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NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956
I. ROLL CALL
II. ORAL COMMUNICATIONS
Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable time
restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from discussing or
acting upon any topic initially presented during oral communication.
III. APPROVAL OF THE MINUTES
Approval of the Minutes of the Utilities Advisory Commission Meeting held on March 7, 2018
IV. AGENDA REVIEW AND REVISION
V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS
VI. GENERAL MANAGER OF UTILITIES REPORT
VII. COMMISSIONER COMMENTS
VIII. UNFINISHED BUSINESS - None
IX. NEW BUSINESS
1. Staff Recommendation that the Utilities Advisory Commission Recommend that Action
the City Council Adopt: 1) a Resolution Approving the Fiscal Year 2019 Electric Financial
Plan, and 2) a Resolution Increasing Electric Rates by 9% by Amending the E-1, E-2, E-2-G,
E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU and E-14 Rate Schedules
2. Staff Recommendation that the Utilities Advisory Commission Recommend that the Action
City Council Adopt: 1) a Resolution Approving the Fiscal Year 2019 Gas Utility Financial Plan;
and 2) a Resolution Increasing Gas Rates by 4% by Amending Rate Schedules G-1 (Residential
Gas Service), G-2 (Residential Master-Metered and Commercial Gas Service), G-3 (Large
Commercial Gas Service), and G-10 (Compressed Natural Gas Service)
3. Local Solar Plan Progress Update and Next Steps Discussion
4. Assessment of CPAU’s Distribution System to Integrate Distributed Energy Resources Discussion
5. Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action
NEXT SCHEDULED MEETING: May 2, 2018 – Special Meeting (Day time)
ADDITIONAL INFORMATION - The materials below are provided for informational purposes, not for action or discussion
during UAC Meetings (Govt. Code Section 54954.2(a)(2)).
Informational Report 12-Month Rolling Calendar Public Letter(s) to the UAC
UTILITIES ADVISORY COMMISSION
THURSDAY, APRIL 12, 2018 – 7:00 P.M. – SPECIAL MEETING
COUNCIL CHAMBERS
Palo Alto City Hall – 250 Hamilton Avenue
Chairman: Michael Danaher Vice Chair: Arne Ballantine Commissioners: Lisa Forssell, A. C. Johnston, Judith Schwartz, Lauren Segal and Terry Trumbull Council Liaison: Eric Filseth
Utilities Advisory Commission Minutes Approved on: Page 1 of 6
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF MARCH 7, 2018 REGULAR MEETING
CALL TO ORDER
Chair Danaher called the meeting of the Utilities Advisory Commission (UAC) to order at 7:00 p.m.
Present: Chair Danaher, Vice Chair Ballantine, Commissioners Forssell, Johnston, Schwartz, Segal,
Trumbull
Absent: None
ORAL COMMUNICATIONS
Tom O'Connor questioned the requirement for a Building Division official to inspect the electrical
reconnection of the home when undergrounding a utility service. In the past, the same City Utilities
Department personnel who disconnected the lines returned to the site to inspect the reconnection and
reconnect the lines. This new procedure is inefficient, unnecessary, and more costly.
Don Jackson remarked that the first step in a Fiber to the Premises project is to define and articulate the
importance, goals, and requirements of internet access for Palo Alto residents. A majority of residents
should support and the City Council should agree to a set of principles, goals, and requirements for internet
access. Potential projects and investments should be considered in light of how they support these goals.
As a natural monopoly, Fiber to the Premises must be owned by the people it serves.
APPROVAL OF THE MINUTES
Commissioner Schwartz revised "anticipated events" to "unscheduled events" in the final paragraph of Item
3 on page 6. On page 8, her comments should be revised to "Commissioner Schwartz requested staff
provide the official position of the CAC and a chart showing applications with the different technologies.
She expressed concern about staffing a new utility should Fiber to the Premises become a reality.
Commissioner Schwartz suggested staff conduct a survey to understand if replacement of commercially
available services are desired by a wide spectrum of citizens." Her subsequent comments of "a case could
be made to fund FTTP to ensure the vitality of businesses" and "development of 5G may not be in the best
interest of consumers" should be deleted.
Commissioner Johnston moved to approve the minutes from the February 7, 2018 regular meeting as
amended. Commissioner Trumbull seconded the motion. The motion carried 7-0 with Chair Danaher, Vice
Chair Ballantine, and Commissioners Forssell, Johnston, Schwartz, Segal, and Trumbull voting yes.
AGENDA REVIEW AND REVISIONS
None
REPORTS FROM COMMISSIONER MEETINGS/EVENTS
Commissioner Schwartz shared pertinent comments she heard while attending the Voices of Experience
workshop on February 15. She had heard one municipal utility talk about how it had designed its customer
DRAFT
Utilities Advisory Commission Minutes Approved on: Page 2 of 6
information system to match what it was looking for from its early phase AMI deployment but then wished
it had spent more time thinking about what it might want the system to do in the future as more AMI
capabilities were added. All utilities that have deployed AMI have discovered tremendous benefits on the
customer side in addition to operational savings, such as the privacy gained by not having meter readers on
the property. While not all these benefits are easily quantifiable, they are real and enduring. Commissioner
Schwartz provided two slides she obtained at the California Energy Storage Alliance annual market
development forum. Community Choice Aggregators (CCA) are promising their customers that the
customers can have 100% solar all the time, which was not realistic. There was a surplus of solar energy at
certain times of day, as well as issues with the system having to ramp quickly. She hoped to talk about
these issues as part of the Integrated Resource Plan (IRP) discussions.
Chair Danaher recently met with European utilities to talk about charging networks and EVs. There is a
general understanding that they need controlled networks so that utilities or others can track and control
what's happening. If the demand for charging can be managed or controlled, given the estimate that 10% of
EVs will be charging at any point in time, 15-20% of capital expenditures for the grid can be saved. In
addition, he met with the CEO of a fast-growing European company that is installing gigabit-speed fiber
optic networks throughout the United Kingdom. The CEO stated that costs have decreased dramatically in
the last few years mainly because the massive build out of the grid in China has created a great deal of
innovation. Prior cost estimates for the fiber utility could be outdated. Also, in meetings with investors in
clean tech and energy tech, Chair Danaher learned that storage is being added for enterprises but not yet
for utilities. Because the cost of generating assets and storage assets are projected to continue decreasing,
investors are challenged by investing in 25-year assets when the assets become cheaper over time.
UTILITIES GENERAL MANAGER REPORT
Dean Batchelor, Chief Operating Officer, delivered the General Manager’s Report.
Utilities Strategic Plan Update. The Strategic Plan was scheduled to be presented to City Council on
February 26 but was postponed to the March 19 Council date as other agenda items went long. We
appreciate Commissioner Schwartz's attendance at the February 26 meeting and would like to take this
opportunity to invite other Commissioners to join us on March 19 to speak in support of the Strategic Plan.
Your guidance throughout this process has been appreciated.
Open House Celebrating a Highly Efficient All-Electric Multi-Family Dwelling in Palo Alto. The City is
cohosting a couple of open houses this month at a newly developed all-electric apartment complex at 430
Forest Avenue. The developer incorporated sustainable building elements such as high performance
materials, advanced building control systems, high efficiency heat pump appliances for water heating and
space conditioning, rooftop solar and electric vehicle charging stations. The owners are applying for LEED
Platinum status and have invited building professionals and members of the public to tour the building at
one of two open houses once construction is complete. Utilities staff will be present to discuss the City's
role in facilitating installation of heat pump water heaters and electric vehicle charging equipment,
including by providing rebates and other resources to accommodate the all-electric building construction.
Please save the date to join other community members at a tour of the building on Wednesday, March 28,
from 6 to 8 pm. Building professionals are invited to an open house on Thursday, March 29, from 3 to 5 pm.
Free Residential Water Efficiency Workshops.
• Saturday, March 10 from 10 am to noon - Laundry to Landscape Graywater Workshop
• Saturday, March 24 from 9 am to noon – Designing Native Gardens Workshop
• Saturday, March 31 from 9 am to 3:45 pm – Avenidas Housing Conference. Utilities staff will be
present to talk about the City's Rate Assistance and Residential Energy Assistance Programs.
• Details and registration for all events are available at cityofpaloalto.org/workshops.
Utilities Advisory Commission Minutes Approved on: Page 3 of 6
Silicon Valley Water Conservation Awards Ceremony. The 10th annual Silicon Valley Water Conservation
Awards ceremony will be held on World Water Day, Thursday March 22 from 6 to 9 pm at the Mitchell Park
Community Center. Please join us to celebrate regional heroes for water conservation. Awards are issued to
businesses, organizations, educational institutions, government agencies, and individuals demonstrating
excellence in water use efficiency. Palo Alto won Water Utility of the Year in 2014. This year’s ceremony will
feature Dr. Wallace J. Nichols, author of “Blue Mind,” for the keynote address and a special reception.
Tickets are $20 and details are available at WaterAwards.org
Green Building Summit. On Thursday, February 22, Utilities staff participated in a Green Building Summit
hosted by the Development Services Department. The goal of the summit was to identify possible Energy
Code modifications for the 2019 Building Code cycle. Other attendees included local architects, green
building professionals, industry experts, and regulators, including California Energy Commissioner Andrew
McAllister. Utilities staff will participate in the technical advisory committees that will follow up on ideas
generated at the summit and, through their participation, will be looking for opportunities to collaborate
with other stakeholders on ways to improve building resource efficiency and facilitate electrification in
existing buildings.
Community Events.
• The Great Race for Saving Water, April 14, 9:00 a.m. to 1:00 p.m., Palo Alto Baylands Athletic
Center.
• Municipal Services Center Open House, May 12, 9:00 a.m. to noon, Municipal Services Center.
COMMISSIONER COMMENTS
None
UNFINISHED BUSINESS
In response to Commissioner Johnston's inquiry regarding the Statement of Work for the Fiber to the
Premises Request for Proposals, Dean Batchelor, Chief Operating Officer, advised that it will be released by
the end of the month.
NEW BUSINESS
ITEM 1: DISCUSSION: Staff Recommendation that the Utilities Advisory Commission Recommend that the
City Council Adopt (1) a Resolution Approving the Fiscal Year 2019 Wastewater Collection Financial Plan;
and (2) a Resolution Increasing Wastewater Rates by 10% by Amending Rate Schedules S-1 (Residential
Wastewater Collection and Disposal), S-2 (Commercial Wastewater Collection and Disposal), S-6
(Restaurant Wastewater Collection and Disposal) and S-7 (Commercial Wastewater Collection and Disposal-
Industrial Discharge).
Eric Keniston, Senior Resource Planner, reported that staff's rate proposal had not changed since the
preliminary review was presented to the UAC in February. Staff recommended a 10% wastewater rate
increase for FY 2019. The major drivers for the rate increase were rising wastewater treatment costs in the
long term and rising capital expenses for the wastewater collection system in the short term. The collection
system capital cost increases comprised about 18% of the cost increases and operational cost increases
about 16%. Projects and bond measures were being planned to renovate the treatment plant. The City
would be the main entity bearing the increase in debt expense on the collection side, but treatment cost
increases would be shared with partners in the Regional Water Quality Control Plant.
In reply to Chair Danaher's query about how many employees were assigned to wastewater treatment and
collection, Phil Bobel, Assistant Director of Public Works, explained that the Public Works Department is
responsible for the treatment plant while the Utilities Department is responsible for the wastewater
collection system. About 70 people work at the wastewater treatment plant, three work for the
engineering group, eight people work for the maintenance group, eight people work in the laboratory, and
14 people work in watershed protection. Originally Public Works was responsible for both treatment and
Utilities Advisory Commission Minutes Approved on: Page 4 of 6
collection, but Public Works grew so large that the management responsibilities were spread over two
departments. Dean Batchelor, Chief Operating Officer, added that wastewater collection employs 30-40
people, and those employees are budgeted to wastewater, gas, and water.
Commissioner Forssell noted the Operations Reserve Fund is predicted to fall below the reserve minimum
and below the risk assessment level. Staff projects construction costs will continue to increase, which will
exacerbate the decrease in the Reserve Fund. She questioned the rationale for not recommending a higher
rate increase to raise the Reserve Fund balance above the minimum. Keniston explained that one of the
assumptions in budgeting is the full amount of expenditures in a year will not occur. Ideally, the overall
operations costs of the utility will be less than projected. Staff provided the alternative scenarios so that the
Commission could choose which to recommend to the Council. Jonathan Abendschein, Assistant Director of
Resource Management, added that a delay in an infrastructure project or a savings in operations could
create sufficient savings to maintain the reserves above the minimum level and sometimes well above the
average level. Capital expenditures in the Wastewater Fund are a much larger proportion of costs than in
any other fund. To the extent capital costs are driving rate increases, the Commission and the Council have
a policy choice to reduce a project or to institute a higher rate increase. Vice Chair Ballantine noted that
there was a downside risk to conservative cost estimates. Staff could end up returning with higher than
forecasted future rate increases if costs were above forecasts because reserves were low. Abendschein
acknowledged that risk. Batchelor also noted that at times it was better to re-scope and re-bid the
contracts to look for a better price. Commissioner Forssell felt keeping the rates low would lead to a risk of
being unable to maintain the pace of infrastructure maintenance. Abendschein stated there could be a risk
of project delays if construction costs increase and staff maintains the rate of main replacement. This is one
of the reasons staff provided alternative scenarios.
In response to Commissioner Schwartz's inquiry regarding why Palo Alto's rates are lower than surrounding
communities, Bobel clarified that the rates for some other cities are much higher because renovation of the
Silicon Valley Clean Water Plant began approximately a decade ago. Commissioner Schwartz noted that
Palo Alto’s rates were so much lower than other cities’ rates, there was room to increase them.
In reply to Commissioner Johnston's query regarding the useful life of sewer pipe and expectations for
construction costs to decrease, Batchelor reported that cast iron pipes have been in the ground for 40-50
years. The new High Density Polyethylene (HDPE) pipe should have a life of 100 years. Abendschein
indicated an increase or decrease in construction costs depends on the economy and competition for
services. The City has made huge progress over the last few decades to replace infrastructure.
Commissioner Johnston preferred not to use deferred maintenance as a means to keep rates at a level that
staff thinks customers will be happy with. If maintaining infrastructure adequately requires rate increases,
then the Commission should think about that. Abendschein advised that staff is seeking that type of policy
direction.
Vice Chair Ballantine felt a Palo Alto citizen would feel better about a lower increase if they could be
confident it would not result in deferred maintenance or a public safety issue. Projects are often planned
knowing that less than 100% will be executed. That does not mean a project is deferred. Sylvia Santos,
Engineering Manager, discussed previous sewer maintenance activities. She reported a 2004 Master Plan
study identified capacity-deficient sewer mains, which staff has addressed since 2004. Since 2005 staff has
replaced about 31% of the sewer system. The sewer system does not have capacity problems. Staff is
confident they are not putting the system at risk by deferring the program by one year. Vice Chair
Ballantine remarked that if 31% of the system is replaced every 20 years and if the pipes last 100 years,
then the replacement program should be complete before pipes need to be replaced again.
Chair Danaher advised that the budget reserve is less of an issue because the budget is small; therefore,
taking corrective action is easier. Abendschein reported staff could return to the Commission at midyear if a
problem develops.
Utilities Advisory Commission Minutes Approved on: Page 5 of 6
In reply to Commissioner Trumbull's request for staff to clarify the Commission's recommendation to
Council, Keniston clarified that it included three actions: the rate changes, approval of the Financial Plan,
and approval of a reserve transfer.
In answer to Commissioner Segal's query regarding deferral of projects due to staffing and budgetary issues
and the role compensation played in these issues, Abendschein replied that staff does not anticipate a
budgetary reason for a project deferral because staff can return midyear for a rate change. Staff can also
defer a project to hold down rates. Staff does not plan for deferral of projects due to staffing issues, but it
can be a reason for project deferral. Batchelor noted that compensation is not the sole reason for recent
staffing problems.
Councilmember Filseth understood staff to say they don't think they are using deferred maintenance to
finance artificially low rates. In response to his question about whether the sewer bill would rise to the level
of other cities' sewer bills once renovation of the water treatment plant begins, Keniston indicated that at
the end of five years Palo Alto's sewer bill is projected to reach the current neighboring communities'
average bills, but it is assumed that rates in the other cities will increase as well. Abendschein added that
lower electric and sewer rates help to keep the overall bill for Palo Alto low.
In reply to Commissioner Schwartz's inquiry regarding how many written protests had been received in
prior years, Keniston reported 10-12 customers submitted written protests in 2017.
Chair Danaher recommended the Commission approve the staff recommendation.
Commissioner Forssell preferred the alternate scenario with an 11% increase because it is more prudent
and less likely to lead to deferral of projects due to lack of funds. Commissioner Segal remarked that if
expenses are deferred or lower than budgeted, then future rate increases can be lower than projected.
ACTION: Commissioner Forssell moved to recommend the City Council adopt (1) a Resolution approving
the Fiscal Year 2019 Wastewater Collection Financial Plan; and (2) a Resolution increasing wastewater rates
by 11% by amending Rate Schedules S-1, S-2, S-6, and S-7. Commissioner Johnston seconded the motion.
The motion carried 6-1 with Chair Danaher and Commissioners Forssell, Johnston, Schwartz, Segal, and
Trumbull voting yes and Vice Chair Ballantine voting no.
ITEM 2. ACTION: Staff recommendation that the Utilities Advisory Commission Recommend that City
Council Adopt: (1) a Resolution Approving the Fiscal Year 2019 Water Utility Financial Plan; and (2) a
Resolution Increasing Water Rates by 4% by Amending Rate Schedules W-1 (General Residential Water
Service ), W-2 (Water Service from Fire Hydrants), W-3 (Fire Service Connections), W-4 (Residential Master-
Metered and General Non-Residential Water Service), and W-7 (Non-Residential Irrigation Water Service).
Eric Keniston, Senior Resource Planner, reported that staff recommends a 4% rate increase for the Water
Utility. The main driver of rate increases are water supply costs in the long term and capital investment
costs in the short term. Staff has a plan to upgrade the storage and reservoir system in the next three years.
FY 2021's rate increase is due to the AMI program. Approximately half of rate increases for FY 2018-2024
are related to increases in water supply costs because the Hetch Hetchy system is undergoing major
improvements. Internally, cost increases are split almost equally between capital and operation expenses.
Staff can utilize Unassigned and Rate Stabilization Reserve Funds before needing to withdraw funds from
the Operations Reserve. Projected rate changes include modified CIP costs and the latest projections for
San Francisco Public Utilities Commission (SFPUC) water costs. The bill impact will be an increase of
approximately 3-4% for most customers.
In response to Commissioner Segal's inquiry about Palo Alto water bills being the highest in comparison to
surrounding cities, Keniston stated Palo Alto's water bill is higher than most agencies' bills, but bills are
comparable for some users. Commissioner Schwartz noted Santa Clara's water bill is less than Palo Alto's
bill because Santa Clara does not purchase Hetch Hetchy water.
Utilities Advisory Commission Minutes Approved on: Page 6 of 6
ACTION: Commissioner Johnston moved to recommend the City Council adopt (1) a Resolution approving
the Fiscal Year 2019 Water Utility Financial Plan; and (2) a Resolution increasing water rates by 4% by
amending Rate Schedules W-1, W-2, W-3, W-4, and W-7. Vice Chair Ballantine seconded the motion. The
motion carried 7-0 with Chair Danaher, Vice Chair Ballantine, and Commissioners Forssell, Johnston,
Schwartz, Segal, and Trumbull voting yes.
ITEM 3. ACTION: Selection of Potential Topic(s) for Discussion at Future UAC Meeting
Chair Danaher noted a discussion of the proposed budget is planned for the May meeting. In response to
Commissioners' questions regarding the time of the meeting, Dean Batchelor, Chief Operating Officer,
explained that the meeting usually begins at noon so that staff from all divisions can be present.
Chair Danaher recalled that the April meeting had been rescheduled in prior years. Batchelor agreed to poll
Commissioners for an alternate date.
Commissioner Schwartz requested a discussion of the General Fund transfer; an update about the customer
outage communication system; a discussion about possibly changing the language of the City's claim to be
carbon neutral; and a discussion of resilience. Batchelor felt the City Attorney's Office should advise staff
regarding a discussion around reallocation of Utilities funds to the General Fund transfer. Jonathan
Abendschein, Assistant Director of Resource Management, advised that staff will not be prepared to
answer Commissioner questions about carbon neutrality prior to the June meeting. Vice Chair Ballantine
remarked that the April meeting would be an appropriate time for Commissioners to share their comments.
Chair Danaher suggested Commissioners begin the discussion in April and continue it in June when staff
was prepared to respond to questions.
In reply to Chair Danaher's query regarding Fiber to the Premises, Batchelor indicated a discussion could be
scheduled for June or after staff receives some responses to the Request for Proposals (RFP). Chair Danaher
requested a copy of the RFP when it is released.
In answer to Commissioner Segal's request for an update regarding the transmission line across Stanford's
property, Batchelor reported staff is awaiting a response from Stanford. Staff will send Stanford a letter
with a due date to make recommendations.
ACTION: No action
The next meeting is scheduled for April 4, 2018.
Meeting adjourned at 8:36 p.m.
Respectfully Submitted,
Marites Ward
City of Palo Alto Utilities
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1
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 12, 2018
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt: 1) a Resolution Approving the Fiscal Year 2019
Electric Financial Plan, and 2) a Resolution Increasing Electric Rates by 9% by
Amending the E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU and E-14
Rate Schedules
REQUEST
Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2019 Electric Financial
Plan (Attachment B), including amendments to the Electric Utility Reserves
Management Practices (Attachment C); and
2. Adopt a resolution (Attachment D) amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Small Non-Residential Electric Service), E-2-G (Small Non-Residential
Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-
Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-
7-G (Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-
Residential Time of Use Electric Service), and E-14 (Street Lights).
EXECUTIVE SUMMARY
The FY 2019 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2028. Costs are projected to rise substantially for the next several years for several
reasons. First, costs for electric supply purchases are increasing as a result of new renewable
energy projects coming online. Increases in transmission costs are also projected. Substantial
additional capital investment in the electric distribution system is planned for FY 2018 through
FY 2023, and operational costs are increasing.
Because of these rising costs, an increase in sales revenues is required. A 9% rate increase is
proposed for July 1, 2018, and a 3% increase projected for July 1, 2019, with (0% to 2%)
increases projected afterward. While 9% would be the overall increase in sales revenues,
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different customer classes will see slightly different increases ranging from 7% to 11%, as
shown in Tables 3 and 4. Actual rate increases are calculated using the 2016 cost of service
analysis (COSA) model created for the City by EES Consulting, which was implemented on July 1,
2016.
Several reserves transfers were approved in the FY 2018 Electric Financial Plan, but have not
been executed yet. These are summarized below. Thanks to improved hydroelectric conditions
in FY 2017 and the first half of FY 2018, staff is able to reduce these reserve transfers in the
proposed FY 2019 Electric Financial Plan, particularly the loan from the Electric Special Projects
Reserve. To completely eliminate the loan from the Electric Special Projects Reserve, a 13% rate
increase would be required on July 1, 2018 (though little or no rate increase would be required
in 2019 in this scenario).
Reserve Transfers: Approved, Proposed, and Alternative Transfers
FY 2018 Financial Plan
Approved Transfers
Staff Proposal
(Rate Changes:
9% 2018, 3% 2019)
Alternative
(Rate Changes:
13% 2018, 0% 2019)
Rate Stabilization
Reserve
$9 million $9 million $9 million
Hydroelectric Reserve Up to $11.4 million $1 million (projected) $1 million (projected)
Electric Special
Projects Reserve Loan
$10 million $6 million None
This proposed rate increase is slightly higher than the 8% July 1, 2018 rate increase in staff’s
preliminary rate projections, which was to be followed by a 4% increase on July 1, 2019.
The FY 2019 Electric Financial Plan also includes a change to the reserves policies for the
Hydroelectric Stabilization Reserve, outlining the method used to determine whether the HRA
will be implemented in a given fiscal year, and authorizing staff to transfer funds between the
Operations and Hydroelectric Stabilization Reserve based on a formula that captures the cost
impact or benefit of hydroelectric generation each year.
BACKGROUND
Every year staff presents the UAC with Financial Plans for its Electric, Gas, Water, and
Wastewater Collection Utilities and recommends any rate adjustments required to maintain
their financial health. These Financial Plans include a comprehensive overview of the utility’s
operations, both retrospective and prospective, and are intended to be a reference for UAC and
Council members as they review the budget and staff’s rate recommendations. Each Financial
Plan also contains a set of Reserves Management Practices describing the reserves for each
utility and the management practices for those reserves.
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DISCUSSION
Summary of Proposed Actions
The two resolutions recommended for Council adoption will accomplish the following:
1. Increase overall electric rates by 9% effective July 1, 2018;
2. Approve the FY 2019 Electric Financial Plan, including a change to the reserves policies
for management of the Hydroelectric Stabilization Reserve.
Proposed and Projected Sales Revenue Requirement, FY 2019 through FY 2023
The proposed July 1, 2019 rate increase would be the third in a series of rate increases from
FY 2016 through FY 2020. Prior to the first increase on July 1, 2016, rates had not been
increased since July 1, 2009 because costs had been low over that period. Table 1 shows the
sales revenue increases needed to recover costs of operation over the forecast period in the FY
2019 Electric Financial Plan.
Table 1: Electric Rate Adjustments, FY 2017 to FY 2023
FY 2017
Approved
FY 2018
Approved
FY 2019
Proposed
FY 2020
Projected
FY 2021
Projected
FY 2022
Projected
FY 2023
Projected
11% 14% 9% 3% 2% 0% 1%
These sales revenue increases are for the utility as a whole, but the rate changes will differ for
individual customer classes. Proposed rate increases for each customer class are discussed
below.
Changes from Prior Financial Forecasts
This projection has changed since the FY 2018 Electric Utility Financial Plan presented last year.
Table 2 compares current rate projections to those projected in the last two year’s Financial
Plans. As shown, the FY 2019 rate projections are higher than projected the last two years,
primarily because staff substantially increased its forecast of transmission costs this year.
Table 2: Projected Electric Rate Trajectory for FY 2019 to FY 2025
Projection FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025
Current
(FY 2019 Financial Plan) 9% 3% 2% 0% 1% 1% 1%
Last year
(FY 2018 Financial Plan) 7% 0% 0% 1% 2% 1% 1%
Two years ago
(FY 2017 Financial Plan) 2% 0% 1% 0% 0% 0% 0%
The rate increases are related to several factors: increasing transmission costs and the cost of
renewable projects coming online, substantial additional capital investment in the electric
distribution system is planned through FY 2023, and operations costs are increasing.
Historically, total electric utility costs (excluding short-term drought impacts) were roughly
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$130 million per year, allowing the electric utility to go without a rate increase from July 1, 2009
to July 1, 2016. Over the period from FY 2016 to FY 2019, though, annual costs are increasing to
roughly $175 million per year, approximately 35%, and are projected to stay at that level
through at least FY 2022. Figure 1 shows the utility’s costs in FY 2016, FY 2019, and FY 2022.
Costs for the supply portfolio steadily increase over that time. Costs for distribution operations
increase as well, but to a lesser extent. Capital costs increase significantly in FY 2019 due to
major one-time capital expenditures, then are projected to decrease by FY 2022. The drop in
capital expense by FY 2022 means that total electric utility costs in FY 2019 and FY 2022 are
projected to be roughly the same.
Figure 1: Electric Utility Costs, FY 2016 Actual vs. FY 2019 and FY 2022 Projections
As shown in Figure 2, the contribution to cost increases from FY 2016 to FY 2019 is mostly
related to the supply portfolio and capital spending, while by FY 2022 the supply portfolio is the
largest contributor. Distribution system operational spending is projected to increase compared
to FY 2016. Some of this is due to projected increases in costs of labor and materials, but most
of the apparent increase is due to the fact that not all budgeted funds for distribution
operations were spent in FY 2016, given staff vacancies and other factors.
