein and finds that sufficient evidence has been presented
setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Senior Deputy City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-2009
Supersedes Sheet No E-1-1 dated 11-1-2008 Sheet No E-1-1
A. APPLICABILITY:
This schedule applies to separately metered single-family residential dwellings receiving retail
energy services from the City of Palo Alto Utilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides electric service.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Tier 1 usage $0.05448
$0.05883
$0.03755
$0.04795
$0.00321
$0.00351
$0.09524
$0.11029
Tier 2 usage
100%-200% ofAny
usage over Tier 1
0.07654
0.09728
0.05045
0.06822
0.00321
0.00351
0.13020
0.16901
Tier 3 usage
Over 200% of Tier 1
0.10349
0.06729
0.00321
0.17399
Minimum Bill ($/day)
0.3067
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 10 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 300 330 kWh. For further discussion of bill calculation and
proration, refer to Rule and Regulation 11.
{End}
SMALL COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2009
Supersedes Sheet No E-2-1 dated 7-1-200911-1-2008 Sheet No E-2-1
A. APPLICABILITY:
This schedule applies to non-demand metered electric service for small commercial customers
and master-metered multi-family facilities.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides electric service.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period
$0.08219
$0.09094
$0.05505
$0.07400
$0.00321
$0.00351
$0.14045
$0.16845
Winter Period
0.07406
0.06417
0.04934
0.04677
0.00321
0.00351
0.12661
0.11445
Minimum Bill ($/day)
0.7657
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.
SMALL COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2009
Supersedes Sheet No E-2-2 dated 7-1-200911-1-2008 Sheet No E-2-2
3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum demand meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The maximum demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that in case the load is
intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A
thermal-type demand meter which does not reset after a definite time interval may be
used at the City's option.
The billing demand to be used in computing charges under this schedule will be the
actual maximum demand in kilowatts for the current month. An exception is that the
billing demand for customers with Thermal Energy Storage (TES) will be based upon the
actual maximum demand of such customers between the hours of noon and 6 pm on
weekdays.
{End}
SMALL COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-2-G-1 dated 7-1-20149-1-2013 Sheet No E-2-G-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities under the Palo Alto Green Program:
1. Small commercial 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
$0.09094
$0.08219
$0.07400
$0.05505
$0.00351
$0.00321 $0.0020
$0.14245
$0.17045
Winter Period
0.06417
0.07406
0.04677
0.04934
0.00351
0.00321 0.0020
0.12861
$0.11645
Minimum Bill ($/day)
0.7657
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$0.09094
$0.08219
$0.07400
$0.05505
$0.00351
$0.00321
$0.16845
$0.14045
Winter Period
0.06417
0.07406
0.04677
0.04934
0.00351
0.00321
0.11445
0.12661
Minimum Bill ($/day) 0.7657
Palo Alto Green Charge (per 1000 kWh block) $2.00
SMALL COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-2-G-2 dated 7-1-20149-1-2013 Sheet No E-2-G-2
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.
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
SMALL COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-2-G-3 dated 7-1-20149-1-2013 Sheet No E-2-G-3
removed.
The maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that in case the load is
intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option.
The billing Demand to be used in computing charges under this schedule will be the
actual maximum Demand in kilowatts for the current month. An exception is that the
billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
{End}
MEDIUM COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-4-1 dated 2-5-20137-1-2009 Sheet No E-4-1
A. APPLICABILITY:
This schedule applies to Demand metered secondary Electric Service for customers with a
Maximum Demand below 1,000 kilowatts. This schedule applies to three-phase Electric
Service and may include Service to master-metered multi-family facilities or other facilities
requiring Demand-metered services, as determined by the City.
B. TERRITORY:
This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $5.31 $2.53 $15.23 $17.14 $20.54 $19.68
Energy Charge (per kWh) 0.06083 0.08218 0.01767 0.01661 0.00321 0.00351 0.08171 0.10229
Winter Period
Demand Charge (per kW) $4.80 $1.55 $9.04 $12.49 $13.84 $14.04
Energy Charge (per kWh) 0.05281 0.06037 0.01716 0.01661 0.00321 0.00351 0.07318 0.08049
Minimum Bill ($/day) 16.3216
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
MEDIUM COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-4-2 dated 2-5-20137-1-2009 Sheet No E-4-2
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a Maximum Demand meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that in case the load is
intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A
thermal-type Demand meter which does not reset after a definite time interval may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such customers between the hours of noon and 6 pm on
weekdays.
4. 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
Adjustment”, if applicable. The adjustment will be applied to a customer’s bill prior to
MEDIUM COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-4-3 dated 2-5-20137-1-2009 Sheet No E-4-3
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
allowed provided the City is not required to supply Service at a particular line voltage
where it has, or will install, ample facilities for supplying at another voltage equally or
better suited to the customer's electrical requirements. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any
customer receiving a discount hereunder and affected by such change. The customer then
has the option to change his system so as to receive Service at the new line voltage or to
accept Service (without voltage discount) through transformers to be supplied by the City
subject to a maximum kilovolt-ampere size limitation.
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 COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-4-4 dated 2-5-20137-1-2009 Sheet No E-4-4
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate 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 COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-4-TOU-1 dated 2-5-20137-1-2009 Sheet No E-4-TOU-1
A. APPLICABILITY:
This voluntary rate schedule applies to Demand metered secondary Electric Service for
customers with Demand between 500 and 1,000 kilowatts per month and who have sustained
this level of usage for at least three consecutive months during the most recent 12 month period.
This schedule applies to three-phase Electric Service and may include Service to master-
metered multi-family facilities or other facilities requiring Demand-metered services, as
determined by the City. In addition, this rate schedule is applicable for customers who did not
pay Power Factor Adjustments during the last 12 months.
