HomeMy WebLinkAboutStaff Report 11887
City of Palo Alto (ID # 11887)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 4/6/2021
City of Palo Alto Page 1
Summary Title: FY 2022 Electric Financial Plan and Rates
Title: Staff and the Utilities Advisory Commission Request the Finance
Committee Recommend the City Council Adopt a Resolution Approving the
Fiscal Year 2022 Electric Financial Plan and Reserve Transfers, and Amending
Utility Rate Schedules E-EEC-1 (Export Electricity Compensation), E-NSE-1
(Net Surplus Electricity Compensation), E-2-G (Residential Master-metered
and Small Non-residential Green Power Electric Service), E-4-G (Medium
Non-residential Green Power Electric Service, and E-7-G (Large Non-
residential Electric Service)
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission (UAC) request that the Finance Committee
recommend that the City Council adopt a Resolution (Attachment A):
1. Approving the Fiscal Year (FY) 2022 Electric Financial Plan (Linked Document,
Attachment B);
2. Approving a transfer of up to $5 million from the Capital Improvement Project (CIP)
Reserve to the Distribution Operations Reserve at the end of FY 2021;
3. Approving a transfer of up to $1 million from the Supply Operations Reserve to the
Electric Special Projects (ESP) reserve at the end of FY 2021;
4. Approving an allocation of up to $1.19 million from the Cap and Trade Program Reserve
at the end of FY 2021 to be spent on local decarbonization programs;
5. Updating the Export Electricity Compensation (E-EEC-1) rate to reflect current
projections of avoided cost, effective July 1, 2021; (Linked Document, Attachment C)
6. Updating the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect current
projections of avoided cost, effective July 1, 2021; (Linked Document, Attachment C)
and
7. Updating the Palo Alto Green program pass-through premium charge on the Residential
Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the
Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non-
Residential Green Power Electric Service (E-7-G) rate schedules to reflect current costs,
CITY OF
PALO
ALTO
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effective July 1, 2021. (Linked Document, Attachment C)
Executive Summary
The FY 2022 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2026. Staff projects costs for the Electric Utility to increase steadily through the
forecast period. Revenue increases between 0% to 5% are projected to be necessary to keep
revenues in line with expenses over the next five years. Rising transmission costs are the
primary contributor to the increases. A lack of precipitation, if it continues through the winter,
may necessitate utilizing funds from the Hydroelectric Rate Stabilization Reserve starting in FY
2021.
Operations costs are expected to increase at or near the inflation rate (2% to 3% per year)
through the forecast period. Projected capital expenses are higher due to the rebuilding of
existing underground districts, substation, the Foothills rebuild, and line voltage upgrades. The
City is also evaluating the cost and scope of other system resiliency projects, such as pole
replacements, which may increase costs as well as rates in the future.
Electric loads have been gradually decreasing and are expected to continue to decrease in the
long-term, mainly due to declining consumption in the commercial sector, putting gradual
upward pressure on rates. This decline has been exacerbated by the COVID pandemic.
Consumption is currently 5% to 10% below long-term consumption trends. Current models
suggest that pandemic economic recovery will take place through 2021 and 2022, with electric
consumption stabilizing on the long run average by 2023.
Based on the relative health of the various Electric reserve funds, staff is recommending no rate
increase for FY 2022, however this will likely result in reserves falling close to the minimum
guideline levels over the next two to three years.
Background
Every year staff presents the Finance Committee and UAC with Financial Plans for its Electric,
Gas, Water, and Wastewater Collection Utilities and recommends any rate adjustments
required to maintain their financial health. These Financial Plans include a comprehensive
overview of the utility’s operations, both retrospective and prospective, and are intended to be
a reference for UAC, Finance Committee and City Council members as they review the budget
and staff’s rate recommendations. Each Financial Plan also contains a set of Reserves
Management Practices describing the reserves for each utility and the management practices
for those reserves.
The Finance Committee reviewed the preliminary financial forecasts at its February 16, 2021
meeting (Staff Report #118641). The UAC reviewed Staff’s FY 2022 Electric Financial Plan,
proposed transfers and rate changes at its March 3, 2021 meeting.
1 https://www.cityofpaloalto.org/civicax/filebank/documents/80154
City of Palo Alto Page 3
Discussion
Staff’s annual assessment of the financial position of the City’s electric utility is completed in
compliance with cost of service requirements set forth in the California Constitution and
applicable statutory law. The assessment includes making long-term projections of market
conditions, of costs associated with the physical condition of infrastructure, and of other factors
that could affect utility costs. Rates are then proposed that will be adequate to recover
projected costs.
Proposed Actions for FY 2021 and FY 2022:
The FY 2022 Electric Utility Financial Plan includes the following proposed actions:
1. Approving the Fiscal Year (FY) 2022 Electric Financial Plan (Linked Document,
Attachment B);
2. Approving a transfer of up to $5 million from the Capital Improvement Project (CIP)
Reserve to the Distribution Operations Reserve at the end of FY 2021;
3. Approving a transfer of up to $1 million from the Supply Operations Reserve to the ESP
reserve at the end of FY 2021;
4. Approving an allocation of up to $1.19 million from the Cap and Trade Program Reserve
at the end of FY 2021, to be spent on local decarbonization programs;
5. Updating the Export Electricity Compensation (E-EEC-1) rate to reflect current
projections of avoided cost, effective July 1, 2021; (Linked Document, Attachment C)
6. Updating the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect current
projections of avoided cost, effective July 1, 2021; (Linked Document, Attachment C)
and
7. Updating the Palo Alto Green program pass-through premium charge on the Residential
Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the
Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non-
Residential Green Power Electric Service (E-7-G) rate schedules to reflect current costs,
effective July 1, 2021. (Linked Document, Attachment C)
The transfer from the CIP Reserve will help fund CIP projects, keep the Distribution Operations
reserve above minimum guideline levels and balance year to year changes in capital
investment.
The transfer to the Electric Special Projects reserve will work towards repaying the remaining
$5 million of a $10 million short-term loan taken from the ESP reserve in FY 2018, during the
last drought. Repaying the full $5 million in FY 2021, which was part of last year’s financial plan,
is not recommended as the Supply Operations Reserve would likely go below the minimum
guideline level in FY 2023 as a result. Instead, staff anticipates repaying the remaining balance
in $1 million installments between FY 2021 and FY 2025.
The City maintains a Cap and Trade Program Reserve within the Electric fund to hold revenues
from the sale of carbon allowances freely allocated by the California Air Resources Board to the
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City’s electric utility. Cap and Trade Program revenues are restricted to support specifically
carbon reducing activities, including local decarbonization.
In accordance with Council’s August 2020 direction, (Staff Report #11556)2 the City has also
exchanged certain types of renewable energy to take advantage of market conditions to reduce
supply costs, fund electric utility programs and capital investment, and raise funds for local
decarbonization. The revenues received from these REC exchanges are kept in the Electric
Supply Reserve. With this Financial Plan, and as described in Staff Report #11556, staff is
allocating Cap and Trade funds equivalent to 1/3 of the FY 2021 REC Exchange program
revenues, or $1.19 million, for future local decarbonization projects.
Table 1 below shows the effects of the proposed transfers on reserve funds, as well as changes
to the CIP min/max guidelines. The attached Electric Financial Plan (Linked Document,
Attachment B) discusses these reserve changes in greater detail:
2 https://www.cityofpaloalto.org/civicax/filebank/documents/78046
City of Palo Alto Page 5
Table 1: Reserves Starting and Ending Balances, Revenues, Expenses, Transfers To/(From)
Reserves, Operations and Capital Reserve Guideline Levels for FY 2021 to FY 2026 ($000)
FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
Starting Reserve Balances
1 Supply Operations 29,429 25,213 20,120 19,588 23,351 28,131
2 Distribution Operations 9,064 10,808 10,729 10,282 11,415 13,836
3 CIP 5,880 880 880 880 880 9,880
4 Electric Special Projects 46,665 47,665 36,649 30,649 31,649 32,649
5 Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400
6 Low Carbon Fuel Standard 6,340 4,080 3,186 2,164 1,092 524
7 Cap and Trade Program - 1,189 2,190 5,749 9,316 12,866
Revenues
8 Supply 112,482 114,293 118,332 124,988 124,256 124,120
9 Distribution 55,588 59,194 68,325 74,410 77,929 77,179
Transfers
10 Supply Operations (2,189) (2,000) (4,560) (4,567) (4,550) (3,700)
11 Distribution Operations 5,000 - - - (9,000) (3,000)
12 CIP (5,000) - - - 9,000 3,000
13 Electric Special Projects 1,000 1,000 1,000 1,000 1,000 -
14 Hydro Stabilization - - - - - -
15 Low Carbon Fuel Standard - - - - - -
16 Cap and Trade Program 1,189 1,000 3,560 3,567 3,550 3,700
Capital Program Contribution
17 Distribution Operations - - - - - -
18 CIP Reserve
Expenses
19 Supply Expenses (114,509) (117,385) (114,305) (116,658) (114,925) (116,756)
20 Distribution Non-CIP Expenses (36,826) (40,645) (48,033) (41,578) (52,581) (53,466)
21 Planned CIP (22,018) (18,628) (20,739) (31,700) (13,926) (21,284)
22 ESP funded - (12,016) (7,000) - - -
23 Hydro funded - - - - - -
24 LCFS funded (2,260) (893) (1,022) (1,072) (568) (453)
Ending Reserve Balance
1+8+10+19 Supply Operations 25,213 20,120 19,588 23,351 28,131 31,795
2+9+11+17+20+21 Distribution Operations 10,808 10,729 10,282 11,415 13,836 13,265
3+12+18 CIP 880 880 880 880 9,880 12,880
4+13+22 Electric Special Projects 47,665 36,649 30,649 31,649 32,649 32,649
5+14+23 Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400
6+15+24 Low Carbon Fuel Standard 4,080 3,186 2,164 1,092 524 71
7+16 Cap and Trade Program 1,189 2,190 5,749 9,316 12,866 16,566
Operations Reserve Guidelines (Supply)
25 Minimum 17,508 17,981 18,461 19,177 18,892 19,193
26 Maximum 35,017 35,962 36,922 38,353 37,784 38,385
Operations Reserve Guidelines (Distribution)
27 Minimum 9,462 9,513 9,803 10,084 10,257 10,472
28 Maximum 15,128 15,152 15,654 16,138 16,402 16,750
CIP Reserve Guidelines
29 Minimum 5,005 4,700 4,232 3,803 3,635 3,499
30 Maximum 25,025 23,502 21,162 19,017 18,173 19,406
Due to the continuing COVID-19 pandemic and economic hardships created by it, the Utilities
Department has chosen to propose a 0% rate increase option for FY 2022 and no more than 5%
rate increases afterwards. Under this scenario, utility reserves are projected to drop to near
their minimum guideline levels. Possible program and service cuts may be needed to make up
the difference if the utility’s financial position ends up being worse than forecasted, but under
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the assumptions used in this financial plan, existing reserves are anticipated to make up for
revenue shortfalls due to the pandemic’s impacts.
Table 2 below shows the new proposed rate trajectory and compares current rate projections
to those projected in last year’s Financial Plan.
Table 1: Projected Electric Rates, FY 2021 to FY 2025
Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
Current 0% 5% 5% 2% 1%
Last Year 0% 5% 5% 3% 0%
FY 2022 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table 3 shows the projected rate adjustments over the next five years and their impact on the
annual median residential electric bill (453 kwh per month in winter, 365 kwh per month in
summer).
Table 3: Projected Rate Adjustments, FY 2022 to FY 2026
FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
Electric Utility 0% 5% 5% 2% 1%
Estimated Bill Impact ($/mo)* - $3.04 $3.19 $1.34 $0.68
* Estimated impact on median residential electric bill, which is currently $60.70
for CY 2020
The rate increases are related to several factors: increasing transmission costs, the need for
substantial additional capital investment in the electric distribution system, potential low hydro
supply, and increasing operations costs due to larger contracting needs to complete electric
distribution system maintenance work. Revenues have also declined as customer usage has
decreased, requiring larger rate increases to cover fixed expenses and offset the shortfalls.
Historically, total electric utility costs (excluding short-term drought impacts) were roughly
$120 million per year, allowing the electric utility to go without a rate increase from July 1, 2009
to July 1, 2016. Over the period from FY 2016 to FY 2018, though, annual costs (net of energy
supply related revenue, like surplus energy sales) increased to roughly $140 million per year
(costs were unusually low in FY 2019 due to some one-time savings from surplus energy sales).
Costs are currently projected to increase to roughly $160 million by FY 2026 (net of surplus
energy sales).
Figure 1 shows the overall utility’s costs (net of surplus sales revenues) in FY 2016, FY 2022, and
FY 2026. Costs for the electric supply portfolio have decreased slightly between FY 2016 and FY
2022, but much of this is due to surplus electric supply revenues that are not expected to
continue indefinitely as well as the fact that customer sales have declined by 1.5% to 2%
annually during this time. Assuming normal hydro conditions going forward, as well as a
continuing trend of load loss, costs are projected to increase by about 1% annually for the
foreseeable future.