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Figure 2: Causes of Electric Utility Cost Increases, FY 2016 vs. FY 2019 and FY 2022
The electric supply portfolio increases are related primarily to transmission cost increases and
renewable energy projects coming online, as shown in Figure 3. 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). All of
these groups intervene in transmission proceedings at the Federal Energy Regulatory
Commission (FERC) and the California Independent System Operator (CAISO) and have achieved
some reductions in long-term transmission costs. Staff is beginning to look at strategies for
containing renewable energy costs, and will discuss these strategies in greater detail through
the ongoing Integrated Resource Planning (IRP) process.
Figure 3: Electric Supply Costs, FY 2016 Actual vs. FY 2019 and FY 2022 Projections
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This Financial Plan still contains reserves transfers. Last year’s Financial Plan (FY 2018)
authorized the use of the entire Supply Rate Stabilization Reserve (approximately $9 million),
up to $11.4 million from the Hydroelectric Stabilization Reserve, and a $10 million loan from
the Electric Special Projects Reserves to keep the Supply and Distribution Operations Reserves
above the minimum reserve guidelines. If a 9% rate increase is adopted for July 1, 2018, this FY
2019 Financial Plan proposes reducing the Electric Special Projects Reserve loan to $6 million,
and is projecting only roughly $1 million being needed from the Hydroelectric Rate Stabilization
Reserve. More information on reserve transfers can be found in the FY 2019 Electric Financial
Plan (Attachment B). Actual expenditures in FY 2017 were lower than budgeted, and cost
savings and revenues from improved hydroelectric generator output also helped mitigate some
of the revenue shortfall that had been projected for FY 2018 in prior Financial Plans.
Staff also recognizes the importance of managing operating costs and maximizing efficiency in
order to minimize rate increases. As discussed above, staff is working on cost containment
measures related to transmission and renewable energy costs. Utility consumers also see some
long-term cost savings from City-wide efforts to manage personnel costs. As reflected in the
Utilities Strategic Plan, staff is exploring additional ways to effectively use available resources,
particularly across Divisions.
Rate Changes by Customer Class
Table 3 shows the rates that will be used to recover sale revenues for each customer class. The
Street Lighting (E-14) class and the E-4 and E-7 Time of Use (TOU) rates are not shown in the
table, but can be seen in the attached rate schedules (Attachment E). These schedules are
omitted for various reasons: the E-14 rate schedule is not easy to summarize, E-7 TOU rate is
not easy to summarize and is only used by one customer, and the E-4 TOU rate schedule is both
difficult to summarize and not utilized by any customers at this time.
Table 3: Electric Rates (Current and Proposed)
Current Rates
Proposed Rates
(7/1/18)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.12159 0.13204 .01045 9%
Tier 2 Energy ($/kWh) 0.19001 0.20328 .01337 7%
Minimum Bill ($/day) 0.2938 0.3164 .0226 8%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.18885 0.20978 .02093 11%
Winter Energy ($/kWh) 0.13267 0.14534 .01267 10%
Minimum Bill ($/day) 0.7328 0.8097 .0769 11%
E-4 & E-4-G (Medium Non-Residential)
Page 7 of 9
Summer Energy ($/kWh) 0.11673 0.12275 0.00602 5%
Winter Energy ($/kWh) 0.08890 0.09480 0.00590 7%
Summer Demand ($/kW) 21.05 25.55 4.50 21%
Winter Demand ($/kW) 15.36 19.39 4.03 26%
Minimum Bill ($/day) 14.8414 16.4591 1.6177 11%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.09802 0.10611 0.00809 8%
Winter Energy ($/kWh) 0.07188 0.07531 0.00343 5%
Summer Demand ($/kW) 23.84 28.40 4.56 19%
Winter Demand ($/kW) 15.59 17.80 2.21 14%
Minimum Bill ($/day) 42.3648 46.6013 4.2365 10%
Table 4 shows the impact of the proposed July 1, 2018 rate changes on the residential and non-
residential bills for various consumption levels. The overall rate change for the residential class
is roughly 8%.
Table 4: Impact of Proposed Electric Rate Changes on Customer Bills
Rate
Schedule
Usage (kwh/mo)
Bill under
Current Rates
($/mo)
Bill Under Rates
Proposed 7/1/18
($/mo)
Change
$/mo %
E-1 300 36.48 39.61 3.13 8.6
(Summer Median) 330 40.13 43.57 3.45 8.6
(Winter Median) 453 63.50 68.57 5.08 8.0
650 100.93 108.62 7.69 7.6
1200 205.44 220.42 14.98 7.3
E-2 1,000 162 179 17 10.5
E-4 160,000 24,071 26,762 2,691 11.2
E-7 500,000 67,466 74,524 7,058 10.5
E-7 2,000,000 269,863 298,095 28,232 10.5
Cost of Service Analysis and Rate Study
The rates discussed in the previous section are based on the cost of service methodology
established in the “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2016. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates.
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
Page 8 of 9
Electric Bill Comparison with Surrounding Cities
Table 6 compares electric bills under current rates as of March 1, 2018 for residential customers
to those in surrounding communities. Under current rates, CPAU’s customer bills are far below
PG&E’s and are lower than others for non-residential customers, but slightly higher than Santa
Clara’s for higher using residential customers.
Table 5: Average Electric Bill Comparison ($/month)
As of March 1, 2018
Customers
Usage
(KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E Santa Clara
Residential
Customers
300 $ 36.48 $ 39.61 $ 63.51 $ 35.18
330 (Summer
Median) 40.12 43.57 71.70 38.83
453 (Winter
Median) 63.50 68.57 104.49 53.78
650 100.93 108.62 160.46 77.73
1200 205.45 220.42 314.42 144.59
Non-
Residential
Customers
1,000 161 179 245 181
160,000 23,732 26,762 30,413 20,850
500,000 62,190 74,524 83,820 62,956
2,000,000 268,475 298,095 361,753 256,247
Proposed Change to Reserve Policies
This financial plan proposes a change to Section 7 of the Electric Utility Reserves Management
Practices (see Attachment C), detailing a procedure for calculating the amount of funds staff is
authorized to transfer between the Operations and the Hydroelectric Stabilization Reserves,
based on the extent to which hydroelectric generation deviates from long-term averages. Funds
will be transferred to or from the Hydroelectric Stabilization Reserve on an annual basis based
on the amount of deviation from average hydroelectric generation for each month of the prior
year, multiplied by the average market price for energy for that month.
NEXT STEPS
The Finance Committee is scheduled to review the FY 2019 Electric Financial Plan in May 2018.
The City Council will consider the recommendations with the FY 2019 budget.
RESOURCE IMPACT
The proposed July 1, 2019 rate changes are projected to increase sales revenues by $12.4
million per year over the forecast period.
POLICY IMPLICATIONS
The proposed electric rate adjustments were developed using the 2016 cost of service study
and methodology, and are consistent with the Council adopted Reserve Management Practices
that are part of the Financial Plan.
ENVIRONMENTAL REVIEW
The UAC's review and recommendation to Council on the FY 2019 Electric Financial Plans and
rate adjustments does not meet the California Environmental Quality Act's definition of a
project, pursuant to Public Resources Code Section 21065, thus no environmental review is
required.
ATIACHMENTS
A. Resolution of the Council of the City of Palo Alto Approving the FY 2019 Electric Utility
Financial Plan
B. Proposed FY 2019 Electric Utility Financial Plan
C. Proposed Revised Electric Utility Reserves Policies
D. Resolution of the Council of the City of Palo Alto Adopting an Electric Rate Increase and
Amending Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU, and
E-14
E. Proposed Amendments to Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-
G, E-7 TOU, and E-14
PREPARED BY:
REVIEWED BY :
APPROVED BY:
ERIC KENISTON, Senior Resource Planner Ce. ~L.,
JONATHAN ABENDSCHEIN, Assistant Director, Resource M~t.
C?Y--~
EDSHIKADA
Utilities General Manager
Page 9of9
Attachment A
* NOT YET APPROVED *
6055013
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2019 Electric Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes
making long-term projections of market conditions, the physical condition of the system, and
other factors that could affect utility costs, and setting rates adequate to recover these costs. It
does this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2019 Electric Utility Financial Plan.
SECTION 2. The Council hereby approves the amended Electric Utility Reserves
Management Practices included in the FY 2019 Electric Utility Financial Plan.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
the California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental review is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
Attachment A
* NOT YET APPROVED *
6055013
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2019 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
ATTACHMENT B
2 | Page
F Y 2019 ELECTRIC UTILITY
F INANCIAL PLAN
FY 2019 TO FY 202 8
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2019 Rate and Reserves Proposals ....................................................... 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3C: Reserves Management Practices .............................................................................. 7
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................... 9
Section 4A: Electric Utility History ............................................................................................... 9
Section 4B: Customer Base ........................................................................................................ 11
Section 4C: Distribution System ................................................................................................. 11
Section 4D: Cost Structure and Revenue Sources ...................................................................... 12
Section 4E: Reserves Structure ................................................................................................... 13
Section 4F: Competitiveness ...................................................................................................... 14
Section 5: Utility Financial Projections ................................................................................. 15
Section 5A: Load Forecast .......................................................................................................... 15
Section 5B: FY 2013 to FY 2017 Cost and Revenue Trends ........................................................ 17
Section 5C: FY 2017 Results ....................................................................................................... 18
Section 5D: FY 2018 Projections ................................................................................................ 19
Section 5E: FY 2019 – FY 2028 Projections ................................................................................ 19
3 | Page
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 21
Section 5G: Long-Term Outlook ................................................................................................. 26
Section 6: Details and Assumptions ..................................................................................... 29
Section 6A: Electricity Purchases ............................................................................................... 29
Section 6B: Operations .............................................................................................................. 31
Section 6C: Capital Improvement Program (CIP) ....................................................................... 32
Section 6D: Debt Service ............................................................................................................ 33
Section 6E: Equity Transfer ........................................................................................................ 34
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 34
Section 6G: Sales Revenues ....................................................................................................... 35
Section 7: Communications Plan .......................................................................................... 36
Appendices ......................................................................................................................... 37
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 38
Appendix B: Electric Utility Reserves Management Practices ................................................... 42
Appendix C: Description of Electric utility Operational Activities .............................................. 47
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 48
4 | Page
SECTION 1 : DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a
section of the distribution system operates. The transmission system operates at
115-500 kV, and this is lowered to 60 kV in the sub-transmission section of the
Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution
system, and finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum
electricity demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Sub-transmission System: The section of the Electric Utility’s distribution system that operates
at 60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115
kV or more. The voltage at the intersection of the Electric Utility’s distribution system
and PG&E’s transmission system is 115 kV. The Electric Utility does not own or
operate any transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
5 | Page
SECTION 2 : EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Electric Utility for the next ten fiscal
years. This Financial Plan describes how revenues will cover the costs of operating the utility
safely over that time while adequately investing for the future. It also addresses the financial
risks facing the utility over the short term and long term, and includes measures to mitigate and
manage those risks.
SECTION 2 A : OVERVIEW OF FINANCIAL POSITION
The Electric Utility’s costs will increase substantially over the next few years, as shown in Table
1. Most of the increases are related to electric supply costs, which are increasing due to
increased transmission costs and the cost of new renewable energy projects coming online.
There are also inflationary increases in operations costs, and some above average capital
investment costs in the short term.
Table 1: Electric Utility Expenses for FY 2017 to FY 2028
Expenses
($000)
FY 2017
(act.)
FY 2018
(est.)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Power Supply
Purchases
80,467 83,506 91,925
94,233
95,111 98,655
98,668
99,059 102,252
103,535
103,178
106,193
Operations
53,034 66,953 57,906
59,521
55,363 56,231
63,077
63,710 60,373
61,421
62,498 63,603
Capital
Projects
11,558 20,961 22,684
18,287
20,097 13,632
14,011
14,400 14,800
15,211
15,633 16,068
TOTAL
145,060 171,420 172,515
172,041
170,571 168,519
175,756
177,169 177,425
180,167
181,309
185,863
To cover these increases in costs, revenues (and therefore rates) need to increase over the next
several years to balance costs and revenues, as shown in Table 2. The table also compares
current rate projections to those projected in last year’s Financial Plan. The rate projections are
higher this year than last year primarily due to lower actual and projected sales, increases to
transmission cost projections and increases to capital investment spending.
Table 2: Projected Electric Rates, FY 2019 to FY 2028
Projection FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Current 9% 3% 2% 0% 1% 1% 1% 1% 1% 1%
Last Year 7% 0% 0% 1% 2% 1% 1% 1% 1% N/A
Table 3 shows the projected reserve transfers over the forecast period. The Supply Rate
Stabilization Reserve is projected to be drawn down entirely by the end of FY 2018. Funds are
also projected to be transferred from the Electric Special Projects (ESP) Reserve, and Council
approved the withdrawal of $10 million as part of the FY 2018 Electric Financial Plan. Any
transfers from the ESP Reserve require Council approval. Council also approved using all
6 | Page
remaining funds ($11.2 million) from the Hydro Stabilization Reserve, but ending reserves show
that only $1 million is warranted at this point.
Table 3: Reserves Transfers for FY 2018 to FY 2028 ($000)
Reserve FY 2018 FY 2019 FY 2020 to FY 2028
Supply Reserves
Electric Special Projects (6,000) (771) (1,780)
Hydro Stabilization (1,000) - -
Supply Rate Stabilization (9,011) - -
Supply Operations 8,163
Distribution Reserves
Capital Improvement Program - - -
Distribution Operations 7,848 771 1,780
*
SECTION 2 B : SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2019:
1. Increase rates effective July 1, 2018 for a 9% increase in system average rates.
2. Approve a transfer of up to $771,000 from the Electric Special Projects Reserve for
Smart Grid related funding.
SECTION 3 : DETAIL OF FY 2019 RATE AND RESERVES PROPOSALS
SECTION 3 A : RATE DESIGN
The rates discussed in the previous section are based on the cost of service methodology
established in “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2015/16. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates. The COSA is based on design guidelines adopted by Council on September 15,
2015 (Staff Report 6061).
SECTION 3 B : CURRENT AND PROPOSED RATES
The City adopted the current rates effective July 1, 2017, when CPAU increased electric rates by
14%. Table 4, below, summarizes the current and proposed rates for the four largest customer
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
7 | Page
classes. The Electric Utility also has specialty rates for smaller groups of customers. These
include variations on its primary rates, such as time of use rates and solar net metering. Staff
proposes a 9% overall increase in revenue. Different customer classes may see different
percentage changes to their rates, based upon their usage of the system and cost to serve each
group.
Table 4: Current and Proposed Electric Rates
Current Rates
Proposed Rates
(7/1/18)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.12159 0.13204 .01045 9%
Tier 2 Energy ($/kWh) 0.19001 0.20328 .01337 7%
Minimum Bill ($/day) 0.2938 0.3164 .0226 8%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.18885 0.20978 .02093 11%
Winter Energy ($/kWh) 0.13267 0.14534 .01267 10%
Minimum Bill ($/day) 0.7328 0.8097 .0769 11%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.11673 0.12275 0.00602 5%
Winter Energy ($/kWh) 0.08890 0.09480 0.00590 7%
Summer Demand ($/kW) 21.05 25.55 4.50 21%
Winter Demand ($/kW) 15.36 19.39 4.03 26%
Minimum Bill ($/day) 14.8414 16.4591 1.6177 11%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.09802 0.10611 0.00809 8%
Winter Energy ($/kWh) 0.07188 0.07531 0.00343 5%
Summer Demand ($/kW) 23.84 28.40 4.56 19%
Winter Demand ($/kW) 15.59 17.80 2.21 14%
Minimum Bill ($/day) 42.3648 46.6013 4.2365 10%
These proposed rates were prepared in conformance with the “FY 2017 City of Palo Alto Electric
Cost of Service and Rate Study,” performed by EES Consulting (2016).
SECTION 3 C : RESERVES MANAGEMENT PRACTICES
This financial plan proposes a change to Section 7 of the Electric Utility Reserves Management
Practices (See Appendix B: Electric Utility Reserves Management Practices), detailing a
procedure for calculating the amount of funds to transfer to or from the Hydroelectric
Stabilization Reserve.
8 | Page
SECTION 3 D : PROPOSED RESERVE TRANSFERS
In the FY 2018 Electric Financial Plan, Council approved several proposed transfers for FY 2017
and FY 2018:
• Transfer up to $911 thousand from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve.
• Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offset
potential costs associated with low hydroelectric generation.
• Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution
Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve.
• Transfer up to $10 million from the ESP Reserve to the Distribution Operations Reserve.
This transfer will be construed as a temporary transfer, to be repaid to the ESP Reserve
within five years.
Ending reserve balances for FY 2017 were higher than projected. Because of this, and to keep
some funds in the Hydroelectric Stabilization Reserve in case of drought, staff only projects that
$1 million will need to be transferred out of the Hydroelectric Stabilization Reserve in FY 2018.
The Electric Special Projects (ESP) reserve in future years shows additional transfers of $2.5
million, to help cover the upgrade of the Electric metering system to AMI. This item has been
discussed in prior years as a possible project to be funded from the ESP.
Proposed transfers for FY 2019 will not be requested by resolution at this time, but will be
requested as part of FY 2019 year-end should ending reserve balances require it.
Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E:
FY 2019 – FY 2028 Projections show the impact of these transfers on reserves levels. Table 5
shows the projected balance of each of the Electric Utility reserves for the period covered by
this Financial Plan. See also: Appendix A: Electric Utility Financial Forecast Detail
Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2017 to FY 2028
Ending Reserve
Balance ($000)
FY 2017
(Act.)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Re-appropriations - - - - - - - - - - - -
Commitments 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971
Underground Loan 730 730 730 730 730 730 730 730 730 730 730 730
Public Benefits 681 - - - - - - - - - - -
Special Projects 51,838 45,838 45,067 42,757 43,247 42,847 42,847 42,847 42,847 42,847 42,847 42,847
Hydro Stabilization 11,400 10,400 10,400 10,400 10,400 13,900 13,900 13,900 13,900 13,900 13,900 13,900
Capital 880 880 880 880 880 880 880 880 880 880 880 880
Rate Stabilization 9,011 - - - - - - - - - - -
Operations 29,913 34,642 29,259 32,789 36,969 36,898 37,985 39,738 42,748 45,049 48,430 49,200
Unassigned - - - - - - - - - - - -
TOTAL 107,424 95,461 89,307 90,527 95,197 98,226 99,313 101,066 104,076 106,377 109,758 110,528
9 | Page
SECTION 4 : UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4 A : ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel
engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity
continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E
proved more economical than the diesel engines, and by the late 1920s CPAU was using its own
diesel engines only during peak demand periods. At that time CPAU owned 45 miles of
distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual
consumption. The diesel engines remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did
throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the
sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto,
which doubled the number of customers. Some was related to the proliferation of electric
appliances, as evidenced by the fact that residential customers were using three times more
electricity in 1970 than they had been in 1950. But the most notable factor was the growth of
industry in Palo Alto during that time. By 1970, commercial customers were using 20 times
more electricity per customer than they had been in 1950. These decades also saw several
other notable events, including:
• 1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of
Reclamation to purchase power from the Central Valley Project (CVP), a contract which
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
• 1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
• 1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
10 | Page
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement
program for its underground system in the early 1990s.
In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and
in 1996 the State legislature passed Assembly Bill 1890, which, among other things, created the
California Independent System Operator (CAISO) to operate the transmission system and the
Power Exchange to facilitate wholesale energy transactions. This restructuring was anticipated
to bring lower costs to consumers, and while CPAU was not required to participate in the
industry restructuring, in 1997 the Council approved a Direct Access Program for the Electric
Utility2 that enabled CPAU to sell electricity outside its service territory and allowed customers
within CPAU’s service territory to choose other providers. The utility unbundled its electric
rates, creating separate supply and distribution components, which would enable customers to
receive only distribution service while purchasing the electricity itself from another provider.
The energy crisis in 2000 to 2001 led to the suspension of direct access by the CPUC in
September 2001 as wholesale energy prices skyrocketed. The Electric Utility was less impacted
than other utilities by the 2000 to 2001 energy crisis thanks to the Calaveras project and its
contract with WAPA for CVP hydropower.
In 2001 CPAU began planning for the impacts associated with the new terms of its contract with
WAPA, set to take effect in 2005. The previous contract had provided 90% of Palo Alto’s power
supply at favorable rates, and PG&E, as a party to the contract, had provided supplemental
power to balance the monthly and annual variability of CVP generation. The new contract
would provide only a third of Palo Alto’s requirement, and the monthly and annual variability in
CVP generation would be passed directly to Palo Alto. As a result, electric supply costs would
increase and CPAU needed to more actively manage its supply portfolio. CPAU began
purchasing power from marketers and also investigated building a power plant in Palo Alto or
partnering in the development of a gas-fired power plant elsewhere. Climate change was also
becoming more of a concern to the community, and gradually CPAU shifted its focus to the
procurement of renewable energy. In 2002 CPAU adopted a goal of achieving 20% of its energy
supply from renewables by 2015. Subsequently CPAU signed its first contract for renewable
power, a contract for energy from a wind generator commencing deliveries in 2005. In 2011 the
renewable energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a
plan to make its electric supply 100% carbon neutral, which it achieves through the
combination of its carbon-free hydroelectric supplies, purchases of long-term renewable energy
supplies, and short-term renewable energy purchases (RECs) to meet the balance of its needs.
2 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
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Figure 1: Customer Consumption By Class (FY 2017)
16%
6%
36%
42%
Residential
Small Comm.
Med. Comm.
Large Comm.
SECTION 4 B : CUSTOMER BASE
The City of Palo Alto’s Electric Utility
provides electric service to the
residents, businesses, and other
electric customers in Palo Alto. There
are roughly 29,600 customers
connected to the electric system,
25,550 (86%) of which are residential
and 4,050 (14%) of which are non-
residential. Residential customers
consumed 147 gigawatt-hours (GWh)
in FY 2017, approximately 16% of the
electricity sold, while non-residential
customers consumed 84% or 771
GWh. Residential customers use
electricity primarily for lighting,
refrigeration, electronics, and air conditioning.3 Non-residential customers use the majority of
their electricity for cooling, ventilation, lighting, office equipment (offices), cooking
(restaurants), and refrigeration (grocery stores).4
As shown in Figure 1 large customer loads represent a large proportion of sales for the Electric
Utility. The proportion of sales to large vs. small customers is greater than for the City’s other
utilities. For example, the largest customers (the 71 customers on the E-7 rate schedule)
account for around 42% of CPAU’s sales. The next largest customer group (the 830 non-
residential customers on the E-4 rate schedule) represents another 36% of sales. In total, that
means that about 3% of customers account for nearly three quarters of the electric load.
SECTION 4 C : DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 472 miles of
distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are
underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line
transformers, around 1,100 underground and substation transformers, and the associated
electric services (which connect the distribution lines to the customers’ homes and businesses).
These lines, substations, transformers, and services, along with their associated poles, meters,
3 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
4 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
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Figure 2: Cost Structure (FY 2017)
55%
37%
8%
Commodity
Supply
Operations
Capital
Figure 4: Hydroelectric Variability (FY 2019)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 3: Revenue Structure (FY 2017)
81%
19%
Sales of Electricity
Other Revenue
and other associated electric equipment, represent the vast majority of the infrastructure used
to deliver electricity in Palo Alto.
SECTION 4 D : COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 55% of the Electric Utility’s
costs in FY 2017. Operational costs
represented roughly 37%, and
capital investment was responsible
for the remaining 8%. CPAU’s non-
hydro long-term commodity supply
is heavily dependent on long-term
contracts which have little variability
in price. On average, costs for these
long-term contracts are not
predicted to increase as quickly as operations and CIP costs, and will steadily become a smaller
proportion of the Electric Utility’s costs. Staff projects commodity supply costs to be
approximately 56% of total costs in FY 2028.
While average year purchase
costs for the electric utility
are predictable due to its
long-term contracts,
variability in hydroelectric
generation can result in
increased or decreased
costs. This is by far the
largest source of variability
the utility faces. Figure 3
shows the difference in costs
under high, projected, and
low hydroelectric generation scenarios
for FY 2019. Additional costs associated
with a very low generation scenario can
range from $9-11 million per year. For
the current hydroelectric risk assessment
see Section 5F: Risk Assessment and
Reserves Adequacy.
As shown in Figure 4 the Electric Utility
receives 81% of its revenue from sales of
electricity and the remainder from
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connection fees, interest on reserves, cost recovery transfers from other funds for shared
services provided by the electric utility, and other sources. Some revenue sources are primarily
accounting entries that reflect things such as CPAU’s participation in a pre-funding program
associated with its contract with WAPA, as well as accounting entries associated with
occasional sales of surplus hydroelectric energy during wet years. Appendix A: Electric Utility
Financial Forecast Detail shows more detail on the utility’s cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 900 largest customers, which provide a similar share of the utility’s revenue stream.
The utility’s retail rate schedules have no fixed charges, although about 24% of the utility’s
revenue comes from peak demand charges on large non-residential customers. Due to
moderate weather and the prevalence of natural gas heating, however, loads (and therefore
revenues) are very stable for this utility, without the large seasonal air conditioning or winter
heating loads seen at some other utilities.
SECTION 4 E : RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of
contingencies. It also maintains two funds, the Supply Fund and the Distribution Fund, to
manage costs associated with electricity supply and electricity distribution, respectively. The
City established this separation of supply and distribution costs as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) in the late 1990s and
early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues to
maintain separate funds to facilitate separation of supply and distribution costs in the rates.
This could be important if California ever decides to broadly reintroduce Direct Access, and may
also be useful for rate design as the nature of utility services evolves in response to higher
penetrations of distributed generation.
The summary below describes the various reserves, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserves for Commitments: Reserves equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserves for Reappropriations: Reserves for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve. This is currently an important
reserve for all utility funds, but changes in budgeting practices will change that in future
years, as described in Section 3C (Reserves Management Practices).
• Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which was accumulated during deregulation of California’s electric system to
fund the stranded costs associated primarily with the Calaveras hydroelectric resource
and the California-Oregon Transmission Project. When that reserve was no longer
needed for that purpose, the reserve was renamed and the purpose was changed to
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fund projects with significant impact that provide demonstrable value to electric
ratepayers.
• Hydroelectric Stabilization Reserve: This contingency reserve is used for managing
additional costs due to below average hydroelectric generation, or to hold surpluses
resulting from above average hydroelectric generation.
• Underground Loan Reserve: This reserve is an accounting tool used to offset receivables
associated with loans made through the underground loan program. It is adjusted
according to principal payments made on those loans.
• Public Benefits Reserve: CPAU’s electric rates include a separate charge called the
“Public Benefits Charge” which generates revenue to be used for energy efficiency,
demand-side renewable energy, research and development, and low-income energy
efficiency services. Any funds not expended in the current year are added to the Public
Benefits Reserve for use in future years.
• Capital Improvement Program (CIP) Reserve: The CIP reserve is used to provide
working capital and contingency funds for the CIP program, as well as to accumulate
funds for major future one-time expenditures. This type of reserve is used in other
utility funds (Electric, Gas, and Wastewater Collection) as well.
• Supply and Distribution Rate Stabilization Reserves: These reserves are intended to be
empty unless one or more large rate increases are anticipated in the forecast period. In
that case, funds can be accumulated to spread the impact of those future rate increases
across multiple years. This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Supply and Distribution Operations Reserves: These are the primary contingency
reserves for the Electric Utility, and are used to manage yearly variances from budget
for operational costs and electric supply costs (aside from variances related to
hydroelectric generation). This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves
are for any financial resources not assigned to the other reserves and are normally
empty.