B. TERRITORY:
This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $1.52$3.12 $5.91$8.96 $7.42$12.08
Mid-Peak 0.541.99 5.915.65 6.447.64
Off-Peak 0.541.13 5.913.26 6.444.39
Energy Charge (per kWh)
Peak
$0.08819
$0.10963
$0.01661
$0.03242
$0.00351
$0.00321
$0.10830
$0.14526
Mid-Peak
0.08367
0.05617
0.01661
0.01623
0.00351
0.00321
0.10378
0.07561
Off-Peak
0.07332
0.04298
0.01661
0.01218
0.00351
0.00321
0.09344
0.05837
Winter Period
Demand Charge (per kW)
Peak $2.77$0.87 $5.10$6.96 $7.87$7.83
Off-Peak 1.490.87 2.946.96 4.437.83
MEDIUM COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-4-TOU-2 dated 2-5-20137-1-2009 Sheet No E-4-TOU-2
Commodity Distribution
Public
Benefits Total
Energy Charge (per kWh)
Peak
$0.07003
$0.06566
$0.02296
$0.01661
$0.00321
$0.00351
$0.09620
$0.08577
Off-Peak
0.04088
0.06167
0.01313
0.01661
$0.00351
0.00321
0.05722
0.08178
Minimum Bill ($/day) 16.3216
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. 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
MEDIUM COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-4-TOU-3 dated 2-5-20137-1-2009 Sheet No E-4-TOU-3
holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Years Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
SEASONAL RATE CHANGES: When the billing period includes use in both the
Summer and the Winter periods, the usage will be prorated based on the number of days
in each seasonal period, and the charges based on the applicable rates therein.. For
further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Demand meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000
kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it
may be removed.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the
designated Time periods as defined under Section D.2.
4. Power Factor Adjustment
Time of Use customers must not have had a Power Factor Adjustment assessed on their
Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month, and must not have fallen
below 95% to avoid the Power Factor Adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should
be subject to Power Factor Adjustments, the Customer will be removed from the E-4-
TOU rate schedule and placed on another applicable rate schedule as is suitable to their
kilowatt Demand and kilowatt-hour usage.
5. Changing Rate Schedules
MEDIUM COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-4-TOU-4 dated 2-5-20137-1-2009 Sheet No E-4-TOU-4
Customers electing to be served under E-4 TOU must remain on said schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 months, the
Customer may request a rate schedule change to any applicable City of Palo Alto full-
service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage.
6. Primary Voltage Discount
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
allowed provided the City is not required to supply Service at a particular line voltage
where it has, or will install, ample facilities for supplying at another voltage equally or
better suited to the Customer's electrical requirements. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any
Customer receiving a discount hereunder and affected by such change. The Customer
then has the option to change his system so as to receive Service at the new line voltage
or to accept Service (without voltage discount) through transformers to be supplied by the
City subject to a maximum kilovolt-ampere size limitation.
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.
MEDIUM COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-4-TOU-5 dated 2-5-20137-1-2009 Sheet No E-4-TOU-5
(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.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-4-G-1 dated 7-1-20149-10-2013 Sheet No E-4-G-1
A. APPLICABILITY:
This schedule applies to Demand Metered Secondary Electric Service for Customers with a
Maximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green
Program. This schedule applies to three-phase Electric Service and may include Service to
Master-metered multi-family facilities or other facilities requiring Demand-Metered Services, as
determined by the City.
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge (per kW)
$2.53 $5.31
$17.14 $15.23
$19.68 $20.54
Energy Charge (per kWh)
0.08218 0.06083
0.01661 0.01767
0.00351 0.00321 0.0020
0.10429 0.08371
Winter Period
Demand Charge (per kW)
$1.55 $4.80
$12.49 $9.04
$14.04 $13.84
Energy Charge (per kWh)
0.06037 0.05281
0.01661 0.01716
0.00351 0.00321 0.0020
0.08249 0.07518
Minimum Bill ($/day) 16.3216
MEDIUM COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-4-G-2 dated 7-1-20149-10-2013 Sheet No E-4-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution
Public
Benefits Total
Summer Period
Demand Charge (per kW)
$2.53
$5.31
$17.14
$15.23
$19.68
$20.54
Energy Charge (per kWh)
0.08218
0.06083
0.01661
0.01767
0.00351
0.00321
0.10229
0.08371
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW)
$1.55
$4.80
$12.49
$9.04
$14.04
$13.84
Energy Charge (per kWh)
0.06037
0.05281
0.01661
0.01716
0.00351
0.00321
0.08049
0.07518
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 16.3216
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
MEDIUM COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-4-G-3 dated 7-1-20149-10-2013 Sheet No E-4-G-3
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.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that in case the load is
intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter, which does not reset after a definite time interval, may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. 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
MEDIUM COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-4-G-4 dated 7-1-20149-10-2013 Sheet No E-4-G-4
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.
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
allowed provided the City is not required to supply Service at a particular line voltage
where it has, or will install, ample facilities for supplying at another voltage equally or
better suited to the Customer's electrical requirements. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any
Customer receiving a discount hereunder and affected by such change. The Customer
then has the option to change the system so as to receive Service at the new line voltage
or to accept Service (without voltage discount) through transformers to be supplied by the
City subject to a maximum kilovolt-ampere size limitation.
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 COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-4-G-5 dated 7-1-20149-10-2013 Sheet No E-4-G-5
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-7-1 dated 2-5-20137-1-2009 Sheet No E-7-1
A. APPLICABILITY:
This schedule applies to Demand metered secondary Service for commercial Customers with a
Maximum Demand of at least 1,000KW per month per site, who have sustained this Demand
level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (kW) $6.42 $2.50 $12.55 $15.85 $18.97 $18.34
Energy Charge (kWh) 0.05662 0.08311 0.01825 0.00087 0.00321 0.00351 0.07808 0.08749
Winter Period
Demand Charge (kW) $5.50 $1.53 $6.04 $14.11 $11.54 $15.65
Energy Charge (kWh) 0.04990 0.05804 0.01898 0.00087 0.00321 0.00351 0.07209 0.06242
Minimum Bill ($/day) 48.5054
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
LARGE COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-7-2 dated 2-5-20137-1-2009 Sheet No E-7-2
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one account
or one meter if the accounts are on one site. A site shall be defined as one or more utility
accounts serving contiguous parcels of land with no intervening public right-of-ways
(e.g. streets) and have a common billing address.