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I I I I I I
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Costs for managing the distribution system (e.g.), maintenance, capital investment, customer
service, billing, etc.) have increased as well, growing by about 3% per year on average in the
past, and projected to grow by nearly 2-4% per year going forward. FY 2022 capital costs are
higher due to the introduction of a large Smart Grid Technologies project, but these costs have
been approved by Council to come from the Electric Special Projects Reserve and will not
impact rates. Comparisons are difficult as FY 2016 capital costs were very low relative to normal
years. Overall, costs are projected to increase by 2% per year over the forecast horizon, but
declining loads will necessitate rate increases greater than this to maintain financial health.
Figure 1: Electric Utility Costs, FY 2016 Actual vs. FY 2022 and FY 2026 Projections
Figure 2 shows electric distribution costs specifically. Capital costs have increased by about 4%
per year on average over the last five years but are skewed in this graph due to a large ($17
million) Smart Grid Technology project budgeted for FY 2022 as well as very low spending
during FY 2016. Going forward, increased costs are related to greater capital investment in the
distribution system (e.g.), underground district rebuilds, as well as substation upgrades). In the
last few years, the City has experienced a higher number of outages in underground districts
due to aging equipment and infrastructure. Distribution system operational spending is
projected to increase by about 3% annually. Some of this is due to projected increases in costs
of labor and materials. While there are higher than anticipated staff vacancies, external
contracts will be used to enable staff to complete necessary electric system maintenance.
180
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FY 2016 FY 2022 Fy 2026
{Projected} {Projected}
■ Electric Distribution ■ Electric Supply
City of Palo Alto Page 8
Figure 2: Electric Distribution Costs, FY 2016 vs. FY 2022 and FY 2026 Projections
While net electric supply portfolio costs stayed relatively stable from FY 2016 to FY 2022, this
was mainly due to surplus energy revenues and decreasing loads driving down generation cost.
Transmission cost increases and, to a lesser extent, operational overhead costs have increased
by 8% annually in the same timeframe, as shown in Figure 3. In the future, staff forecasts that
increased costs will continue largely come from transmission costs. These increases are due to
rehabilitation and replacement of the existing statewide electric transmission system as well as
expansion of that system to accommodate new generation, mostly renewable.
Staff works to contain transmission costs through partner agencies, including the Transmission
Agency of Northern California (TANC) and Northern California Power Agency (NCPA), and
through direct partnerships with other local utilities (the Bay Area Municipal Transmission
group, BAMx). These groups intervene in transmission proceedings at the Federal Energy
Regulatory Commission (FERC) and the California Independent System Operator (CAISO), and
have achieved some reductions in long-term transmission costs. Staff is beginning to look at
strategies to achieve cost savings in electric supply and will discuss these strategies in greater
detail in future meetings.
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FY 2016 FY 2022 (Projected) Fy 2026 (Projected)
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City of Palo Alto Page 10
Table 4: Residential Monthly Electric Bill Comparison (Effective 1/1/2021, $/mo.)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
300 41.27 74.96 36.96
453 (Median) 69.22 113.19 56.50
650 107.37 174.55 81.66
1200 213.89 347.48 151.91
Summer
300 41.27 77.09 36.96
(Median) 365 52.18 97.53 45.27
650 107.37 187.14 81.66
1200 213.89 360.08 151.91
Table 5 shows the average monthly electric bill for commercial customers for various usage
levels.
Table 5: Commercial Monthly Electric Bill Comparison (1/1/2021, $/mo.)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 177 272 185
160,000 24,795 30,804 20,239
500,000 77,477 80,675 63,096
2,000,000 273,431 308,918 252,172
Net Energy Metering Buyback Rates
The City operates two Net Energy Metering (NEM) programs. Solar customers served by the
City of Palo Alto's (CPAU) original NEM program, also called NEM 1, are compensated at retail
rates for electricity they export to the grid, and solar customers served by the NEM successor
program, or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are
compensated at the Export Electricity Compensation (E-EEC-1) rate for exported electricity.
Customers on the NEM 1 program who have chosen to have the value of any annual net
generation they produced over the past 12 months credited back to their account do so under
the Net Metering Net Surplus Electricity Compensation (E-NSE-1) rate, which is calculated using
the utility’s avoided costs from the prior year. The Net Surplus Electricity Compensation rate
represents the value of the City’s avoided costs or value of customer-generated electricity in
Palo Alto during the prior calendar year, including compensation for the energy, avoided
capacity charges, avoided transmission and ancillary service charges, avoided transmission and
distribution (T&D) losses, and renewable energy credits (RECs), or environmental attributes.
Under the City’s NEM successor program, participating solar customers in Palo Alto are billed at
the current retail rate for electricity drawn from the grid, and receive a credit for electricity they
export to the grid at the Export Electricity Compensation (E-EEC-1) buyback rate. This buyback
rate also reflects the avoided cost or value of customer-generated electricity in Palo Alto,
City of Palo Alto Page 11
calculated on a forward-looking basis for the upcoming fiscal year. As shown in the table below,
the current avoided cost for solar generation in Palo Alto is 10.78 cents/kWh, which is slightly
higher than the avoided cost on the current NEM buyback rate (10.09 cents/kWh). This increase
in the overall avoided cost is driven by a small increase in the value of the energy and in the
City’s avoided transmission charges.
Table 6: NEM Compensation Rates – Current vs. Proposed
Rate
Current
$/kWh
Proposed
$/kWh
Export Electricity (E-EEC-1) $0.1009 $0.1078
Net Surplus Electricity (E-NSE-1) $0.0877 $0.0992
Palo Alto Green (PAG) Program
The PaloAltoGreen (PAG) program provides CPAU’s commercial customers an opportunity to
voluntarily pay a premium to receive renewable electricity credits to match their energy usage.
Under this program, CPAU staff purchase and retire Green-e certified renewable energy
certificates (RECs) in the wholesale market on behalf of PAG customers. This enables
participating commercial customers to claim credit for the REC purchases in order to satisfy
their corporate sustainability goals and meet federal “green certification” requirements.
The PAG charge is a pass-through charge; the revenue collected through the PAG rate premium
is intended to fully recover the costs of administering the program. The PAG program has very
low overhead costs (e.g., the cost of hiring an auditor to carry out an annual Green-e
verification process for the program), so the vast majority of the program cost is the purchase
cost of the RECs. In the past year there has been a significant increase in the wholesale cost of
Green-e certified RECs in the Western US market (from approximately $1.50/REC to $6/REC). As
such, the PAG rate premium needs to be raised from $2 per 1,000 kWh block (2 cents/kWh) to
$6 per 1,000 kWh block (6 cents/kWh). This change will be reflected on the Residential Master-
Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-
Residential Green Power Electric Service (E-4-G), and the Large Non-Residential Green Power
Electric Service (E-7-G) rate schedules.
Timeline
The City Council will consider adopting the Financial Plan and rate amendments as part of the
FY 2022 budget review and adoption process. If Council approves the proposed rate changes,
they will become effective July 1, 2021.
Stakeholder Engagement
The UAC reviewed preliminary financial forecasts at its December 2, 2020 meeting (Staff Report
City of Palo Alto Page 12
#116493), and the Finance Committee reviewed the preliminary forecasts at its February 16,
2021 meeting (Staff Report #118644).
The UAC reviewed staff’s recommendation on the FY 2022 Electric Financial Plan, proposed
transfers and rate increases at its March 3, 2021 meeting. At that meeting, Commissioners
inquired whether staffing issues were still a concern with regards to projected CIP work. Staff
responded that CPAU had consultants on contract, were looking at possibly outsourcing project
design work, and that additional field crews were being hired to fill out in-house crews. The
UAC approved staff’s recommendation 6-0, Commissioner Scharff absent.
If approved, the Finance Committee’s recommendation on the FY 2022 Electric rate changes
and transfers will be presented to City Council in June during the budget adoption process.
Resource Impact
The FY 2022 Budget is being developed concurrently with these rates and depending on the
final recommendations from the Finance Committee, adjustments to the budget may be
required. The attached FY 2022 Electric Financial Plan provides a more comprehensive overview
of projected costs and revenue changes for the next five years.
Environmental Review
The Finance Committee’s review and recommendation to Council on the FY 2022 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
• Attachment B: FY22 Electric Financial Plan
• Attachment C: Electricity Compensation Rates
3 https://cityofpaloalto.org/civicax/filebank/documents/79340
4 https://www.cityofpaloalto.org/civicax/filebank/documents/80154
Attachment A
* NOT YET APPROVED *
6055487
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2022 Electric Utility Financial Plan and Reserve Transfers and Amending
Utility Rate Schedules E-EEC-1 (Export Electricity Compensation), E-NSE-1 (Net
Surplus Electricity Compensation Rate), E-2-G (Residential Master-Metered
and Small Non-Residential Green Power Electric Service), E-4-G (Medium Non-
Residential Green Power Electric Service), and E-7-G (Large Non-Residential
Green Power Electric Service)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes making
long-term projections of market conditions, the physical condition of the system, and other
factors that could affect utility costs, and setting rates adequate to recover these costs. It does
this with the goal of providing safe, reliable, and sustainable utility services at competitive rates.
The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
C. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of the
City of Palo Alto may by resolution adopt rules and regulations governing utility services, fees and
charges.
D. On ____, 2021, the City Council heard and approved the proposed rate increase
at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2022 Electric Utility Financial Plan.
SECTION 2. The Council hereby approves the following transfers as described in the
FY 2022 Electric Utility Financial Plan:
1. Approve a transfer of up to $5 million from the Capital Improvement Project
Reserve to the Distribution Operations Reserve;
2. Approve a transfer of up to $1 million from the Supply Operations Reserve to the
Electric Special Project reserve;
Attachment A
* NOT YET APPROVED *
6055487
3. Approve an allocation of up to $1.189 million from the Cap and Trade Program
Reserve for local decarbonization programs.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-EEC-1 (Export Electricity Compensation) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-EEC-1, as amended, shall become effective July 1, 2021.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-NSE-1 (Net Surplus Electricity Compensation Rate) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-NSE-1, as amended, shall become effective
July 1, 2021.
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-2-G (Residential Master-Metered and Small Non-Residential Green Power Electric
Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-2-G, as
amended, shall become effective July 1, 2021.
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-4-G (Medium Non-Residential Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall become
effective July 1, 2021.
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended to read
as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become effective
July 1, 2021.
SECTION 8. The Council makes the following findings:
a. The revenue derived from the adoption of this resolution shall be used only for the
purpose set forth in Article VII, Section 2, of the Charter of the City of Palo Alto.
b. The fees and charges adopted by this resolution are charges imposed for a specific
government service or product provided directly to the payor that are not provided
to those not charged, and do not exceed the reasonable costs to the City of providing
the service or product.
//
//
//
//
//
Attachment A
* NOT YET APPROVED *
6055487
//
SECTION 9. The Council finds that approving the Financial Plan does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources Code
Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental assessment is required. The Council finds that
changing electric rates to meet operating expenses, purchase supplies and materials, meet
financial reserve needs and obtain funds for capital improvements necessary to maintain service
is not subject to the California Environmental Quality Act (CEQA), pursuant to California Public
Resources Code Sec. 21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a).
After reviewing the staff report and all attachments presented to Council, the Council
incorporates these documents herein and finds that sufficient evidence has been presented
setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2022 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2022 TO FY 2026
Attachment B
2 | Page
FY 2022 ELECTRIC UTILITY
FINANCIAL PLAN
FY 2022 TO FY 2026
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 .................................................................................. 8
Section 3: Detail of FY 2021 Rate and Reserves Proposals ....................................................... 8
Section 3A: Rate Design ............................................................................................................... 8
Section 3B: Current and Proposed Rates ..................................................................................... 8
Section 3C: Bill Impact of Proposed Rate Changes .................................................................... 10
Section 3D: Proposed Reserve Transfers ................................................................................... 11
Section 4: Utility Overview .................................................................................................. 12
Section 4A: Electric Utility History ............................................................................................. 12
Section 4B: Customer Base ........................................................................................................ 15
Section 4C: Distribution System ................................................................................................. 15
Section 4D: Cost Structure and Revenue Sources ...................................................................... 16
Section 4E: Reserves Structure ................................................................................................... 17
Section 4F: Competitiveness ...................................................................................................... 18
Section 5: Utility Financial Projections ................................................................................. 19
Section 5A: Load Forecast .......................................................................................................... 19
Section 5B: FY 2015 to FY 2019 Cost and Revenue Trends ........................................................ 21
Section 5C: FY 2019 Results ....................................................................................................... 22
Section 5D: FY 2020 Projections ................................................................................................ 23
Section 5E: FY 2021 – FY 2025 Projections ................................................................................ 23
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 25
3 | Page
Section 5G: Long-Term Outlook ................................................................................................. 31
Section 5H: Alternative Rate Projections ................................................................................... 33
Section 6: Details and Assumptions ..................................................................................... 33
Section 6A: Electricity Purchases ............................................................................................... 33
Section 6B: Operations .............................................................................................................. 35
Section 6C: Capital Improvement Program (CIP) ....................................................................... 36
Section 6D: Debt Service ............................................................................................................ 37
Section 6E: Equity Transfer ........................................................................................................ 38
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 38
Section 6G: Sales Revenues ....................................................................................................... 39
Section 7: Communications Plan .......................................................................................... 40
Appendices ......................................................................................................................... 42
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 43
Appendix B: Electric Utility Reserves Management Practices ................................................... 47
Appendix C: Description of Electric utility Operational Activities .............................................. 52
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 53
4 | Page
SECTION 1: DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a section
of the distribution system operates. The transmission system operates at 115-500 kV,
and this is lowered to 60 kV in the sub-transmission section of the Electric Utility’s
distribution section, then 12 kV or 4 kV in the rest of the distribution system, and
finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum electricity
demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Sub-transmission System: The section of the Electric Utility’s distribution system that operates at
60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115 kV
or more. The voltage at the intersection of the Electric Utility’s distribution system and
PG&E’s transmission system is 115 kV. The Electric Utility does not own or operate any
transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
5 | Page
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Electric Utility for the next FY 2022 - 2026.