SECTION 4 F : COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2017 was
$589.02 under current CPAU rates, 38% lower than the annual bill for a PG&E customer with
the same consumption and approximately 12% higher than the annual bill for a City of Santa
Clara customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X,
which includes most surrounding comparison communities.
Table 6 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara
(Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown
below were in effect as of March 1, 2018.
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Over the next several years low usage customers in PG&E territory are expected to continue to
see higher percentage rate increases than high usage customers as PG&E compresses its tiers
from the highly exaggerated levels that have been in place since the energy crisis. This is likely
to make the bill for the median Palo Alto consumer look even more favorable compared to
most PG&E customers. Even with the compressed tiers, bills for high usage Palo Alto consumers
are likely to remain substantially lower than the bills for high usage PG&E customers.
The bill calculations show bills under the existing rates, not the proposed July 1, 2018 rates.
However, even with the proposed rate increases, Palo Alto’s residential bills will remain
substantially below PG&E’s current rates, but slightly above Santa Clara’s.
Table 6: Residential Monthly Electric Bill Comparison (Effective 3/1/18, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(March)
300 36.48 63.51 35.18
453 (Median) 63.50 104.49 53.78
650 100.93 159.64 77.73
1200 205.45 313.60 144.59
Summer
(July)
300 36.48 63.51 35.18
(Median) 330 40.12 71.70 38.83
650 100.93 161.28 77.73
1200 205.45 315.24 144.59
Table 7 shows the average monthly electric bill for commercial customers for various usage
levels. Even with the proposed rate increases, Palo Alto’s commercial bills will remain
substantially below PG&E’s, and below Santa Clara’s for some commercial customers.
Table 7: Commercial Monthly Electric Bill Comparison (3/1/18, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 161 245 181
160,000 23,732 30,413 20,850
500,000 62,190 83,820 62,956
2,000,000 268,475 361,753 256,247
SECTION 5 : UTILITY FINANCIAL PROJECTIONS
SECTION 5 A : LOAD FORECAST
Figure 5 shows a 33-year history of Palo Alto electricity consumption. Average electricity
consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then
electricity consumption has declined slowly as a result of a continuing focus on energy
efficiency, as well as the adoption of more stringent appliance efficiency standards and energy
standards in building codes.
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Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2028. Sales after the July
2016 rate change decreased by 6% from projections. To be conservative, the forecast assumes
that current trends continue and sales through the forecast period decline slightly.
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Figure 6: Forecasted Electricity Consumption
SECTION 5 B : FY 201 3 TO FY 2017 COST AND REVENUE TRENDS
The annual expenses for the Electric Utility remained fairly stable between FY 2013 and FY
2017, as shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail
Section 6A: Electricity Purchases discusses the factors influencing Electric Utility expenses. Since
FY 2012, total expenses for the utility have included the costs of renewable resources coming
online. In FY 2014 through FY 2015 commodity costs were higher due to lower than average
output from hydroelectric resources.
Commodity costs and capital investments are responsible for most of the changes in the
utility’s expenses over the last six years. Operational costs decreased during that time but will
increase once staffing levels return to normal levels.
Actual Projection
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2017 and Projections through FY 2028
SECTION 5 C : FY 2017 RESULTS
Total cost of purchasing electricity was lower than the forecast by approximately $3.9 million.
Capital improvement costs were lower than the forecasted level by $9.9 million. Sales revenues
were higher than the forecast by $2.9 million, but there was also $4.8 million in surplus sales
revenue beyond what was budgeted. While net revenues were still lower than cost by $3
million, the net reserve withdrawal was lower than originally anticipated ($25 million). The
lower withdrawal in FY 2017 will allow for reserves to be used in future years.
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Table 8 FY 2017, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues higher than forecast $(2,881) Revenue increase
Wholesale and other revenues higher than
forecast
(5,978) Revenue increase
Lower capital improvement costs (9,932) Cost decrease
Lower purchased electricity costs (3,904) Cost decrease
Higher operations costs 344 Cost increase
Net Cost / (Benefit) of Variances $(22,352)
SECTION 5 D : FY 2018 PROJECTIONS
Last year, staff recommended (and Council approved) a 14% rate change for July 1, 2017, the
start of FY 2018. Current sales revenue projections for 2018 are roughly $1.5 million higher than
expected in last year’s financial plan. Based on current hydro conditions, wholesale costs are
again expected to contribute to other revenues being higher by $5.5 million. Purchased
electricity cost projections for 2018 are anticipated to be $4.5 million lower than in last year’s
financial plan. However, capital cost estimates and operations cost estimates (which includes
other than purchased electricity costs) increased by $5.3 million and $3.8 million, respectively.
Table 9 FY 2018, Change in Projected Results, 2018 Forecast vs. 2019 Forecast ($000)
Net Cost/(Benefit) Type of change
Sales revenues (1,454) Revenue increase
Wholesale and other revenues higher than
forecast
(5,476) Revenue increase
Capital improvement costs 5,388 cost increase
Purchased electricity costs (4,481) cost decrease
Operations costs 3,848 cost increase
Net Cost / (Benefit) of Variances $2,175
SECTION 5 E : FY 2019 – FY 2028 PROJECTIONS
As shown in Figure 7 above, staff projects costs for the Electric Utility to increase at a fairly
steady rate through the forecast period. Revenue increases of 9% in FY 2019 and another 3% in
FY 2020 are projected to bring revenues in line with expenses. Rising electricity purchase costs
are the primary contributor to the increases. Electricity purchase costs have increased
substantially since FY 2013 as new renewable projects have come online to fulfill the City’s
environmental goals, and as transmission costs have increased due to improvements being
made to the California grid. Operations costs are expected to increase at or near the inflation
rate (2-4 %/year) through the forecast period. Projected capital expenses for FY 2018 through
FY 2023 are higher in FY 2018 through FY 2021 due to work on the Upgrade Downtown project,
as well as anticipated AMI and smart grid implementation. Once these larger, one-time project
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cost increases are completed, annual CIPs are anticipated to decline back to levels seen in
recent years. This forecast also assumes that smart grid costs are funded from the Electric
Special Projects Reserves.
Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund
Reserves) and Figure 9 (for Distribution Fund Reserves), below. The Supply Rate Stabilization
Reserve will be empty by the end of FY 2018.
Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2017 and Projections through FY 2028
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Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2017 and Projections through FY 2028
SECTION 5 F : RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two contingency reserves, the Supply Operations Reserve and
the Distribution Operations Reserve. This Financial Plan maintains reserves above the reserve
minimum for the Distribution Operations Reserve throughout the forecast period. Reserve
levels also exceed the short-term risk assessment level for the Distribution Fund. The Supply
Operations Reserve, however, may end up below minimum levels and below the short-term risk
assessment level.
There are a variety of risks associated with the Supply Fund as are shown in Table 10. Because
of the high range of uncertainty in energy price predictions more than three years in the future,
this risk assessment is only performed for the first two fiscal years of the forecast period. It is
important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 10 is very low.
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Table 10: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2019 FY 2020
1. Production from Hydroelectric
Resources: Western 6.8 6.2 Lower than forecasted hydro
2. Production from Hydroelectric
Resources: Calaveras 3.3 2.6 Lower than forecasted hydro
3. Market Price (Energy) 2.2 0.8 Higher than forecasted market prices for
energy
4. Transmission/CAISO 3.3 3.3 High-end transmission forecast scenario
5. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
6. Western Cost 3.5 3.5 Risk of rate adjustments from Western
7. Regulatory and Legal 0.0 0.0 Risks associated with legislative uncertainties
Electric Supply Fund Risks $19.9
million
$17.4
million
Projected Supply Operations +
Hydro Stabilization Reserve
Levels
$39.6
million
$43.2
million
Of the risks faced by the Electric Utility’s Supply Fund in FY 2019, the risk of a dry year with very
low hydroelectric output is normally the largest, accounting for nearly half the total cost of all
adverse outcomes. Since the utility’s costs for its hydroelectric resources are almost entirely
fixed, costs do not decline when the output of those resources are low, but the utility needs to
buy power to replace the lost output. The converse happens when hydroelectric output is
higher than average.
Of the remaining risks for FY 2019, $3.3 million is related to the projected costs if transmission
cost increases are higher than staff’s current forecast. $3.5 million is related to the uncertainty
to Western’s rates for Restoration costs.
As shown in Figure 10, the Supply Operations Reserve was below the minimum reserve
guidelines at the end of FY 2017. However, through reserve transfers and rate increases, staff
projects the Supply Operations Reserve to stay within the reserve guideline levels throughout
the forecast period. Figure 11 shows that the combined Hydro Stabilization and Supply
Operations Reserves are projected to be above what is needed for the risk assessment level.
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Figure 10: Electric Supply Operations Reserve Adequacy
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Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 11 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2023. As shown in Figure 12, the Distribution Operations Reserve will stay within the
reserve guidelines over the course of the forecast period, although it was recorded below the
minimum reserve guidelines at the end of FY 2017. The risk assessment includes the revenue
shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 11: Electric Distribution Fund Risk Assessment ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Total non-commodity revenue $53,387 $53,732 $53,534 $53,883 $54,773
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $4,214 $4,241 $4,225 $4,253 $4,323
CIP Budget $22,684 $18,287 $20,097 $13,632 $14,011
CIP Contingency @10% $2,268 $1,829 $2,010 $1,363 $1,401
Total Risk Assessment value $6,482 $6,070 $6,235 $5,616 $5,724
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Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, staff projects the CIP Reserve to be at or above the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels, CIP Commitments are nearly impossible to project that far out, and
adjustments to the reserve can be made in future years.
Figure 13: Electric CIP Reserve Adequacy
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SECTION 5 G : LONG-TERM OUTLOOK
This forecast covers the period from FY 2019 through FY 2028, but various long-term
developments may create new costs for the utility over the next 5 to 35 years. While it is
challenging to accurately forecast the impact these events will have on the utility’s costs, it is
worth noting them as future milestones and keeping them in mind for long-term planning
purposes.
For the supply portfolio, the 2020s will see a number of notable events. The contract with
Western for power from the CVP will expire in 2024. Determining the future relationship with
Western after 2024 will be important in the years leading up to the contract expiration,
especially because this resource represents nearly 40% of the electric portfolio, and is the
utility’s largest source of carbon-free electricity. The utility’s three earliest and lowest cost
renewable contracts will also begin expiring around that time, with the first contract expiring in
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
27 | Page
megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those
contracts expire. Although recent prices have been in that range (or even lower), and costs
may decrease in the future, current renewable projects also benefit from a wide range of tax
and other incentives that may or may not be available in the 2020s and beyond. However, staff
is in the process of procuring a replacement for the contract expiring in 2021 at a lower price
than any of the City’s current renewable contracts.
The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs
dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032
(assuming the Utility does not issue any new debt). The project will only be 40 years old at that
time. Calaveras debt service represents roughly 70% of the annual costs of that project (and
nearly 7% of the utility’s total costs), so when the debt is retired, the project could be a low-
cost asset for the utility, providing carbon-free energy equal to around 13% of the Electric
Utility’s supply needs in an average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to 5 million per year in revenue from
allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to
pay for energy efficiency programs and to purchase renewable energy to support the utility’s
Carbon Neutral Plan. Staff expects that revenue source to continue through 2020. However,
discussions at the state level are ongoing and will determine whether or not these allocations
continue past 2020, as well as any restrictions CARB may wish to enact on usage of allocation
sales revenues. If the Electric Utility no longer received these allowances or was limited in how
it could spend revenues, it would have to fund these programs from sales revenues.
Transmission costs are also continuing to rise. If the State continues to increase mandates or
incentives for renewable energy development, integrating these new projects into the
transmission grid will be an ever increasing challenge, some costs of which will be borne by Palo
Alto. The planned expansion of the CAISO to a larger regional grid control area may result in
additional transmission costs that could further increase CPAU’s transmission costs. In addition
to the costs of new transmission lines that will need to be built, flexible resources will be
required to balance rapid changes in wind or solar output throughout the day. Palo Alto will
likely bear some of the costs of these new lines and resources. CPAU is also currently
investigating installing a second transmission interconnection for Palo Alto, which could be
funded by the Electric Special Projects Reserve.
Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these
factors may begin to create notable increases in electric consumption and have a variety of
impacts on the distribution system. As housing stock is turned over, however, stricter building
codes may help to counteract load growth, as may increasing numbers of rooftop solar
installations. The utility has already started to take some of these factors into account in its
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long-term planning processes, but will need to continue to incorporate them into its planning
methodologies.
Over the long term, it is conceivable that electricity could replace natural gas and petroleum
almost entirely. Many, if not most, vehicles would use electricity, though hydrogen is another
potential fuel source under development and other technologies might be developed. Staff are
undertaking initial analysis of these types of scenarios in the context of the Sustainability and
Climate Action Plan (S/CAP) development process. These types of scenarios require careful
planning for the associated load growth to make sure the distribution system does not end up
overloaded, or conversely, to avoid over investment, and the evaluation of changes to utility
distribution system management to accommodate integration of the various technologies
involved in electrification.
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SECTION 6 : DETAILS AND ASSUMPTIONS
SECTION 6 A : ELECTRICITY PURCHASES
As shown in Figure 14 the utility gets roughly 50% of its energy from hydroelectric projects in a
normal year (FY 2014 and FY2015 were dry). Contracts with renewable sources made up just
over 30% of the portfolio in FY 2016, and 50% in FY 2017. Staff expects contracts with
renewable sources to continue at approximately 50% of the portfolio for the forecast period.
The remainder comes from unspecified market sources. Under the City’s Carbon Neutral Plan,
CPAU purchases RECs corresponding to the amount of market energy it purchases.
Figure 12: Electricity Supply by Source
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Figure 15 shows the historical and projected costs for the electric supply portfolio,5 as well as
average and actual hydroelectric generation.6 Electric supply costs increased in FY 2013, FY
2014, and FY 2015 due to the drought, which reduced the amount of generation from
hydroelectric resources. Costs decreased slightly in FY 2016 due to better than expected market
purchase costs, and FY 2017 and FY 2018 had lower hydroelectric costs. Increases in renewable
energy costs are expected as various renewable projects come online to fulfill the City’s carbon
neutral and RPS goals. Transmission charges are also projected to increase as new transmission
lines are built throughout California to accommodate new renewable projects. In total, electric
supply costs are projected to increase to $85 million by FY 2020, at which point all currently
contracted renewable projects will be online. Supply costs are only projected to change slightly
in subsequent years.
Figure 13: Electric Supply Portfolio Costs, Historical and Projected
5 Costs are shown net of wholesale revenues, and cannot be directly compared with the electric supply purchase
figures shown in Appendix A: Electric Utility Financial Forecast Detail
6 Average hydroelectric generation increased in January of 2015 due to an increase in the utility’s contractual share
of the output of the CVP Federal hydropower project.
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SECTION 6 B : OPERATIONS
CPAU’s Electric Utility operations include the following activities:
• Administration, including financial management of charges allocated to the Electric
Utility for administrative services provided by the General Fund and for Utilities
Department administration, as well as debt service and other transfers. Additional detail
on Electric Utility debt service is provided in Section 6D (Debt Service)
• Customer Service
• Engineering work for maintenance activities (as opposed to capital activities)
• Operations and Maintenance of the distribution system; and
• Resource Management
Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 2013 to FY 2017, Operations costs stayed relatively flat. In 2013 there was a one-time
increase in expenses associated with an adjustment to the value of the City’s investment
portfolio. In 2018 there is an increase in administration costs. Debt service and transfers costs
increase (reflecting transfers in from the ESP reserve). However, over the forecast horizon,
excluding debt service and transfers, staff project costs to increase by roughly 2-3% per year.
Figure 14: Historical and Projected Electric Utility Operational Costs
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SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
Staff projects CIP spending for FY 2019 through FY 2024 to be consistent with last year’s
forecast, though there is a slight shift in the funding by project category. There will be a
reduction in capital cost and revenue related to the VA Hospital project as the VA will be
responsible for the installation, and associated costs, of electric facilities; there will be a
reduction in funding for Undergrounding as current projects are completed; there will be an
increase in funding for Underground Rebuilding and 4/12kV Conversion as improvements are
made to the system in portions of the Crescent Park/Duveneck/St. Francis/Community
Center/Leland Manor/Garland neighborhoods to facilitate rebuild of the Hopkins Substation;
and increase in funding for replacement of distribution system and substation facilities that are
at the end of their useful life. Other significant projects still slated to continue are deteriorated
wood pole replacements, pole relocations to facilitate the Caltrain Railway Electrification
project, Smart Grid upgrades, and ongoing capital investment in the electric distribution system
to maintain/improve reliability. This forecast assumes that the utility finances smart grid
projects from the Electric Special Projects Reserve and with additional funding from the water
and gas funds, but it would also be possible to use bond financing.
Excluding the one-time projects listed above, the CIP plan for FY 2019 to FY 2023 is primarily
funded by utility rates, but other sources of funds include connection fees (for Customer
Connections), phone and cable companies (primarily for undergrounding), and other funds (for
smart grid). The details of the CIP budget will be available in the Proposed FY 2019 Utilities
Capital Budget. Figure 17 shows the FY 2018 projected budget and the five year CIP spending
plan, although these figures are preliminary pending budget discussions starting in May. The
‘committed’ column represents funds committed to contracts for which work has not yet been
completed or invoices paid.
Figure 15: Electric Utility CIP Spending ($000)
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
One-Time Projects 5,021 (128) 4,893 123 1,400 1,300 10,750 5,000 5,000
System Expansion 3,507 (27) 3,481 - - - - - -
Reliability 3,711 (129) 3,582 153 1,067 317 150 - -
Undergrounding 4,395 (40) 4,355 353 900 - 2,000 2,250 500
4/12 Kv Conversion 270 (1) 269 - - 1,750 800 - -
Underground Rebuilding 3,385 (3) 3,382 3 - 2,656 1,500 350 350
Ongoing Projects 6,714 (882) 5,832 3,255 3,145 3,625 3,280 3,280 3,230
Customer Connections
(Fee Funded)4,087 (1,149) 2,938 589 3,220 3,336 3,456 3,580 3,600
TOTAL 31,091 (2,359) 28,732 4,476 9,732 12,984 21,936 14,460 12,680
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year.
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
33 | Page
SECTION 6 D : DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently
makes payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax
Credit Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction
costs of solar demonstration projects at the Municipal Services Center, Baylands Interpretive
Center, and Cubberley Community Center. The capacity of these projects totaled 250 kW. In
exchange for funding part of the construction costs, the Electric Utility receives the RECs from
these projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are
interest free (the investors receive a tax credit from the federal government). This bond
issuance is secured by the net revenues of the Electric Utility. Debt service for this bond
continues through 2021, and for the financial forecast period is as follows:
Table 11: Electric Utility Debt Service ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2007 Clean Renewable
Energy Bonds 100 100 100 100 - -
The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage
ratio of 125% of debt service. The current Financial Plan maintains compliance with these
covenants throughout the forecast period, as shown in Appendix C.
The Electric Utility also pledges reserves and net revenue as security for the bond issuances
listed in Table 13, even though the Electric Utility is not responsible for the debt service
payments. The Electric Utility’s reserves or net revenues would only be called upon if the
responsible utilities are unable to make their debt service payments. Staff does not currently
foresee this occurring.
Table 12: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Electric Utility’s:
Net Revenues Reserves
1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water $1,457 No Yes
*Net of Federal interest subsidy
34 | Page
SECTION 6 E : EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.7 Each year it is calculated
according to the 2009 Council-adopted methodology, and does not require additional Council
action.
SECTION 6 F : WHOLESALE REVENUES AND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 19% comes
from other sources. Of these other sources, about 50 to 60% represents wholesale revenues of
surplus energy sales included solely for accounting purposes. These revenues have offsetting
electric supply purchase costs, and do not normally affect the utility’s net position. Of the
remaining revenues, the largest revenue sources are interest on reserves, connection fees for
new or replacement electric services, and carbon allowance revenues associated with the
State’s cap-and-trade program. In FY 2017 these sources represented roughly 28% of revenue
from sources other than electricity sales. The remaining FY 2017 revenues consisted of a variety
of one-time transfers.
Revenues from connection fees have increased since FY 2009 varying from year to year.
Revenue from connection fees decreased slightly during the recession, but has increased
substantially since then, peaking in FY 2016 and declining somewhat in FY 2017. Staff forecasts
slightly higher revenue from this source in 2018 through 2021 with revenue leveling out in
subsequent years.
Staff projects carbon allowance and interest income revenues to stay relatively stable through
the forecast period. However, both of these revenue sources are subject to some uncertainty.
The State’s cap-and-trade program regulations only describe the program through 2020. This
forecast assumes the program will remain in place with similar program design following 2020,
but that may not be the case. CARB is in the process of establishing post-2020 rules.
The forecast for interest income assumes current interest rates continue and there are no
major reserve reductions aside from what is anticipated in this Financial Plan. If interest rates
rise, interest income could increase, and if reserves decrease (due to drought or a withdrawal
from the ESP reserve for a major project), interest income would decrease.
7 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to equity transfer methodology.
35 | Page
SECTION 6 G : S ALES REVENUES
The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7
provide the basis for sales revenue projections. As discussed in Section 5A, sales revenues for
this utility stay relatively stable due to the mild climate in Palo Alto. In addition, Palo Alto is a
built out City, with incremental growth in population and relatively stable commercial customer
loads.
36 | Page
SECTION 7 : COMMUNICATIONS PLAN
The FY 2019 Electric Utility communications strategy covers these primary areas: rates,
efficiency, renewables, operations, infrastructure, safety, and changes to utility economic
conditions in the wake of the drought. CPAU communication methods include use of the
Utilities website, utility bill inserts, messaging on bills and envelopes, email newsletters, print
ads in local publications, videos and participation in community outreach events.
In FY 2019, CPAU is proposing a nine percent increase in electric utility rates. Prior to FY 2017,
electric utility rates had not increased since 2009, as the City has been drawing down reserves
from the Electric Fund. The rate increase will be necessary in FY 2018 and again in FY 2019, as
these reserves drop below the reserve target level. Communications will focus on the reasons
why a rate increase is necessary, due to an increase in transmission fees and new renewable
projects coming online, rising operating and capital costs, and how drought affected the City’s
reserves. Palo Alto purchases a significant portion of its electricity from hydroelectric resources.
Several-year drought conditions reduced available hydroelectric supplies, requiring the City to
purchase more costly replacement electric supplies. Since the State may not received a great
deal of precipitation in the latter part of FY 2018, communications staff will now focus
messaging on how increased hydroelectric supplies could still impact and potentially change the
forecast for electric rates moving forward, at least in the short-term.
Despite these costs and increasing rates, CPAU’s electric utility rates remain lower than the
neighboring community average, including for municipal and investor-owned utilities (PG&E).
Keeping costs low is one of the benefits CPAU offers its customers as a public utility provider.
CPAU will continue to communicate about the environmental benefits of the City’s carbon
neutral electric supply portfolio. Outreach includes apprising the public of major renewable
energy purchase agreements, which contribute toward Palo Alto’s long-term energy security
and commitment to sustainability. Recent power purchase agreements have allowed CPAU to
procure long-term renewable electric supplies at low costs. While upfront capital costs to bring
these renewable projects online may initially contribute towards some increase in CPAU’s
electric rates, staff expect these higher costs to taper off once the projects begin commercial
operations. CPAU will highlight these environmental attributes and value in our
communications.
Throughout the year, communications staff promote CPAU’s electric efficiency services, rebates
and local renewable energy programs. Within the past few years, CPAU has launched new
programs that allow customers to better understand and manage their energy use. Programs
such as the Home Efficiency Genie and commercial energy efficiency programs help residents
and businesses better understand energy usage, activities and/or upgrades they can implement
to improve efficiency and reduce utility costs. CPAU will be launching an upgraded version of its
online utility account services portal (www.cityofpaloalto.org/myutilitiesaccount) this year,
which can provide customers with direct access and more information about utility account and
consumption data.