4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of
the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that in case the load is
intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A
thermal-type Demand meter which does not reset after a definite time interval may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
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
LARGE COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-7-3 dated 2-5-20137-1-2009 Sheet No E-7-3
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
allowed provided the City is not required to supply Service at a particular line voltage
where it has, or will install, ample facilities for supplying at another voltage equally or
better suited to the Customer's electrical requirements. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any
Customer receiving a discount hereunder and affected by such change. The Customer
then has the option to change his system so as to receive Service at the new line voltage
or to accept Service (without voltage discount) through transformers to be supplied by the
City subject to a maximum kVA size limitation.
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-
LARGE COMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-7-4 dated 2-5-20137-1-2009 Sheet No E-7-4
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.4) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-7-TOU-1 dated 2-5-20137-1-2009 Sheet No E-7-TOU-1
A. APPLICABILITY:
This voluntary rate schedule applies to Demand metered secondary Service for commercial
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 $4.24 $1.48 $8.25 $5.33 $12.49 $6.80
Mid-Peak 2.06 0.51 4.13 5.33 6.19 5.84
Off-Peak 1.17 0.51 2.06 5.33 3.23 5.84
Energy Charge (per kWh)
Peak $0.07029 $0.09267 $0.02296 $0.00087 $0.00321 $0.00351 $0.09646 $0.09705
Mid-Peak 0.05867 0.08792 0.01901 0.00087 0.00321 0.00351 0.08089 0.09230
Off-Peak 0.04870 0.07705 0.01567 0.00087 0.00321 0.00351 0.06758 0.08143
Winter Period
Demand Charge (per kW)
Peak $3.04 $0.78 $3.38 $7.15 $6.42 $7.92
Off-Peak 1.59 0.78 1.68 7.15 3.27 7.92
LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-7-TOU-2 dated 2-5-20137-1-2009 Sheet No E-7-TOU-2
Energy Charge (per kWh)
Peak
$0.05617
$0.06009
$0.02142
$0.00087
$0.00321
$0.00351
$0.08080
$0.06447
Off-Peak
0.04663
0.05643
0.01767
0.00087
0.00321
0.00351
0.06751
0.06081
Minimum Bill ($/day) 48.5054
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except
holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except
holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday
All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except
holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except
LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-7-TOU-3 dated 2-5-20137-1-2009 Sheet No E-7-TOU-3
holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Years Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
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
meter if the accounts are on one site. A site shall be defined as one or more utility accounts
serving contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and
have a common billing address.
4. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Demand meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000
kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it
may be removed.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the
designated Time periods as defined under Section D.2.
5. Power Factor Adjustment
Time of Use customers must not have had a Power Factor Adjustment assessed on their Service
for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt-
ampere hours consumed during the month, and must not have fallen below 95% to avoid the
Power Factor Adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be
LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-7-TOU-4 dated 2-5-20137-1-2009 Sheet No E-7-TOU-4
subject to Power Factor Adjustments, the Customer will be removed from the E-7-TOU rate
schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand
and kilowatt-hour usage.
6. Changing Rate Schedules
Customers electing to be served under E-7 TOU must remain on said schedule for a minimum of
12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a
rate schedule change to any applicable City of Palo Alto full-service rate schedule as is suitable
to their kilowatt Demand and kilowatt-hour usage.
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
allowed provided the City is not required to supply Service at a particular line voltage
where it has, or will install, ample facilities for supplying at another voltage equally or
better suited to the Customer's electrical requirements. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any
Customer receiving a discount hereunder and affected by such change. The Customer
then has the option to change his system so as to receive Service at the new line voltage
or to accept Service (without voltage discount) through transformers to be supplied by the
City subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20162-5-2013
Supersedes Sheet No E-7-TOU-5 dated 2-5-20137-1-2009 Sheet No E-7-TOU-5
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 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 COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-7-G-1 dated 7-1-20149-10-2013 Sheet No E-7-G-1
A. APPLICABILITY:
This schedule applies to Demand Metered Service for large commercial 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)
$2.50 $6.42
$15.85 $12.55
$18.34 $18.97
Energy Charge (per kWh)
0.08311 0.05562
0.00087 0.01825
0.00351 0.00321 0.0020
0.08949 0.07908
Winter Period
Demand Charge (per kW)
$1.53 $5.50
$14.11 $6.04
$15.65 $11.54
Energy Charge (per kWh)
0.05804 0.04990
0.00087 0.01898
0.00351 0.00321 0.0020
0.06442 0.07409
Minimum Bill ($/day) 48.5054
LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-7-G-2 dated 7-1-20149-10-2013 Sheet No E-7-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution
Public
Benefits Total
Summer Period
Demand Charge (per kW)
$2.50 $6.42
$15.85 $12.55
$18.34 $18.97
Energy Charge (per kWh)
0.08311 0.05562
0.00087 0.01825
0.00351 0.00321
0.08749 0.07708
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW)
$1.53
$5.50
$14.11
$6.04
$15.65
$11.54
Energy Charge (per kWh)
0.05804
0.04990
0.00087
0.01898
0.00351
0.00321
0.06242
0.07209
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 48.5054
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-7-G-3 dated 7-1-20149-10-2013 Sheet No E-7-G-3
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.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that in case the load is
intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Request for Service
Qualifying Customers may request Service under this schedule for more than one
Account or one Meter if the Accounts are at one site. A site shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and have a common billing address.
5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-7-G-4 dated 7-1-20149-10-2013 Sheet No E-7-G-4
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. 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
allowed; provided, however, the City is not required to supply Service at a qualified line
voltage where it has, or will install, ample facilities for supplying at another voltage
equally or better suited to the Customer's Electrical requirements. The City retains the
right to change its line voltage at any time after providing reasonable advance notice to
any Customer receiving a discount hereunder and affected by such change. The
Customer then has the option to change the system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
9. Standby Charge
LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-7-G-5 dated 7-1-20149-10-2013 Sheet No E-7-G-5
a. Applicability: The standby charge, subject to the exemptions in subsection
D(9)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2014
Supersedes Sheet No E-7-G-6 dated 7-1-20149-10-2013 Sheet No E-7-G-6
{End}
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-01-2009
Supersedes Sheet No. E-14-1 dated 7-01-20097-01-2008 Sheet No. E-14-1
A. APPLICABILITY: This schedule applies to all street and highway lighting installations owned by any governmental
agency other than the City of Palo Alto.