This Financial Plan describes how revenues will cover the costs of operating the utility safely over
that time while adequately investing for the future. It also addresses the financial risks facing the
utility over the short term and long term and includes measures to mitigate and manage those
risks.
SECTION 2A: OVERVIEW OF FINANCIAL POSITION
The Electric Utility’s costs are projected to increase by about 2% per year on average from FY
2021 - 2026, as shown in Table 1. The majority of cost is related to electric supply purchases,
which are increasing mainly due to increased transmission costs, and after the projected drop in
consumption in FY 2021 due to the COVID crisis, are projected to grow at an estimated 2.5% per
year on average. Operations and maintenance costs are about one third of total costs and are
projected to increase by about 2% per year on average due to both inflationary as well as salary
and benefits increases. Capital improvement costs are projected to rise steeply in the short term
as the Smart Grid technology project gets underway, then stabilize to between $18 to $20 million
a year thereafter. Ongoing projects will include rebuilds of existing underground districts as well
as substation improvements and voltage conversion projects.
Table 1: Electric Utility Expenses for FY 2020 to FY 2026
Expenses
($000)
FY 2020
(act)
FY 2021
(est) FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
Power Supply
Purchases 90,646 93,402 96,219 98,071 102,284 104,443 106,133
Operations 52,497 60,020 60,762 63,245 64,965 61,611 62,543
Capital Projects 15,540 22,018 30,643 27,739 31,700 13,926 21,284
TOTAL 158,682 175,440 187,624 189,055 198,949 179,980 189,960
Due to the continuing COVID-19 pandemic and economic hardships created by it, the Utilities
Department has chosen to propose a 0% rate increase option for FY 2022 and no more than 5%
rate increases afterwards. Under this scenario, utility reserves are projected to drop to near
their minimum guideline levels. Possible program and service cuts may be needed to make up
the difference, but existing reserves are currently anticipated to make up for revenue shortfalls.
Table 2 below shows the new proposed rate trajectory and compares current rate projections to
those projected in last year’s Financial Plan.
Table 2: Projected Electric Rates, FY 2021 to FY 2025
Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
Current 0% 5% 5% 2% 1%
Last Year 0% 5% 5% 3% 0%
6 | Page
The Electric Utility maintains several reserves for the purposes of rate stabilization, such as the
Hydro Stabilization reserve, which is used to mitigate against both dry and wet hydro conditions.
The Electric Utility also has a CIP Reserve which is used to manage cash flow for capital projects,
and fund capital contingencies such as unexpected spikes in CIP spending which do not merit
separate bond financing.
Table 3 shows the projected reserve transfers over the forecast period. Per Council approval, $10
million was transferred from the Electric Special Projects (ESP) Reserve in FY 2018 to the
Operations Reserve to mitigate higher supply costs due to the drought, the costs of new
renewable energy projects coming online and increasing transmission charges. Any transfers
from the ESP Reserve require Council approval. $5 million was repaid in FY 2020, and staff
anticipates repaying the remaining balance in $1 million installments between FY 2021 and FY
2025. During this time, withdrawals from the ESP Reserve for the Smart Grid Technologies project
will also occur. In addition, in accordance with Council policy, staff will also fund the Cap and
Trade Program Reserve with unspent revenues from the sale of carbon allowances freely
allocated to the electric utility, as directed in Staff Report #11556 .1
Because of the possible economic impacts which may arise because of the ongoing COVID
pandemic, staff is presenting all of these transfers as ‘up to’ amounts. If ending FY 2021 reserves
are adversely impacted and/or FY 2022 outlooks for the Electric Utility change, staff may
recommend transferring smaller amounts, or forgoing some of all of the transfers, as needed to
keep the Operations Reserves within guideline ranges, to the greatest extent possible.
1 https://www.cityofpaloalto.org/civicax/filebank/documents/78046
7 | Page
Table 3: Reserves Starting and Ending Balances, Revenues, Expenses, Transfers To/(From)
Reserves, Operations and Capital Reserve Guideline Levels for FY 2021 to FY 2026 ($000)
FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
Starting Reserve Balances
1 Supply Operations 29,429 25,213 20,120 19,588 23,351 28,131
2 Distribution Operations 9,064 10,808 10,729 10,282 11,415 13,836
3 CIP 5,880 880 880 880 880 9,880
4 Electric Special Projects 46,665 47,665 36,649 30,649 31,649 32,649
5 Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400
6 Low Carbon Fuel Standard 6,340 4,080 3,186 2,164 1,092 524
7 Cap and Trade Program - 1,189 2,190 5,749 9,316 12,866
Revenues
8 Supply 112,482 114,293 118,332 124,988 124,256 124,120
9 Distribution 55,588 59,194 68,325 74,410 77,929 77,179
Transfers
10 Supply Operations (2,189) (2,000) (4,560) (4,567) (4,550) (3,700)
11 Distribution Operations 5,000 - - - (9,000) (3,000)
12 CIP (5,000) - - - 9,000 3,000
13 Electric Special Projects 1,000 1,000 1,000 1,000 1,000 -
14 Hydro Stabilization - - - - - -
15 Low Carbon Fuel Standard - - - - - -
16 Cap and Trade Program 1,189 1,000 3,560 3,567 3,550 3,700
Capital Program Contribution
17 Distribution Operations - - - - - -
18 CIP Reserve
Expenses
19 Supply Expenses (114,509) (117,385) (114,305) (116,658) (114,925) (116,756)
20 Distribution Non-CIP Expense (36,826) (40,645) (48,033) (41,578) (52,581) (53,466)
21 Planned CIP (22,018) (18,628) (20,739) (31,700) (13,926) (21,284)
22 ESP funded - (12,016) (7,000) - - -
23 Hydro funded - - - - - -
24 LCFS funded (2,260) (893) (1,022) (1,072) (568) (453)
Ending Reserve Balance
1+8+10+19 Supply Operations 25,213 20,120 19,588 23,351 28,131 31,795
2+9+11+17+20+21 Distribution Operations 10,808 10,729 10,282 11,415 13,836 13,265
3+12+18 CIP 880 880 880 880 9,880 12,880
4+13+22 Electric Special Projects 47,665 36,649 30,649 31,649 32,649 32,649
5+14+23 Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400
6+15+24 Low Carbon Fuel Standard 4,080 3,186 2,164 1,092 524 71
7+16 Cap and Trade Program 1,189 2,190 5,749 9,316 12,866 16,566
Operations Reserve Guidelines (Supply)
25 Minimum 17,508 17,981 18,461 19,177 18,892 19,193
26 Maximum 35,017 35,962 36,922 38,353 37,784 38,385
Operations Reserve Guidelines (Distribution)
27 Minimum 9,462 9,513 9,803 10,084 10,257 10,472
28 Maximum 15,128 15,152 15,654 16,138 16,402 16,750
CIP Reserve Guidelines
29 Minimum 5,005 4,700 4,232 3,803 3,635 3,499
30 Maximum 25,025 23,502 21,162 19,017 18,173 19,406
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SECTION 2B: SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2021:
1. Approve a transfer of up to $5 million from the Capital Improvement Project (CIP) Reserve
to the Distribution Operations Reserve;
2. Approve a transfer of up to $1 million from the Supply Operations Reserve to the Electric
Special Projects (ESP) reserve; and
3. Approve an allocation of up to $1.189 million from the Supply Operations to the Cap and
Trade Reserve.
Staff proposes the following actions for the Electric Utility in FY 2022:
1. No increase to retail electric rates effective July 1, 2021;
2. Update the Export Electricity Compensation (EEC-1) rate to reflect current projections of
avoided cost, effective July 1, 2021;
3. Update the Net Surplus Electricity Compensation Rate (E-NSE) rate to reflect current
projections of avoided cost, effective July 1, 2021; and
4. Update the Palo Alto Green program pass-through premium charge on the Residential
Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the
Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non-
Residential Green Power Electric Service (E-7-G) rate schedules to reflect current costs,
effective July 1, 2021.
SECTION 3: DETAIL OF FY 2022 RATE AND RESERVES PROPOSALS
SECTION 3A: RATE DESIGN
The Electric Utility’s rates are evaluated and implemented in compliance with cost of service
requirements set forth in the California Constitution and applicable statutory law. This Financial
Plan is based on staff’s assessment of the financial position of the Electric Utility, and updated
using the methodology from the “City of Palo Alto Electric Cost of Service and Rate Study”2
drafted by EES Consulting, Inc. in 2015/16. The COSA is also based on design guidelines adopted
by Council on September 15, 2015 (Staff Report 6061).
SECTION 3B: CURRENT AND PROPOSED RATES
The City adopted the current rates effective July 1, 2019, when CPAU increased electric rates by
8%. As the Utilities Department is currently not recommending a rate change for FY 2022, the
current rates are the same as proposed rates, and are reflected in Table 4 below:
2 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
9 | Page
Table 4: Current and Proposed Electric Rates
Current
Rates
Proposed Rates
(7/1/2020)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.13757 0.13757 No Change -%
Tier 2 Energy ($/kWh) 0.19367 0.19367 - -%
Minimum Bill ($/day) 0.3283 0.3283 - -%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.20853 0.20853 - -%
Winter Energy ($/kWh) 0.14624 0.14624 - -%
Minimum Bill ($/day) 0.8359 0.8359 - -%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.12848 0.12848 - -%
Winter Energy ($/kWh) 0.09946 0.09946 - -%
Summer Demand ($/kW) 28.91 28.91 - -%
Winter Demand ($/kW) 18.97 18.97 - -%
Minimum Bill ($/day) 17.2742 17.2742 - -%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.11432 0.11432 - -%
Winter Energy ($/kWh) 0.07738 0.07738 - -%
Summer Demand ($/kW) 30.69 30.69 - -%
Winter Demand ($/kW) 17.05 17.05 - -%
Minimum Bill ($/day) 42.3648 42.3648 - -%
Net Energy Metering Buyback Rates
The City operates two Net Energy Metering (NEM) programs. Solar customers served by the City
of Palo Alto's (CPAU) original NEM program, also called NEM 1, are compensated at retail rates
for electricity they export to the grid, and solar customers served by the NEM successor program,
or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are compensated at
the Export Electricity Compensation (EEC-1) rate for exported electricity.
Customers on the NEM 1 program who have chosen to have the value of any annual net
generation they produced over the past 12 months credited back to their account do so under
the Net Metering Net Surplus Electricity Compensation (E-NSE) rate, which is calculated using the
utility’s avoided costs from the prior year. The Net Surplus Electricity Compensation rate
represents the value of the City’s avoided cost or value of customer-generated electricity in Palo
Alto, including compensation for the energy, avoided capacity charges, avoided transmission and
ancillary service charges, avoided transmission and distribution (T&D) losses, and renewable
energy credits (RECs), or environmental attributes.
Under the City’s NEM successor program, participating solar customers in Palo Alto are billed at
the current retail rate for electricity drawn from the grid, and receive a credit for electricity they
10 | Page
export to the grid at the Export Electricity Compensation (EEC-1) buyback rate. This buyback rate
also reflects the avoided cost or value of customer-generated electricity in Palo Alto, calculated
on a forward-looking basis for the upcoming fiscal year. As shown in the table below, the current
avoided cost for solar generation in Palo Alto is 10.78 cents/kWh, which is slightly higher than
the avoided cost on the current NEM buyback rate (10.09 cents/kWh). As the table indicates, this
increase in the overall avoided cost is driven by a small increase in the value of the energy and in
the City’s avoided transmission charges.
Table 5: NEM Buyback Rates – Current vs. Proposed
Rate
Current
$/kWh
Proposed
$/kWh
Export Electricity (E-EEC) $0.1009 $0.1078
Net Surplus Electricity (E-NSE) $0.0877 $0.0992
Palo Alto Green (PAGreen) Program
The PaloAltoGreen (PAG) program provides CPAU’s commercial customers an opportunity to
voluntarily pay a premium to receive renewable electricity credits to match their energy usage.
Under this program, CPAU staff purchase and retire Green-e certified renewable energy
certificates (RECs) in the wholesale market on behalf of PAG customers. This enables participating
commercial customers to claim credit for the REC purchases in order to satisfy their corporate
sustainability goals and meet federal “green certification” requirements.