37 | Page
APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
6053706
APPENDIX A : ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
6053706
(page intentionally left blank)
6053706
1 FISCAL YEAR FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
2
3 ELECTRIC LOAD
4 Purchases (MWh)976,319 980,894 979,005 977,292 945,703 939,991 943,995 940,694 937,221 933,569 931,545 930,263 930,117 929,943 930,376 930,646
5 Sales (MWh)946,841 950,784 936,773 937,157 917,687 909,595 910,883 907,697 904,346 900,823 898,869 897,632 897,492 897,324 897,742 898,002
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1154$ 0.1164$ 0.1158$ 0.1156$ 0.1249$ 0.1421$ 0.1555$ 0.1599$ 0.1635$ 0.1641$ 0.1652$ 0.1669$ 0.1680$ 0.1697$ 0.1714$ 0.1731$
9 Change in System Average Rate 0%1%0%0%10%14%9%3%2%0%1%1%1%1%1%1%
10 Change in Average Residential Bill -4%-1%-5%3%11%11%9%2%1%0%0%1%0%1%1%1%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)1,886,000 305,000 - - - - - - - - - - - - - -
14 Commitments (Non-CIP)2,737,000 3,528,000 3,164,000 3,102,000 3,777,205 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955
15 Restricted for Debt Service - - - - - - - - - - - - - - - -
16 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - - -
17 Central Valley Project Reserve 314,000 313,000 329,000 - - - - - - - - - - - - -
18 Underground Loan Reserve 742,000 738,000 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147
19 Public Benefits Reserves 1,149,000 2,197,000 2,064,000 2,574,000 1,839,000 681,330 - - - - - - - - - -
20 Electric Special Projects Reserve 50,320,000 51,838,000 51,838,000 51,838,000 51,837,855 51,837,855 45,837,855 45,066,855 42,756,855 43,246,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855
21 Hydro Stabilization Reserve - - - 17,000,000 11,400,000 11,400,000 10,400,000 10,400,000 10,400,000 10,400,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000
22 Capital Reserves - - - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964
23 Rate Stabilization Reserves 74,609,000 69,029,000 70,049,000 14,411,000 9,010,840 9,010,840 - - - - - - - - - -
24 Operations Reserves - - - 22,498,000 21,850,187 29,912,981 34,641,783 29,259,490 32,789,083 36,969,282 36,897,671 37,985,478 39,737,801 42,748,287 45,048,867 48,430,259
25 Unassigned - - - - - - - - - - - - - - - -
26 TOTAL STARTING RESERVES 132,757,000 128,948,000 129,178,000 112,153,000 100,444,086 107,424,072 95,460,704 89,307,411 90,527,004 95,197,203 98,225,592 99,313,399 101,065,722 104,076,208 106,376,788 109,758,180
27
28 REVENUES
29 Net Sales 109,974,337 110,246,264 108,873,377 108,312,917 114,624,726 129,258,435 141,615,949 145,108,190 147,822,418 147,803,571 148,490,131 149,814,486 150,733,945 152,238,348 153,846,972 155,483,550
30 Wholesale Revenues 6,635,790 6,010,409 6,267,000 5,534,000 16,188,920 18,115,996 13,718,260 14,366,366 16,106,798 17,749,617 17,407,062 17,763,941 17,932,747 18,052,704 18,231,927 18,351,535
31 Other Revenues and Transfers In 9,624,213 13,669,185 9,688,480 10,253,288 11,225,911 13,776,378 12,774,423 15,587,102 18,162,776 12,892,050 12,893,787 13,340,108 13,817,482 14,277,277 14,766,816 15,008,399
32 TOTAL REVENUES 126,234,340 129,925,858 124,828,858 124,100,205 142,039,557 161,150,809 168,108,632 175,061,658 182,091,992 178,445,238 178,790,981 180,918,535 182,484,174 184,568,329 186,845,715 188,843,484
33
34 EXPENSES
35 Electric Supply Purchases 61,313,637 68,785,977 80,022,010 79,114,644 80,467,136 83,505,886 91,924,961 94,232,563 95,111,327 98,655,001 98,667,977 99,059,024 102,252,401 103,534,874 103,178,257 106,193,402
36 Operating Expenses
37 Administration
38 Allocated Charges 4,399,674 4,139,837 4,511,222 5,148,470 3,990,822 7,717,624 7,911,314 8,109,875 8,312,961 8,520,857 8,733,973 8,952,419 9,176,328 9,405,838 9,641,088 9,882,222
39 Rent 3,875,836 4,051,044 4,147,742 4,997,101 5,121,102 5,284,977 5,443,527 5,606,832 5,775,037 5,948,288 6,126,737 6,310,539 6,499,855 6,694,851 6,895,697 7,102,568
40 Debt Service 9,265,736 9,020,651 9,037,000 8,985,994 8,953,893 8,955,166 8,808,619 8,818,349 8,783,507 8,792,388 9,624,493 9,259,612 4,898,677 4,896,047 4,894,784 4,893,296
41 Transfers and Other Adjustments 16,797,054 11,329,973 11,003,993 6,044,224 12,702,945 13,041,626 13,305,787 14,190,505 14,194,567 14,198,730 14,202,997 14,207,370 14,211,853 14,216,448 14,221,158 14,225,986
42 Subtotal, Administration 34,338,299 28,541,506 28,699,957 25,175,789 30,768,762 34,999,393 35,469,246 36,725,562 37,066,073 37,460,263 38,688,199 38,729,940 34,786,714 35,213,185 35,652,727 36,104,071
43 Resource Management 3,024,268 3,541,524 2,138,615 2,035,834 1,985,620 3,446,889 3,569,550 3,697,054 3,806,324 3,905,053 4,007,389 4,112,406 4,220,176 4,330,770 4,444,262 4,560,728
44 Demand Side Management 3,529,529 3,187,875 3,491,470 3,723,605 4,271,786 4,327,895 4,214,985 3,955,387 3,913,776 3,888,167 3,989,346 4,050,076 4,111,910 4,174,870 4,238,976 4,304,249
45 Operations and Mtc 9,601,481 9,488,627 10,716,881 11,514,846 11,811,016 13,349,204 13,790,502 14,247,795 14,653,401 15,030,198 15,419,751 15,819,400 16,229,407 16,650,041 17,081,577 17,524,297
46 Engineering (Operating)1,114,945 1,102,008 1,230,160 1,578,022 1,656,522 1,963,752 2,016,569 2,070,856 2,124,317 2,177,782 2,232,696 2,288,996 2,346,715 2,405,890 2,466,557 2,528,754
47 Customer Service 2,007,322 2,032,231 1,548,851 1,538,363 2,540,424 2,253,647 2,338,475 2,426,869 2,500,743 2,566,062 2,633,909 2,703,550 2,775,032 2,848,403 2,923,715 3,001,018
48 Allowance for Unspent Budget - - - - - (1,693,958) (1,746,621) (1,801,090) (1,850,867) (1,898,145) (1,946,926) (1,996,961) (2,048,282) (2,100,923) (2,154,917) (2,210,299)
49 Subtotal, Operating Expenses 53,615,844 47,893,770 47,825,933 45,566,460 53,034,130 58,646,823 59,652,706 61,322,433 62,213,767 63,129,381 65,024,365 65,707,408 62,421,672 63,522,237 64,652,898 65,812,819
50 Capital Program Contribution 15,113,859 13,016,111 14,005,915 11,128,015 11,558,306 20,961,467 22,684,258 18,287,069 20,096,699 13,632,467 14,010,831 14,399,781 14,799,614 15,210,638 15,633,168 16,067,528
51 TOTAL EXPENSES 130,043,340 129,695,858 141,853,858 135,809,118 145,059,572 163,114,176 174,261,925 173,842,065 177,421,793 175,416,849 177,703,174 179,166,213 179,473,688 182,267,749 183,464,323 188,073,749
52
53 ENDING RESERVES
54 Reappropriations (Non-CIP)305,000 - - - - - - - - - - - - - - -
55 Commitments (Non-CIP)3,528,000 3,164,000 3,102,000 3,777,205 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955 2,970,955
56 Restricted for Debt Service - - - - - - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 1,000,000 - - - - - - - - - - - - - -
58 Central Valley Project Reserve 313,000 329,000 - - - - - - - - - - - - - -
59 Underground Loan Reserve 738,000 734,000 730,000 729,000 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147 730,147
60 Public Benefits Reserves 2,197,000 2,064,000 2,574,000 1,839,000 681,330 - - - - - - - - - - -
61 Electric Special Projects Reserve 51,838,000 51,838,000 51,838,000 51,837,855 51,837,855 45,837,855 45,066,855 42,756,855 43,246,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855 42,846,855
62 Hydro Stabilization Reserve - - 17,000,000 11,400,000 11,400,000 10,400,000 10,400,000 10,400,000 10,400,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000 13,900,000
58 Capital Reserve - - - - 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964 879,964
59 Rate Stabilization Reserve 69,029,000 70,049,000 14,411,000 9,010,840 9,010,840 - - - - - - - - - - -
60 Operations Reserve - - 22,498,000 21,850,187 29,912,981 34,641,783 29,259,490 32,789,083 36,969,282 36,897,671 37,985,478 39,737,801 42,748,287 45,048,867 48,430,259 49,199,994
61 Unassigned - - - - - - - - - - - - - - - -
62 TOTAL ENDING RESERVES 128,948,000 129,178,000 112,153,000 100,444,086 107,424,072 95,460,704 89,307,411 90,527,004 95,197,203 98,225,592 99,313,399 101,065,722 104,076,208 106,376,788 109,758,180 110,527,915
63
64 OPERATIONS RESERVE
65 Min (60 days of non-capital expenses)23,548,140 23,951,699 25,284,688 26,787,740 28,433,604 29,085,490 29,522,382 30,404,668 30,871,314 31,204,714 31,350,294 31,906,809 32,202,955 33,062,399
66 Target (90 days of non-capital expenses)33,151,752 33,702,675 35,213,317 37,399,610 39,798,416 40,704,489 41,286,535 42,534,995 43,158,110 43,579,432 43,717,052 44,469,055 44,828,434 46,030,637
67 Max (120 days of non-capital expenses)42,755,364 43,453,651 45,141,947 48,011,480 51,163,228 52,323,488 53,050,688 54,665,323 55,444,905 55,954,149 56,083,809 57,031,301 57,453,913 58,998,876
68 Risk Assessment Value 4,645,297 4,373,014 4,338,548 5,838,255 6,482,008 6,069,525 6,234,830 5,615,913 5,724,011 5,877,611 5,991,317 6,152,535 6,318,310 6,488,774
6053706
1 FISCAL YEAR FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
2
3 REVENUES
4 Net Sales 87%85%87%87%81%80%84%83%81%83%83%83%83%82%82%82%
5 Other Revenues and Transfers In 13%15%13%13%19%20%16%17%19%17%17%17%17%18%18%18%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 46%52%55%54%42%41%48%49%47%48%48%48%50%50%49%50%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%3%3%4%3%5%5%5%5%5%5%5%5%5%5%5%
13 Rent 3%3%3%4%4%3%3%3%3%3%3%4%4%4%4%4%
14 Debt Service 7%7%6%7%6%5%5%5%5%5%5%5%3%3%3%3%
15 Transfers and Other Adjustments 13%9%8%4%9%8%8%8%8%8%8%8%8%8%8%8%
16 Subtotal, Administration 26%22%20%19%21%21%20%21%21%21%22%22%19%19%19%19%
17 Resource Management 2%3%2%1%1%2%2%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 7%7%8%8%8%8%8%8%8%9%9%9%9%9%9%9%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 2%2%1%1%2%1%1%1%1%1%1%2%2%2%2%2%
21 Allowance for Unspent Budget 0%0%0%0%0%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 39%34%31%31%34%33%32%33%33%34%34%34%32%33%33%33%
23 Capital Program Contribution 12%10%10%8%8%13%13%11%11%8%8%8%8%8%9%9%
24 TOTAL EXPENSES 96%97%96%93%83%87%93%92%91%90%90%90%90%91%91%91%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
28 1. Load Net Revenue 77,428 652,853 1,208,477
29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 3,397,119
30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 539,073
31 4. Carbon Neutral Cost 331,630 303,022 114,983
32 5. Market Price 909,196 775,584 1,138,589
33 6. Local Capacity 475,962 408,388 446,695
34 7. Transmission/CAISO 4,555,915 3,741,647 2,806,120
35 8. Plant Outage 1,000,000 1,000,000 1,000,000
36 9. Western Cost 3,130,000 2,704,738 2,973,619
37 10. Regulatory & Legal - - -
38 11. Supplier Default - - -
39 TOTAL 20,170,708 19,380,490 13,624,674
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 196%172%303%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
44 Distribution Revenue Variance 3,244,706 3,260,213 3,182,718 3,742,109 4,213,582 4,240,818 4,225,160 4,252,666 4,322,928 4,437,632 4,511,355 4,631,471 4,754,993 4,882,021
45 10% CIP Program Contingency 1,400,592 1,112,802 1,155,831 2,096,147 2,268,426 1,828,707 2,009,670 1,363,247 1,401,083 1,439,978 1,479,961 1,521,064 1,563,317 1,606,753
46 Total Risk Asssessment Value 4,645,297 4,373,014 4,338,548 5,838,255 6,482,008 6,069,525 6,234,830 5,615,913 5,724,011 5,877,611 5,991,317 6,152,535 6,318,310 6,488,774
47 Projected Operations Reserve 22,498,000 21,850,187 29,912,981 34,641,783 29,259,490 32,789,083 36,969,282 36,897,671 37,985,478 39,737,801 42,748,287 45,048,867 48,430,259 49,199,994
48 Operations Reserve, % of Risk Value 484%500%689%593%451%540%593%657%664%676%714%732%767%758%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- - 15,208,552 15,033,113 15,472,236 16,163,913 17,553,876 17,965,924 18,133,345 18,744,756 18,928,400 18,961,720 18,799,559 19,040,477 19,012,969 19,540,493
46 Target (90 days of non-capital expenses)- - 22,812,829 22,549,669 23,208,354 24,245,869 26,330,813 26,948,886 27,200,017 28,117,133 28,392,600 28,442,580 28,199,338 28,560,716 28,519,453 29,310,739
47 Max (120 days of non-capital expenses)- - 30,417,105 30,066,225 30,944,472 32,327,825 35,107,751 35,931,847 36,266,689 37,489,511 37,856,800 37,923,439 37,599,117 38,080,955 38,025,937 39,080,986
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- - 8,339,587 8,918,586 9,812,452 10,623,828 10,879,728 11,119,566 11,389,038 11,659,912 11,942,914 12,242,995 12,550,735 12,866,332 13,189,986 13,521,906
51 Target (90 days of non-capital expenses)- - 10,338,923 11,153,006 12,004,964 13,153,741 13,467,602 13,755,604 14,086,518 14,417,862 14,765,510 15,136,852 15,517,714 15,908,339 16,308,981 16,719,898
52 Max (120 days of non-capital expenses)- - 12,338,259 13,387,426 14,197,475 15,683,655 16,055,477 16,391,641 16,783,999 17,175,812 17,588,105 18,030,710 18,484,692 18,950,347 19,427,976 19,917,890
53 Risk Assessment Value 4,645,297 4,373,014 4,338,548 5,838,255 6,482,008 6,069,525 6,234,830 5,615,913 5,724,011 5,877,611 5,991,317 6,152,535 6,318,310 6,488,774
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1140%1193%1315%1288%1391%1487%1621%1664%1691%1740%1601%1679%3262%3312%3329%3415%
57 Available Reserves (5x Debt Service)*13.5 14.0 12.1 10.8 11.7 10.3 9.8 9.9 10.5 10.8 10.0 10.6 20.6 21.1 21.8 22.0
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 meet its debt covenants.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 42 | Page
APPENDIX B : ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c) For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f) For operating contingencies, as described in Section 12 (Operations Reserves)
g) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserves for Commitments)
b) For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c) As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d) To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 11.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 43 | Page
h) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 14 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Commitments will be set to an amount equal to the total remaining spending
authority for all contracts in force for the Electric Supply Fund and Electric Distribution
Fund, respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Reappropriations will be set to an amount equal to the amount of all remaining
capital and non-capital budgets that will be reappropriated to the following fiscal year for
each Fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of
Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve
and Adoption of Electric Special Project Reserve Guidelines). These policies and timelines
are included from Resolution 9206 as amended to refer to the reserves structure set forth
in these Reserves Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2017;
f) Any uncommitted funds remaining at the end of FY 2022 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
Section 7. Hydroelectric Stabilization Reserve
The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts
associated with variations in generation from hydroelectric resources. Staff will manage the
Hydroelectric Stabilization Reserve as follows:
a) Projected Hydro Output: Near the end of each fiscal year, staff will determine the
actual and expected hydro output for that fiscal year, compare that to the long-term
average annual output level (495,957 MWh as of March 2018), and multiply the
difference by the average of the monthly round-the-clock forward market prices for
each month of the current fiscal year.
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June 2018 44 | Page
b) Changes in Reserves. Staff is authorized to transfer the amount described in Sec.
7(a) from the Operations Reserve to the Hydroelectric Stabilization Reserve for
hydro output deviations above long-term average levels, or transfer this amount
from the Hydroelectric Stabilization Reserve to the Operations Reserve for hydro
output deviations below long-term average levels.
c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after
the transfers described above shall be the basis for staff’s determination, with
Council approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-
HRA) for the following fiscal year.
d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve
according to the following guideline levels:
Minimum Level $3 million
Target Level $19 million
Maximum Level $35 million
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 60 days of budgeted CIP expense
Maximum Level 120 days of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve
for Commitments as a result of a change in contractual commitments related to CIP
projects. Any other additions to or withdrawals from the CIP reserve require Council
action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 45 | Page
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to d) above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 46 | Page
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were
funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an
alternative plan that retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 47 | Page
APPENDIX C : DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL ACTIVITIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Electric Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process.
It does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
• monitoring the substations and performing routine maintenance;
• performing preventative maintenance on the system;
• monitoring the system’s status from the UCC using SCADA;
• maintaining the SCADA system;
• investigating outages and other customer complaints and performing emergency
repairs;
• clearing vegetation near overhead power lines; and
• testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX D : SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 1 | Page
APPENDIX A : ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices are used when developing the Electric Utility
Financial Plan:
Section 1. Definitions
a)“Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019,
FY 2015 to FY 2019 would be the Financial Planning Period.
b)“Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c)“Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d)“Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserve for Commitments)
b)For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c)For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d)For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e)For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f)For operating contingencies, as described in Section 12 (Operations Reserves)
g)Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserves for Commitments)
b)For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c)As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d)To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
e)For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f)For rate stabilization, as described in Section 11) (Rate Stabilization Reserves)
ATTACHMENT C
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 2 | Page
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 14 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Commitments will be set to an amount equal to the total remaining spending
authority for all contracts in force for the Electric Supply Fund and Electric Distribution
Fund, respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Reappropriations will be set to an amount equal to the amount of all remaining
capital and non-capital budgets that will be reappropriated to the following fiscal year for
each Fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of
Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve
and Adoption of Electric Special Project Reserve Guidelines). These policies and timelines
are included from Resolution 9206 as amended to refer to the reserves structure set forth
in these Reserves Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) Set a goal to commit funds by the end of FY 2017;
f) Any uncommitted funds remaining at the end of FY 2022 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed;
Section 7. Hydroelectric Stabilization Reserve
The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts
associated with variations in generation from hydroelectric resources. Staff will manage the
Hydroelectric Stabilization Reserve as follows:
a) Projected Hydro Output: Near the end of each fiscal year, staff will calculate the
actual/expected hydro output for that fiscal, compare that to the long-term average
annual output level (495,957 MWh as of March 2018), and multiply the difference
by the average of the monthly round-the-clock forward market prices for each
month of the fiscal year.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 3 | Page
b) Changes in Reserves: Staff is authorized to transfer the amount described in Sec. 7(a)
from the Operations Reserve to the Hydroelectric Stabilization Reserve for hydro
output deviations above long-term average levels, or transfer this amount from the
Hydroelectric Stabilization Reserve to the Operations Reserve for hydro output
deviations below long-term average levels.
c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after
the transfers described above shall be the basis for staff’s determination, with
Council approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-
HRA) for the following fiscal year.
a)d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve
according to the following guideline levels:
Minimum Level $3 million
Target Level $19 million
Maximum Level $35 million
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 60 days of budgeted CIP expense
Maximum Level 120 days of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve
for Commitments as a result of a change in contractual commitments related to CIP
projects. Any other additions to or withdrawals from the CIP reserve require Council
action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 4 | Page
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to d) above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of Operations and Maintenance (O&M) and
commodity expense forecasted for that year in the Financial Plan.
Minimum Level 60 days of Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
ELECTRIC UTILITY FINANCIAL PLAN
June 2018 5 | Page
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s Operations Reserve are lower than the minimum level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of
any fiscal year, the next Financial Plan presented to the City Council must include a plan to
assign them to a specific purpose or return them to the Electric Utility ratepayers by the end
of the first fiscal year of the next Financial Planning Period. For example, if there were
funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an
alternative plan that retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
Attachment D
* NOT YET APPROVED *
6055014 1
Resolution No. _________
Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Residential Master-Metered and Small Non-Residential
Electric Service), E-2-G (Residential Master-Metered and Small Non-
Residential Green Power Electric Service), E-4 (Medium Non-
Residential Electric Service), E-4-G (Medium Non-Residential Green
Power Electric Service), E-4 TOU (Medium Non-Residential Time of
Use Electric Service), E 7 (Large Non-Residential Electric Service), E-7-
G (Large Non-Residential Green Power Electric Service), E-7 TOU
(Large Non-Residential Time of Use Electric Service), and E-14 (Street
Lights).
R E C I T A L S
A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2018.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2 (Residential Master-Metered and Small Non-Residential Electric Service) is
hereby amended to read as attached and incorporated. Utility Rate Schedule E-2, as amended,
shall become effective July 1, 2018.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-2-G (Residential Master-Metered and Small Non-Residential Green Power
Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule
E-2-G, as amended, shall become effective July 1, 2018.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 (Medium Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2018.
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Non-Residential Green Power Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall
become effective July 1, 2018.
Attachment D
* NOT YET APPROVED *
6055014 2
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Non-Residential Time of Use Electric Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended,
shall become effective July 1, 2018.
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Non-Residential Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective
July 1, 2018.
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become
effective July 1, 2018.
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Non-Residential Time of Use Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become
effective July 1, 2018.
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated.
Utility Rate Schedule E-14, as amended, shall become effective July 1, 2018.
SECTION 11. The Council makes the following findings:
a. The revenue derived from the adoption of this resolution shall be used only for the
purpose set forth in Article VII, Section 2, of the Charter of the City of Palo Alto.
b. The fees and charges adopted by this resolution are charges imposed for a specific
government service or product provided directly to the payor that are not provided
to those not charged, and do not exceed the reasonable costs to the City of
providing the service or product.
c. The adoption of this resolution changing electric rates to meet operating expenses,
purchase supplies and materials, meet financial reserve needs and obtain funds for
capital improvements necessary to maintain service is not subject to the California
Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec.
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After
reviewing the staff report and all attachments presented to Council, the Council
incorporates these documents herein and finds that sufficient evidence has been
presented setting forth with specificity the basis for this claim of CEQA exemption.
Attachment D
* NOT YET APPROVED *
6055014 3
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-1-1 dated 7-1-20176 Sheet No E-1-1
A. APPLICABILITY:
This schedule applies to separately metered single-family residential dwellings receiving Electric
retail energy sServices from the City of Palo Alto Utilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Eelectric Sservice.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Tier 1 usage
$0.0708366
05
$0.05690164 $0.00431391 $0.132042159
Tier 2 usage
Any usage over Tier 1
0.11808253 0.080897358 0.00431391 0.2032819002
Minimum Bill ($/day) 0.31642938
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Ccustomer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Calculation of Usage Tiers
Tier 1 Eelectricity usage shall be calculated and billed based upon a level of 11 kWh per
day, prorated by Mmeter reading days of Sservice. As an example, for a 30-day bill, the
Tier 1 level would be 330 kWh. For further discussion of bill calculation and proration,
refer to Rule and Regulation 11.
{End}
ATTACHMENT E
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-2-1 dated 7-1-20167 Sheet No E-2-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities:
1.Small non-residential Customers receiving Nnon-Ddemand Mmetered Eelectric Sservice;
and
1.2. for small non-residential Ccustomers with Accounts at Master-Metered and master-
metered mmulti-family facilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Eelectric Sservice.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period
$0.111424059
1 $0.0790309123 $0.0039100431 $0.1888520978
Winter Period 0.0707828520 0.0535606275 0.00433911 0.1453413267
Minimum Bill ($/day) 0.73288097
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a cCustomer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-2-2 dated 7-1-20167 Sheet No E-2-2
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Ddemand Mmeter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The maximum Ddemand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Ddemand Mmeter which does not reset after a definite time interval may be
used at the City's option.
The billing Ddemand to be used in computing charges under this schedule will be the
actual maximum Ddemand in kilowatts for the current month. An exception is that the
billing Ddemand for Ccustomers with Thermal Energy Storage (TES) will be based upon
the actual maximum Ddemand of such Ccustomers between the hours of noon and 6 pm
on weekdays.
{End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC
SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-2-1 dated 7-1-20167 Sheet No E-2-1
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-2017
Supersedes Sheet No E-2-G-1 dated 7-1-2016 Sheet No E-2-G-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities under the Palo Alto Green Program:
1.Small non-residential Customers receiving Non-Demand Metered Eelectric Sservice; and
2.Customers with Aaccounts at Master-Mmetered multi-family facilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1.100% Renewable Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Palo Alto
Green
Charge Total
Summer Period
$0.11424105
91
$0.07903091
23
$0.003943
1 $0.0020
$0.190852
1178
Winter Period
0.075200782
8
0.053560627
5 0.0039431 0.0020
$0.134671
4734
Minimum Bill ($/day) 0.73288097
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits Total
Summer Period
$0.10591114
24
$0.07903091
23
$0.003943
1
$0.188852
0978
Winter Period
0.075200782
8
0.053560627
5 0.0039431
0.1346714
534
Minimum Bill ($/day) 0.73288097
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-2017
Supersedes Sheet No E-2-G-2 dated 7-1-2016 Sheet No E-2-G-2
Palo Alto Green Charge (per 1000 kWh block) $2.00
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewable
sources, and create a transparent and sustainable market that encourages new
development of wind and solar power.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-2017
Supersedes Sheet No E-2-G-3 dated 7-1-2016 Sheet No E-2-G-3
4.Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer-s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option.
The billing Demand to be used in computing charges under this schedule will be the
actual maximum Demand in kilowatts for the current month. An exception is that the
billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-1 dated 7-1-20167 Sheet No E-4-1
A. APPLICABILITY:
This schedule applies to Demand metered Ssecondary Electric Service for Ccustomers with a
mMaximum Demand below 1,000 kilowatts. This schedule applies to three-phase Electric
Service and may include Service to master-metered multi-family facilities or other facilities
requiring Demand-metered sServices, as determined by the City.
B. TERRITORY:
This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.383.28 $17.6722.27 $21.0525.55
Energy Charge (per kWh) 0.0952609930 0.0175601914 0.0039431 0.1167312275
Winter Period
Demand Charge (per kW) $1.931.84 $13.4317.55 $15.3619.39
Energy Charge (per kWh) 0.0674307135 0.0175601914 0.0039431 0.0889009480
Minimum Bill ($/day) 14.841416.4591
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-2 dated 7-1-20167 Sheet No E-4-2
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a Maximum Demand Mmeter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer-’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Mmeter which does not reset after a definite time interval may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Ccustomers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Ccustomers between the hours of noon and 6 pm
on weekdays.
4. Power Factor
For new or existing Ccustomers whose Demand is expected to exceed or has exceeded
300 kilowatts for three consecutive months, the City has the option of installing
applicable Mmetering to calculate a Power Factor. The City may remove such
Mmetering from the Service of a Ccustomer whose Demand has been below 200
kilowatts for four consecutive months.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-3 dated 7-1-20167 Sheet No E-4-3
When such metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Ccustomer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent (0.25%) for each one percent (1%) that the monthly Power Factor of the
Ccustomer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Mmetering is installed, the monthly Power Factor shall be the Power Factor coincident
with the Ccustomer's Maximum Demand.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any City of Palo Alto full-
service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage
profile.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Ccustomer's electrical requirements, as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Ccustomer receiving the discount in this section. The
Ccustomer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-4 dated 7-1-20167 Sheet No E-4-4
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate Mmeter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-5 dated 7-1-20167 Sheet No E-4-5
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-1 dated 7-1-20167 Sheet No E-4-G-1
A. APPLICABILITY:
This schedule applies to Demand mMetered Secondary Electric Service for Customers with a
mMaximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green
Program. This schedule applies to three-phase Electric Service and may include Service to
Master-metered multi-family facilities or other facilities requiring Demand -mMetered Services,
as determined by the City.
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1.100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge (per kW) $3.383.28 $17.6722.27 $21.0525.55
Energy Charge (per kWh) 0.0952609930 0.0175601914 0.0039431 0.0020 0.1187312475
Winter Period
Demand Charge (per kW) $1.931.84 $13.4317.55 $15.3619.39
Energy Charge (per kWh) 0.0674307135 0.0175601914 0.0039431 0.0020 0.0909009680
Minimum Bill ($/day) 14.841416.4591
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-2 dated 7-1-20167 Sheet No E-4-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.383.28 $22.2717.67 $21.0525.55
Energy Charge (per kWh) 0.0952609930 0.0175601914 0.0043391
0. 1167312275
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.931.84 $13.4317.55 $15.3619.39
Energy Charge (per kWh) 0.0674307135 0.0175601914 0.0039431 0.0889009480
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 14.841416.4591
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-3 dated 7-1-20167 Sheet No E-4-G-3
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the
option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter, which does not reset after a definite time interval, may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with
the Customer's Maximum Demand.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full-service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-4 dated 7-1-20167 Sheet No E-4-G-4
6. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new
development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change the system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-4-G-5 dated 7-1-20167 Sheet No E-4-G-5
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-1 dated 7-1-20176 Sheet No E-4-TOU-1
A. APPLICABILITY:
This voluntary rate schedule applies to Demand metered Ssecondary Electric Service for
Ccustomers with Demand between 500 and 1,000 kilowatts per month and who have sustained
this level of usage for at least three consecutive months during the most recent 12 month period.
This schedule applies to three-phase Electric Service and may include Service to Mmaster-
Mmetered multi-family facilities or other facilities requiring Demand-metered Sservices, as
determined by the City. In addition, this rate schedule is applicable for Ccustomers who did not
pay Ppower Ffactor Aadjustments during the last 12 months.
B. TERRITORY:
This rate schedule applies everywhereanywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $2.122.08 $6.097.68 $8.219.76
Mid-Peak 0.6366 6.097.68 6.768.31
Off-Peak 0.6366 6.097.68 8.316.76
Energy Charge (per kWh)
Peak $0.1014409552 $0.0175601914 $0.0039431 $0.1229111897
Mid-Peak 0.0983512028 0.0175601914 0.0039431 0.1198214373
Off-Peak 0.0874807381 0.0175601914 0.0039431 0.1089509726
Winter Period
Demand Charge (per kW)
Peak $1.027 $7.499.78 $8.5610.80
Off-Peak 1.027 7.499.78 8.5610.80
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-2 dated 7-1-20176 Sheet No E-4-TOU-2
Commodity Distribution Public Benefits Total
Energy Charge (per kWh)
Peak $0.0816407821 $0.017561914 $0.0039431 $0.1031110166
Off-Peak 0.0573806714 0.017561914 $0.0039431 0.0788509059
Minimum Bill ($/day) 14.841416.4591
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-3 dated 7-1-20176 Sheet No E-4-TOU-3
SEASONAL RATE CHANGES: When the billing period includes use in both the
Summer and the Winter periods, the usage will be prorated based on the number of days
in each seasonal period, and the charges based on the applicable rates therein.. For
further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Demand Mmeter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000
kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it
may be removed.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the
designated tTime periods as defined under Section D.2.