B. TERRITORY:
Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City.
C. RATES: Per Lamp Per Month
Class A: Utility supplies energy
and switching service only.
kWh's Per Month
Burning Schedule: All Night/Midnight All Night Midnight
Lamp Rating:
Mercury-Vapor Lamps
100 watts 42/20 $ 12.08 $ 8.92
175 watts 68/35 14.41 11.23
400 watts 154/71 29.66 22.87
High Pressure Sodium Vapor Lamps
120 volts
70 watts 29/15 10.59 7.43
100 watts 41/20 14.19 10.36
150 watts 60/30 18.43 15.48
240 volts
70 watts 34/17 11.85 8.92
100 watts 49/25 15.488.59 11.23
150 watts 70/35 18.43 12.72
200 watts 90/45 20.5515.87 16.31
250 watts 110/55 23.3219.50 16.51
310 watts 134/167 27.3224.13 21.60
400 watts 167/84 33.4731.07 24.78 Fluorescent Lamps
40 watts 15/8 4.46 3.60
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
(Continued)
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-2016
Supersedes Sheet No. E-14-2 dated 7-1-2009 Sheet No. E-14-2
Per Lamp Per Month -–
Class C: Utility supplies energy
and switching service and
maintains entire system,
including lamps and glassware.
kWh's Per Month
Burning Schedule: All Night/Midnight All Night Midnight
Lamp Rating:
Mercury-Vapor Lamps
100 watts 42/20 $ 13.56 $ 10.36
175 watts 68/35 16.31 12.91
250 watts 97/49 20.32 15.70
400 watts 154/71 30.2932.58 23.32
Incandescent Lamps
189 watts (2,500 L) 65/32 14.41 11.46
295 watts (4,000 L) 101/5 18.43 14.41
405 watts (6,000 L) 139/70 23.32 19.27
620 watts (10,000 L) 212/106 32.42 26.88
Fluorescent Lamps
25 watts 12/6 5.30 4.04
40 watts 15/8 5.49 4.46
55 watts 18/9 6.36 4.68
High Pressure Sodium Vapor Lamps
120 volts
70 watts 29/15 11.02 7.84
100 watts 41/20 14.82 10.81
150 watts 60/30 19.06 15.91
240 volts
70 watts 34/17 12.2928.61 9.33
100 watts 49/25 16.0930.79 11.85
150 watts 70/35 19.0634.43 13.35
200 watts 90/45 21.18 16.94
250 watts 110/55 23.7441.70 17.38
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
(Continued)
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-2016
Supersedes Sheet No. E-14-2 dated 7-1-2009 Sheet No. E-14-2
Light Emitting Diode (LED) Lamps
70 watts-equivalent 23.79
100 watts-equivalent 25.44
150 watts-equivalent 26.96
250 watts 31.12
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
(Continued)
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-01-2009
Supersedes Sheet No. E-14-2 dated 7-1-20097-01-2008 Sheet No. E-14-2
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
(Continued)
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2009
Supersedes Sheet No. E-14-4 dated 7-1-20097-1-2008 Sheet No. E-14-4
D. SPECIAL CONDITIONS:
1. Type of Service: This schedule is applicable to series circuit and multiple street lighting
systems to which the Utility will deliver current at secondary voltage. Unless otherwise
agreed, multiple current will be delivered at 120/240 volts, three-wire, single-phase. In
certain localities the Utility may supply service from 120/208 volt star-connected poly-phase
lines in place of 240-volt service. Single phase service from 480-volt sources will be
available in certain areas at the option of the Utility when this type of service is practical
from the Utility's engineering standpoint. All currents and voltages stated herein are
nominal, reasonable variations being permitted. New lights will normally be supplied as
multiple systems.
2. Point of Delivery: Delivery will be made to the customer's system at a point or at points
mutually agreed upon. The Utility will furnish the service connection to one point for each
group of lamps, provided the customer has arranged his system for the least practicable
number of points of delivery. All underground connections will be made by the customer or
at the customer's expense.
3. Switching: Switching will be performed by the Utility (on the Utility's side of points of
delivery) and no charge will be made for switching provided there are at least 10 kilowatts of
lamp load on each circuit separately switched, including all lamps on the circuit whether
served under this schedule or not; otherwise, an extra charge of $2.50 per month will be
made for each circuit separately switched unless such switching installation is made for the
Utility's convenience or the customer furnishes the switching facilities and, if installed on the
Utility's equipment, reimburses the Utility for installing and maintaining them.
4. Annual Burning Schedule: The above rates apply to lamps which will be turned on and off
once each night in accordance with a regular burning schedule agreeable to the customer but
not exceeding 4,100 hours per year for all-night service and 2,050 hours per year for
midnight service.
5. Maintenance: The rates under Class C include all labor necessary for replacement of
glassware and for inspection and cleaning of the same. Maintenance of glassware by the
Utility is limited to standard glassware such as is commonly used and manufactured in
reasonably large quantities. A suitable charge will be made for maintenance of glassware of a
type entailing unusual expense. Under Class C, the rates include maintenance of circuits
between lamp posts and of circuits and equipment in and on the posts, provided these are all
of good standard construction; otherwise, the Utility may decline to grant Class C rates.
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
(Continued)
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167-1-2009
Supersedes Sheet No. E-14-4 dated 7-1-20097-1-2008 Sheet No. E-14-4
Class C rates applied to any agency other than the City of Palo Alto also include painting of
posts with one coat of good ordinary paint as required to maintain good appearance but do
not include replacement of posts broken by traffic accidents or otherwise.
6. Multilamp Electroliers: The above charges are made on per-lamp basis. For posts
supporting one or more lamps, where the lamps are less than nine feet apart, the above
charges for Class C will be reduced by 6 percent (6%) computed to the nearest whole cent,
for all lamps other than the first one.