The PAG charge is a pass-through charge; the revenue collected through the PAG rate premium
is intended to fully recover the costs of administering the program. The PAG program has very
low overhead costs (e.g., the cost of hiring an auditor to carry out an annual Green-e verification
process for the program), so the vast majority of the program cost is the purchase cost of the
RECs. In the past year there has been a significant increase in the wholesale cost of Green-e
certified RECs in the Western US market (from approximately $1.50/REC to $6/REC). As such, the
PAG rate premium needs to be raised from $2 per 1,000 kWh block (2 cents/kWh) to $6 per 1,000
kWh block (6 cents/kWh). This change will be reflected on the Residential Master-Metered and
Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green
Power Electric Service (E-4-G), and the Large Non-Residential Green Power Electric Service (E-7-
G) rate schedules.
SECTION 3C: BILL IMPACT OF PROPOSED RATE CHANGES
As no rate change is proposed for July 1, 2021, there is no table showing the impact of rate
changes. For more on comparisons of rates with surrounding agencies, see Section 4F:
Competitiveness below.
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SECTION 3D: PROPOSED RESERVE TRANSFERS
In FY 2018, Council approved a $10 million loan from the Electric Special Projects (ESP) reserve,
and this financial plan includes full repayment by FY 2025. The pace of payback may be
moderated based upon the general financial health of the electric fund. $5 million was repaid in
FY 2020, and this financial plan assumes repayment of the remaining $5 million in $1 million
installments by FY 2025.
In addition, and based upon the actual ending balances of the Supply and Distribution Operations
Reserves for FY 2021, staff requests withdrawing up to $5 million from the Capital Improvement
(CIP) Reserve to both fund CIP projects and keep the Distribution Operations fund above
minimum guideline levels. Staff further intends to add funds in the CIP reserve in future years, to
keep its balance within guideline levels and to fund contingencies such as projected higher future
CIP needs and costs.
The City maintains a Cap and Trade Program Reserve within the Electric fund to hold revenues
from the sale of carbon allowances freely allocated by the California Air Resources Board to the
City’s electric utility. Cap and Trade Program revenues are provided to the electric utility to
support a wide variety of carbon reducing activities, including local decarbonization. In
accordance with Council policy, staff will fund the Cap and Trade Program Reserve with unspent
revenues from the sale of carbon allowances freely allocated to the electric utility, as directed in
Staff Report #11556 .3
In accordance with Council’s August 2020 direction, (Staff Report #11556)4 the City has also
exchanged certain types of renewable energy to take advantage of market conditions to reduce
supply costs, fund electric utility programs and capital investment, and raise funds for local
decarbonization. The revenues received from these REC exchanges are kept in the Electric Supply
Reserve. With this Financial Plan, and as described in Staff Report #11556, staff is allocating Cap
and Trade funds equivalent to 1/3 of the FY 2021 REC Exchange program revenues, or $1.189
million, for future local decarbonization projects.
Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E:
FY 2022 – FY 2026 Projections show the impact of these transfers on reserves levels. Table 5
shows the projected balance of each of the Electric Utility reserves for the period covered by this
Financial Plan. See also: Appendix A: Electric Utility Financial Forecast Detail
3 https://www.cityofpaloalto.org/civicax/filebank/documents/78046
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Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2019 to FY 2025
Ending Reserve
Balance ($000)
FY 2020
(Act.) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
Re-appropriations - - - - - - -
Commitments 3,519 3,519 3,519 3,519 3,519 3,519 3,519
Low Carbon Fuel
Standard (LCFS) 6,340 4,080 3,186 2,164 1,092 524 71
Cap and Trade - 1,189 2,190 5,749 9,316 12,866 16,566
Underground Loan 727 727 727 727 727 727 727
Public Benefits 1,905 2,664 3,435 4,275 5,101 5,861 6,575
Special Projects 46,665 47,665 36,649 30,649 31,649 32,649 32,649
Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400 15,400
Capital 5,880 880 880 880 880 9,880 12,880
Rate Stabilization - - - - - - -
Distribution and
Supply Operations 38,494 36,192 30,832 29,629 33,771 39,372 42,368
Unassigned - - - - - - -
TOTAL 118,928 112,314 96,817 92,991 101,454 120,798 130,754
SECTION 4: UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4A: ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel engine
in 1914 due to rising fuel oil costs. As the population and the demand for electricity continued to
grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E proved more
economical than the diesel engines, and by the late 1920s CPAU was using its own diesel engines
only during peak demand periods. At that time CPAU owned 45 miles of distribution lines and
the City used 9.7 GWh annually, less than 1% of today’s annual consumption. The diesel engines
remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did throughout
the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the sales in 1950
(30 GWh). Some of that growth was related to a development boom in Palo Alto, which doubled
the number of customers. Some was related to the proliferation of electric appliances, as
evidenced by the fact that residential customers were using three times more electricity in 1970
than they had been in 1950. But the most notable factor was the growth of industry in Palo Alto
during that time. By 1970, commercial customers were using 20 times more electricity per
13 | Page
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.
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 Utility5 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
5 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
14 | Page
to balance the monthly and annual variability of CVP generation. The new contract would provide
only a third of Palo Alto’s requirement, and the monthly and annual variability in CVP generation
would be passed directly to Palo Alto. As a result, electric supply costs would increase and CPAU
needed to more actively manage its supply portfolio. CPAU began purchasing power from
marketers and also investigated building a power plant in Palo Alto or partnering in the
development of a gas-fired power plant elsewhere. Climate change was also becoming more of
a concern to the community, and gradually CPAU shifted its focus to the procurement of
renewable energy. In 2002 the Council adopted a goal of achieving 20% of its energy supply from
renewables by 2015. Subsequently the City signed its first contract for renewable power, a
contract for energy from a wind generator commencing deliveries in 2005. In 2011 the renewable
energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a plan to make
its electric supply 100% carbon neutral, which it achieves through the combination of its carbon-
free hydroelectric supplies, purchases of long-term renewable energy supplies, and short-term
renewable energy purchases (RECs) to meet the balance of its needs.
15 | Page
SECTION 4B: CUSTOMER BASE
The City of Palo Alto’s Electric Utility
provides electric service to the
residents, businesses, and other
electric customers in Palo Alto. There
are roughly 29,800 customers
connected to the electric system,
25,700 (86%) of which are residential
and 4,100 (14%) of which are non-
residential. Residential customers
consumed 152 gigawatt-hours (GWh)
in FY 2020, approximately 18% of the
electricity sold, while non-residential
customers consumed 82% or 703 GWh.
Residential customers use electricity
primarily for lighting, refrigeration,
electronics, and air conditioning.6 Non-residential customers use the majority of their electricity
for cooling, ventilation, lighting, office equipment (offices), cooking (restaurants), and
refrigeration (grocery stores).7
As shown in Figure 1, Large customer loads represent the biggest proportion of sales for the
Electric Utility. The proportion of sales to large vs. small customers is greater than for the City’s
other utilities. For example, the largest customers (the 70 customers on the E-7 rate schedule)
account for around 43% of CPAU’s sales. The next largest customer group (the 890 non-
residential customers on the E-4 rate schedule) represents another 33% of sales. In total, that
means that about 3% of customers account for nearly three quarters of the electric load.
SECTION 4C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 472 miles of
distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are
underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line
transformers, around 1,100 underground and substation transformers, and the associated
electric services (which connect the distribution lines to the customers’ homes and businesses).
These lines, substations, transformers, and services, along with their associated poles, meters,
and other associated electric equipment, represent the vast majority of the infrastructure used
to deliver electricity in Palo Alto.
6 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
7 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
Figure 1: Customer Consumption By Class (FY 2020)
18%
6%
33%
43%Residential
Small Comm.
Med. Comm.
Large Comm.
16 | Page
SECTION 4D: COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 57% of the Electric Utility’s
costs in FY 2020. Operational costs
represented roughly 33%, 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. Staff projects commodity supply costs to be
approximately 56% of total costs in FY 2026.
While average year purchase
costs for the electric utility
are predictable due to its
long-term contracts,
variability in hydroelectric
generation can result in
increased or decreased costs.
This is by far the largest
source of variability the
utility faces. Figure 3 shows
the difference in costs under
high, projected, and low
hydroelectric generation scenarios for FY
2020. Additional costs associated with a
very low generation scenario can range
from $9-11 million per year. For the
current hydroelectric risk assessment see
Section 5F: Risk Assessment and Reserves
Adequacy.
As shown in Figure 4 the Electric Utility
receives 79% of its revenue from sales of
electricity and the remainder from
connection fees, interest on reserves, cost recovery transfers from other funds for shared
services provided by the electric utility, accounting entries that reflect things such as CPAU’s
participation in a pre-funding program associated with its contract with WAPA, revenues from
Figure 2: Cost Structure (FY 2020)
57%
33%
10%
Commodity Supply
Operations
Capital
Figure 3: Hydroelectric Variability (FY 2020)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 4: Revenue Structure (FY 2020)
79%
21%
Sales of Electricity
Other Revenue
17 | Page
sales of surplus hydroelectric energy during wet years, as well as LCFS and Cap and Trade
revenues. Appendix A: Electric Utility Financial Forecast Detail shows more detail on the utility’s
cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 960 largest customers, which provide a similar share of the utility’s revenue stream.
About 25% of the utility’s revenue comes from peak demand charges on large non-residential
customers. Due to moderate weather and the prevalence of natural gas heating, however, loads
(and therefore revenues) are very stable for this utility, without the large seasonal air
conditioning or winter heating loads seen at some other utilities.
SECTION 4E: RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of contingencies
and for ease of reporting. It also maintains two funds, the Supply Fund and the Distribution Fund,
to manage costs associated with electricity supply and electricity distribution, respectively. The
City established this separation of supply and distribution costs as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) in the late 1990s and
early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues to maintain
separate funds to facilitate separation of supply and distribution costs in the rates. This could be
important if California ever decides to broadly reintroduce Direct Access, and is useful for rate
design as the nature of utility services evolves in response to higher penetrations of distributed
generation. Thus, individual reserves may reside within a particular fund (for instance, Electric
Special Projects is under Electric Supply) or be included within both funds (there are both Supply
and Distribution Reserves for Commitments).
The summary below describes the various reserves, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserves for Commitments: Reserves equal to the utility’s outstanding contract liabilities
for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserves for Reappropriations: Reserves for funds dedicated to projects re-appropriated
by the City Council, nearly all of which are capital projects. Most City funds, including the
General Fund, have a Re-appropriations Reserve. This is currently an important reserve
for all utility funds, but changes in budgeting practices will change that in future years, as
described in Section 3C (Reserves Management Practices).
• Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which was accumulated during deregulation of California’s electric system to
fund the stranded costs associated primarily with the Calaveras hydroelectric resource
and the California-Oregon Transmission Project. When that reserve was no longer needed
for that purpose, the reserve was renamed and the purpose was changed to fund projects
with significant impact that provide demonstrable value to electric ratepayers.
18 | Page
• 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.
• Cap and Trade Program Reserve: This reserve tracks unspent or unallocated revenues
from the sale of carbon allowances freely allocated by the California Air Resources Board
to the electric utility, under the State’s Cap and Trade Program. Funds in this Reserve are
managed in accordance with the City’s Policy on the Use of Freely Allocated Allowances
under the State’s Cap and Trade Program.
• Low Carbon Fuel Standard (LCFS) Reserve: This reserve tracks revenues earned via the
sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City,
in accordance with California’s Low Carbon Fuel Standard program.
• Public Benefits Reserve: CPAU’s electric rates include a separate charge called the “Public
Benefits Charge” which generates revenue to be used for energy efficiency, demand-side
renewable energy, research and development, and low-income energy efficiency
services. Any funds not expended in the current year are added to the Public Benefits
Reserve for use in future years.
• Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to accumulate
funds for future expenditure on CIP projects, as well as to manage cash flow for ongoing
capital projects. This reserve can also act as a contingency reserve for unforeseen capital
expenses. This type of reserve is used in other utility funds (Water, Gas, and Wastewater
Collection) as well.
• Supply and Distribution Rate Stabilization Reserves: These reserves are intended to be
empty unless one or more large rate increases are anticipated in the forecast period. In
that case, funds can be accumulated to spread the impact of those future rate increases
across multiple years. This type of reserve is used in other utility funds (Gas, Wastewater
Collection, and Water) as well.
• Supply and Distribution Operations Reserves: These are the primary contingency
reserves for the Electric Utility, and are used to manage yearly variances from budget for
operational costs and electric supply costs (aside from variances related to hydroelectric
generation). This type of reserve is used in other utility funds (Gas, Wastewater Collection,
and Water) as well.
• Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves
are for any financial resources not assigned to the other reserves and are normally empty.
SECTION 4F: COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2020 was
$728 under current CPAU rates, about 37% lower than the annual bill for a PG&E customer with
the same consumption and approximately 19% higher than the annual bill for a City of Santa Clara
customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X, which
includes most surrounding comparison communities.
19 | Page
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, 2021.
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.