4. Power Factor Adjustment
Time of Use Ccustomers must not have had a Ppower Ffactor Aadjustment assessed on
their Service for at least 12 months. Power factor is calculated based on the ratio of
kilowatt hours to kilovolt-ampere hours consumed during the month, and must not have
fallen below 95% to avoid the pPower Ffactor Aadjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should
be subject to Ppower Ffactor Aadjustments, the Customer will be removed from the E-4-
TOU rate schedule and placed on another applicable rate schedule as is suitable to their
kilowatt Demand and kilowatt-hour usage.
5. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 months, the
Customer may request a rate schedule change to any applicable City of Palo Alto full-
service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage.
6. Primary Voltage Discount
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-4 dated 7-1-20176 Sheet No E-4-TOU-4
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements, as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Mmeter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate Mmeter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more
of the non-utility generators on the Customer’s side of the City’s revenue Mmeter
are not operating, the Maximum Demand will be reduced by the sum of the
Maximum Generation of those non-utility generators, but in no event shall the
Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-4-TOU-5 dated 7-1-20176 Sheet No E-4-TOU-5
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-1 dated 7-1-20176 Sheet No E-7-1
A. APPLICABILITY:
This schedule applies to Demand Mmetered secondary Service for large non-residential
Customers with a Maximum Demand of at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies everyanywhere the City of Palo Alto provides Electric Service.
C. RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (kW) $3.49 $20.3524.91 $23.8428.40
Energy Charge (kWh) 0.0935310108 0.0005800072 0.0039431 0.0980210611
Winter Period
Demand Charge (kW) $1.901.81 $13.6915.99 $15.517.809
Energy Charge (kWh) 0.0673907028 0.0005800072 0.0043391 0.0718807531
Minimum Bill ($/day) 42.364846.6013
D. SPECIAL NOTES:
1.Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-2 dated 7-1-20176 Sheet No E-7-2
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one
Aaccount or one Mmeter if the Aaccounts are on one site. A site shall be defined as one
or more utility Aaccounts serving contiguous parcels of land with no intervening public
right-of-ways (e.g. streets) and have a common billing address.
4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Mmeter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of
the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-
type Demand Mmeter which does not reset after a definite time interval may be used at
the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-3 dated 7-1-20176 Sheet No E-7-3
5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option to install applicable
Mmetering to calculate a Power Factor. The City may remove such Mmetering from the
Service of a Customer whose Demand has been below 200 kilowatts for four consecutive
months.
When such metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The pPower fFactor Aadjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent (0.25%) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Mmetering is installed, the monthly Power Factor shall be the Power Factor coincident
with the Customer's Maximum Demand.
6. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a particular line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's electrical requirements , as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change his system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kVA size limitation.
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-4 dated 7-1-20176 Sheet No E-7-4
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Mmeter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate Mmeter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.4) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Mmeter are not operating, the Maximum Demand will
be reduced by the sum of the Maximum Generation of those non-utility
generators, but in no event shall the Customer’s Maximum Demand be reduced
below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
LARGE NON-RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No E-7-5 dated 7-1-20176 Sheet No E-7-5
Section 2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-1 dated 7-1-20167 Sheet No E-7-G-1
A. APPLICABILITY:
This schedule applies to Demand mMetered Service for large non-residential Customers who
choose Service under the Palo Alto Green Program. A Customer may qualify for this rate
schedule if the Customer’s Maximum Demand is at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1.100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge ( per kW) $3.49 $20.3524.91 $23.8428.40
Energy Charge (per kWh) 0.0935310108 0.0005800072 0.0039431 0.0020 0.1000210811
Winter Period
Demand Charge (per kW) $1.901.81 $13.6915.99 $15.5917.80
Energy Charge (per kWh) 0.0673907028 0.0005800072 0.0039431 0.0020 0.0738807731
Minimum Bill ($/day) 42.364846.6013
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-2 dated 7-1-20167 Sheet No E-7-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.49 $20.3524.91 $23.8428.40
Energy Charge (per kWh) 0.0935310108 0.0005800072 0.0043391 0.0980210611
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.901.81 $13.6915.99 $15.5917.80
Energy Charge (per kWh) 0.0673907028 0.0005800072 0.0039431 0.0718807531
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 42.364846.6013
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-3 dated 7-1-20167 Sheet No E-7-G-3
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the
option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if the Customer’s load is
intermittent or subject to fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Request for Service
Qualifying Customers may request Service under this schedule for more than one
Account or one Meter if the Accounts are at one site. A site shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and have a common billing address.
5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Ppower fFactor Aadjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-4 dated 7-1-20167 Sheet No E-7-G-4
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with
the Customer's Maximum Demand.
6. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile
7. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new
development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
8. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, but the City is not required to supply Service at a qualified line voltage where it
has, or will install, ample facilities for supplying at another voltage equally or better
suited to the Customer's Electrical requirements , as determined in the City’s sole
discretion. The City retains the right to change its line voltage at any time after providing
reasonable advance notice to any Customer receiving the discount in this section. The
Customer then has the option to change the system so as to receive Service at the new
line voltage or to accept Service (without voltage discount) through transformers to be
supplied by the City subject to a maximum kilovolt-ampere size limitation.
9. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(9)(e), applies to Customers that have a non-utility generation source
LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-G-5 dated 7-1-20167 Sheet No E-7-G-5
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-1 dated 7-1-20167 Sheet No E-7-TOU-1
A. APPLICABILITY:
This voluntary rate schedule applies to Demand mMetered secondary Service for non-
residential Ccustomers with a Maximum Demand of at least 1,000KW per month per site, who
have sustained this Demand level at least 3 consecutive months during the last twelve months.
In addition, this rate schedule is applicable for customers Customers who did not pay Ppower
Ffactor Aadjustments during the last 12 months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $2.222.29 $6.848.37 $9.0610.66
Mid-Peak 0.6461 6.848.37 7.488.98
Off-Peak 0.6461 6.848.37 7.488.98
Energy Charge (per kWh)
Peak $0.1017710293 $0.0005872 $0.0043391 $0.1062610796
Mid-Peak 0.0986812961 0.0005872 0.0039431 0.1031613464
Off-Peak 0.0877707954 0.0005872 0.0039431 0.0922608457
Winter Period
Demand Charge (per kW)
Peak $0.9692 $6.938.10 $7.899.02
Off-Peak 0.9692 6.938.10 7.899.02
Energy Charge (per kWh)
Peak $0.0803607252 $0.0005872 $0.0039431 $0.0848407755
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-2 dated 7-1-20167 Sheet No E-7-TOU-2
Off-Peak 0.0564706225 0.0005872 0.0039431 0.0609606728
Minimum Bill ($/day) 42.364846.6013
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
2. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday
All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving
Day, and Christmas Day. The dates will be those on which the holidays are legally observed.
SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-3 dated 7-1-20167 Sheet No E-7-TOU-3
period, and the charges based on the applicable rates therein. For further discussion of bill
calculation and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Ccustomers may request Service under this schedule for more than one Aaccount or
one Mmeter if the Aaccounts are on one site. A site shall be defined as one or more utility
Aaccounts serving contiguous parcels of land with no intervening public right-of-ways (e.g.
streets) and have a common billing address.
4. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive
months, a Demand Mmeter will be installed as promptly as is practicable and thereafter
continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for
twelve consecutive months, whereupon, at the option of the City, it may be removed.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated
tTime periods as defined under Section D.2.
5. Power Factor Adjustment
Time of Use Ccustomers must not have had a pPower fFactor aAdjustment assessed on their
Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to
kilovolt-ampere hours consumed during the month, and must not have fallen below 95% to avoid
the Ppower Ffactor Aadjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be
subject to Ppower Ffactor Aadjustments, the Customer will be removed from the E-7-TOU rate
schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand
and kilowatt-hour usage.
6. Changing Rate Schedules
Customers electing to be served under E-7 TOU must remain on said schedule for a minimum of
12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a
rate schedule change to any applicable City of Palo Alto full-service rate schedule as is suitable
to their kilowatt Demand and kilowatt-hour usage.
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-4 dated 7-1-20167 Sheet No E-7-TOU-4
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered,
but the City is not required to supply Service at a particular line voltage where it has, or will
install, ample facilities for supplying at another voltage equally or better suited to the Customer's
electrical requirements , as determined in the City’s sole discretion. The City retains the right to
change its line voltage at any time after providing reasonable advance notice to any Customer
receiving the discount in this section. The Customer then has the option to change his system so
as to receive Service at the new line voltage or to accept Service (without voltage discount)
through transformers to be supplied by the City subject to a maximum kilovolt-ampere size
limitation.
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue Mmeter and that occasionally require backup
power from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate mMeter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue mMeter are not
operating, the Maximum Demand will be reduced by the sum of the Maximum
LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20187
Supersedes Sheet No E-7-TOU-5 dated 7-1-20167 Sheet No E-7-TOU-5
Generation of those non-utility generators, but in no event shall the Customer’s
Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing cycle, the
standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code Section
2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No. E-14-1 dated 7-1-20176 Sheet No. E-14-1
A. APPLICABILITY:
This schedule applies to all street and highway lighting installations.
B. TERRITORY:
Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City.
C. RATES:
Per Lamp Per Month
Class A: Utility supplies energy
and switching service only.
Lamp Rating:
High Pressure Sodium Vapor Lamps
100 watts 9.6610.32
200 watts 17.8319.04
250 watts 21.9223.41
310 watts 27.1228.96
400 watts 34.9237.30
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No. E-14-2 dated 7-1-20176 Sheet No. E-14-2
Per Lamp Per Month –
Class C: Utility supplies energy
and switching service and
maintains entire system,
including lamps and glassware.
Lamp Rating:
Mercury-Vapor Lamps
400 watts 34.9437.26
High Pressure Sodium Vapor Lamps
70 watts 30.4832.50
100 watts 32.9335.12
150 watts 37.0239.49
250 watts 45.1948.21
Light Emitting Diode (LED) Lamps
70 watts-equivalent 25.0626.71
100 watts-equivalent 26.9128.69
150 watts-equivalent 28.6230.52
250 watts 33.3035.52
D. SPECIAL CONDITIONS:
1. Type of Service: This schedule is applicable to series circuit and multiple street lighting
systems to which the Utility will deliver current at secondary voltage. Unless otherwise
agreed, multiple current will be delivered at 120/240 volts, three-wire, single-phase. In
certain localities the Utility may supply service from 120/208 volt star-connected poly-phase
lines in place of 240-volt service. Single phase service from 480-volt sources will be
available in certain areas at the option of the Utility when this type of service is practical
from the Utility's engineering standpoint. All currents and voltages stated herein are
nominal, reasonable variations being permitted. New lights will normally be supplied as
multiple systems.
2. Point of Delivery: Delivery will be made to the customer's system at a point or at points
mutually agreed upon. The Utility will furnish the service connection to one point for each
group of lamps, provided the customer has arranged his system for the least practicable
number of points of delivery. All underground connections will be made by the customer or
at the customer's expense.
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20178
Supersedes Sheet No. E-14-3 dated 7-1-20176 Sheet No. E-14-3
3. Switching: Switching will be performed by the Utility (on the Utility's side of points of
delivery) and no charge will be made for switching provided there are at least 10 kilowatts of
lamp load on each circuit separately switched, including all lamps on the circuit whether
served under this schedule or not; otherwise, an extra charge of $2.50 per month will be
made for each circuit separately switched unless such switching installation is made for the
Utility's convenience or the customer furnishes the switching facilities and, if installed on the
Utility's equipment, reimburses the Utility for installing and maintaining them.
4. Annual Burning Schedule: The above rates apply to lamps which will be turned on and off
once each night in accordance with a regular burning schedule agreeable to the customer but
not exceeding 4,100 hours per year.
5. Maintenance: The rates under Class C include all labor necessary for replacement of
glassware and for inspection and cleaning of the same. Maintenance of glassware by the
Utility is limited to standard glassware such as is commonly used and manufactured in
reasonably large quantities. A suitable charge will be made for maintenance of glassware of a
type entailing unusual expense. Under Class C, the rates include maintenance of circuits
between lamp posts and of circuits and equipment in and on the posts, provided these are all
of good standard construction; otherwise, the Utility may decline to grant Class C rates.
Class C rates applied to any agency other than the City of Palo Alto also include painting of
posts with one coat of good ordinary paint as required to maintain good appearance but do
not include replacement of posts broken by traffic accidents or otherwise.
10. . System Owned In-Part by Utility : Where, at customer's request, the Utility installs, owns,
and maintains any portion of the lighting fixtures, supports, and/or interconnecting circuits,
an extra monthly charge of one and one-fourth percent of the Utility's estimate of additional
investment shall be made.
11. Rates For Lamps Not on Schedule: In the event a customer installs a lamp which is not
presently represented on this schedule, the Utility will prepare an interim rate reflecting the
Utility's estimated costs associated with the specific lamp size. This interim rate will serve as
the effective rate for billing purposes until the new lamp rating is added to Schedule E-14.
{End}
Page 1 of 8
2
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 12, 2018
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend that
the City Council Adopt: 1) a Resolution Approving the Fiscal Year 2019 Gas Utility
Financial Plan; and 2) a Resolution Increasing Gas Rates by 4% by Amending Rate
Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered and
Commercial Gas Service), G-3 (Large Commercial Gas Service), and G-10
(Compressed Natural Gas Service)
RECOMMENDATION
Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2019 Gas Utility Financial
Plan (Attachment B); and
2. Adopt a resolution (Attachment C) increasing gas rates by amending Rate Schedules G-1
(Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas
Service), G-3 (Large Commercial Gas Service), and G-10 (Compressed Natural Gas
Service) (Attachment D).
EXECUTIVE SUMMARY
The FY 2019 Gas Utility Financial Plan includes projections of the utility’s costs and revenues for
FY 2019 through FY 2028. Gas rates related to distribution costs were last adjusted by 8% on July
1, 2016, and the FY 2018 Financial Plan included a tentative rate increase of 4% for FY 2019. The
proposed FY 2019 Gas Utility Financial Plan includes a 6% increase in distribution rates, resulting
in a 4% overall gas rate increase, on July 1, 2018. Increases of 7% to 8% are projected over the
next four years. In addition, the plan proposes transfers to the Operations Reserve of $129,000
and $2 million from the Rate Stabilization Reserve in FY 2018 and FY 2019, respectively, to ensure
that there are appropriate financial reserves for contingencies. The Rate Stabilization Reserve is
projected to be zero by the end of FY 2020.
Gas Utility expenses are projected to increase by roughly 3 to 4 percent annually from FY 2019
to FY 2028. In the short term, some increases in operations costs are related to the cross-bore
Page 2 of 8
inspection program, but capital improvement program (CIP) costs have also increased as the
economy has improved. Future CIP project costs have been revised upwards from prior forecasts
to reflect higher bids on gas CIP projects. Commodity costs are the most volatile component of
the Gas Utility’s expenses, but market prices have been steady and current forecasts project
increases of around 1% to 2% annually.
Gas usage was trending downward over the last several years, most likely due to relatively warm
winter heating seasons, as well as lower hot water usage during the drought, but a cooler winter
and the end of drought restrictions has brought increased usage. Gas usage has generally
recovered to pre-drought levels, but as with water, it is difficult to determine whether long run
usage will resume the declining trend seen over the last few decades.
BACKGROUND
Every year staff presents the UAC with Financial Plans for its Electric, Water, Gas, and Wastewater
Collection Utilities and recommends any rate adjustments required to maintain their financial
health. These Financial Plans include a comprehensive overview of the utility’s operations, both
retrospective and prospective, and are intended to be a reference for UAC and Council members
as they review the budget and staff’s rate recommendations. Each Financial Plan also contains a
set of Reserves Management Practices describing the reserves for each utility and the
management practices for those reserves.
The UAC reviewed preliminary financial forecasts at its February 7, 2018 meeting. Staff has not
revised the preliminary projections presented at that meeting.
DISCUSSION
Staff’s annual assessment of the financial position of the City’s gas utility is completed to ensure
adequate revenue to fund operations in compliance with the cost of service requirements set
forth in the California Constitution (Proposition 26). This includes making long-term projections
of market conditions, the physical condition of the system, and other factors that could affect
utility costs, and setting rates adequate to recover these costs.
Proposed Actions for FY 2018
The FY 2019 Gas Utility Financial Plan includes the following proposed action:
1. Reduce the $1.22 million proposed transfer from the Rate Stabilization Reserve to the
Operations Reserve proposed in the FY 2019 Gas Financial Plan to $129,000.
Proposed Actions for FY 2019
The FY 2019 Gas Utility Financial Plan also includes the following proposed action:
1. Amend gas rate schedules (see Attachment D) to increase rates by approximately 4%.
2. Transfer up to $2 million from the Rate Stabilization Reserve to the Operations Reserve.
Page 3 of 8
The reserve transfers will enable staff to maintain sufficient funds in the Gas Operations Reserve
levels while spreading the required rate increases for the gas utility over several years. These
proposed actions are described in more detail in the FY 2019 Gas Financial Plan (Attachment B).
Staff proposes to adjust gas rates as shown in Table 1 and Table 2 below, effective July 1, 2018.
These changes are projected to increase the system average gas rate by roughly 4%. These rate
changes are included in the proposed amended rate schedules in Attachment D.
Table 1: Current and Proposed Monthly Service Charges
Rate Schedule
Monthly Service Charge
($/month)
Change
Current (as of
7/1/16)
Proposed for
FY 2019
($) (%)
G-1 (Residential) $10.32 $10.94 $0.62 6%
G-2 (Small Commercial) 78.23 82.94 4.69 6%
G-3 (Large Commercial) 377.43 400.08 22.65 6%
G-10 (CNG) 52.93 56.11 3.18 6%
Table 2: Current and Proposed Gas Distribution Charges
Change
Current (as of
11/1/16)
Proposed
for FY 2019
($) (%)
G-1 (Residential)
Tier 1 Rates $0.3933 $0.4239 $0.0306 7.8%
Tier 2 Rates 0.9319 0.9948 0.0629 6.7%
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.5767 0.6183 0.0416 7.2%
G-3 (Large Commercial)
Uniform Rate 0.5687 0.6098 0.0411 7.2%
G-10 (Compressed Natural Gas)
Uniform Rate 0.0093 0.0100 0.0007 7.2%
Bill Impact of Proposed Rate Changes
Table 3 shows the impact of the proposed July 1, 2018 rate changes on the median residential
bill. The average increase is roughly 4% based on commodity prices in February 2018, but some
customers may see slightly higher or lower increases due to slight changes in the composition
of the utility’s costs, as well as prevailing market prices.
Page 4 of 8
Table 3: Impact of Proposed Gas Rate Changes on Residential Bills
Usage
(Therms/month)
Bill under
Current Rates
Bill under
Proposed Rates
Change
$/mo. %
Winter (Using February 2018 commodity prices)
30 $36.93 $ 38.47 $ 1.54 4%
54 (median) 58.21 60.49 2.28 4%
80 94.20 98.04 3.84 4%
150 193.98 202.23 8.25 4%
Summer (Using July 2017 commodity prices)
10 18.73 $ 19.90 $ 1.17 6%
18 (median) 25.45 27.08 1.63 6%
30 40.57 43.16 2.59 6%
45 61.26 65.17 3.91 6%
Table 4 shows the impact of the proposed July 1, 2018 rate changes on various representative
commercial customer bills.
Table 4: Impact of Proposed Gas Rate Changes on Commercial Bills
(Using February 2018 commodity prices)
Usage
(Therms/month)
Bill under Current
Rates
Bill under
Proposed Rates
Change
%
500 613 639 4%
5,000 5,430 5,642 4%
10,000 10,781 11,202 4%
50,000 53,493 55,571 4%
FY 2019 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table shows the projected rate adjustments over the next five years and their impact on the
annual median residential gas bill.
Table 5: Projected Rate Adjustments, FY 2019 to FY 2023
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Gas Utility 4% 8% 7% 7% 4%
Estimated Bill Impact ($/mo)* $1.56 $3.25 $3.07 $3.29 $2.01
* estimated impact on median residential gas bill, which is currently $39.09 for CY 2017.
One of the main drivers for the increase in the Gas Utility’s short run costs (and therefore rates)
over the next several years are increases in capital improvement costs. In FY 2014, FY 2015 and
FY 2017, costs for the gas utility were unusually low as new main replacements were not
budgeted. The gas, water and wastewater utilities generally try to perform a main replacement
annually in each utility, but in the gas utility budgeting new projects was not feasible in those
Page 5 of 8
years. In FY 2014 and FY 2015, this was due to the fact that staff was completing a prior major
gas main replacement project, the largest in utility history, which completed replacement of all
ABS gas mains in Palo Alto. Then, FY 2016 included replacements of gas mains on University
Avenue, a project that has evolved into the Upgrade Downtown project involving a coordinated
replacement of several different types of infrastructure to avoid multiple disruptions to the
business district. This has been a multi-year planning effort that did not allow for design of other
new projects. This allowed the Gas Utility to temporarily keep rates lower than they would
typically have been needed to be to fund future operations and capital replacement. These future
capital replacement costs will be higher, as well. As the emphasis on infrastructure improvement
has taken hold both regionally and nationally, contractor bids for new projects have risen greatly
from where they were during the last recession. Lastly, one additional project which will increase
costs on a one-time basis is the modification of gas meters to an Advanced Metering
Infrastructure platform (AMI). Much of this project is expected to be completed by FY 2021.
Over the longer term, increases to Operations costs are projected to be the larger cost driver.
Growth in this category of expenses is to increase by about 2 to 3% annually. Gas commodity
costs are the most variable, being subject to market forces. This category of costs is currently
forecast to remain relatively stable, but this can change rapidly.
Figures 1 below illustrates the projected long run changes in the Gas Utility’s costs. The figures
use FY 2013 and FY 2022 as comparison years because of one time savings in FY 2014, FY 2015,
and FY 2017 due to a lack of main replacement funding. Projected cost increases over the FY 2013
to FY 2022 time period are primarily related to Operations (two thirds of the increase), and
Capital forms the other third. Commodity costs actually decreased between these two time
periods.
Figure 1: FY 2013 and FY 2022 costs
$0
$5,000
$10,000
$15,000
$20,000
$25,000
Operations Capital Commodity
$(
0
0
0
'
s
)
FY 2013
FY 2022
Page 6 of 8
It’s worth noting that although costs are increasing 17% over the FY 2013 to FY 2022 time period,
the average customer rate is projected to increase 19% over that period. This is due to the fact
that rates were lower than cost in FY 2013, so will need to rise more steeply than costs through
FY 2022. Distribution rates were not increased from July 2012 through July 2016 because of one-
time cost savings during that time. Raising rates would have resulted in accumulation of reserves
in excess of reserve guidelines.
Changes from Preliminary Financial Forecast
After presenting the preliminary financial forecast to the UAC on February 7, 2018, additional
budget information and changes to usage projections have been changed in outer years, but the
FY 2019 proposal of a 4% overall rate increase remains the same.
Gas Bill Comparison with Surrounding Cities
Table 6 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of July 2017 (to illustrate a summer month bill) and
February 2018 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2017 was $469.05, about 14% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 6: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(February 2018)
30 36.93 42.39 -12.9%
(Median) 54 58.21 76.31 -23.7%
80 94.20 126.58 -25.6%
150 193.98 264.07 -26.5%
Summer
(July 2017)
10 18.73 13.01 44.0%
(Median) 18 25.45 23.41 8.7%
30 40.57 45.24 -10.3%
45 61.26 72.72 -15.8%
Table 7 shows the monthly gas bills for commercial customers for various usage levels for rates
in effect as of February 2018. Bills for CPAU customers at the usage levels shown are around 2%
to 27% higher for commercial customers than for PG&E customers. This is a substantial
improvement over the calendar year 2013 bill comparison, when commercial gas bills for CPAU
customers were 27% to 44% higher than for PG&E customers. This is primarily attributable to
PG&E’s increased distribution rates as the commodity rates for CPAU and PG&E are very similar,
both being based on spot market gas prices.
Page 7 of 8
Table 7: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect February 2018)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 613 600 2%
5,000 5,430 5,242 4%
10,000 10,781 9,211 17%
50,000 53,493 42,036 27%
NEXT STEPS
The Finance Committee is scheduled to review the FY 2019 Gas Financial Plan in May 2018. The
City Council will consider adopting the Financial Plan and rate amendments as part of the FY 2019
budget review and adoption process. If Council approves the proposed rate changes, they will
become effective July 1, 2018.
RESOURCE IMPACT
Normal year sales revenues for the Gas Utility are projected to increase by roughly 4% ($1.2
million) as a result of the proposed rate increases, not including fluctuations in commodity
revenue/cost. See the attached FY 2019 Gas Financial Plan for a more comprehensive overview
of projected cost and revenue changes for the next ten years.
POLICY IMPLICATIONS
The proposed gas rate adjustments are consistent with Council-adopted Reserve Management
Practices that are part of the Financial Plan, and were developed using a cost of service study and
methodology consistent with industry-accepted cost of service principles.
ENVIRONMENTAL REVIEW
The UAC’s review and recommendation to Council on the FY 2019 Gas Financial Plan and rate
adjustments does not meet the California Environmental Quality Act’s definition of a project,
pursuant to Public Resources Code Section 21065, thus no environmental review is required.
ATTACHMENTS
A. Resolution of the Council of the City of Palo Alto Approving the FY 2019 Gas Utility
Financial Plan
B. Proposed FY 2019 Gas Utility Financial Plan
C. Resolution of the Council of the City of Palo Alto Adopting a Gas Rate Increase and
Amending Rate Schedules G-1, G-2, G-3, and G-10
D. Amended Rate Schedules G-1, G-2, G-3, and G-10 (proposed changes shown in in
redline/strikeout)
PREPARED BY: ERIC KENISTON, Senior Resource Planner C €:,~
JO NATHA N ABENDSCHE I N, Assistant Di rector, Resource Management c -2-_ . Cfo::;
REVIEWED BY:
APPROVED BY:
EDSHIKADA
General Manager of Utilities
Page 8of8
Attachment A
* NOT YET APPROVED *
6055005
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2019 Gas Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes
making long-term projections of market conditions, the physical condition of the system, and
other factors that could affect utility costs, and setting rates adequate to recover these costs. It
does this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby adopts the FY 2019 Gas Utility Financial Plan.