7. Operating Schedules Other Than All-Night and Midnight: Rates for regular operating
schedules other than all-night and midnight will be the midnight rates plus or minus
one-eleventh of the difference between the midnight and the all-night rate, computed to the
nearest whole cent, for each half hour per night more or less than midnight service. This
adjustment will apply only to lamps on regular operating schedules which do not exceed
4,500 hours per year.
8. Street Light Lamps, Standard and Nonstandard Ratings: The rates for incandescent lamps
under Class A are applicable for service to regular street lamps only and must be increased
by 6 percent, computed to the nearest whole cent, for service to group-replacement street
lamps. The rates under Class C are applicable to both regular and group-replacement street
lamps.
9. Continuous Operation: The rate for continuous 24-hour operation under Class A service will
be twice the all-night rate.
10. . System Owned In-Part by Utility : Where, at customer's request, the Utility installs, owns,
and maintains any portion of the lighting fixtures, supports, and/or interconnecting circuits,
an extra monthly charge of one and one-fourth percent of the Utility's estimate of additional
investment shall be made.
11. Rates For Lamps Not on Schedule: In the event a customer installs a lamp which is not
presently represented on this schedule, the Utility will prepare an interim rate reflecting the
Utility's estimated costs associated with the specific lamp size. This interim rate will serve as
the effective rate for billing purposes until the new lamp rating is added to Schedule E-14.
{End}
UNMETERED ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-16
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-201610-16-2012
Supersedes Sheet No.E-16-3 dated 10-16-20127-26-2011 Sheet No. E-16- 1
A. APPLICABILITY:
This rate schedule is applicable under the terms and conditions of the City of Palo Alto
Utilities Department to Customers who contract with the City for unmetered electric
service for billboards, unmetered telephone services, telephone booths, railroad signals,
cathodic protection units, traffic cameras, wireless antenna and related equipment,
community antenna television and video systems, cable TV power supplies, and
automatic irrigation systems and also applies to other miscellaneous Electric Utility fees
to various public agencies and private entities.
B. TERRITORY:
Within the incorporated limits of the City of Palo Alto and land owned or leased by the City.
C. NET MONTHLY BILL:
1. Customer Charge: ............ $9.00 per month
2. Energy Charge:
(for all kWh supplied) using Electric Rate Schedule E2 plus all applicable riders
3. Minimum Charge:
Minimum monthly charge will be the Customer Charge.
D. DETERMINATION OF ENERGY REQUIREMENTS:
a. Initial Inventory
Customer shall enter into a contract for service under this Schedule and provide a written
inventory of all equipment at each of service requested, including the type and nameplate
rating for each piece of equipment. The billing energy for each point of service will be
determined by the Utilities Electric Engineering Division estimation of the kWh usage
based on the type, rating and quantity of the equipment provided by the Customer.
Monthly bill will be based on the following calculations:
1. Total Wattage.
2. Total Wattage times estimated annual operating hours as set in the contract equals
annual watt hours.
3. Annual watt hours divided by 1000 hours equals annual kilowatt hours (kWh)
UNMETERED ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-16
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-201610-16-2012
Supersedes Sheet No.E-16-3 dated 10-16-20127-26-2011 Sheet No. E-16- 2
4. Annual kWh divided by twelve (12) months equal monthly kWh.
5. Monthly kWh times current rate per kWh = monthly bill for each unmetered
service location or equipment.
b. Updating Inventory
Customer will update its inventory by informing the Utilities Electric Engineering
Division in writing of changes in type, rating and/or quantity of equipment as such
changes occur, and billings will be adjusted accordingly. Upon Utilities Electric
Engineering Division request, but no later than the one year anniversary of the date on
which Customer first takes service, Customer shall provide an updated inventory of all
equipment at each point of service.
c. Test Metering
The Utilities Electric Engineering Division may, at its discretion, test meter the load at
various types and ratings of the Customer’s equipment to the extent necessary to verify
the estimated kWh usage used for billing purpose and, where dictated by such test
metering, Utilities Electric Engineering Division will make prospective adjustments in
estimated usage for subsequent billing purposes; however, Utilities shall be under no
obligation to test meter- the load of Customer’s equipment. Utilities’ decision not to test
meter the load of Customer’s equipment shall not release Customer from the obligation to
provide to Utilities Electric Engineering Division, and to update, annually as provided in
section b, an accurate inventory of the types, rating and quantities of equipment upon
which billing is based.
d. Inspection
The Utilities Electric Engineering Division shall endeavor to inspect the equipment at
each point of service annually as close to the anniversary date of the contract as is
practical, and make prospective adjustments in billing as indicated by such inspections;
however, Utilities shall be under no obligation to conduct such inspections for the
purpose of determining accuracy of billing or otherwise. Utilities decisions not to
conduct such inspections shall not release Customer from the obligation to provide to
Utilities Electric Engineering Division, and to update, an accurate inventory of the types,
rating and quantities of equipment upon which billing is based.
e. Billing for Service
As the service described in this schedule is unmetered, Customer agrees to pay amounts
billed in accordance with the current inventory, regardless of whether any of the
installations of the Customer’s equipment were electrically operable during the period in
UNMETERED ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-16
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-201610-16-2012
Supersedes Sheet No.E-16-3 dated 10-16-20127-26-2011 Sheet No. E-16- 3
question and regardless of the cause of such equipment failure to operate.
E. MISCELLANEOUS RATES:
Service Description Rate *
1. Traffic Signal maintenance and energy costs
(A) Controller $522.26 ea
(B) 8" Lamp (LED) $1.85 ea
(C) 12" & PVH Lamp (LED) $2.16 ea
(D) Pedestrian Head (LED) $5.58 ea
(E) Vehicle, System and
Bike Sensor Loop $43.22 ea
21. License Fee for Electric Conduit Usage
(A) Exclusive use $1.94/ft/yr
(B) Non-Exclusive use $0.97/ft/yr
32. Processing Fee for Electric Conduit Usage Actual Cost
43. License Fee for Utility Pole Attachments
(A) 1 ft. of usable space $29.59/pole/yr
(B) 2 ft. of usable space $32.39/pole/yr
(C) 3 ft. of usable space $35.18/pole/yr
(D) 4 ft. of usable space $37.98/pole/yr
54. Processing Fee for Utility Pole Attachments $55.00/pole
65. License Fee for mounting communication equipment
including distributed antenna systems on utility poles $270.00/pole/yr
* Rates are monthly unless otherwise indicated.