Table 6: Residential Monthly Electric Bill Comparison (Effective 1/1/2021, $/mo.)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
300 41.27 74.96 36.96
453 (Median) 69.22 113.19 56.50
650 107.37 174.55 81.66
1200 213.89 347.48 151.91
Summer
300 41.27 77.09 36.96
(Median) 365 52.18 97.53 45.27
650 107.37 187.14 81.66
1200 213.89 360.08 151.91
Table 7 shows the average monthly electric bill for commercial customers for various usage levels.
Table 7: Commercial Monthly Electric Bill Comparison (1/1/2021, $/mo.)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 177 272 185
160,000 24,795 30,804 20,239
500,000 77,477 80,675 63,096
2,000,000 273,431 308,918 252,172
SECTION 5: UTILITY FINANCIAL PROJECTIONS
SECTION 5A: LOAD FORECAST
Figure 5 shows a 36-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. In recent years, some larger commercial customers have relocated operations or
shifted to more commercial type usage. It is unknown how long this trend may continue, or what
20 | Page
the longer term impacts of COVID and work-from home policies might mean for commercial
utilization in Palo Alto.
Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2026. The solid black straight
line is the long term average trend of usage.
The small-dash red line estimates the estimated drop in consumption due to the ongoing COVID
response and is what was used for the current 0% scenario. Staff worked with Northern California
Power Agency to incorporate UCLA’s Anderson School GDP forecast to estimate the impact of
the COVID-19 pandemic. Based upon the forecast and the electricity load impact to date, the
UCLA GDP forecast was added to capture the effect of the large and sharp COVID-19 recession
through December of 2022. After this, the assumption is that sales will resume to at a level
slightly below the long-term trend line. However, these projections will be revised if continuing
sales patterns indicate further declines or increases, or changes in customer mix occur.
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Figure 6: Forecasted Electricity Consumption
SECTION 5B: FY 2016 TO FY 2020 COST AND REVENUE TRENDS
As shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail, the
annual expenses for the Electric Utility remained fairly stable between FY 2015 and FY 2017 but
increased in FY 2018. On the capital side, the large Upgrade Downtown CIP project got underway
in FY 2018, which was a much larger project than usual. Electric supply costs increased as new
renewable projects came online, and transmission costs rose and have continued to rise as
improvements are made to the overall California grid.
Section 6A: Electricity Purchases discusses the factors influencing Electric Utility expenses. Since
FY 2012, total expenses for the utility have included the costs of renewable resources coming
online. In FY 2014 through FY 2015 commodity costs were higher due to lower than average
output from hydroelectric resources. Transmission costs have increased, as projected in prior
financial plans. Better than average hydro conditions in FY 2019 led to lower than expected
generation expenses as well as better than expected surplus energy revenues.
Commodity costs have increased, on average, by about 4.6% per year over this timeframe.
Operations costs have increased by about 2% annually on average. Revenues have increased on
average by about 6% per year over this period, although FY 2018 sales revenues were lower than
projected due to declining sales, and FY 2020 sales have been impacted by COVID.
Actual Projection
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2019 and Projections through FY 2025
SECTION 5C: FY 2020 RESULTS
FY 2020 saw lower sales than expected with the onset of the COVID pandemic, but other
revenues (such as surplus energy sales) came in higher, offsetting the loss. Net purchase costs
came in slightly higher than budget, and while O&M costs came in lower than projected,
administrative and overhead costs came in higher. The net effect to the Operating Reserves were
that they were $400,000 lower than estimated in the FY 2021 financial Plan.
Table 8 FY 2020, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues lower than forecast $983 Revenue decrease
Surplus sales, interest, and other income higher
than expected
(1,068) Revenue increase
Higher net purchase cost 435 Cost increase
Higher operating expense 50 Cost increase
Net Cost / (Benefit) of Variances $400
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SECTION 5D: FY 2021 PROJECTIONS
Last year, staff recommended (and Council approved) no rate change for July 1, 2020. Sales are
still declining but not as fast as projected earlier, and staff is estimating $4.8 million higher sales
for FY 2021. Purchase costs are projected to increase by about $5.4 million, mainly due to poor
projected hydro conditions. Other revenues are projected to be about $2.7 million higher,
primarily from increasing EMA/Market sales (sales of surplus energy) as well as REC sales
revenue. A revised operations cost outlook increased projected expenses by about $3.6 million
compared to the FY 2020 Financial Plan, mainly from revised administration costs as FY 2020
actuals were higher. Programs funded by the City’s LCFS budget increased as well. With the
increased sales outlook, net purchase costs are expected to be $5.4 million higher.
Table 9 FY 2021, Change in Projected Results, 2022 Forecast vs. 2021 Forecast ($000)
Net Cost/(Benefit) Type of change
Modified reserve transfers (5,156) Operations
Reserve increase
Sales revenues higher than forecasted (4,834) Revenue increase
Wholesale and other revenues higher than forecast (2,690) Revenue increase
Purchased electricity costs higher than forecasted 5,440 Cost increase
Operations costs 3,630 Cost decrease
Net Cost / (Benefit) of Variances to Ops Reserve ($3,610)
SECTION 5E: FY 2022 – FY 2026 PROJECTIONS
As shown in Figure 7 above, staff projects costs for the Electric Utility to increase at a fairly steady
rate through the forecast period. Revenue increases between 0% to 5% are projected to keep
revenues in line with expenses over the next five years. Rising electricity purchase costs are the
primary contributor to the increases. Electricity purchase costs are increasing substantially, as
transmission costs rise to make improvements to the California grid. Operations costs are
expected to increase at or near the inflation rate (2-3%/year) through the forecast period.
Projected capital expenses are higher due to the rebuilding of existing underground districts,
substation and line voltage upgrades. The City is also evaluating the cost and scope of other
system resiliency projects, such as pole replacements, which may increase costs as well as rates
in the future.
The forecast also assumes the Smart Grid project to bring advanced metering to the Electric, Gas
and Water utilities will start with $12 million in FY 2022 and additional $7 million in FY 2023.
Funding for this project will come out of the Electric Special Projects reserve, as can be seen in
Figure 8 below and in Appendix A: Electric Utility Financial Forecast detail.
Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund
Reserves) and Figure 9 (for Distribution Fund Reserves), below.
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Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2020 and Projections through FY 2026
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Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2020 and Projections through FY 2026
SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two primary contingency reserves, the Supply Operations
Reserve and the Distribution Operations Reserve. In the past, the Supply and Distribution funds
had Rate Stabilization Reserves (RSR) but both have been drawn to zero, as approved in prior
financial plans. In addition, the Electric Utility has a Hydro Stabilization reserve, an Electric Special
Projects reserve and a Capital reserve, which can be utilized with prior Council approval.
This Financial Plan maintains reserves above the reserve minimum for the Distribution
Operations Reserve throughout the forecast period. Reserve levels also exceed the short-term
risk assessment level for the Distribution Fund. The Supply Operations Reserve is also currently
within guideline levels.
There are a variety of risks associated with the Supply Fund as are shown in Table 10. Because of
the high range of uncertainty in energy price predictions more than three years in the future, this
risk assessment is only performed for the first two fiscal years of the forecast period. It is
important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 10 is very low.
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Table 10: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of
Adverse
Outcomes (M$)
Estimates of
Adverse
Outcomes (M$)
FY 2022 FY 2023
1. Load Net Revenue 3.1 3.2
2. Hydro Production:
Western & Calaveras 4.8 4.6
3. Renewable Production:
Landfill & Wind & Solar 1.8 1.8
4. Carbon Neutral Cost 0.9 0.9
5. REC Sales 1.5 1.8
6. Market Price 0.3* 0.8**
7. Resource Adequacy 1.6 1.4
8. Transmission/CAISO 3.7~ 3.9~
9. Plant Outage 1.0 1.0
10. Western Cost 1.6 1.6
11. Legislative & Regulatory 0.0 0.0
12. Supplier Default 0.2† 0.2†
Electric Supply Fund Risks $ 20.5 million $ 21.0 million
Of the risks faced by the Electric Utility’s Supply Fund, the risk of a dry year with very low
hydroelectric output is normally the largest, accounting for nearly one-third ($4.8 million) of all
the adverse cost uncertainty. Since the utility’s costs for its hydroelectric resources are almost
entirely fixed, costs do not decline when the output of those resources are low, but the utility
needs to buy power to replace the lost output. The converse happens when hydroelectric output
is higher than average.
Of the remaining risks for FY 2022, $3.7 million is related to potential transmission cost increases
(above staff’s current forecast). $3.1 million is related to the potential that total load (and the
associated retail sales revenue) may be lower than projected, $1.8 million is associated with
uncertainty around renewables production, and $1.6 million is associated with possible
decreases in Resource Adequacy capacity sales revenues (and/or increases in Resource Adequacy
capacity purchase costs).
As shown in Figure 10, staff projects the Supply Operations Reserve to remain slightly above the
minimum guideline levels, dropping to its lowest in FY 2023 but recovering to target levels by FY
2026. Figure 11 shows that the combined Hydro Stabilization, Supply Rate Stabilization and
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Supply Operations Reserves are projected to be above what is needed for the risk assessment
level.
Figure 10: Electric Supply Operations Reserve Adequacy
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Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 11 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2026. As shown in Figure 12, the Distribution Operations Reserve is also projected
to drop near to the minimum reserve guidelines in FY 2023, but is projected to recover to near
target levels over the course of the forecast period. The risk assessment includes the revenue
shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
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Table 11: Electric Distribution Fund Risk Assessment ($000)
FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
Total non-commodity revenue $55,969 $62,474 $67,870 $71,707 $71,475
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $4,417 $4,931 $5,357 $5,659 $5,641
CIP Budget $30,643 $27,739 $21,700 $13,926 $21,284
CIP Contingency @10% $3,064 $2,774 $2,170 $1,393 $2,128
Total Risk Assessment value $7,482 $7,705 $7,527 $7,052 $7,770
Figure 12: Electric Distribution Operations Reserve Adequacy
The Electric Utility also has a Capital Improvement Program (CIP) Reserve that acts as a reserve
for short term capital contingencies or as a place to set aside funds for large, one-time projects
that the Utilities would otherwise need to debt-fund. In the future, staff would also like to use
this reserve to manage cash flow for capital projects on an ongoing basis as well.
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Figure 13 below reflects the maximum and minimum CIP Reserve guideline levels, starting in FY
2021. Because of the fluctuating annual dollar amounts and timing of CIP projects budgeted to
occur during the forecast period, as well as the potential for new ongoing projects to be included
in the CIP plan in later years, four years of budgeted CIP is used to calculate the reserve maximum
levels. The minimum CIP Reserve level is 20% of the maximum CIP Reserve guideline level.
Because of constrained operating conditions resulting from the COVID epidemic and a desire not
to raise rates too quickly, the 2022 Financial Plan doesn’t anticipate funding the CIP Reserve from
the Distribution Operations Reserve until FY 2025 ($9 million). In future years, the CIP Reserve
will reflect actual fluctuations in CIP expenditures (money spent on actual projects in a given
year). CIP expenditures are currently reflected in the Operations Reserve. Staff is anticipating,
once the CIP Reserve has an adequate ending balance, to annually fund the CIP reserve with an
amount based on average anticipated CIP spending for that year (currently estimated at $18 to
$19 million annually, but subject to change as new projects are added), and have any cost savings
or over-runs be reflected in the CIP Reserve instead of the Operations Reserve, as described
above. This will allow for better transparency and accounting of CIP related funds, will address
uneven annual funding associated with ongoing CIP projects, and offer a funding source for one-
time or immediately needed projects. Having the reserve guidelines in place will ensure the
reserve has sufficient funding for budgeted CIP as fluctuating annual amounts of capital
investment occur going forward.
Figure 13 shows the projected CIP Reserve balances and guideline levels for FY 2021 through FY
2026, as well as the prior reserve and guidelines in FY 2020. Because of constrained financial
conditions, the CIP reserve is projected to be below the minimum guideline for a few years, until
reserve funding can take place.
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Figure 13: Electric CIP Reserve Adequacy
SECTION 5G: LONG-TERM OUTLOOK
This forecast covers the period from FY 2022 through FY 2026, but various long-term
developments may create new costs for the utility over the next 10 to 35 years. While it is
challenging to accurately forecast the impact these events will have on the utility’s costs, it is
worth noting them as future milestones and keeping them in mind for long-term planning
purposes.
For the supply portfolio, the 2020s will see a number of notable events. The contract with
Western for power from the CVP will expire in 2024. Determining the future relationship with
Western after 2024 will be important in the years leading up to the contract expiration, especially
because this resource represents nearly 40% of the electric portfolio and is the utility’s largest
source of carbon-free electricity. The utility’s three earliest and lowest cost renewable contracts
will also begin expiring around that time, with the first contract expiring in 2021 and the last in
2028. These three contracts, plus one more expiring in 2030, currently provide 17% to 18% of the
energy for the utility’s supply portfolio at prices under $65 per megawatt-hour (MWh). It is
difficult to know what renewable energy prices will be when those contracts expire. Although
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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 .
Some additional debt may be issued to fund the costs of relicensing the project, but this is not
anticipated to be as high as the current debt service. The project will only be 40 years old at that
time, and hydroelectric projects can last for 70-100 years before major rebuilding is needed.