SECTION 2. The Council hereby approves the transfer of up to $129,000 in FY 2019
from the Rate Stabilization Reserve to the Operations Reserve, as described in the FY 2019 Gas
Utility Financial Plan approved via this resolution.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
governmental activity which will not cause a direct or indirect physical change in the
environment, and therefore, no environmental assessment is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
Attachment A
* NOT YET APPROVED *
6055005
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2019 GAS
UTILITY
FINANCIAL PLAN
FY 2019 TO FY 2028
ATTACHMENT B
GAS UTILITY FINANCIAL PLAN
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GAS UTILITY FINANCIA L PLAN
FY 201 9 TO FY 202 8
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2018 Rate and Reserve Proposals ........................................................ 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3C: Proposed Reserve Transfers ...................................................................................... 9
Section 4: Utility Overview .................................................................................................. 10
Section 4A: Gas Utility History ................................................................................................... 10
Section 4B: Customer Base ........................................................................................................ 11
Section 4C: Distribution System ................................................................................................. 12
Section 4D: Cost Structure and Revenue Sources ...................................................................... 13
Section 4E: Reserves Structure ................................................................................................... 13
Section 4F: Competitiveness ...................................................................................................... 14
Section 4G: Gas Supply Rates .................................................................................................... 15
Section 5: Utility Financial Projections ................................................................................. 16
Section 5A: Load Forecast .......................................................................................................... 16
Section 5A: FY 2013 to FY 2017 Cost and Revenue Trends ........................................................ 17
Section 5B: FY 2017 Results ....................................................................................................... 18
Section 5C: FY 2018 Projections ................................................................................................. 19
Section 5D: FY 2019-FY 2028 Projections .................................................................................. 19
Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 20
Section 5F: Long-Term Outlook ................................................................................................. 22
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Section 6: Details and Assumptions ..................................................................................... 23
Section 6A: Gas Purchase Costs ................................................................................................. 23
Section 6B: Operations .............................................................................................................. 24
Section 6C: Capital Improvement Program (CIP) ....................................................................... 25
Section 6D: Debt Service ............................................................................................................ 27
Section 6E: Equity Transfer ........................................................................................................ 28
Section 6F: Revenues ................................................................................................................. 28
Section 6G: Communications Plan ............................................................................................. 29
Appendices ......................................................................................................................... 31
Appendix A: Gas Financial Forecast Detail ................................................................................ 32
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 33
Appendix C: Gas Utility Reserves Management Practices ......................................................... 35
Appendix D: Description of Gas Utility Cost Categories ............................................................ 39
Appendix E: Gas Utility Communications Samples .................................................................... 40
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SECTION 1: DEFINITIONS AND ABBR EVIATIONS
ABS: Acrylonitirile butydene styrene, a plastic gas main material
AMI: Advanced Metering Infrastructure
CARB: California Air Resources Board
CIP: Capital Improvement Program
CNG: Compressed Natural Gas
CPAU: City of Palo Alto Utilities Department
CPUC: California Public Utilities Commission
Cross-bore: A cross-bore exists when one utility line has been drilled or “bored” through a portion
of another line. Gas cross-bores can occur in sewer lines as a result of “horizontal boring”
construction practices.
Distribution: transportation of gas to customers.
GMR Program: Gas Main Replacement Program
Local Transportation: transportation of gas to Palo Alto across PG&E’s distribution system from
PG&E City Gate.
Malin: a delivery hub referred to in gas purchase contracts and located in Malin, Oregon, where
the northern end of PG&E’s Redwood Transmission Pipeline is located.
MMBtu: Millions of British thermal units, a unit of gas measurement equal to ten therms.
Commonly used for high volume gas measurement. Wholesale purchases of gas from suppliers
are typically measured in MMBtu.
O&M: Operations and Maintenance
PE or HDPE: Polyethylene, a gas main material (more specifically, High-Density Polyethylene)
PG&E: Pacific Gas and Electric
PG&E Citygate, or Citygate: a delivery hub referred to in gas purchase contracts. Any gas delivered
to PG&E’s distribution system (such as gas delivered at the southern end of PG&E’s Redwood
Transmission Pipeline) is said to have been delivered at PG&E Citygate.
PVC: Polyvinyl chloride, a plastic gas main material
Summer: April 1 to October 31
Therms: The standard unit of measurement for natural gas sales to customers, equal to 100,000
British thermal units. Therms measure the heating value of the gas, rather than its volume .
Transmission: transportation of gas between major gas delivery hubs via a gas transmission
pipeline, such as PG&E’s Redwood pipeline.
UAC: Utilities Advisory Commission, an appointed body that advises the City Council on CPAU
issues.
Winter: November 1 to March 31
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SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Gas Utility for the next ten years. This
Financial Plan provides revenues to cover the costs of operating the utility safely over that time
while adequately investing for the future. It also addresses the financial risks facing the utility
over the short term and long term, and includes measures to mitigate and manage those risks.
SECTION 2 A : OVERVIEW OF F INANCIAL P OSITION
This financial plan projects non-commodity costs to increase from FY 2019 through FY 2028 at
about 3.5% per year on average. In the short term, some of these cost increases are related to
the cross-bore inspection program, but capital improvement program (CIP) costs have also
increased as the economy has improved. The national and regional focus on infrastructure
improvement has created more demand, and the pool of skilled construction labor has not grown
at the same pace. While CPAU generally plans a new gas main replacement project every year,
recent larger than expected bids have required resizing and redesign of some existing plan ned
projects. Because of this (as well as the complexity of the project), CIP costs for FY 2018 increased
for the University Avenue Business District project, which is scheduled to begin construction in
mid-2018. Due to the amount of planning required for this project, no new CIP work was
budgeted for FY 2017, and because of the complexity of the University Avenue project, no CIP
work is budgeted for FY 2019, resulting in one-time cost savings. The next new main replacement
project after the University Avenue project will take place in FY 2020. Table 1 shows the Gas
Utility expenses over the period of this financial plan .
Table 1: Gas Utility Expenses for FY 2017 to FY 2028 (Thousand $’s)
Expenses
($000)
FY
2017
(act.)
FY
2018
(est.)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Commodity costs 12,563 14,137 13,022 12,851 13,040 13,233 13,499 13,855 14,188 14,576 14,731 14,932
Operations 21,050 20,302 20,509 21,133 20,579 21,874 22,508 23,270 24,048 24,879 24,303 24,649
Capital Projects 2,214 7,804 5,197 10,217 12,080 9,815 9,892 9,970 10,050 10,131 10,214 10,299
TOTAL 35,827 42,243 38,728 44,202 45,698 44,922 45,898 47,095 48,286 49,587 49,248 49,880
To ensure that revenues cover projected rising costs, the financial plan includes the rate
trajectory shown in Table 2.
Table 2: Projected Gas Rate Trajectory for FY 2019 to FY 2028
Projection FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
FY
2028
Current Financial Plan 4% 8% 7% 7% 4% 4% 1% 1% 0% 2%
FY 2018 Financial Plan 4% 6% 6% 5% 3% 3% 2% 1% 0% N/A
FY 2017 Financial Plan 7% 4% 1% 1% 1% 1% 1% 1% N/A N/A
The Gas Utility has a Rate Stabilization Reserve, which can be used to smooth rate increases over
several years. This Financial Plan projects that these reserves will be exhausted by the end of FY
2020. The Gas Utility also has a CIP Reserve to help offset one-time and/or unanticipated, spikes
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in CIP spending which do not merit separate bond financing. Table 3 shows the projected reserve
transfers over the forecast period.
Table 3: Transfers To/(From) Reserves for FY 2018 to FY 2028 ($000)
Reserve FY 2018 FY 2019 FY 2020 to FY 2028
Rate Stabilization (129) (2,006) (4,404)
CIP - - (3,820)
Operations 129 2,006 8,224
SECTION 2 B : SUMMARY OF PROPOSE D ACTIONS
Staff proposes the following actions for the Gas Utility in FY 2018:
1. Amend the proposal of a $1.2 million transfer from the Rate Stabilization Reserve to the
Operations Reserve, as proposed in the FY 2018 Gas Financial Plan, to a transfer of
$129,000, based on projected ending Operations Reserve levels.
Staff proposes the following actions for the Gas Utility in FY 2019:
2. Increase distribution rates by 6% (a 4% overall increase) for FY 2019, primarily reflecting
increases to capital expenditures and also increased operations costs . See Section 3B:
Current and Proposed Rates for more details.
3. Transfer $2 million from the Rate Stabilization Reserve to the Operations Reserve. See
Section 3D: Proposed Reserve Transfers for more details.
SECTION 3: DETAIL OF FY 201 8 RATE AND RESERVE PRO POSALS
SECTION 3 A : RATE DESIGN
The Gas Utility’s rates are evaluated and implemented in compliance with cost of service
requirements. The Gas Utility’s current rates are based on the methodology from the April 2012
Gas Utility Cost of Service Study completed by Utility Financial Solutions.1 In preparation for an
update to the study, staff discussed a proposed scope with the Utilities Advisory Commission in
October 2016, and the Council in November 2016 2 . The updated study is projected to be
completed by late FY 2018 or the early part of FY 2019, and will provide guidance for the next
proposed rate action.
SECTION 3 B : CURRENT AND PROPOS ED RATES
On July 1, 2012 CPAU restructured its rates so that the commodity component varied monthly to
match changes in gas market prices.3 In addition, CPAU increased monthly service charges to
recover the cost of providing gas service to customers. In January 2015, the Council adopted a
1 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
2 Staff Report 7416 11/14/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54576
3 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
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new rate component to collect the costs of purchasing allowances for the purpose of compliance
with the State’s cap-and-trade program.4 This component changes depending on the cost of
allowances and gas demand. In October 2016, the Council adopted a resolution changing the
Local Transportation rate (which had been collapsed into the Distribution rate in 2015 to
streamline bill presentation), to be a pass-through of PG&E’s Gas Transportation Rate to
Wholesale/Resale Customers (G-WSL) charge to Palo Alto.5 This went into effect November 1,
2016. In December 2016, Council approved a carbon neutral gas plan, with a goal of achieving a
carbon neutral gas portfolio by FY 2018.6 The plan is for costs associated with the plan to be a
passed through directly to customers as well, although the rate impact is not to exceed $0.10 per
therm. Three years’ worth of volumetric rate history can be found on Palo Alto’s website.7
CPAU has four rate schedules: one for separately metered residential customers (G-1), one for
small commercial and master-metered multi-family residential customers (G-2), one for
customers using over 250,000 therms per year (G-3) and a specific schedule for the Compressed
Natural Gas station (G-10). All customers pay a monthly service charge, which represents meter
reading, billing, and other customer service costs, as well as a portion of operations and
maintenance cost. All customers are also charged for each therm of gas used. Separately metered
residential customers are charged on a tiered basis, differentiated by season. During the winter
months, the first 2 therms per day (60 therms for a 30 day billing period) are charged a base price
per CCF, and all additional units charged a higher price per therm . During the summer months,
the first tier level is 0.667 therms per day, or 20 therms for a 30 day billing period. Commercial
customers pay a uniform price for each therm used.
Table 4 shows the current monthly service charges for all rate schedules. Table 95 shows the
consumption charges related to distribution charges. As mentioned earlier, commodity charges
change monthly, and transportation charges are tied to the PG&E G-WSL rate schedule. Some
recent commodity price history is discussed in Section 6A: Gas Purchase Costs.
4 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537
5 Staff Report 7260 10/17/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54165
6 Staff Report 7533 12/05/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54882
7 Monthly Gas Commodity & Volumetric Rates http://www.cityofpaloalto.org/civicax/filebank/documents/30399
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Table 4: Current and Proposed Monthly Service Charges
Rate Schedule
Monthly Service Charge
($/month)
Change
Current (as of
7/1/16)
Proposed for
FY 2019
($) (%)
G-1 (Residential) $10.32 $10.94 $0.62 6%
G-2 (Small Commercial) 78.23 82.94 4.69 6%
G-3 (Large Commercial) 377.43 400.08 22.65 6%
G-10 (CNG) 52.93 56.11 3.18 6%
Table 5: Current and Proposed Gas Distribution Charges
Change
Current (as of
11/1/16)
Proposed
for FY 2019
($) (%)
G-1 (Residential)
Tier 1 Rates $0.3933 $0.4239 $0.0306 7.8%
Tier 2 Rates 0.9319 0.9948 0.0629 6.7%
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.5767 0.6183 0.0416 7.2%
G-3 (Large Commercial)
Uniform Rate 0.5687 0.6098 0.0411 7.2%
G-10 (Compressed Natural Gas)
Uniform Rate 0.0093 0.0100 0.0007 7.2%
SECTION 3 C : BILL IMPACT OF PRO POSED RATE CHANGES
Table 6 shows the impact of the proposed July 1, 2018 rate changes on the median residential
bill. The average increase is roughly 4% based on prices in February 2018, but some customers
may see slightly higher or lower increases due to slight changes in the composition of the utility’s
costs, as well as prevailing market prices.
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Table 6: Impact of Proposed Gas Rate Changes on Residential Bills
Usage
(Therms/month)
Bill under
Current Rates
Bill under
Proposed Rates
Change
$/mo. %
Winter (Using February 2018 commodity prices)
30 $36.93 $ 38.47 $ 1.54 4%
54 (median) 58.21 60.49 2.28 4%
80 94.20 98.04 3.84 4%
150 193.98 202.23 8.25 4%
Summer (Using July 2017 commodity prices)
10 18.73 $ 19.90 $ 1.17 6%
18 (median) 25.45 27.08 1.63 6%
30 40.57 43.16 2.59 6%
45 61.26 65.17 3.91 6%
Table 7 shows the impact of the proposed July 1, 2018 rate changes on various representative
commercial customer bills.
Table 7: Impact of Proposed Gas Rate Changes on Commercial Bills
(Using February 2018 commodity prices)
Usage
(Therms/month)
Bill under Current
Rates
Bill under
Proposed Rates
Change
%
500 613 639 4%
5,000 5,430 5,642 4%
10,000 10,781 11,202 4%
50,000 53,493 55,571 4%
SECTION 3D: PROPOSED RESERVE TRANSFERS
The FY 2018 Financial Plan proposed a $1.2 million transfer from the Rate Stabilization Reserve
into the Operations Reserve in FY 2018. Lower actual expenses in FY 2017 resulted in higher
ending reserve balances than initially projected, so staff recommends revising the transfer down
to $129,000 at this time. A tentative transfer of $2 million in FY 2019, followed by $4.4 million in
FY 2020, is included in the financial projections in this Financial Plan. In addition, $3.8 million in
the CIP Reserve may need to be utilized in FY 2021. This will help mitigate additional, one -time
costs related to the replacement of gas meters for AMI deployment. The transfers in general will
enable CPAU to maintain adequate Operations Reserve levels while moderating the pace of
increase in gas rates. The impact of these transfers on reserves levels can be seen in Appendix A:
Gas Utility Financial Forecast Detail.
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SECTION 4: UTILITY O VERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information and to help readers better understand the forecasts in Section 5: Utility
Financial Projections and Section 6: Details and Assumptions.
SECTION 4 A : GAS UTILITY HISTORY
On September 22, 1917, the City of Palo Alto issued a bond to purchase the property of Palo Alto
Gas Company and continue it as a municipal enterprise. At the time, the system was comprised
of 21 miles of mains, 1,900 meters, and was valued at $65,500. PG&E supplied the gas, which
was synthesized from coal at its Potrero gasification facility. Almost immediately the City faced
challenges. Losses were at nearly 25% according to PG&E’s master meter, and PG&E had filed
with the Railroad Commission (the forerunner to today’s CPUC) to increase rates by nearly 72.5%.
Despite these initial hurdles, Palo Alto’s system grew tremendously, and by 1924 revenues had
exceeded those of the electric utility. Sales were such that the annual reports of the time noted
gas usage “appears to be greater than that of any other city in the state, showing that gas is a
very popular form of fuel in Palo Alto.” Just prior to the acquisition of the neighboring town of
Mayfield’s gas system (centered around today’s California Avenue) in 1929, the miles of main in
service and customers connections had doubled.
Notable changes to the gas supply itself came in 1930, when PG&E ceased supplying purely
manufactured (or coal) gas from its Potrero Hill facility in San Francisco and instead switched to
natural gas. In 1935, a supplementary butane injection system (later retired) was purchased from
Standard Oil to mitigate large wintertime peaks. Gas sales were at 248,658 million cubic feet
(MCF) with 4,849 active services.
Early gas mains in Palo Alto were made of steel, but in the 1950s, like many other utilities, CPAU
switched to ABS plastic. CPAU switched to PVC plastic in the early 1970s, but around 100 miles
of ABS mains had already been installed. A 1990 evaluation of the system found a steadily
increasing rate of gas leaks associated with those mains, something that other gas utilities had
also been experiencing. To reduce leaks, CPAU accelerated its main replacement program from
7,000 feet (1.3 miles) of replacements per year to 20,000 feet (3.8 miles) per year . This would
enable the utility to replace all of its ABS and its most vulnerable steel and PVC mains with
polyethylene (PE) mains over the course of the following 36 years.8 As of 2015 the Gas Utility
had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic
protection was not effective. Current main replacement projects will target the last ~800 feet of
remaining ABS main as well as tackling PVC replacement. A PVC risk analysis to determine the
appropriate footage of annual PVC replacement for future CIP projects is currently being
conducted. This is an example of how local control of its Gas Utility has provided Palo Alto
residents with substantial benefits. During the 1990s and 2000s, while CPAU was increasing its
8 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990
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main replacement rate to ensure a robust gas distribution system, PG&E was underspending on
safety-related infrastructure, according to a past audit.9
In the 1990s, while grappling with the issues surrounding its distribution system, CPAU was also
participating in major changes to the structure of the gas industry in California . Until 1988 CPAU
had a formal policy of setting its rates equal to PG &E’s rates and successfully did so with the
exception of one year in the mid-1970s. At times this led to inadequate revenue (1974 to 1981)
as PG&E, the City’s only gas supplier, regularly filed requests with the CPUC to increase the
wholesale gas supply rates charged to the Gas Utility. In the 1990s, as the CPUC began
deregulating the natural gas industry in California, the Gas Utility began purchasing gas from
suppliers other than PG&E. In 1997 the CPUC adopted the “Gas Accord,”10 which enabled the Gas
Utility (along with other local transportation-only customers) to obtain transmission rights on
PG&E’s Redwood transmission pipeline running from Malin, Oregon into California.
In 2000/2001 the California energy crisis occurred, causing major disruptions to the Gas Utility’s
supply costs. Wholesale gas prices rose over 500% between January 2000 and January 2001. The
Council approved drawing down reserves to provide ratepayer relief and, for two years following
the crisis, CPAU rates were above PG&E’s as reserves were replenished. In April 2001 the Council
approved a hedging practice of buying fixed price gas one to three years into the future . After
reaching a low point in October 2001, prices continued to rise, and as a result the CPAU hedging
strategy frequently resulted in a wholesale supply cost advantage compared to PG&E until prices
began to decline steeply in mid-2008. At that point the Gas Utility’s wholesale supply costs
became higher than market gas prices due to fixed price contracts entered into prior to 2008. As
a result the Gas Utility’s wholesale supply costs were higher than PG&E’s for several years. In
2012 Council approved a plan to formally cease the hedging strategy and purchase all gas on the
short-term (“spot”) markets. As of July 1, 2012, the commodity portion of the gas rates changes
every month based on the spot market gas price.
SECTION 4 B : CUSTOMER BASE
CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas
customers in Palo Alto. Close to 23,600 customers are connected to the natural gas system,
approximately 22,000 (93%) of which are residential and 1,600 (7%) of which are non-residential.
Residential customers consume about 11 to 13 million therms of gas per year, roughly 45% of the
gas sold, while non-residential customers consume 55% (about 14 to 16 million therms).
Residential customers use gas primarily for space heating (46% of gas consumed) and water
heating (42%), with the remainder consumed for other purposes such as cooking, clothes drying,
9 Focused Financial Audit of The Pacific Gas & Electric Company’s Gas Distribution Operations , Overland Consulting,
made available through a CPUC Administrative Law Judge’s ruling on A12-11-009/I13-03-007 on 5/31/2013
10 CPUC decision 97-08-055. Since then, the Gas Accord has been amended four times, with the most recent being
Gas Accord V, application A.09-09-013
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and heating pools and spas.11 Non-residential customers use gas for space and water heating
(73% of gas consumed), cooking (20%), and industrial processes (6%).12
The Gas Utility receives gas at the four receiving stations within Palo Alto where CPAU’s
distribution system connects with Pacific Gas and Electric’s (PG&E’s) system. These receiving
stations are jointly operated by CPAU and PG&E. CPAU purchases gas from various natural gas
marketers, with PG&E providing only local transportation service (transportation from the PG&E
City Gate gas delivery hub to Palo Alto). CPAU also has transmission rights on PG&E’s transmission
pipeline from Malin, Oregon to PG&E City Gate, allowing it to purchase lower priced gas at that
location. CPAU does not produce or store any natural gas, and purchases gas in the monthly and
daily spot markets. The cost of the purchased gas is passed through directly to customers through
a rate adjuster that varies monthly with market prices. In a similar fashion, the cost for local
transportation is now tied to PG&E’s G-WSL rate schedule, and varies when and if PG&E changes
its rate schedule. The cost of purchased gas and PG&E local transportation service usually
account for roughly one third of the utility’s expenditures.
SECTION 4 C : DISTRIBUTION SYSTE M
To deliver gas from the receiving stations to its customers, the utility owns 210 miles of gas mains
(which transport the gas to various parts of the city) and close to 23,600 gas services (which
connect the gas mains to the customers’ gas lines). These mains and services, along with their
associated valves, regulators, and meters, represent the vast majority of the i nfrastructure used
to deliver gas in Palo Alto. CPAU has an ongoing CIP to repair and replace its infrastructure over
time, the expense of which normally accounts for around 15 to 20% of the utility’s expenditures.
Costs for main replacements have been going up in recent years.
In addition to the CIP, the Gas Utility performs a variety of maintenance activities related to the
system, such as monitoring the system for leaks, testing and replacing meters, monitoring the
condition of steel pipe, and building and replacing gas services for buildings being built or
redeveloped throughout the city. The utility also shares the costs of other system-wide
operational activities (such as customer service, billing, meter reading, supply planning, energy
efficiency, equipment maintenance, and street restoration) with the City’s other utilities . These
maintenance and operations expenses, as well as associated administration, debt service, rent,
and other costs, make up roughly half of the utility’s expenses. In addition to these ongoing
activities, CPAU has conducted a program to find and replace cross-bores over the last several
years. Currently, $1 million is budgeted per year for the cross-bore program through FY 2021.
However, the ongoing cross-bore investigation may require additional funding, or extend for
longer into the future, as the remaining sewer lines are more difficult to examine than the
majority of the wastewater collection system that has been examined to date.
11 http://energyalmanac.ca.gov/naturalgas/overview.html
12 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Statistics shown are for
end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located.
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SECTION 4 D : C OST S TRUCTURE AND R EVENUE S OURCES
As shown in Figure 1, the Gas
Utility receives 95% of its revenue
from sales of gas and the
remainder from capacity and
connection fees, interest on
reserves, and other sources.
Appendix A: Gas Utility Financial
Forecast Detail shows more detail
on the utility’s cost and revenue
structures.
As shown in Figure 2, in FY 2017,
gas purchase costs accounted for
roughly 31% of the Gas Utility’s
costs. This percentage can vary
widely from year to year, as this
cost is based upon market
purchases, and now also includes
costs related to cap and trade.
Operational costs in FY 2017
represented roughly 51%, of
expenses and capital investment
was responsible for the remaining
18%. CIP is normally about 20% of
expenses, but this may be lower in
times when new budgeting for
projects is deferred, as happened in FY 2017.
SECTION 4 E : RESERVES STRUCTURE
CPAU maintains six reserves for its Gas Utility to manage various types of contingencies. The
summary below describes each of these briefly. See Appendix C: Gas Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
Reserve for Commitments: A reserve equal to the utility’s outstanding contract liabilities
for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
Reserve for Reappropriations: A reserve for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including the
General Fund, have a Reappropriations Reserve.
Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to accumulate
funds for future expenditure on CIP projects and is anticipated to be empty unless a major
one-time CIP expenditure is expected in future years. This CIP can also act as a
Figure 2: Cost Structure (FY 2017)
51%
31%
18%
Operations
Gas Purchases
Capital
Figure 1: Revenue Structure (FY 2017)
95%
5%
Sales of Gas
Other Revenue
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contingency reserve for the CIP. This type of reserve is used in other utility funds (Electric,
Water, and Wastewater Collection) as well.
Rate Stabilization Reserve: This reserve is intended to be empty unless one or more large
rate increases are anticipated in the forecast period. In that case, funds can be
accumulated to spread the impact of those future rate increases across multiple years.
This type of reserve is used in other utility funds (Electric, Water, and Wastewater
Collection) as well.
Operations Reserve: This is the primary contingency reserve for the Gas Utility, and is
used to manage yearly variances from budget for operational gas costs. This type of
reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as well.
Unassigned Reserve: This reserve is for any funds not assigned to the other reserves and
is normally empty.
SECTION 4 F : COMPETITIVENESS
Table 8 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of July 2017 (to illustrate a summer month bill) and
February 2018 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2017 was $469.05, about 14% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 8: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(February 2018)
30 36.93 42.39 -12.9%
(Median) 54 58.21 76.31 -23.7%
80 94.20 126.58 -25.6%
150 193.98 264.07 -26.5%
Summer
(July 2017)
10 18.73 13.01 44.0%
(Median) 18 25.45 23.41 8.7%
30 40.57 45.24 -10.3%
45 61.26 72.72 -15.8%
Table 9 shows the monthly gas bills for commercial customers for various usage levels for rates in
effect as of February 2018. Bills for CPAU customers at the usage levels shown are around 2% to
27% higher for commercial customers than for PG&E customers. This is a substantial
improvement over the calendar year 2013 bill comparison, when commercial gas bills for CPAU
customers were 27% to 44% higher than for PG&E customers. This is primarily attributable to
PG&E’s higher distribution rates as the commodity rates for CPAU and PG&E are very similar, both
being based on spot market gas prices.
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Table 9: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect February 2018)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 613 600 2%
5,000 5,430 5,242 4%
10,000 10,781 9,211 17%
50,000 53,493 42,036 27%
SECTION 4 G : GAS SUPPLY RATES
Starting in July 2012, CPAU replaced a “laddering” hedging strategy for purchasing gas supplies
with a strategy to buy gas on the short-term, or “spot” markets and pass the commodity cost to
customers on a monthly basis. Figure 3 shows the actual commodity prices charged. Commodity
prices have fluctuated by around $0.20 over the last two years, but have generally been lower
than prices seen in 2013 and 2014.
Figure 3: Gas Commodity Rates from July 2012 through February 2018
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SECTION 5 : UTILITY F INANCIAL PROJECTIONS
SECTION 5 A : LOAD F O RECAST
Gas usage in Palo Alto is volatile, varying with both economic and weather conditions . As shown
in Figure 4, in the early 1970’s, gas purchases reached over 45 million therms per year . Usage
dropped dramatically in the 1976/1977 drought when customers saved significant amounts of
(hot) water by upgrading to efficient showerheads. During the 1980s and 90s average gas usage
was around 36 million therms per year. Usage dropped again in the early 2000’s. In FY 2001, gas
prices escalated during the California energy crisis and Palo Alto’s rates increased by nearly 200%.
From 2003 to 2011, usage decreased by 2.3% mainly as a result of continued customer
investments in energy efficiency.
In 2014 and 2015, unusually warm winters, as well as ongoing drought, caused gas usage to
tumble to historic lows. In FY 2017 and FY 2018, as the drought has eased, gas usage has started
to increase again.
Figure 4: Historic Gas Consumption
Gas consumption, as denoted by the dotted line in Figure 5, is projected to recover somewhat
and resume the long run trend of decreasing usage over the forecast period, although changes
such as replacement of gas appliances with electric appliances or customer behavior may result
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in lower long run usage. As with prior drought/gas usage declines in the past, it is likely that
consumption will not come back to pre-conservation levels. It is too early to tell, however, where
the new ‘normal’ level of consumption will be.
Figure 5: Forecast Gas Consumption
SECTION 5 A : FY 201 3 TO FY 201 7 COST AND REVENUE TRE NDS
Figure 6 and Appendix A: Gas Utility Financial Forecast Detail show how costs have changed
during the last five years as well as how staff project costs to change over the next decade.