F. NOTES:
The fees set forth in Section E.1 through E.65, inclusive, are subject to adjustment annually in
accordance with fluctuations in the Consumer Price Index (CPI), if any. The base for computing
UNMETERED ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-16
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-201610-16-2012
Supersedes Sheet No.E-16-3 dated 10-16-20127-26-2011 Sheet No. E-16- 4
the adjustment is the Consumer Price Index for All Urban Consumers (CPI-U) for the San
Francisco-Oakland-San Jose MSA, which is published by the U.S. Department of Labor,
Bureau of Labor Statistics for the month of December of a base year, which falls within the
year in which a master license agreement is signed by the City and the licensee. The adjustment
shall be calculated, if there is an increase or decrease between December of a base year (when
the rate(s) is/are first applicable) and December of any subsequent base year.
{End}
EXCERPTED DRAFT MINUTES OF THE APRIL 12, 2016
UTILITIES ADVISORY COMMISSION SPECIAL MEETING
ITEM 1: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt 1) a Resolution Approving the Fiscal Year 2017 Electric Financial Plan
and Amending the Electric Utility Reserves Management Practices, and 2) a Resolution
Increasing Electric Rates by Amending the E-1, E-2, E-2-G, E-4, E-4-G, E-4-TOU, E-7, E-7-G, E-7-
TOU, E-14, and E-16 Rate Schedules, and Repealing Rate Schedules E-18 and E-18-G
Senior Resource Planner Jonathan Abendschein summarized the written report. He explained
that distribution and power supply costs are increasing requiring an 11% rate increase this July
followed by a 10% rate increase next year. He said that this is the first rate change since July
2009 and the first electric rate change since the passage of Proposition 26. A cost of service
analysis (COSA) was completed to support the rates and ensure that they are compliant with
Proposition 26. Abendschein reminded that the UAC reviewed, and the Council adopted,
electric rate design guidelines and that the COSA is to be completed in two phases. The first
phase of the COSA is complete and provided tonight with the second phase starting in late 2016
to examine rate options that need further study and may need advanced metering technologies
such as time-of-use rates.
Abendschein said that the projected cost and revenue profile, which reveals that in FY 2015 and
FY 2016, revenues did not cover costs and that costs are increasing due to new renewable
projects coming on line, increases in capital costs and some increases in operations and
maintenance cost related to deferred maintenance and the difficulty filling vacant positions in
the Operations Division. Abendschein said that the drought caused short-term cost increases
that were funded from reserves. Consistent with the purpose of the reserves, the Rate
Stabilization and Hydro Stabilization Reserves were drawn down in FY 2015 and FY 2016 and
are expected to be exhausted by the end of FY 2017. Although staff would have liked to keep
the rate increase under 10%, the level of reserves requires a larger increase this year and, even
with two years of significant rate increases in FY 2017 and FY 2018, the Supply Operations
Reserve falls $3.9 million below the minimum guideline level. Abendschein said that this is
allowed as long as the Council approves and the financial plan shows the reserve climbing
above the minimum level during the planning period. He added that there is uncertainty in the
hydroelectric generation forecast and the spring rains may increase the generation above what
is in the forecast. Abendschein said that the risk of any negative impact to the bond rating by
falling below the minimum guideline level is very small due to the presence of the significant
balance in the Electric Special Projects Reserve, which provides a substantial cushion for the
financial health of the Electric Fund.
ATTACHMENT F
Commissioner Danaher asked what rate increase would be required to keep the Supply
Operations Reserve above the minimum guideline level. Abendschein said that a 14% rate
increase would be required in July 2016 to ensure that the reserve remain above the minimum
level. Abendschein said that the projected 11% and 10% rate increases do a good job matching
revenues to costs over the next several years. If too large of a rate increase is implemented too
early to refill reserves, there could be a need to reduce rates in the future, which is difficult to
explain.
Abendschein said the Electric Distribution Operations Reserve also goes to minimum guideline
level in FY 2016, but is projected to be above the minimum level for the planning horizon
(through FY 2023).
Abendschein explained that a cost of service analysis (COSA) includes three steps: calculation of
the revenue requirement, determination of how much revenue to collect from each customer
class, and design of rates to collect the revenues. The COSA involves examining the
consumption patterns of each customer group. The result of the new COSA is that there is a
different alignment of costs by customer class since the last Electric COSA was performed. This
is caused by changing consumption patterns for each customer group.
Chair Foster asked if the increased costs for the streetlighting and traffic lights would be paid by
the City’s General Fund. Abendschein confirmed this understanding. Chair Foster said that the
cost for streetlighting doesn’t seem like a cost of service in the same sense it does for other
customer classes. He said that the rate impact for the residents and businesses is softened by
hitting the General Fund with these increased costs. Assistant Director said that this is not the
reason the cost allocation realignment is being done, but agreed that this is the effect of the
change.
Commissioner Danaher said that the goal of the COSA is to have a transparent way to see the
costs for each customer group and that this is an appropriate way to show the costs of services
such as streetlighting. Chair Foster said that he is not surprised by the cost, but is worried that
this new expense for the General Fund will result in other priorities not being able to be funded
since the General Fund has limited sources of funds. Commissioner Danaher asked if the
increase cost was driven by the change of streetlights to more efficient LED lamps. Abendschein
said that the revenue requirement was developed by determining all the costs—capital and
operating—that are needed for the streetlighting and traffic signal service. Abendschein said
that Utilities has coordinated very closely with the City’s Office of Management and Budget on
this proposal.