Calaveras debt service represents roughly 70% of the annual costs of that project (and nearly 7%
of the utility’s total costs), so when the debt is retired, the project could be a low-cost asset for
the utility, providing carbon-free energy equal to around 13% of the Electric Utility’s supply needs
in an average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to $5 million per year in revenue from allocated
carbon allowances under the State’s cap-and-trade program. It uses that revenue to pay for
energy efficiency programs and to purchase renewable energy to support the utility’s Carbon
Neutral Plan. Staff expects that revenue source to continue through 2020. However, discussions
at the state level are ongoing and will determine whether or not these allocations continue till
2030, as well as any further restrictions CARB may wish to enact on usage of allocation sales
revenues. If the Electric Utility no longer received these allowances or was limited in how it could
spend revenues, it would have to fund these programs from sales revenues.
Transmission costs are also continuing to rise. If the State continues to increase mandates or
incentives for renewable energy development, integrating these new projects into the
transmission grid will be an ever-increasing challenge, some costs of which will be borne by Palo
Alto. The planned expansion of the CAISO to a larger regional grid control area may result in
additional transmission costs that could further increase CPAU’s transmission costs. In addition
to the costs of new transmission lines that will need to be built, flexible resources will be required
to balance rapid changes in wind or solar output throughout the day. Palo Alto will likely bear
some of the costs of these new lines and resources. CPAU is also currently investigating installing
a second transmission interconnection for Palo Alto, which could be funded by the Electric Special
Projects Reserve.
Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these factors
may begin to create notable increases in electric consumption and have a variety of impacts on
the distribution system. As housing stock is turned over, however, stricter building codes may
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help to counteract load growth, as may increasing numbers of rooftop solar installations. The
utility has already started to take some of these factors into account in its long-term planning
processes but will need to continue to incorporate them into its planning methodologies.
Over the long term, electricity may replace natural gas and petroleum almost entirely as part of
the City’s efforts to combat climate change. Many, if not most, vehicles would use electricity,
though hydrogen is another potential fuel source under development and other technologies
might be developed. Staff are undertaking initial analysis of these types of scenarios in the
context of the Sustainability and Climate Action Plan (S/CAP) development process. These types
of scenarios require careful planning for the associated load growth to make sure the distribution
system does not end up overloaded, or conversely, to avoid over investment, and the evaluation
of changes to utility distribution system management to accommodate integration of the various
technologies involved in electrification.
SECTION 5H: ALTERNATIVE RATE PROJECTIONS
Staff has no alternative projections at this time.
SECTION 6: DETAILS AND ASSUMPTIONS
SECTION 6A: ELECTRICITY PURCHASES
As shown in Figure 14 the utility gets roughly 50% of its energy from hydroelectric projects in a
normal year (FY FY2015 was dry). Contracts with renewable sources made up just over 30% of
the portfolio in FY 2016, and 50% in FY 2017. Staff expects contracts with renewable sources to
continue at approximately 50% of the portfolio for the forecast period. The remainder comes
from unspecified market sources. Under the City’s Carbon Neutral Plan, CPAU purchases RECs
corresponding to the amount of market energy it purchases.
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Figure 14: Electricity Supply by Source
Figure 15 shows the historical and projected costs for the electric supply portfolio,8 as well as
average and actual hydroelectric generation.9 Electric supply costs increased in FY 2013, FY 2014,
and FY 2015 due to the drought, which reduced the amount of generation from hydroelectric
resources. Costs decreased slightly in FY 2016 due to better than expected market purchase
costs, and FY 2017 and FY 2018 had lower hydroelectric costs. Renewable energy costs assumed
a larger portion of cost as various renewable projects came online to fulfill the City’s carbon
neutral and RPS goals, although some of the older, higher priced contracts will start expiring as
early as FY 2022. The current market outlook is that newer renewables projects should come in
at lower costs. Transmission charges are also projected to increase as new transmission lines are
built throughout California to accommodate new renewable projects. In total, electric supply
costs are projected to increase to about $87 million by FY 2026, at which point all currently
contracted renewable projects will be online. Supply costs are only projected to change slightly
in subsequent years.
8 Costs are shown net of wholesale revenues, and cannot be directly compared with the electric supply purchase
figures shown in Appendix A: Electric Utility Financial Forecast Detail.
9 Average hydroelectric generation based on the current E-HRA tariff.
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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.
From FY 2016 to FY 2020, overall Operations costs have risen annually by about 4% on average.
Starting in FY 2021 and continuing for several years, Operations and Maintenance costs are
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increased mainly due to the introduction of a contract line crew to help while the Utility is
understaffed. These costs may be reduced depending on how much work is needed and may be
phased out as longer-term employees are gained. Demand side management costs are increasing
in FY 2021 to reflect new and ongoing costs related to Low Carbon Fuel Standard rebates.
Revenues from the same program will offset most of these costs.
Figure 21: Historical and Projected Electric Utility Operational Costs
SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP)
Staff projects CIP spending for FY 2022 through FY 2026 to be consistent with last year’s forecast,
though there is a slight shift in the funding by project category. There will be a reduction in
funding for Undergrounding as current projects are completed and delayed; there will be an
increase in funding for Underground Rebuilding and 4/12kV Conversion as improvements are
made to the system in portions of the Crescent Park/Duveneck/St. Francis/Community
Center/Leland Manor/Garland neighborhoods to facilitate rebuild of the Hopkins Substation; and
increase in funding for replacement of distribution system and substation facilities that are at the
end of their useful life. Other significant projects still slated to continue are deteriorated wood
pole replacements, substation physical security upgrades, pole relocations to facilitate the
Caltrain Railway Electrification project, Smart Grid upgrades, and ongoing capital investment in
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the electric distribution system to maintain/improve reliability. This forecast assumes that the
utility finances smart grid projects (along with funding from the water and gas funds), the Foothill
fire mitigation rebuilds, and the 115kV electric interconnection from the Electric Special Projects
Reserve, but it would also be possible to use bond financing. The full deployment of the smart
grid project has tentatively been moved out to start in FY 2023.
Excluding the one-time projects listed above, the CIP plan for FY 2022 to FY 2026 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, foothill rebuilds, electric interconnection). The details of the CIP budget will be
available in the Proposed FY 2022 Utilities Capital Budget. Figure 17 shows the FY 2022 projected
budget and the five year CIP spending plan, although these figures are preliminary pending
budget discussions starting in May. The ‘committed’ column represents funds committed to
contracts for which work has not yet been completed or invoices paid.
Figure 22: Electric Utility CIP Spending ($000)
SECTION 6D: DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently makes
payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax Credit
Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction costs
of solar demonstration projects at the Municipal Services Center, Baylands Interpretive Center,
and Cubberley Community Center. The capacity of these projects totaled 250 kW. In exchange
for funding part of the construction costs, the Electric Utility receives the RECs from these
projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are interest
free (the investors receive a tax credit from the federal government). This bond issuance is
secured by the net revenues of the Electric Utility. Debt service for this bond continues through
2021, and for the financial forecast period is as follows:
Table 15: Electric Utility Debt Service ($000)
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
2007 Clean Renewable
Energy Bonds 100 100 - - -
Project Category
Current
Budget *
Spending,
Curr. Yr.
Remain.
Budget **Committed FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
One Time Projects 4,456 (310) 4,146 265 4,000 2,000 2,000 11,000 -
Reliability 3,531 (1,923) 1,609 1,042 4,020 5,690 4,040 3,000 2,563
Undergrounding 1,548 (35) 1,513 126 - 56 3,750 250 -
4/12 Kv Conversion 1,830 (7) 1,823 - 166 50 120 2,120 1,820
Underground Rebuild 4,955 (24) 4,931 17 2,110 250 400 4,050 461
Ongoing 3,766 (1,051) 2,715 1,169 5,830 4,445 3,805 3,605 3,672
Customer Connections 2,400 (1,515) 885 352 2,550 2,700 2,400 2,400 2,472
Total 22,486 (4,863) 17,623 2,971 18,676 15,191 16,515 26,425 10,987
* Includes unspent funds from previous years carried forward or re-appropriated into the current fiscal year.
** Equal to CIP Reserves (Reserve for Re-appropriations + Reserve for Commitments)
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The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage
ratio of 125% of debt service. The current Financial Plan maintains compliance with these
covenants throughout the forecast period, as shown in Appendix C.
The Electric Utility also pledges reserves and net revenue as security for the bond issuances listed
in Table 16, even though the Electric Utility is not responsible for the debt service payments. The
Electric Utility’s reserves or net revenues would only be called upon if the responsible utilities are
unable to make their debt service payments. Staff does not currently foresee this occurring.
Table 16: 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
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water $1,457 No Yes
*Net of Federal interest subsidy
SECTION 6E: EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.10 Each year it is calculated
according to the 2009 Council-adopted methodology and does not require additional Council
action.
SECTION 6F: WHOLESALE REVENUES AND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about one quarter
comes from other sources. Of these other sources, about 50% to 60% represents wholesale
revenues of surplus energy sales. These revenues may offset electric supply purchase costs,
smooth rate increases, or fund reserves or other costs. Of the remaining revenues, the largest
revenue sources are interest on reserves, connection fees for new or replacement electric
services, and carbon allowance revenues associated with the State’s cap-and-trade program. In
FY 2020 these sources represented roughly 33% of revenue from sources other than electricity
sales. The remaining FY 2020 revenues consisted of a variety of one-time transfers.
Revenues from connection fees have increased since FY 2009 varying from year to year.
Connection fee revenues are collected to offset costs incurred in setting up new connections and
are pass-through in nature. Revenue from connection fees decreased slightly during the
recession, but has increased substantially since then, peaking in FY 2016 declining somewhat in
10 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed changes
to equity transfer methodology.
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FY 2017 and FY 2018, then hitting a new high in FY 2019. Staff forecasts slightly lower revenue
from this source in 2021 with revenue leveling out in subsequent years.
Staff projects carbon allowance and interest income revenues to stay relatively stable through
the forecast period. However, both of these revenue sources are subject to some uncertainty.
This forecast assumes the program State’s cap-and-trade program will remain in place but with
declining returns through 2030. This scenario may be pessimistic, but matches what has
transpired for free allowances in the gas fund.
The forecast for interest income assumes current interest rates continue and there are no major
reserve reductions aside from what is anticipated in this Financial Plan. If interest rates rise,
interest income could increase, and if reserves decrease (due to drought or a withdrawal from
the ESP reserve for a major project), interest income would decrease.
SECTION 6G: SALES REVENUES
The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7
provide the basis for sales revenue projections. As discussed in Section 5A, sales revenues for this
utility have been decreasing due to load reduction but are helped by the mild climate in Palo Alto.
Palo Alto is a built-out City, so the opportunities for increased load growth are limited to the
existing footprint of commercial structures and incremental growth in population. As utilization
of existing spaces changes, and energy efficiency measures continue, Palo Alto could see greater
load loss. Increased loads from electric vehicles and the electrification of households may
increase loads somewhat.
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SECTION 7: COMMUNICATIONS PLAN
The fiscal year (FY) 2022 Electric Utility communications strategy covers these primary areas:
efficiency services and utility bill savings; capital improvement, operations and maintenance for
infrastructure safety and reliability; renewables and carbon neutral portfolio; beneficial
electrification; and cost containment measures. The City of Palo Alto Utilities (CPAU)
communication methods include use of the utilities website, utility bill inserts, messaging on
utility bills, email newsletters, print and digital ads in local publications, social media, and
community message boards.
In FY 2022, CPAU is proposing no increase in electric utility rates. Communications will focus on
helping customers with efficiency services, rate assistance and bill payment relief programs to
help them navigate a challenging economic situation during the COVID-19 pandemic. They will
also highlight CPAU’s decision to defer rate increases as a benefit of the organization’s
management of its financial portfolio, including use of reserves for situations such as what we
could not anticipate but observed in 2020. While the cost of transmission fees, capital
investment, construction and contract labor costs have increased, CPAU is able to insulate
customers against significant rate increases because of its financial portfolio management. Staff
anticipates that rate increases around 5% each year beyond FY 2022 will be required in order to
keep the reserves within a healthy margin.
CPAU continues to make cost containment an ongoing priority and part of an annual cycle,
consistent with the Utilities Strategic Plan. CPAU’s electric utility rates remain lower than the
neighboring community average, such as for investor-owned utilities like PG&E. The average Palo
Alto resident’s monthly electric bill is around 34% lower than the PG&E average. Keeping costs
low is one of the benefits CPAU offers its customers as a public utility provider.
CPAU customers also benefit from local control and policy setting, and community values-driven
programs and services, including the decision to go carbon neutral in 2013. Palo Alto’s renewable
energy purchase agreements contribute to our utility’s long-term energy security and
commitment to sustainability. 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.