The annual expenses for the gas utility decreased substantially between 2013 and 2017. Lower
gas sales in conjunction with the drought, as well as lower gas market prices in FY 2015 and FY
2016 (as shown in Figure 3 above) resulted in lower overall commodity expenses. FY 2014, FY
2015 and FY 2017 were notable due to the fact that no new funding was added for main
replacement projects. In FY 2014 and FY 2015, this was due to the fact that staff was completing
a prior major gas main replacement project, the largest in utility history, which completed
replacement of ABS gas mains in Palo Alto. The FY 2016 project included replacements of gas
mains on University Avenue, a project that has evolved into the Upgrade Downtown project
involving a coordinated replacement of several different types of infrastructure to avoid multiple
disruptions to the business district. This has been a multi-year planning effort that did not allow
for design of other new projects. This allowed the Gas Utility to temporarily keep rates lower
than they will need to be to fund future operations and capital replacement .
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Revenues have generally matched expenses in most years and were higher than expenses in FY
2017. As shown in Figure 6 below, revenues were below cost in FY 2013 and nearly at cost in FY
2016. The absence of new budget funding for main replacement projects for several years, as
well as the availability of relatively large reserves, forestalled the need for rate increases until
now.
As shown in Figure 6, the last adjustment to gas distribution rates was in July 2016 when CPAU
increased rates by 8%. In FY 2012, commodity rates were changed to a market-based, monthly
pass-through cost—and commodity rates (and usage) fell, so revenues (and gas supply costs)
actually declined in FY 2013 after the rate increase. Figure 6 assumes no change in gas supply
costs over the forecast period to illustrate the impact of proposed distribution rate changes on
the overall customer bill. In reality, gas supply costs are uncertain and are passed through to
customers as they change month to month.
Figure 6: Gas Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2017 and Projections through FY 2028
SECTION 5 B : FY 201 7 RESULTS
Sources of funds for FY 2017 were lower than projections by $885,000, but operational expenses
came in well below the expected budget. Total FY 2017 expenses were $32.7 million compared
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to projections of $36.9 million in the FY 2018 Financial Plan. Table 10 summarizes the variances
from forecast.
Table 10: FY 2017, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Purchase costs lower than forecast (479) Cost savings
Operations cost savings (3,774) Cost savings
Decreased interest income and other
non-sales revenues 1,753
Revenue decrease
Increased sales revenues (867) Revenue increase
Net Cost / (Benefit) of Variances (3,368)
SECTION 5 C : FY 201 8 PROJECTIONS
Current projections indicate that sales revenues will be slightly higher than last year’s forecast,
but other revenues have been revised downwards based on prior year actuals. While gas
purchase costs are not projected to increase appreciably during the forecast period, the current
financial plan anticipates CIP costs will be substantially higher in FY 2018 than projected in the
prior financial plan. Table 11 summarizes the current and projected variances from the FY 2018
Financial Plan.
Table 11: FY 2018 Projected Results vs. Current Financial Plan Forecast ($000)
Net Cost/ (Benefit) Type of change
Sales revenues higher than forecast (160) Revenue increase
Other revenues and interest lower than forecast 1,272 Revenue decrease
Purchase cost decrease (2,108) Cost decrease
Operations & maintenance and customer service
cost decreases
(1,477) Cost decrease
Capital Improvement Cost increases 5,730 Cost increase
Net Cost / (Benefit) of Variances 3,259
SECTION 5 D : FY 201 9 -FY 202 8 PROJECTIONS
Figure 6 above shows that staff projects costs for the Gas Utility to rise substantially in FY 2018,
and then to increase at around 2.9% per year on average through FY 2028. In Operations, there
is a short run addition of $1 million, starting in FY 2019, for cross-bore inspections (this expense
is projected to continue for at least three years), as well as general inflationary increases of
around 2 to 3% per year. Salaries and benefits expenses are projected to rise at 3 to 4% per year,
per the City’s Long Range Financial Plan. Construction costs continue to increase, which resulted
in increased costs in FY 2018 for the University Avenue Business District project, which is
scheduled to begin construction in mid-2018. Due to the amount of planning required for this
project, no new CIP work was budgeted for FY 2017, and because of its complexity, no CIP work
is budgeted for FY 2019, resulting in one-time cost savings. The next new main replacement
project after the University Avenue project will take place in FY 2020, and ongoing main
replacement is expected to be more expensive. In addition to these trends, additional costs
related to AMI deployment are projected in FY 2020 and 2021. Gas commodity costs are the most
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variable component but are currently projected to increase by less than 2% annually. Since this
is a pass-through cost to customers, the risk of these costs being higher or lower than expected
has a minimal impact on reserves.
As shown in Figure 7, this financial plan projects the Rate Stabilization Reserves to be depleted
by FY 2020.
Figure 7: Gas Utility Reserves
Actual Reserve Levels for FY 2017 and Projections through FY 2028
SECTION 5 E : RISK ASSESSMENT AND RESERVES ADEQUAC Y
This financial plan projects the Gas Utility’s primary contingency reserve, the Operations Reserve,
to be within guideline levels throughout the forecast period, barring either short-run budget
savings and/or larger future increases. Figure 8 shows the Operations Reserve within the
guideline levels.
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Figure 8: Operations Reserve Adequacy
Forecasted Operations Reserve levels also exceed the short-term risk assessment for the Utility.
Table 12 summarizes the risk assessment calculation for the Gas Utility through FY 2023. The
same methodology is used for FY 2024 through FY 2028 as well. The risk assessment includes the
revenue shortfall that could accrue due to:
1. Lower than forecasted distribution sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Table 12: Gas Risk Assessment ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Total non-commodity revenue $21,457 $23,226 $25,843 $28,443 $29,930
Max. revenue variance, previous ten years 16% 16% 16% 16% 16%
Risk of revenue loss $3,441 $3,725 $4,144 $4,561 $4,799
CIP Budget $3,894 $8,875 $10,697 $8,391 $8,425
CIP Contingency @10% $389 $888 $1,070 $839 $842
Total Risk Assessment value $3,830 $4,612 $5,214 $5,400 $5,642
Finally, the City created the CIP Reserve at the end of FY 2015 to act as a contingency reserve for
capital improvement projects. Current guidelines state that the balance of this reserve should fall
between 12 and 24 months of budgeted CIP expense, but staff will continue to review this reserve
and the appropriateness of the current minimum and maximum guideline levels.
At the end of FY 2017, the sum of the CIP Reserve and existing Commitments was $8 million, as
shown in Figure 7.
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SECTION 5 F : LONG -TERM OUTLOOK
In the longer term (5 to 35 years out) it is very difficult to predict the Gas Utility’s commodity
costs. A variety of long-term trends could affect commodity costs either positively or negatively.
Continuing improvement in gas extraction technology, such as fracking, could continue to create
generous supplies of gas, but these technologies are also under greater scrutiny with respect to
their environmental impacts. On the demand side, a continued shift from coal to natural gas for
electricity generation, an expansion of export capabilities, or an increase in manufacturing in the
U.S. might drive up natural gas prices, but other factors, such as generally more mild winters,
might drive gas demand lower. It is also difficult to predict the magnitude of the additional cost
impacts associated with the State’s cap-and-trade program over the long term. In the face of this
uncertainty, CPAU is able to protect the financial position of the Gas Utility by continuing its
current strategy of passing these costs directly to its customers via month-varying rate
adjustment mechanisms. The City pursues a policy of purchasing offsets to make gas usage in
Palo Alto carbon neutral. The cost is not to exceed $0.10/therm.
Future CIP investment needs for the Gas Utility may be lower than in the past, although costs per
foot for main replacement have been increasing substantially. The Gas Utility has replaced nearly
all of its ABS gas mains and its most problematic steel and PVC mains as well. The PE pipe being
used now is expected to have at least a fifty-year lifetime, and there is growing evidence that it
may last much longer than that. This would result in lower CIP investment over the long term.
CPAU is considering performing a study in the near future to develop its future main
replacements priorities and strategy.
Long-term state or local climate goals could also have a major impact on the Gas Utility. The
Global Warming Solutions Act, Assembly Bill 32 (AB32), set a goal of reducing greenhouse gas
(GHG) emissions to 1990 levels by 2020. In its December 2007 Climate Protection Plan, the City
set a goal of lowering emissions to 15% below 2005 levels by 2020. As a community Palo Alto
achieved these goals in 2012 even with continued use of natural gas for heating, cooking, and
industrial processes. However, to achieve the recently adopted Sustainability and Climate Action
Plan (S/CAP) goal of an 80% reduction in carbon emissions by 2030, or the State’s adopted goal
of an 80% reduction in emissions by 2050, extensive electrification of gas-using appliances is
necessary. If significant amounts of electrification occurred, stranded investment and higher
rates could be required as the costs of the distribution system are recovered over a lower sales
base. It is instructional that, in the recent discussion draft of its scoping plan update, CARB says,
to meet those goals, natural gas use would have to be “mostly phased out.”13 Staff intends to
begin evaluating how to manage potential impacts of these trends over the next few years.
13 Climate Change Scoping Plan, First Update, Discussion Draft for Public Review and Comment , California Air
Resources Board, October 2013, pg 88.
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SECTION 6 : D ETAILS AND A SSUMPTIONS
SECTION 6 A : GAS PURCHASE COSTS
The Gas Utility purchases much of its gas for delivery at Malin, Oregon which is almost always
cheaper than delivery at PG&E Citygate, even including the costs of transmission from Malin to
Citygate. The Gas Utility purchases gas on a month-ahead and day-ahead basis in the spot market.
The last few years have seen gas prices in a relatively narrow but low band. High levels of natural
gas in storage, along with warmer than normal weather on the West coast has kept prices low,
as shown in Figure 9.
Figure 9: Gas Market Prices at PG&E Citygate
Gas commodity costs are expected to increase slowly but steadily over the next several years.
Figure 10 shows the projected gas prices used to generate this forecast. Projections for
transmission costs associated with transporting gas over PG&E’s Redwood transmission pipeline
(from Malin, Oregon to the PG&E Citygate) are based on rates adopted in the most recent update
to the Gas Accord.
Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary
adder to PG&E’s local transportation rate,14 but in December 2014 PG&E applied to the CPUC to
14 California Public Utilities Commission Advice Letter 3430-G, effective January 1, 2014. Also see CPUC Decision
12-12-30 regarding the Pipeline Safety Enhancement Plan Adder.
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more than double local transportation costs. The application was not settled until late 2016. As
these charges are dictated by PG&E and are outside of Palo Alto’s control, staff proposed making
these costs pass-through charge, similar to the commodity charge, and this became effective in
November 2016.
Figure 10: Wholesale Gas Price Projections
SECTION 6 B : OPERATIONS
Operations costs include the Customer Service, Demand Side Management, Operations and
Maintenance (including Engineering), Resource Management, and Administration categories in
Figure 11, below. Debt service, rent, and transfers are also included in Operations costs
(excluding the General Fund equity transfer). Appendix D: Description of Gas Utility Cost
Categories includes detailed descriptions of the activities associated with these cost categories.
Operations costs are projected to increase by 2 to 4% per year. Salary and benefits, inflation, and
other assumptions match those used in the City’s long-range financial forecast.
Operations costs for FY 2019 to FY 2021 include funding for the cross-bore program. In the 1970s
CPAU, like many other utilities, adopted horizontal drilling as an alternative to trenching when
installing new gas services. This created the possibility of cross-bores, which can happen when a
gas service is bored through a sewer lateral. Though cross-bores are very rare, they can create a
dangerous situation when a contractor attempts to clear a blocked sewer line, because if the
cross-bored gas service is damaged during the line, clearing it can result in a gas leak. CPAU has
been inspecting new gas services since 2001, and in 2011 began video inspections of the sewer
laterals at the location of horizontally-drilled gas services installed before 2001. This inspection
program has cost roughly $1 million per year since FY 2012. While a majority of sewer laterals
have been inspected, staff has come across several services which are not able to be scoped,
either due to infiltration by roots or broken/collapsed pipe segments. Staff has included $3
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million in additional funding between FY 2019 and FY 2021 for this program, but the program will
likely require additional funding in future years to complete.
Figure 11: Historical and Projected Operational Costs
SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
The Gas Utility’s CIP program consists of the following programs and budgets:
The Gas Main Replacement Program, under which the Gas Utility replaces aging gas
mains ranked to have the highest threat scores within the system.
Customer Connections, which covers the cost when the Gas Utility installs new services
or upgrades existing services at a customer’s request in response to development or
redevelopment. The Gas Utility charges a fee to these customers to cover the cost of
these projects.
Ongoing Projects, which covers the cost of routine meter, regulator, and service
replacement, minor projects to improve reliability or increase capacity, and other general
improvements.
Tools and Equipment, which covers the cost of capitalized equipment, such as directional
boring, gas pipeline maintenance and emergency equipment.
One-time Projects, which represents occasional large projects that do not fall into any
other category.
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Table 13 shows the current status of these project categories and future projected spending.
Table 13: Budgeted Gas CIP Spending ($000)
The Gas Main Replacement (GMR) Program is in the final stages of completing a major milestone
with the replacement of gas mains made from Acrylonitrile-Butadiene-Styrene (ABS) plastic. The
program to replace ABS and other low-performing materials within the gas system started in the
1990s (see Section 4A: Gas Utility History for more detail). CPAU temporarily slowed down its FY
2014 and 2015 CIP appropriations in this category in order to finalize the last major ABS main
replacement project and to catch up on projects t hat had accumulated due to staffing issues.
With the replacement of all ABS mains with Polyethylene (PE) plastic near completion, the
material most at risk for failure is the remaining Polyvinyl chloride (PVC) plastic and steel
(wrapped, with cathodic protection). The next focus of the GMR program will be the replacement
of all PVC mains with PE mains. CPAU is considering updating the Gas System Master Plan to
determine which sections of pipeline to prioritize and assist in determining the pace of main
replacement (approximately three miles of main each year, or 1.5% of the system).
The current budget for the gas main replacement program takes into account the recent rise in
construction costs. Several factors are contributing to the increase in constructio n costs and
include economic recovery in the Bay Area, a greater focus on infrastructure improvement by
many municipal agencies, and the higher demand for utility contractors within these fields. CPAU
has seen the replacement cost per linear foot increase by 25% to 50% over the last couple of
years. The Gas Utility posted the most recent project for competitive bid (the Upgrade Downtown
Project) and this resulted in very few contractor bids and an eventual contract price that was
much higher than estimated (staff has requested $6.7 million additional funding in FY 2018
related to this project) . Staff is beginning to include the higher construction cost in future project
estimates in order to maximize the amount of pipe replaced, as well as insuring the over all
integrity of the gas system. Currently, CPAU plans to replace as many aging mains as possible
within its current budget. However, if this trend of higher construction cost continues, the Gas
Utility may require larger CIP budgets and as a result, an increase in rates.
Staff has also included projections for costs related to AMI deployment, primarily centered
around meter replacement costs in FY 2021.
Staff projects ongoing projects, tools and equipment, and customer connections to cost
approximately $2.7 million in FY 2019 and remain relatively flat through the end of the forecast
period. In practice, these projects can fluctuate dramatically depending on prices of material,
system conditions and the pace of development and redevelopment in the city. It is worth noting
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
One Time Projects 129 (1) 128 42 1,680 530 2,320 - -
Gas Main Replacement 10,913 (225) 10,688 311 600 7,150 7,150 7,150 7,150
Tools And Equipment 89 (5) 84 15 370 120 120 100 100
Ongoing Projects 1,455 (164) 1,291 134 1,044 1,075 1,107 1,141 1,175
Customer Connections 1,414 (418) 997 99 1,303 1,342 1,383 1,424 1,467
TOTAL 14,001 (812) 13,189 600 4,997 10,218 12,080 9,815 9,892
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
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that fee revenue pays for the Customer Connections program, so when costs go up fees will be
adjusted as well. .
Aside from customer connections and transfers from other funds, the CIP plan for FY 2019 to FY
2023 is funded by utility rates. Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
shows the details of the plan.
SECTION 6 D : DEBT SERVICE
The Gas Utility currently makes debt service payments on one bond issuance, the 2011 Series A
Utility Revenue Refunding Bonds. This bond issuance was to refinance the $18 million principal
remaining on the Utility Revenue Bonds, 2002 Series A issued for the Gas and Water Utilities to
finance various improvements to the distribution systems . $9.4 million of this issuance was
secured by the net revenues of the Gas Utility. Table 14 shows debt service for this bond for the
financial forecast period. Debt service on this bond will continue through 2026.
Table 14: Gas Utility Debt Service
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
2011 Utility Revenue
Refunding Bonds, Series A
802 801 801 803 804 805 803 800 803 1
The 2011 bonds include two covenants stating that 1) the Gas Utility will maintain a debt
coverage ratio of 125% of debt service, and 2) that the City will maintain “Available Reserves”15
equal to five times the annual debt service. The current financial plan complies with these
covenants throughout the forecast period, as shown in Table 15 and
Table 16.
Table 15: Debt Service Coverage Ratio ($000)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Revenues 37,112 36,361 38,526 41,445 44,381 46,250 47,956 48,837 49,742 49,505
Expenses
(Excluding CIP and
Debt Service)
(26,079) (25,309) (25,572) (25,192) (25,765) (26,408) (27,104) (27,763) (28,489) (28,865)
Net Revenues 11,033 11,052 12,954 16,253 18,616 19,842 20,852 21,074 21,253 20,639
Debt Service 802 801 801 803 804 805 803 800 803 1
Coverage Ratio 1375% 1381% 1618% 2023% 2315% 2464% 2596% 2633% 2648% N/A
15 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities
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Table 16: Debt Service Minimum Reserves ($000)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Gas Utilitya 22,986 20,619 14,943 10,690 10,149 10,501 11,362 11,913 12,882 13,140
Debt Serviceb 802 801 801 803 804 805 803 800 803 1
Reserves Ratioc 29x 26x 19x 13x 13x 13x 14x 15x 16x N/A
a) CIP, Rate Stabilization, Operations, and Unassigned Reserves
b) Gas Utility’s share of the debt service on the 2011 bonds.
c) Calculated using only Gas Utility reserves. The actual reserves ratio for the 2011 bonds is calculated based on the
combined Electric, Gas, and Water Utility reserves and total debt service and is higher than shown here.
The Gas Utility’s reserves and net revenue are also pledged as security for the bond issuances
listed in Table 17, even though the Gas Utility is not responsible for the debt service payments.
The Gas Utility’s reserves or net revenues would only be called upon if the responsible utilities
are unable to make their debt service payments. Staff does not currently foresee this occurring.
Table 17: Other Issuances Secured by Gas Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Gas Utility’s:
Net Revenues Reserves
1995 Series A Utility
Revenue Bonds Storm Drain $680 Yes No
1999 Utility Revenue
Bonds, Series A
Wastewater Collection
Wastewater Treatment
Storm Drain
$1,207 No Yes
2009 Water Revenue
Bonds (Build America
Bonds)
Water $1,977* No Yes
*Net of Federal interest subsidy
SECTION 6 E : E QUITY T RANSFER
The City calculates the equity transfer from its Gas Utility based on a methodology adopted by
Council in 2009 that has remained unchanged since.16 Each year it is calculated according to the
2009 Council-adopted methodology, and does not require additional Council action.
SECTION 6 F : REVENUE S
The Gas Fund receives most of its revenues from sales of gas, but about 5% comes from other
sources. The largest of these comes from service connection and capacity fees, followed closely
by sales of allowances related to California’s cap-and-trade program. Another revenue item
related to the cap-and-trade program is collected in customers’ bills. While the State provides
CPAU with a certain number of free allowances each year, the Gas Utility is required to sell a
portion of those in accordance with the regulations. In order to have enough allowances to cover
16 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed changes
to equity transfer methodology.
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customers’ natural gas emissions, CPAU must buy allowances at market, and subsequently passes
through the cost of those allowances to customers. The regulations do not allow the revenue
derived from the sale of the free allowances to offset allowance purchases, thus the pass-through
rate component.
This financial plan bases sales revenue projections on the load forecast in Section 5A: Load
Forecast. Except where stated otherwise, these load forecasts are based on normal weather.
Weather can vary substantially, however, and this can affect revenues substantially. Also,
changes in customer behavior, as well as changes to more efficient gas appliances, or switching
to electric appliances, will modify these forecasts. Staff continually evaluate forecasts to see
when new trends emerge.
SECTION 6 G : COMMUNICATIONS PLAN
The FY 2019 communications strategy covers four primary areas: operations, infrastructure,
safety, efficiency, renewables and rates. Since moving to market pricing for commodity rates, the
City’s website posts changes to the commodity rates monthly. The City promotes gas use
efficiency incentives year-round, but most heavily during winter months to impact heating
activities. Promotional methods include community outreach events, print ads in local
publications, utility bill inserts, messaging on the bills and envelopes, website pages, email blasts,
videos for the web and use of social media.
To keep customers apprised of the status and accomplishments of capital improvement projects,
the City maintains a network of project web pages. Print and digital ads, social media and email
blasts drive traffic to the website. CPAU emphasizes safety topics year-round. CPAU is engaging
in several campaigns and programs in FY 2019 to promote gas utility efficiency and awareness of
the City’s carbon neutral natural gas utility. Programs such as the Home Efficiency Genie and
commercial energy efficiency programs help residents and businesses better understand energy
usage, activities and/or upgrades they can implement to improve efficiency and reduce utility
costs. CPAU will be launching an upgraded version of its online utility account services portal
(www.cityofpaloalto.org/myutilitiesaccount) this year, which can provide customers with direct
access and more information about utility account and consumption data.
Stepping up efforts to promote gas safety education, staff is focusing outreach among
stakeholders to increase awareness of the need to call USA (811) before digging for anyone who
may excavate in and around Palo Alto, such as plumbers and contractors. Staff is also focusing
outreach on the importance of contacting CPAU to check for potential sewer and gas line cross -
bores prior to clearing a sewer line. Additional outreach messaging includes keeping fats, oils and
greases out of drains, and ensuring clear access to meters. CPAU has developed a number of
safety outreach materials to distribute to customers at community outreach events, emergency
preparedness fairs, school and business meetings. The use of materials featuring photos of some
unusual ways people obstruct access to their meters, including using them as bike racks and
building storage sheds around them, highlights meter access awareness.
CPAU will continue to promote safety, infrastructure, operations, efficiency and rate adjustment
messages through a variety of marketing and media channels. Every year, CPAU publishes an
updated gas safety awareness brochure and mails it to all customers in Palo Alto, as well as to
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plumbers, contractors and excavators that may work in and around the area. Staff talk with
business customers at special facilities meetings, attend neighborhood safety and emergency
preparedness fairs and offer presentations to school and community groups. While print
materials and website pages still feature prominently, CPAU is increasing emphasis on outreach
through email newsletters, direct mail, newspaper inserts, social media and online videos. The
Gas Safety Public Awareness Plan contains saved copies of all outreach materials and logs of
activities; the Department of Transportation reviews this Plan at least once per year.
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APPENDICES
Appendix A: Gas Financial Forecast Detail
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
Appendix C: Gas Utility Reserves Management Practices
Appendix D: Description of Gas Utility Cost Categories
Appendix E: Gas Utility Communications Samples
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APPENDIX A : GAS FINANCIAL FORECA ST D ETAIL
($'000)($'000)
Actual Actual Actual
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
1 RATE CHANGE (%)*12%0%0%0%8%0%4%8%7%8%4%4%1%1%0%1%
2 SALES IN THOUSAND THERMS 28,901 28,117 28,881 26,719 27,829 27,434 27,289 26,752 26,847 26,547 26,245 25,939 25,726 25,507 25,095 25,071
3
4 Utilities Retail Sales 33,759 34,843 29,515 28,065 34,110 34,012 33,096 34,849 37,506 40,126 41,690 43,082 43,663 44,218 43,971 44,693
5 Service Connection & Capacity Fees 731 654 748 961 940 1,048 1,079 1,111 1,145 1,179 1,179 1,179 1,179 1,179 1,179 1,179
6 Other Revenues & Transfers In 830 313 414 2,346 694 1,508 1,818 2,261 2,599 2,895 3,185 3,467 3,740 4,074 4,079 4,205
7 Interest plus Gain or Loss on Investment (239)706 450 730 13 545 368 304 196 181 196 228 255 272 276 284
8 Total Sources of Funds 35,081 36,517 31,127 32,102 35,758 37,112 36,361 38,526 41,445 44,381 46,250 47,956 48,837 49,742 49,505 50,361
9
10 Purchases of Utilities:
11 Supply Commodity 12,461 12,992 9,537 6,648 9,720 9,998 8,587 8,226 8,205 8,200 8,268 8,429 8,569 8,708 8,855 9,001
12 Supply Transportation 994 1,333 982 (1,051)2,843 3,331 3,507 3,473 3,482 3,490 3,497 3,504 3,510 3,515 3,520 3,524
13 Total Purchases 13,455 14,325 10,519 5,597 12,563 13,329 12,094 11,699 11,687 11,690 11,765 11,933 12,079 12,223 12,375 12,525
14
15 Administration (CIP + Operating)4,273 3,988 4,007 3,337 2,450 2,519 2,577 2,640 2,707 2,775 2,845 2,906 2,968 3,051 3,106 3,178
16 Customer Service 1,358 1,338 1,195 1,097 1,581 1,643 1,700 1,781 1,858 1,925 1,992 2,051 2,107 2,155 2,184 2,237
17 Demand Side Management 630 438 632 566 855 879 900 922 945 969 993 1,015 1,036 1,065 1,084 1,110
18 Engineering (Operating)340 352 369 426 355 367 377 390 404 416 428 439 450 461 469 480
19 Operations and Maintenance 4,940 4,119 4,403 4,153 4,321 5,482 5,651 5,871 5,087 5,261 5,433 5,586 5,732 5,868 5,953 6,094
20 Resource Management 506 516 556 3,002 566 1,393 1,530 1,777 1,999 2,210 2,420 2,626 2,830 3,093 3,107 3,176
21 Debt Service Payments 296 805 804 249 227 802 801 801 803 804 805 803 800 803 1 1
22 Rent 219 419 431 443 455 467 480 492 505 519 532 546 561 574 587 601
23 Transfers to General Fund 5,971 5,811 5,730 6,194 6,594 7,035 6,888 7,069 7,069 7,972 8,214 8,629 9,072 9,547 9,539 9,538
24 Other Transfers Out 207 606 151 303 510 523 533 543 554 566 579 590 601 617 628 642
25 Capital Improvement Programs 7,620 1,026 1,832 6,889 2,214 7,804 5,197 10,217 12,080 9,815 9,892 9,970 10,050 10,131 10,214 10,299
26 Total Uses of Funds 39,814 33,743 30,629 32,256 32,690 42,243 38,728 44,202 45,698 44,922 45,898 47,095 48,286 49,587 49,248 49,880
27
28 Into/ (Out of) Reserves (4,733)2,773 498 (154)3,067 (5,131)(2,367)(5,676)(4,253)(541)352 861 551 155 257 481
29
30 Reappropriations + Commitments 19,363 11,305 6,491 6,255 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209
31 Plant Replacement 1,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
32 CIP Reserve 0 0 1,591 3,820 3,820 3,820 3,820 3,820 0 0 0 0 0 0 0 0
33 Rate Stabilization 11,318 15,981 7,215 6,018 6,539 6,411 4,291 0 0 0 0 0 0 0 0 0
34 Operations Reserve 0 0 10,847 10,296 13,549 8,547 8,300 6,915 6,482 5,941 6,293 7,153 7,705 8,673 8,930 9,411
35 Unassigned 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 1
36 Total Reserves 31,681 27,286 26,144 26,389 28,117 22,986 20,619 14,943 10,690 10,149 10,501 11,362 11,913 12,882 13,140 13,621
37 (1,142)245 1,728 (5,131)(2,367)(5,676)(4,253)(541)352 861 551 968 258 481
38 Short Term Risk Assessment Value 1,226 3,753 3,516 3,928 3,830 4,612 5,214 5,400 5,642 5,843 5,919 5,991 5,935 6,034
39
40 Operations Reserve Guidelines
41 Min (60 Days Commodity + O&M) 5,620 5,000 5,690 5,698 5,533 5,576 5,488 5,706 5,828 5,986 6,142 6,308 6,242 6,328
42 Target (90 Days Commodity + O&M) 8,429 7,500 8,535 8,547 8,300 8,364 8,232 8,560 8,742 8,978 9,213 9,462 9,362 9,492
43 Max (120 Days Commodity + O&M) 11,239 10,000 11,380 11,396 11,067 11,152 10,976 11,413 11,656 11,971 12,284 12,616 12,483 12,656
44
City of Palo Alto
Gas Utility
Fiscal Year
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APPENDIX B : GAS UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
ONE TIME PROJECTS
GS-15001 Security at Receiving Stations 64,700 64,700 - (1,101) 128,299 41,534 - - - - -
Unk AMI Project 180,000 530,000 2,320,000 - -
GS-18000 Gas ABS/Tenite Replacement - 1,500,000 - - - -
Subtotal, One-time Projects 64,700 64,700 - (1,101) 128,299 41,534 1,680,000 530,000 2,320,000 - -
GAS MAIN REPLACEMENT (GMR) PROGRAM
GS-11000 GMR - Project 21 100,000 100,000 - - 200,000 - - - - - -
GS-12001 GMR - Project 22 (150,372) 3,104,410 6,722,029 (224,576) 9,451,491 310,563 600,000
GS-13001 GMR - Project 23 337,000 700,000 - - 1,037,000 - - 6,500,000 - - -
GS-14003 GMR - Project 24 - - - - - - - 650,000 6,500,000 - -
GS-15000 GMR - Project 25 - - - - - - - - 650,000 6,500,000 -
GS-16000 GMR - Project 26 - - - - - - - - - 650,000 6,500,000
GS-20000 GMR - Project 27 - - - - - - - - - - 650,000
GS-20001 GMR - Project 28 - - - - - - - - - - -
Subtotal, Gas Main Replacement Program 286,628 3,904,410 6,722,029 (224,576) 10,688,491 310,563 600,000 7,150,000 7,150,000 7,150,000 7,150,000
TOOLS AND EQUIPMENT
GS-13002 General Shop Equipment/Tools - 50,000 - - 50,000 - 350,000 100,000 100,000 100,000 100,000
GS-14004 Gas Distribution System Model 19,574 19,574 - (4,660) 34,488 14,914 20,000 20,000 20,000
Subtotal, Tools and Equipment 19,574 69,574 - (4,660) 84,488 14,914 370,000 120,000 120,000 100,000 100,000
ONGOING PROJECTS
GS-11002 Gas System Improvements 75,624 555,672 - (114,215) 517,081 37,979 246,036 253,417 261,020 268,851 276,916
GS-03009 System Ext. - Unreimbursed - 204,455 - (19,127) 185,328 - 421,180 433,816 446,830 460,234 474,042
GS-80019 Gas Meters and Regulators 126,772 492,453 - (30,676) 588,549 96,096 376,652 387,952 399,591 411,579 423,926
Subtotal, Ongoing Projects 202,396 1,252,580 - (164,018) 1,290,958 134,075 1,043,868 1,075,185 1,107,441 1,140,664 1,174,884
CUSTOMER CONNECTIONS (FEE FUNDED)
GS-80017 Gas System Extensions 74,468 1,339,823 - (417,703) 996,588 98,562 1,303,315 1,342,415 1,382,688 1,424,169 1,466,894
Subtotal, Customer Connections 74,468 1,339,823 - (417,703) 996,588 98,562 1,303,315 1,342,415 1,382,688 1,424,169 1,466,894
GRAND TOTAL 647,766 6,631,087 6,722,029 (812,058) 13,188,824 599,648 4,997,183 10,217,600 12,080,129 9,814,833 9,891,778
Funding Sources
Connection Fees 1,017,000 - 1,078,935 1,111,303 1,144,642 1,178,981 266,894
Utility Rates 5,614,087 6,722,029 3,918,248 9,106,297 10,935,487 8,635,852 9,624,884
CIP-RELATED RESERVES DETAIL
6/30/2017
(Actual)
6/30/2018
(Unaudited)
Reappropriations 298,178 12,589,176
Commitments 349,588 599,648
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APPENDIX C : GAS UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Gas Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015
to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets
as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Gas Utility’s Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
Section 3. Distribution Fund Reserves
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Gas Utility’s Capital
Improvement Program (CIP), as described in Section 6 (CIP Reserve)
d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 8 (Operations Reserve)
f) Any funds not included in the other reserves will be considered Unassigned Reserves and
shall be returned to ratepayers or assigned a specific purpose as described in Section 9
(Unassigned Reserves)
Section 4. Reserve for Commitments
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Commitments will be set to an amount equal to the total remaining spending authority for
all contracts in force for the Wastewater Collection Utility at that time.