Chair Foster asked about the large increase in the Municipal Rates (Rate Schedule E-18) and
which customers they would impact. Abendschein said that these customers are the City
facilities and that when the E-18 rate is repealed, the facilities will be assigned to an applicable
rate schedule. He said that this utility—the Electric Fund—is the last utility with these special
rate schedules for City facilities. Utilities has coordinated with the Office of Management and
Budget on these changed proposal. Chair Foster asked if the Palo Alto Unified School District is
part of the customer group. Abendschein responded that it is only City facilities such as City Hall
and the Regional Water Quality Control Plant (RWQCP), but does not include the school district.
Abendschein said that the bill impact for each facility depends on the new rate schedule that
they would be assigned to and that some facilities could experience rate increases of 35% or
more, but some, such as the RWQCP, will not as that facility will move to the E-7 rate schedule
which has similar rates to the current E-18 rates. The smaller City facilities that are moved to
the E-2 or E-4 rate schedules will have larger increases.
Abendschein explained that the recommended rate design for residential customers (on Rate
Schedule E-1) is for two tiers, instead of the current three tiers, since the two-tier rate design
most closely matches the cost of service. He added that the proposal includes the addition of a
minimum charge for all customers. Abendschein said that the residential rate design proposal is
to be consistent with the cost of service down to the rate level as required by Proposition 26.
He said that the non-residential rates continue with the same rate design as in current rates.
Commissioner Schwartz recommended reviewing Bluebonnet Electric Cooperative’s website,
which has a good explanation of the components of their electric rates.
Abendschein showed the bill impact of the rate changes for residential (E-1) customers as a
result of collapsing the three tiers to two tiers. The largest users have a lesser increase in
percentage terms.
Commissioner Ballantine asked if next year’s anticipated rate increase of 10% will have a
disproportionate impact on residential customers again. Abendschein said that this year’s
changes rebalance the cost of service relationship between the customer classes and the
changes next year should be more proportionate and not impact one customer group much
differently than any other.
Commissioner Ballantine asked about whether staff evaluated the impact of two-tier vs. three-
tier rates when trying to match the rate structure to the cost of service with respect to the
impact on electric vehicle (EV) charging. Abendschein said that there was not sufficient time to
conduct detailed analysis on the impact on EV charging, but that this will be reviewed in more
detail in Phase 2 of the COSA. Commissioner Ballantine said that with higher EV penetration,
the third tier might need to come back or there is some type of fixed cost when peak daytime
load needs to be expanded to accommodate EV charging. He said that the carrying capacity of
the grid may change as it relates to peak demand, but not necessarily energy. Abendschein said
that the City has a fair amount of excess distribution capacity currently and, even with Palo
Alto’s high penetration of EVs, the impact is still not significant enough to cause cost increases
to the distribution system at this time and there will be sufficient time to adjust to a dramatic
increase in EV penetration, if it actually occurs. Abendschein added that the bulk of the
residential EV charging occurs during the middle of the night and not at the distribution
system’s peak times.
Commissioner Danaher noted that the draft Sustainability and Climate Action Plan encourages
EVs and asked whether EV owners would be pushed into the highest price tier. Abendschein
noted that the rate proposal eliminates the highest priced third tier so the impact on EVs is
reduced from current rates.
Vice Chair Cook said that the community doesn’t like rate increases. However, we have been
blessed with rates that have not changed in 8 years and the rate comparisons show that the
rate increase still results in relatively low rates compared to neighboring utilities. Vice Chair
Cook asked if the rate proposal would result in any discouragement of EVs or of electrification
to reduce GHG emissions. Abendschein said that there are many drivers for electrification and
cost is not necessarily all of it. The rate increase will tend to discourage electrification, but the
elimination of the third tier will encourage electrification. Abendschein noted that gas rates are
projected to increase as well.
Commissioner Ballantine stated that in a recent presentation to the UAC, staff showed that the
economics of solar thermal systems (hot water heating) are challenging. He said that these rate
changes will improve the cost-effectiveness of solar PV, which could push people to use solar
for electricity rather than for its thermal heat. However, this is a less efficient way to use energy
from the sun so this change will push towards thermal use. He said that using heat from the
sun to make heat makes more sense from a physics perspective.
Vice Chair Cook asked whether smart meters will change the cost of service since customers
may adjust their usage based on better information provided to them. Abendschein said that it
was too early to conclude anything since the CustomerConnect program is still underway and
that Phase 2 of the study will show more results as to changing customer behavior that may
change the factors that contribute to the allocation of costs in the cost of service study.
Vice Chair Cook said that the community has enjoyed stable rates for a long time, but will need
to accept the rate increase at this point. He commented that Proposition 26 has taken away
the ability to design rates to some extent, which can be very frustrating. Abendschein reminded
that this is why the rate design guidelines are taken to the UAC for recommendation and the
Council for approval in advance of conducting a new COSA.
Chair Foster asked if the projected 11% in FY 2017, then a 10% rate for FY 2018 followed by a
2% increase in FY 2019 could be spread out more evenly over the those years—for example, 8%
per year in FY 2017 and FY 2018 following by a higher than 2% increase in FY 2019. Abendschein
explained that the reserve would fall far below the minimum in that case. Alternately, the City
would have to cut back on capital improvements or maintenance to reduce cost. Abendschein
referred the Commission to the rapidly escalating costs in FY 2016 and FY 2017 shown in Figure
7 on page 20 of the FY 2017 Electric Financial Plan. He said that rates must follow those costs.
Chair Foster asked how much lower the reserves would go with an 8%, rather than an 11% rate
increase in July. Abendschein said that the reserve would almost be exhausted in that case. He
noted that reducing the increase in FY 2017 and FY 2018 would require a larger increase in FY
2019 and FY 2020 to the extent that rates would then be too high to not only recover costs, but
to refill reserves such that a rate decrease could be needed in the future, which would be
difficult to explain to customers.
Chair Foster would prefer not to hit the General Fund with the cost of streetlights and traffic
lights as he thinks that the General Fund will have to reduce programs and funds elsewhere to
pay the increased cost. He would also like to continue with three tiers for the E-1 rate schedule
to promote conservation. Senior Deputy City Attorney Jessica Mullan said that the streetlights
rates must be based on the cost of providing the services and any alteration to the proposal
must be cost-justified. Chair Foster said that all residents and businesses benefit from
streetlights including businesses and residents. Chair Foster asked how long the streetlight
service has been provided by Utilities as a “freebie”. Assistant Director Jane Ratchye said that
this is the first time that the Electric Fund will be subject to Proposition 26 since the City hasn’t
changed rates since it was effective in 2010. Mullan added that now that the City is adjusting its
electric rates, it is under Proposition 26 and all electric rates must be cost-justified, which is
why the COSA was so careful to make sure that all rates are based on the cost of service.