Programs such as the Home Efficiency Genie and commercial energy efficiency audits help
residents and businesses better understand energy usage, activities and/or upgrades they can
implement to improve efficiency and keep utility costs low. In 2020, we began offering a virtual
Genie in-home assessment and webinars about home energy and water efficiency to help
customers keep utility costs low while working and studying from home during the pandemic
shelter-in-place order. CPAU is exploring additional opportunities to help customers electrify
homes, buildings, and personal transportation. Rebates for residential appliances such as heat
pump water heaters and electric vehicle charging stations for multi-family and non-profit
facilities are incentivizing more and more customers to take action. Staff are piloting programs
to explore electrification technologies in other applications as well. These efforts are in line with
41 | Page
the City’s Sustainability and Climate Action Plan goals to reduce greenhouse gas emissions. CPAU
launched an upgraded version of its online utility account services portal in 2020, which provides
customers with direct access and more information about utility account and consumption data.
42 | Page
APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
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APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
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6053706
1 FISCAL YEAR FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
2
3 ELECTRIC LOAD 160 162
4 Purchases (MWh)977,292 945,703 925,329 905,071 879,913 818,593 835,246 870,922 875,208 867,019 858,859
5 Sales (MWh)937,157 917,687 899,997 884,322 854,760 796,450 812,790 846,966 851,449 843,454 835,431
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1156$ 0.1249$ 0.1413$ 0.1487$ 0.1624$ 0.1624$ 0.1624$ 0.1707$ 0.1799$ 0.1843$ 0.1837$
9 Change in System Average Rate 0%10%13%5%9%0%0%5%5%2%0%
10 Change in Average Residential Bill 3%11%11%6%8%-1%-1%5%5%2%-1%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)- - - - - - - - - - -
14 Commitments (Non-CIP)3,102,055 3,777,205 2,970,955 3,725,000 3,910,695 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525
15 Low Carbon Fuel Standard (LCFS) Reserve - - - - - 6,340,000 4,079,577 3,186,120 2,163,917 1,091,927 524,278
16 Cap and Trade Program 1,189,129 2,189,551 5,749,259 9,315,900 12,866,019
17 Underground Loan Reserve 730,000 729,000 730,147 730,147 726,659 726,659 726,659 726,659 726,659 726,659 726,659
18 Public Benefits Reserves 2,574,000 1,839,000 681,330 681,330 809,700 1,904,547 2,664,195 3,434,974 4,274,785 5,101,307 5,861,122
19 Electric Special Projects Reserve 51,837,855 51,837,855 51,837,855 41,837,855 41,664,855 46,664,855 47,664,855 36,649,107 30,649,107 31,649,107 32,649,107
20 Hydro Stabilization Reserve 17,000,000 11,400,000 11,400,000 11,400,000 11,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000
21 Capital Reserves - - 879,964 879,964 879,964 5,879,964 879,964 879,964 879,964 879,964 9,879,964
22 Rate Stabilization Reserves 14,410,840 9,010,840 9,010,840 9,010,840 - - - - - - -
23 Operations Reserves 22,497,607 21,850,187 29,912,981 18,600,000 45,244,167 38,493,671 36,021,324 30,848,860 29,870,224 34,765,907 41,967,828
24 Unassigned - - - 244,354 - - - - - - -
25 TOTAL STARTING RESERVES 112,152,357 100,444,086 107,424,072 87,109,490 104,636,040 118,928,221 112,144,228 96,833,761 93,232,441 102,449,297 123,393,502
26
27 REVENUES
28 Net Sales 108,312,917 114,624,726 127,172,308 131,471,245 137,026,501 129,362,400 132,016,388 144,585,888 153,177,157 155,480,812 153,468,878
29 Wholesale Revenues 4,301,366 16,188,920 18,106,327 21,060,071 20,686,925 24,172,722 26,268,047 26,065,562 29,160,236 28,622,338 28,722,008
30 Other Revenues and Transfers In 11,714,494 11,225,911 13,373,312 19,914,635 15,260,935 16,958,432 15,201,708 16,006,051 17,060,870 18,081,320 19,108,217
31 TOTAL REVENUES 124,328,776 142,039,557 158,651,947 172,445,951 172,974,361 170,493,554 173,486,143 186,657,501 199,398,263 202,184,470 201,299,104
32
33 EXPENSES
34 Electric Supply Purchases 75,705,000 80,467,136 94,629,654 89,625,027 90,645,768 93,402,295 96,218,872 98,071,366 102,283,824 104,443,425 106,132,953
35 Operating Expenses
36 Administration
37 Allocated Charges 4,934,195 3,990,822 6,374,241 4,568,027 6,146,498 6,269,614 6,395,499 6,524,037 6,654,904 6,788,290 6,937,026
38 Rent 4,997,101 5,121,102 5,284,977 5,454,097 5,666,805 6,798,087 6,974,837 7,156,183 7,342,244 7,533,142 7,729,004
39 Debt Service 8,885,994 8,953,893 8,867,395 8,464,883 7,170,631 8,061,159 8,068,219 8,900,247 8,914,853 4,898,677 4,896,047
40 Transfers and Other Adjustments 11,798,865 13,052,376 13,632,059 13,342,321 10,200,181 13,859,349 14,460,996 14,618,796 14,996,752 15,004,867 15,013,144
41 Subtotal, Administration 30,616,155 31,118,193 34,158,672 31,829,328 29,184,115 34,988,209 35,899,551 37,199,262 37,908,752 34,224,975 34,575,221
42 Resource Management 2,083,812 1,985,620 1,873,954 2,082,405 2,849,071 2,915,597 2,999,304 3,091,930 3,174,074 3,252,752 3,337,994
43 Demand Side Management 3,643,924 4,271,786 3,889,846 3,655,547 2,733,047 6,813,274 5,597,849 6,226,330 6,735,444 6,579,673 6,835,735
44 Operations and Mtc 11,523,881 11,811,016 11,528,747 11,606,585 13,450,568 13,753,878 14,120,144 14,519,515 14,882,486 15,234,376 15,454,139
45 Engineering (Operating)1,592,024 1,656,522 1,790,942 1,838,799 2,051,303 2,093,560 2,138,697 2,185,640 2,231,923 2,278,475 2,321,056
46 Customer Service 1,540,884 2,190,993 2,291,246 2,180,400 2,228,469 2,281,952 2,351,324 2,428,904 2,496,527 2,560,731 2,589,553
47 Allowance for Unspent Budget - - - - - (1,413,087) (1,172,410) (1,203,369) (1,232,103) (1,260,236) (1,285,146)
48 Subtotal, Operating Expenses 51,000,680 53,034,130 55,533,407 53,193,063 52,496,573 61,433,382 61,934,458 64,448,212 66,197,103 62,870,747 63,828,552
49 Capital Program Contribution 9,331,367 11,558,306 18,803,467 10,770,456 15,539,840 22,017,870 30,643,280 27,739,243 31,700,480 13,926,093 21,284,122
50 TOTAL EXPENSES 136,037,047 145,059,572 168,966,528 153,588,546 158,682,181 176,853,547 188,796,610 190,258,821 200,181,407 181,240,265 191,245,628
51
52 ENDING RESERVES
53 Reappropriations (Non-CIP)- - 9,063,000 - - - - - - - -
54 Commitments (Non-CIP)3,777,205 2,970,955 8,637,000 3,910,695 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525
55 Low Carbon Fuel Standard (LCFS) Reserve - - - - 6,340,000 4,079,577 3,186,120 2,163,917 1,091,927 524,278 71,297
56 Cap and Trade Program 1,189,129 2,189,551 5,749,259 9,315,900 12,866,019 16,565,994
57 Underground Loan Reserve 729,000 730,147 730,147 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659
58 Public Benefits Reserves 1,839,000 681,330 681,330 809,700 1,904,547 2,664,195 3,434,974 4,274,785 5,101,307 5,861,122 6,574,538
59 Electric Special Projects Reserve 51,837,855 51,837,855 41,837,855 41,664,855 46,664,855 47,664,855 36,649,107 30,649,107 31,649,107 32,649,107 32,649,107
60 Hydro Stabilization Reserve 11,400,000 11,400,000 11,400,000 11,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000
57 Capital Reserve - 879,964 879,964 879,964 5,879,964 879,964 879,964 879,964 879,964 9,879,964 12,879,964
58 Rate Stabilization Reserve 9,010,840 9,010,840 9,010,840 - - - - - - - -
59 Operations Reserve 21,850,187 29,912,981 18,600,000 45,244,167 38,493,671 36,021,324 30,848,860 29,870,224 34,765,907 41,967,828 45,060,895
60 Unassigned - - 244,354 - - - - - - - -
61 TOTAL ENDING RESERVES 100,444,086 107,424,072 101,084,490 104,636,040 118,928,221 112,144,228 96,833,761 93,232,441 102,449,297 123,393,502 133,446,979
62
6053706
1 FISCAL YEAR FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
2
3 REVENUES
4 Net Sales 87%81%80%76%79%76%76%78%77%77%77%
5 Other Revenues and Transfers In 13%19%20%24%21%24%24%22%23%23%23%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 54%42%50%53%53%52%46%45%46%49%48%
10 Operating Expenses
11 Administration
12 Allocated Charges 4%3%4%3%4%4%3%3%3%4%4%
13 Rent 4%4%3%4%4%4%4%4%4%4%4%
14 Debt Service 7%6%5%6%5%5%4%5%5%3%3%
15 Transfers and Other Adjustments 9%9%8%9%6%8%8%8%8%8%8%
16 Subtotal, Administration 23%21%20%21%18%20%19%20%20%19%18%
17 Resource Management 2%1%1%1%2%2%2%2%2%2%2%
18 Operations and Mtc 8%8%7%8%8%8%7%8%8%8%8%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 1%2%1%1%1%1%1%1%1%1%1%
21 Allowance for Unspent Budget 0%0%0%0%0%-1%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 35%34%31%32%31%31%30%31%31%31%30%
23 Capital Program Contribution 7%8%11%7%10%11%16%15%11%8%11%
24 TOTAL EXPENSES 96%83%91%92%95%94%92%90%89%88%89%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
28 1. Load Net Revenue 652,853 1,208,477
29 2. Hydro Production: Western & Calaveras 9,050,313 3,397,119
30 3. Renewable Production: Landfill & Wind & 743,945 539,073
31 4. Carbon Neutral Cost 303,022 114,983
32 5. Market Price 775,584 1,138,589
33 6. Local Capacity 408,388 446,695
34 7. Transmission/CAISO 3,741,647 2,806,120
35 8. Plant Outage 1,000,000 1,000,000
36 9. Western Cost 2,704,738 2,973,619
37 10. Regulatory & Legal - -
38 11. Supplier Default - -
39 TOTAL 19,380,490 13,624,674
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 172% 303%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026
44 Distribution Revenue Variance 3,260,213 3,182,718 3,742,109 3,915,276 4,447,787 4,432,418 4,417,304 4,930,733 5,356,652 5,659,448 5,641,151
45 10% CIP Program Contingency 933,137 1,155,831 1,880,347 1,077,046 1,553,984 2,001,787 3,064,328 2,773,924 2,170,048 1,392,609 2,128,412
46 Total Risk Asssessment Value 4,193,350 4,338,548 5,622,455 4,992,321 6,001,771 6,434,205 7,481,632 7,704,657 7,526,700 7,052,057 7,769,564
47 Projected Operations Reserve 21,850,187 29,912,981 18,600,000 45,244,167 38,493,671 36,191,535 30,831,986 29,628,922 33,771,081 39,672,192 42,667,847
48 Operations Reserve, % of Risk Value 521% 689% 331% 906% 641% 562% 412% 385% 449% 563% 549%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)14,498,215 15,472,236 17,841,143 16,831,022 16,953,628 17,508,370 17,981,164 18,461,032 19,176,632 18,891,837 19,192,697
46 Target (90 days of non-capital expenses)21,747,322 23,208,354 26,761,715 25,246,533 25,430,442 26,262,555 26,971,747 27,691,548 28,764,949 28,337,756 28,789,046
47 Max (120 days of non-capital expenses)28,996,429 30,944,472 35,682,287 33,662,044 33,907,256 35,016,739 35,962,329 36,922,065 38,353,265 37,783,675 38,385,394
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)8,513,675 9,755,012 8,008,309 7,869,900 8,621,917 9,462,487 9,512,586 9,802,609 10,084,238 10,256,803 10,471,541
51 Target (90 days of non-capital expenses)10,708,963 11,918,803 10,309,464 10,096,233 11,071,856 12,295,398 12,332,333 12,728,321 13,111,059 13,329,457 13,610,674
52 Max (120 days of non-capital expenses)12,904,252 14,082,593 12,610,618 12,322,566 13,521,795 15,128,308 15,152,079 15,654,034 16,137,881 16,402,112 16,749,808
53 Risk Assessment Value 4,193,350 4,338,548 5,622,455 4,992,321 6,001,771 6,434,205 7,481,632 7,704,657 7,526,700 7,052,057 7,769,564
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1326%1391%1593%1587%1896%1821%1860%1726%1790%3315%3371%
57 Available Reserves (5x Debt Service)*10.9 11.7 9.4 11.9 16.1 13.5 11.6 10.1 11.0 24.0 26.0
58 *For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to mee
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 47 | Page
APPENDIX B: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c) For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f) For operating contingencies, as described in Section 12 (Operations Reserves)
g) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserves for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c) As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d) To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 11.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 14 (Unassigned Reserves).