Commissioner Ballantine agreed that it’s not only City employees that benefit from streetlights,
but the greater city and community—all ratepayers—that benefit. Vice Chair Cook added that
there are many things that are a common good and asked why ratepayers would pay for that
common good and not roads or other services. Commissioner Ballantine said that the City
doesn’t supply electricity to the roads. Chair Foster said that the City has no ability to raise
taxes for this service. Commissioner Schwartz said that it is more transparent to show the true
cost of providing this service and that if the rates for streetlights were not increased to cover
the cost of providing the service, the rest of the electric rates would have to increase even
more. Chair Foster said that of the $12 million revenue increase for this rate increase, $2 million
is for the increased cost of streetlights. Chair Foster asked how the City would be able to cover
these increased costs. Mullan said that she couldn’t speak to the budget process the Council
will go through to balance the budget, but she wanted to clarify that streetlights are an electric
service and that service must be provided at cost-based rates. Chair Foster said that she would
recommend that the City develop a creative way to fund this cost rather than put it on the
General Fund. Commissioner Ballantine said that the changes to the municipal rates (repealing
the E-18 rate schedule) will also add significant costs to the General Fund. Chair Foster agreed
that the hit to the General Fund is not just the $2 million for the streetlights, but an additional
increase for electric service for municipal facilities. Abendschein said that the total impact to
the General Fund is about $2.5 million since the E-18 rate affects some customers who are not
the General Fund (such as the RWQCP). Vice Chair Cook said that he heard earlier that Utilities
staff worked with the City to coordinate this change. He asked if the General Fund expressed
any concerns. Abendschein said that concerns were expressed, but that staff incorporated the
change and included these increased costs when it prepared the City’s financial forecast last
fall.
Commissioner Schwartz asked if there are public hearings to educate the community about the
rate changes and asked if there should be additional communication efforts given the large
increases. Ratchye added that the Utilities Communication Manager has developed a
comprehensive communication plan for the rate increase. Commissioner Schwartz asked if the
UAC can provide suggestions to improve communications.
Chair Foster asked for Commission comment on two versus three tiers for the E-1 Rate
Schedule. Commissioner Schwartz noted that the investor-owned utilities (IOUs) have gone
from five tiers to four and then three and will soon go to two tiers, then to time-of-use (TOU)
rates with no tiers. Abendschein said that it’s nice to be consistent with other utilities, but the
proposal was developed because it is the most consistent with the cost of service.
Commissioner Schwartz commented that a two-tier rate structure is better for EV owners.
Abendschein said that the rates also provide more of an equitable incentive for all customers to
install PV, instead of only high energy users who are in the highest (most expensive) tier. It also
improves the incentive for all customers to increase efficiency.
Commissioner Ballantine noted that the rate impact percentage-wise is the lowest for the
highest users. He said that the first tier increases by 16%, tier two increases by 30%, but the
third tier falls by 3%. Although the model developed these rates, no rate structure can actually
exactly reflect the cost of service. Abendschein said that the model is used to allocate actual
costs and those decisions have to be explainable and fully justifiable—the method does not
involve averaging, or a statistical scenario—and industry standard methodologies were used to
allocate the costs and develop the rates. Commissioner Ballantine asked if there is any way to
re-create a third tier since the percentage difference is so low.
Commissioner Schwartz asked if a larger increase on high energy users—so that their increase
would be comparable to lower energy users—could potentially fund the streetlights. She said
that he higher energy users may be less price sensitive. Abendschein said that the only way to
do that is to find a cost of service nexus with streetlights and noted that we are constrained by
the imperative to develop rates based on the cost of service. He said that when judgement was
used, staff used the judgement to align as close as possible to the policy guidelines established
by Council, but there are many constraints now that there weren’t in the past. Abendschein
said that the need to have cost of service based rates requires that many of the policy decisions
that were made in the past need to be undone.
Commissioner Ballantine asked if residential rates could be seasonal like the non-residential
rates. Abendschein said that the rates effectively do that since the residential class is a winter-
peaking group and the tier one cutoff reflects the summer usage so that the tier two usage is
for winter usage. Commissioner Ballantine said that EV use is not seasonal. Abendschein said
that if seasonal rates were developed for residents, the rates would be higher in the winter
than in the summer.
Chair Foster asked if there were any recommendations before a motion is made. Commissioner
Ballantine said that perhaps a work group could examine the consultant’s work to see if there is
any strategy to use to change the proposal. Chair Foster said that there is a certain frustration
when presented with rates and COSAs since there seems to be very little that can be done.
Chair Foster said that the dropping of the three tiers could be justified. Abendschein said that
the COSA does not justify three tiers.
Chair Foster said that there seems to be little room to not increase the streetlight costs to the
General Fund. Interim Director Ed Shikada mentioned that the General Fund has anticipated
that it needed to fund streetlights and stated that the transition is recommended by the City
Manager. Chair Foster responded that the hit to the General Fund includes not just for
streetlights, but also for the change to Municipal Rates, and asked if there was any source of
funds that the General Fund can use to pay these increased costs. Shikada said that one source
of funds could be the gasoline tax, which could potentially be used for streetlights, but
revenues from that source are diminishing. He also mentioned that a new transportation tax is
being discussed that could be used for keeping streets in good repair. Shikada concluded that
the General Fund is aware of these changes and supports the recommendation that the Electric
Fund no longer funds these services.
ACTION:
Vice Chair Cook moved to recommend that the UAC recommend Council approve staff’s
proposal and Commissioner Schwartz seconded the motion. The motion carried unanimously
(5-0) with Chair Foster, Vice Chair Cook, Commissioners Ballantine, Danaher, and Schwartz
voting yes and Commissioners Eglash and Hall absent.