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June 2018 48 | Page
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves
for Commitments will be set to an amount equal to the total remaining spending authority
for all contracts in force for the Electric Supply Fund and Electric Distribution Fund,
respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves
for Reappropriations will be set to an amount equal to the amount of all remaining capital
and non-capital budgets that will be reappropriated to the following fiscal year for each Fund
in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of
Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve
and Adoption of Electric Special Project Reserve Guidelines). These policies and timelines are
included from Resolution 9206 as amended to refer to the reserves structure set forth in
these Reserves Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2017;
f) Any uncommitted funds remaining at the end of FY 2022 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
Section 7. Hydroelectric Stabilization Reserve
The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts associated
with variations in generation from hydroelectric resources. Staff will manage the
Hydroelectric Stabilization Reserve as follows:
a) Projected Hydro Output: Near the end of each fiscal year, staff will determine the
actual and expected hydro output for that fiscal year, compare that to the long-term
average annual output level (495,957 MWh as of March 2018), and multiply the
difference by the average of the monthly round-the-clock forward market prices for
each month of the current fiscal year.
b) Changes in Reserves. Staff is authorized to transfer the amount described in Sec. 7(a)
from the Operations Reserve to the Hydroelectric Stabilization Reserve for hydro
output deviations above long-term average levels, or transfer this amount from the
Hydroelectric Stabilization Reserve to the Operations Reserve for hydro output
deviations below long-term average levels.
c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after the
transfers described above shall be the basis for staff’s determination, with Council
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June 2018 49 | Page
approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-HRA) for
the following fiscal year.
d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve
according to the following guideline levels:
Minimum Level $3 million
Target Level $19 million
Maximum Level $35 million
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the principal
payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires action
by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels are
calculated for each fiscal year of the Financial Planning Period and approved by Council
resolution.
Minimum Level 20% of the maximum CIP Reserve guideline
level
Maximum Level Average annual (12 month)11 CIP budget, for
48 months of budgeted CIP expenses12
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve for
Commitments as a result of a change in contractual commitments related to CIP projects.
Any other additions to or withdrawals from the CIP reserve require Council action.
c) Minimum Level:
i) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve reaching
its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is
below its minimum level at the end of FY 2017, staff must present a plan by June 30,
2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff
may present, and the Council may adopt, an alternative plan that takes longer than
one year to replenish the reserve, or that does so in a shorter period of time.
11 Each month is calculated based upon 1/12 of the annual budget.
12 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual
average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use
to derive the annual average would be FY 2022 through FY 2025 etc.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 50 | Page
d) Maximum Level: If there are funds in this reserve in excess of the maximum level staff
must propose in the next Financial Plan to transfer these funds to another reserve or
return them to ratepayers in the funds to ratepayers, or designate a specific use of funds
for CIP investments that will be made by the end of the next Financial Planning period.
Staff may also seek City Council to approve holding funds in this reserve in excess of the
maximum level if they are held for a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period. The Council may approve exceptions
to this requirement, when proposed by staff to provide greater rate stabilization to
customers.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to 11 above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
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
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June 2018 51 | Page
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were funds
in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning Period is
FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign the funds
in the Unassigned Reserve by the end of FY 2017. Staff may present an alternative plan that
retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
Section 15. Low Carbon Fuel Standard (LCFS) Reserve
This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the
California Air Resources Board to the City, as well as expenses incurred, in accordance with
California’s Low Caron Fuel Standard program. At the end of each fiscal year, the LCFS
Reserve will be adjusted by the net of revenues and expenses associated with California’s
LCFS program.
Section 16. Cap and Trade Program Reserve
This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the electric utility, under the State’s Cap
and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy
on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the
Policy), adopted by Council Resolution 9487 in January 2015.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 52 | Page
APPENDIX C: DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL ACTIVITIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Electric Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process. It
does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large commercial
customers who have more complex requirements for their electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution system
maintenance activities, including:
• monitoring the substations and performing routine maintenance;
• performing preventative maintenance on the system;
• monitoring the system’s status from the UCC using SCADA;
• maintaining the SCADA system;
• investigating outages and other customer complaints and performing emergency
repairs;
• clearing vegetation near overhead power lines; and
• testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX D: SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
EXPORT ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-EEC-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-EEC-1 Sheet No.E-EEC-1
dated 7-1-20169 Effective 7-1-202119
A. APPLICABILITY:This Rate Schedule applies in conjunction with the otherwise applicable Rate Schedules for eachCustomer class. This Rate Schedule may not apply in conjunction with any time-of-use Rate Schedule.This Rate Schedule applies to Customer-Generators as defined in Rule and Regulation 2 who are eithernot eligible for Net Energy Metering or who are eligible for Net Energy metering but elect to takeService under this Rate Schedule.
B.TERRITORY:Applies to locations within the service area of the City of Palo Alto.This Rate Schedule appliesanywhere the City of Palo Alto provides Electric Service.
C. RATE:The following buyback rate shall apply to all electricity exported to the grid.Per kWh
Export electricity compensation rate $0.107809
D. SPECIAL CONDITIONS1.Metering equipment: Electricity delivered by CPAU to the Customer-Generator or received byCPAU from the Customer-Generator shall be measured using a Meter capable of registering theflow of electricity in two directions (aka “bidirectional meter”). The electrical powermeasurements will be used for billing the Customer-Generator. CPAU shall furnish, install andown the appropriate Meter.
2.Billing:a.CPAU shall measure during the billing period, in kilowatt-hours, the electricity deliveredand received after the Customer-Generator serves its own instantaneous load.b. CPAU shall bill the Customer-Generator consumption charges for the electricity deliveredby CPAU to the Customer-Generator based on the Customer-Generator’s applicable RateSchedule. c.In the event the electricity generated exceeds the electricity consumed and therefore isreceived by CPAU, the Customer will receive a credit for all electricity received by CPAUat the buyback Rate designated in section C above.
{End}
Attachment C
NET METERING NET SURPLUS ELECTRICITY COMPENSATION
UTILITY RATE SCHEDULE E-NSE-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No. E-NSE-1 Sheet No.E-NSE-1
dated 07-01-20196 Effective 7-1-202119
A. APPLICABILITY: This Rate Schedule applies to eligible residential and small commercial Net Energy Metering Customers who, at the end of an annual settlement period, as described in Rule 29, are Net Surplus Customer-Generators of electricity who elect to receive monetary compensation as such preference is indicated on the net surplus electricity election form. This Rate Schedule only applies to Customers who participate in Net Energy Metering, and does not apply to Customers that take Service under the City’s Net Energy Metering Successor Rate, as each of these terms are defined in Rule and Regulation 2. B. TERRITORY: This Rate Schedule applies anywhere the City of Palo Alto provides Electric Service. C. RATES: Per kWh Net Surplus Electricity Compensation rate $0.09928771 D. SPECIAL CONDITIONS 1. Net Surplus Electricity Compensation Rate eligibility shall be determined as specified in Rule 29. Net surplus electricity, as specified in Rule 29, if applicable, will be multiplied by the above compensation rate to determine the Customer’s annual net surplus electricity compensation stated in dollars. 2. Additional terms, conditions and definitions govern Net Energy Metering Service and Interconnection, as described in Rule 29. {End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-G-1 Sheet No E-2-G-1
dated 7-1-20189 Effective 7-1-202119
A. APPLICABILITY: This Rate Schedule applies to the following Customers receiving Electric Service from the City of Palo Alto Utilities under the Palo Alto Green Program: 1. Small non-residential Customers receiving Non-Demand Metered Electric Service; and
2. Customers with Accounts at Master-Metered multi-family facilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period $0.11855 $0.08551 $0.00447 $0.00620
$0.21453053
Winter Period 0.08502 0.05675 0.00447 0.00620
$0.152241
4824
Minimum Bill ($/day) 0.8359 2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period $0.11855 $0.08551 $0.00447 $0.20853
Winter Period 0.08502 0.05675 0.00447 0.14624
Minimum Bill ($/day)
0.8359
Palo Alto Green Charge (per 1000 kWh block) $62.00
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-G-2 Sheet No E-2-G-2
dated 7-1-20189 Effective 7-1-202119
D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer and Winter Periods, usage will be prorated based upon the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewable
sources, and create a transparent and sustainable market that encourages new development of wind and solar power. Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-2-G-3 Sheet No E-2-G-3
dated 7-1-20189 Effective 7-1-202119
4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer-s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option. The billing Demand to be used in computing charges under this schedule will be the actual maximum Demand in kilowatts for the current month. An exception is that the billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on weekdays. {End}
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-1 Sheet No E-4-G-1
dated 7-1-20189 Effective 7-1-202119
A. APPLICABILITY: This Rate Schedule applies to Demand metered Secondary Electric Service for Customers with a maximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green Program. This Rate Schedule applies to three-phase Electric Service and may include Service to Master-metered multi-family facilities or other facilities requiring Demand metered Service, as
determined by the City. B. TERRITORY: The Rate Schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge (per kW) $4.41 $24.50 $28.91
Energy Charge (per kWh) 0.10536 0.01865 0.00447 0.00620 0.134048
Winter Period
Demand Charge (per kW) $2.75 $16.22 $18.97
Energy Charge (per kWh) 0.07634 0.01865 0.00447 0.00620 0.105146
Minimum Bill ($/day) 17.2742
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-2 Sheet No E-4-G-2
dated 7-1-20189 Effective 7-1-202119
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $4.41 $24.50 $28.91
Energy Charge (per kWh) 0.10536 0.01865 0.00447 0.12848
Palo Alto Green Charge (per 1000 kWh block) $26.00
Winter Period
Demand Charge (per kW) $2.75 $16.22 $18.97
Energy Charge (per kWh) 0.07634 0.01865 0.00447 0.09946
Palo Alto Green Charge (per 1000 kWh block) $26.00
Minimum Bill ($/day) 17.2742 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill
amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-3 Sheet No E-4-G-3
dated 7-1-20189 Effective 7-1-202119
The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter, which does not reset after a definite time interval, may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays.
4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four consecutive months. When such Metering is installed, the monthly Electric bill will include a “Power Factor Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-hours
to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 5. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full-service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
6. Palo Alto Green Program Description and Participation
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-4 Sheet No E-4-G-4
dated 7-1-20189 Effective 7-1-202119
Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the production of renewable energy, increase the financial value of power from renewal sources, and creates
a transparent and sustainable market that encourages new development of wind and solar. Customers choosing to participate shall fill out a Palo Alto Green Power Program application provided by the Customer Service Center. Customers may request at any time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto
Green Program. 7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable
advance notice to any Customer receiving the discount in this section. The Customer then has the option to change the system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation
source.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-4-G-5 Sheet No E-4-G-5
dated 7-1-20189 Effective 7-1-202119
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 NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-1 Sheet No E-7-G-1
dated 7-1-20198 Effective 7-1-202119
A. APPLICABILITY: This Rate Schedule applies to Demand metered Service for large non-residential Customers who choose Service under the Palo Alto Green Program. A Customer may qualify for this Rate Schedule if the Customer’s Maximum Demand is at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months. B. TERRITORY: The Rate Schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge ( per kW) $5.03 $25.66 $30.69
Energy Charge (per kWh) 0.10932 0.00053 0.00447 0.00620 0.1163212032
Winter Period
Demand Charge (per kW) $2.89 $14.16 $17.05
Energy Charge (per kWh) 0.07238 0.00053 0.00447 0.00620 0.0793808338
Minimum Bill ($/day) 49.1139
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-2 Sheet No E-7-G-2
dated 7-1-20198 Effective 7-1-202119
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $5.03 $25.66 $30.69
Energy Charge (per kWh) 0.10932 0.00053 0.00447 0.11432
Palo Alto Green Charge (per 1000 kWh block) $62.00
Winter Period
Demand Charge (per kW) $2.89 $14.16 $17.05
Energy Charge (per kWh) 0.07238 0.00053 0.00447 0.07738
Palo Alto Green Charge (per 1000 kWh block) $62.00
Minimum Bill ($/day) 49.1139 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed.
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-3 Sheet No E-7-G-3
dated 7-1-20198 Effective 7-1-202119
The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays. 4. Request for Service
Qualifying Customers may request Service under this schedule for more than one Account or one Meter if the Accounts are at one site. A site, for the purposes of this Rate Schedule, consists of one or more Accounts which cover contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and which have a common billing
address. 5. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to the computation of any primary voltage discount. The power factor adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load
was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-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
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-4 Sheet No E-7-G-4
dated 7-1-20198 Effective 7-1-202119
the Customer's Maximum Demand. 6. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile 7. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the production of renewable energy, increase the financial value of power from renewal sources, and creates a transparent and sustainable market that encourages new
development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program application provided by the Customer Service Center. Customers may request at any time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
8. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a qualified line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's Electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change the system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation.
9. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No E-7-G-5 Sheet No E-7-G-5
dated 7-1-20198 Effective 7-1-202119
occasionally require backup power from the City due to non-operation of the non-utility generation source. b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76 c. Meters: A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section.
e. Exemptions: (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End}