Section 5. Reserve for Reappropriations
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Reappropriations will be set to an amount equal to the amount of all remaining capital and
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non-capital budgets, if any, that will be re-appropriated to the following fiscal year for each
fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels are
calculated for each fiscal year of the Financial Planning Period bas ed on the levels of CIP
expense budgeted for that year.
Minimum Level 12 months of budgeted CIP expense
Maximum Level 24 months of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve for
Commitments as a result of a change in contractual commitments related to CIP projects.
Any other additions to or withdrawals from the CIP reserve require Council action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP Reserve
for the purpose of determining compliance with the CIP Reserve minimum guideline
level.
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve reaching
its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is
below its minimum level at the end of FY 2017, staff must present a plan by June 30,
2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff
may present, and the Council may adopt, an alternative plan that takes longer than
one year to replenish the reserve, or that does so in a shorter period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds may
be added to this reserve. If there are funds in this reserve in excess of the maximum level
staff must propose to transfer these funds to another reserve or return them to
ratepayers in the next Financial Plan. Staff may also seek Council approval to hold funds
in this reserve in excess of the maximum level, if they are held for a specific future purpose
related to the CIP.
Section 7. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and held
to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate
Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization
Reserve at the end of any fiscal year, any subsequent Gas Utility Financial Plan must result in
the withdrawal of all funds from this Reserve by the end of the F inancial Planning Period.
Section 8. Operations Reserve
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The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves
described in Section 4-Section 7 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for that
year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months of
the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015 . In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Gas Utility’s Fund Balance
shall be automatically included in the Unassigned Reserve described in Section 9, below.
Section 9. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas Utility’s
Fund Balance will be held in the Unassigned Reserve. If there are any funds in the Unassigned
Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council
must include a plan to assign them to a specific purpos e or return them to the Gas Utility
ratepayers by the end of the first fiscal year of the next Financial Planning Period. For
example, if there were funds in the Unassigned Reserves at the end of FY 2015, and the next
Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a plan
to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff may
present an alternative plan that retains these funds or returns them over a longer period of
time.
Section 10. Intra-Utility Transfers Between Supply and Distribution Funds
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The Gas Utility records costs in two separate funds: the Gas Supply Fund and the Gas
Distribution Fund. At the end of each fiscal year staff is authorized to transfer an amount
equal to the difference between Gas Supply Fund costs and Gas Supply Fund Revenues from
the Gas Distribution Fund Operations Reserve to the Gas Supply Fund, or vice versa . Such
transfers shall be included in the ordinance closing the budget for the fiscal year.
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APPENDIX D : DESCRIP TION OF GAS UTILITY COST CATEGORIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Gas Utility’s share of the call center, meter reading,
collections, and billing support functions. Billing support encompasses staff time associated with
bill investigations and quality control on certain aspects of the billing process. It does not include
maintenance of the billing system itself, which is incl uded in Administration. This category also
includes CPAU’s key account representatives, who work with large commercial customers who
have more complex requirements for their gas services.
Resource Management: This category includes gas procurement, contract management, rate
setting, and tracking of legislation and regulation related to the gas industry.
Operations and Maintenance: This category includes the costs of a variety of distribution system
maintenance activities, including:
surveying the gas system (50% of the system each year) and repairing any leaks found;
investigating reports of damaged mains or services and perform emergency repairs;
building and replacing gas services for new or redeveloped buildings; and
testing and replacing meters to ensure accurate sales metering.
This category also includes a variety of functions the utility shares with other City utilities,
including:
the Field Services team (which does field research of various customer service issu es);
the Cathodic Protection team (which monitors and maintains the systems that prevent
corrosion in metal pipes and reservoirs); and
the General Services team (which manages and maintains equipment, paves and restores
streets after gas, water, or sewer main replacements, and provides welding services,
including certified gas line welding services)
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services and Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering gas efficiency programs and the
direct cost of rebates paid.
Engineering (Operating): The Gas Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX E : GAS UTILITY COMMUNIC ATIONS SAMPLES
Attachment C
* NOT YET APPROVED *
6055006
Resolution No. _________
Resolution of the Council of the City of Palo Alto Increasing Gas
Rates by Amending Rate Schedules G-1 (Residential Gas Service),
G-2 (Residential Master-Metered and Commercial Gas Service), G-3
(Large Commercial Gas Service), and G-10 (Compressed Natural Gas
Service Service)
R E C I T A L S
A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
B. On ____, 2018, the City Council heard and approved the proposed rate increase
at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-1 (Residential Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-1, as amended, shall become effective July 1, 2018.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-2 (Residential Master-Metered and Commercial Gas Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule G-2, as amended, shall
become effective July 1, 2018.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-3 (Large Commercial Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-3, as amended, shall become effective July 1, 2018.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-10 (Compressed Natural Gas Service Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule G-10, as amended, shall become effective
July 1, 2018.
SECTION 5. The City Council finds as follows:
a. Revenues derived from the gas rates approved by this resolution do not exceed the
funds required to provide gas service.
b. Revenues derived from the gas rates approved by this resolution shall not be used
for any purpose other than providing gas service, and the purposes set forth in
Article VII, Section 2, of the Charter of the City of Palo Alto.
Attachment C
* NOT YET APPROVED *
6055006
SECTION 6. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
SECTION 7. The Council finds that the adoption of this resolution changing gas rates
to meet operating expenses, purchase supplies and materials, meet financial reserve needs and
obtain funds for capital improvements necessary to maintain service is not subject to the
California Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec.
21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After reviewing
the staff report and all attachments presented to Council, the Council incorporates these
documents herein and finds that sufficient evidence has been presented setting forth with
specificity the basis for this claim of CEQA exemption.
Attachment C
* NOT YET APPROVED *
6055006
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-1 Effective 97-1-20187
dated 119-1-20176 Sheet No G-1-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from City of Palo Alto
Utilities:
1. Separately-metered single-family residential Customers.
2.Separately-metered multi-family residential Customers in multi-family residential facilities.
B. TERRITORY:
This schedule applies anywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ....................................................................................................$10.9432
Tier 1 Rates: Per Therm
Supply Charges:
1.Commodity (Monthly Market Based) .......................................... $0.10-$2.00
2.Cap and Trade Compliance Charge ..................................................$0.00-$0.25
3. Transportation Charge........................................................................$0.00-$0.15
4.Carbon Offset Charge ........................................................................$0.00-$0.10
Distribution Charge: .............................................................................................$0.42393933
Tier 2 Rates: (All usage over 100% of Tier 1)
Supply Charges:
1.Commodity (Monthly Market Based) .......................................... $0.10-2.00
2.Cap and Trade Compliance Charge ...................................................$0.00-$0.25
3. Transportation Charge........................................................................$0.00-$0.15
4.Carbon Offset Charge ........................................................................$0.00-$0.10
Distribution Charge: .............................................................................................$0.99489319
D. SPECIAL NOTES:
1. Calculation of Cost Components
ATTACHMENT D
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-2 Effective 97-1-20187
dated 119-1-20176 Sheet No G-1-2
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance
with the state’s Cap and Trade Program, including the cost of acquiring compliance
instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap
and Trade Compliance Charge will change in response to changing market conditions,
retail sales volumes and the quantity of allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse
gases produced in the burning of natural gas. The Carbon Offset Charge will change in
response to changing market conditions, changing sales volumes and the quantity of
offsets purchased within the Council-approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges
will fall within the minimum/maximum ranges set forth in Section C.
2. Seasonal Rate Changes:
The Summer period is effective April 1 to October 31 and the Winter period is effective from
November 1 to March 31. When the billing period includes use in both the Summer and the
Winter periods, the usage will be prorated based on the number of days in each seasonal
period, and the charges based on the applicable rates for each period. For further discussion
of bill calculation and proration, refer to Rule and Regulation 11.
3. Calculation of Usage Tiers
Tier 1 natural gas usage shall be calculated and billed based upon a level of 0.667 therms per
day during the Summer period and 2.0 therms per day during the Winter period, rounded to
the nearest whole therm, based on meter reading days of service. As an example, for a 30
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-3 Effective 97-1-20187
dated 119-1-20176 Sheet No G-1-3
day bill, the Tier 1 level would be 20 therms during the Summer period and 60 therms during
the Winter period months. For further discussion of bill calculation and proration, refer to
Rule and Regulation 11.
{End}
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-1 Effective 97-1-20187
dated 119-1-20176 Sheet No G-2-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use less than 250,000 therms per year at one site.
2. Master-metered residential Customers in multi-family residential facilities.
B. TERRITORY:
This schedule applies anywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ...............................................................................................$82.9278.23
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................... $0.10-$2.00
2. Cap and Trade Compliance Charges ................................................. $0.00-0.25
3. Transportation Charge........................................................................$0.00-$0.15
4. Carbon Offset Charge ........................................................................$0.00-$0.10
Distribution Charge: ........................................................................................................$0.61835767
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with
the state’s Cap and Trade Program, including the cost of acquiring compliance instruments
sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade
Compliance Charge will change in response to changing market conditions, retail sales
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-2 Effective 97-1-20187
dated 119-1-20176 Sheet No G-2-2
volumes and the quantity of allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced in the burning of natural gas. The Carbon Offset Charge will change in response to
changing market conditions, changing sales volumes and the quantity of offsets purchased
within the Council-approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges will
fall within the minimum/maximum ranges set forth in Section C.
{End}
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-1 Effective 97-1-20187
dated 119-1-20176 Sheet No G-3-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from the City of Palo
Alto Utilities:
1. Commercial Customers who use at least 250,000 therms per year at one site.
2. Customers at City-owned generation facilities.
B. TERRITORY:
This schedule applies anywhere the City of Palo Alto provides Nnatural Ggas Sservice.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: $400.08377.43
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................................... $0.10-$2.00
2. Cap and Trade Compliance Charges ...................................................... $0.00-0.25
3. Transportation Charge .......................................................................... $0.00-$0.15
4. Carbon Offset Charge ........................................................................... $0.00-$0.10
Distribution Charge: .....................................................................................................$0.60985687
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance
with the state’s Cap and Trade Program, including the cost of acquiring compliance
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-2 Effective 97-1-20187
dated 119-1-20176 Sheet No G-3-2
instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap
and Trade Compliance Charge will change in response to changing market conditions,
retail sales volumes and the quantity of allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse
gases produced in the burning of natural gas. The Carbon Offset Charge will change in
response to changing market conditions, changing sales volumes and the quantity of
offsets purchased within the Council-approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges
will fall within the minimum/maximum ranges set forth in Section C.
2. Request for Service
A qualifying Customer may request service under this schedule for more than one
account or meter if the accounts are located on one site. A site consists of one or more
contiguous parcels of land with no intervening public right-of- ways (e.g. streets).
3. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable City of Palo
Alto full-service rate schedule.
{End}
COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-1 Effective 97-1-20187
dated 119-1-20176 Sheet No.G-10-1
A. APPLICABILITY:
This schedule applies to the sale of natural gas to the City-owned compressed natural gas (CNG) fueling
station at the Municipal Service Center in Palo Alto.
B. TERRITORY:
Applies to the City’s CNG fueling station location located at the Municipal Service Center in City of
Palo Alto.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ...............................................................................................$56.1152.93
Per Therm
Supply Charges:
Commodity (Monthly Market Based) ................................................................ $0.10-$2.00
Cap and Trade Compliance Charges .............................................................. $0.00 to $0.25
Transportation Charge........................................................................................ $0.00-$0.15
Carbon Offset Charge ........................................................................................ $0.00-$0.10
Distribution Charge ....................................................................................................$0.01000.0093
D. SPECIAL CONDITIONS
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for
any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount
may be broken down into appropriate components as calculated under Section C.
The Commodity charge is based on the monthly natural gas Bidweek Price Index for delivery at
PG&E Citygate, accounting for delivery losses to the Customer’s Meter.
The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the
state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to
cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will
COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-2 Effective 97-1-20187
dated 119-1-20176 Sheet No.G-10-2
change in response to changing market conditions, retail sales volumes and the quantity of
allowances required.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases produced
in the burning of natural gas. The Carbon Offset Charge will change in response to changing market
conditions, changing sales volumes and the quantity of offsets purchased within the Council-
approved per therm cap.
The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for
delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges will fall
within the minimum/maximum range set forth in Section C.
{End}
1
3
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 12, 2018
SUBJECT: Local Solar Plan Progress Update and Next Steps
RECOMMENDATION
This is an informational report to provide an update on the progress to date on the Local Solar
Plan and to seek input from the Utilities Advisory Commission (UAC) on next steps. UAC
feedback will help guide staff’s level of effort in promoting Council-directed program initiatives
and to reach the goal of meeting 4% of the City’s electricity needs with local solar energy by
2023. No action is requested.
EXECUTIVE SUMMARY
In 2014, City Council adopted the Local Solar Plan (LSP) (Staff Report 4608, Resolution 9402)
and set a goal of meeting 4% of Palo Alto’s electrical energy needs from local solar by 2023, up
from 0.7% in 2013. The plan recognizes the various benefits of local generation in reducing
transmission and distribution losses and the potential to provide grid reliability support for the
community. The LSP unified the City’s approach towards local solar by integrating existing
programs and incentives (including PV Partners rebates, Net Energy Metering (NEM), and Clean
Local Energy Accessible Now (CLEAN) feed-in-tariff) and sought to do so in a cost-effective
manner. Further, when Council approved the LSP, it further directed staff to evaluate for
consideration three program initiatives to accelerate solar deployment in Palo Alto in the
following order of priority 1) a community solar program; 2) a solar donation program; and 3) a
solar group-buy.
Since the adoption of the plan, the City has made considerable progress towards redirecting
staff effort related to solar from state mandated programs to cost-effective local programs.
Specifically, resources were shifted from managing a state-mandated rebate program, PV
Partners, and the original Net Energy Metering program (NEM 1) to more cost-effective
programs such as the NEM Successor Program (NEM 2) and a solar group-buy program.
Through the PV Partners rebate program, $13 million in rebate funds were fully reserved over a
10-year period as required by state law (SB1 of 2007), and no additional funds have been added
to the program. NEM 1, which compensates customers for exported electricity at full retail
rates, closed to new customers in December 2017. Beginning in January 2018 all new solar
customers are part of the NEM 2 program, and these new customers will be compensated for
electricity they export at a rate based on the utility’s avoided cost. Staff has made progress in
2
attracting six CLEAN projects that will meet 0.5% of the City’s electricity needs. To support
residents interested in installing rooftop solar, in 2017 the City participated for the third year in
a row in the regional solar group-buy program Bay Area SunShares, which offers access to
vetted solar contractors and discounted solar prices for rooftop solar installation. The
SunShares program acknowledged the City as a top outreach partner, as amongst all outreach
partners the City had the highest number of contracts signed and kilowatts installed through
the program in two of its three years of participation.
Over the past five years, the number of solar customers in Palo Alto has increased from 500 to
over 1000, and by end of the calendar year (CY) 2018, approximately 2.2% of Palo Alto’s energy
needs will be met by local resources. However, it is unclear whether the City can reach the goal
of meeting 4% of its electrical energy demand by 2023 with current programs and incentives
and given the prevailing economics of solar in Palo Alto. Meeting the LSP goal will likely require
additional resources to promote programs like community solar that have been more
challenging to get started. Staff is seeking the following feedback from the UAC, as well as any
other comments it has on the LSP and local solar generally:
• Any perspective the UAC has on the importance of local solar to community members and
the value of meeting the 4% by 2023 goal.
• Any additional information that could be presented at future meetings to assist the UAC
with solar-related policy questions.
Staff is currently operating under Council direction (via the LSP) that solar should be a
standalone program priority. This priority was set based on the perception that the community
wanted the City to prioritize continued expansion of local solar. That question was asked of the
community in the 2017 National Citizen Survey (Attachment D),1 with 58% rating “Increasing
local solar generation capacity within city boundaries” as “essential” or “very important.”
However, with limited resources, staff has been considering whether to recommend that solar
be evaluated in the context of other Distributed Energy Resource (DER) 2 programs instead of as
a standalone priority. Solar programs could be incorporated into a broader DER strategy (the
DER Plan), weighing solar programs against other possible DER programs to create the program
portfolio that most effectively contributes to City priorities like customer/community
satisfaction, efficient use of the electric grid, resiliency, carbon reduction, and efficient use of
energy. That portfolio may or may not include programs like community solar, depending on
what other programs are available. Staff will seek additional input from the community on local
solar programs as part of an upcoming survey related to DERs. This input could be used to
enable staff to begin prioritizing solar programs against other DER programs. Staff would like
1 For the full survey, visit the City of Palo Alto City Auditor’s website:
https://www.cityofpaloalto.org/gov/depts/aud/reports/accomplishments/default.asp
2 DERs are electrical energy resources connected to the City of Palo Alto Utilities (CPAU) electric distribution grid
that can significantly change the location, timing, and magnitude of the CPAU’s electric loads. The California Public
Utilities Code 769 defines “distributed resources” as distributed renewable generation resources such as solar
photovoltaics (PV), energy efficiency (EE), energy storage (ES), electric vehicles (EV), and demand response (DR)
technologies.
3
the UAC’s feedback on this possible approach. Based on UAC’s input, staff expects to come back
with an updated LSP and/or a new DER Plan for approval by this summer.
BACKGROUND
The City has a long history of supporting local solar and has offered various programs over the
years to facilitate customer adoption of local solar, most specifically rooftop photovoltaics (PV).
An overview of these programs is listed in Attachment A. In 2014, the City Council adopted the
LSP which unified the City’s approach toward local solar, set an overarching goal of meeting 4%
of the City’s total electrical energy needs from local solar by 2023, and laid out a set of diverse
strategies to meet the goal. Since 2015, considerable effort was expended on revising state-
mandated programs (PV Partners rebates, NEM); implementing cost-effective local programs;
and streamlining Palo Alto’s permitting and integration process. The last update on staff’s
efforts towards implementing the LSP was provided to the UAC in December 2015 (Staff Report
6213).
At the June 2017 UAC meeting, staff presented a preliminary outline of a community solar
program. 3 The UAC expressed concerns about the benefits of pursuing community solar, or any
local solar, given the City’s carbon neutral portfolio and the high cost of local solar, especially
when compared to solar located remotely, as demonstrated in recent solar power purchase
agreements executed by the City. As such, the UAC directed staff to return with a discussion
related to customer interest, cost-effectiveness, required staff effort, and the merits of
implementing local solar and thus achieving the Council-approved LSP goals and program
initiatives.
The LSP cites a number of benefits of local solar. The value of some of these benefits (avoided
renewable purchases, transmission and distribution) are quantified in the City’s CLEAN Program
and net surplus energy buyback rates at roughly nine cents per kWh:
• the fact that it is a carbon-free resource, reducing the amount of renewable energy the City
must buy for the community,
• that it avoids the cost of losses from transmitting and distributing electricity from distant
power facilities, reducing the need to build expensive transmission lines throughout the
state, and
• improving grid reliability (for example, with smart inverters or when paired with storage).
The LSP focus is on transitioning away from programs and rates which provide incentives to
customers installing solar and instead towards development of proper incentives, tools and
programs to facilitate solar in the future along with an emphasis on reducing “soft” costs.
DISCUSSION
This report provides an update on solar installed in Palo Alto through the PV Partners rebate
program, the original NEM program, and the CLEAN program, as well as the status of program
3 Refer to June 2017 UAC report: Staff Recommendation that the Utilities Advisory Commission Recommend that
the City Council Approve Community Solar Preliminary Program Design Elements
4
initiatives identified under the LSP, including: 1) the solar group-buy program, 2) the
community solar program, and 3) the solar donation program. Attachment B summarizes the
progress made on the various LSP strategies.
• PV Partners Rebate Program Update
As of December 31, 2017, 7.94 MW of solar PV has been installed on 740 customer sites. All
residential funds were reserved in August 2014, while commercial funds were reserved in April
2016. No new applications are being accepted into the program at this time, and installations
are expected to be completed by May 2018.
• Net Energy Metering Program Update
Palo Alto transitioned from its original NEM program (NEM 1) to the NEM Successor program
(NEM 2) on December 31, 2017.4 Currently, 9.5 MW of PV capacity has been installed under
NEM 1 by over 1000 customers, and an additional 2.4 MW of capacity is under reservation by
about 100 customers. In the last few months of the program the number of customers applying
for NEM 1 reservations increased relative to previous months. This included residential
customers signing up for NEM 1 reservations as part of the annual solar group-buy (SunShares)
outreach in August through December 2017 and a few large commercial customers submitting
applications for NEM 1 reservations.5
Starting January 2018, new solar customers in Palo Alto are being connected under the NEM
Successor Program (NEM 2) and will be compensated for electricity they export to the grid at an
Export Electricity Compensation (EEC-1) rate 6. This change in the rate at which customers are
compensated for electricity they export lowers the financial pay-back for customers installing
new PV systems and thus could dampen the growth of customer solar adoption. Palo Alto has
also started collecting interconnection fees for NEM 2 customers; according to State law, no fee
could be charged under the original NEM program.
The transition to NEM 2 is a critical milestone for Palo Alto solar programs to move away from a
state-mandated program to city-directed, cost-effective programs. This transition is aligned
with the LSP strategy to develop proper price signals and rates to encourage solar installation
while ensuring that rates are cost-based and that they do not create an undue burden on non-
solar customers. Implementation of NEM 2 is currently underway and has required
4 California state law Senate Bill 656 required all electric utilities to offer Net Energy Metering (NEM) to eligible customers on a
first-come, first-served basis up to a maximum cap based on the utility’s aggregate customer peak demand. NEM 1 billing
arrangement provides a bill credit to customers with eligible solar or other generation technologies to receive a full retail rate
for the electricity generated by their system.
5 NEM 1 capacity reservations are above Staff’s estimate at the time of latest NEM 1 cap approval by the Council (Staff Report
8718). However, the resource impact is expected to remain similar as large commercial projects with reservations are going to
use most of the electricity generated on site, without exporting much electricity at the NEM 1 compensation rate.
6 Utility Rate Schedule E-EEC-1;This rate reflects avoided cost or value of customer-generated electricity in Palo Alto, including
compensation for the energy, avoided capacity, avoided transmission and ancillary service charges, avoided transmission and
distribution (T&D) losses, and renewable energy credits (RECs), or environmental attributes.
5
modifications of existing business systems and processes.7 Staff provided extensive outreach to
community members and solar vendors during the transition to minimize confusion about
program changes.
• CLEAN Program Update
Currently, the 3 MW of program capacity available at the $0.165 per kWh contract price is close
to full subscription with six local solar projects. Table 1 below lists these projects, their
corresponding capacity, and operating status. Four of these solar projects are located at
rooftops of public garages and are developed along with onsite electric vehicle (EV) chargers.8
There have been no applications for the non-solar renewable category of the program. This
program will remain available to new projects at published avoided costs ($0.088 to
$0.091/kWh)9 once 3 MW of capacity at the $0.165/kWh price is fully subscribed.
Table 1: Solar Projects under Palo Alto CLEAN program
Project Name Capacity (kW) Status
445 Bryant St. garage 251.5 Operating since July 2017
520 Webster St. garage 388.6 Operating since July 2017
475 Cambridge St. garage 392.1 Almost complete
275 Cambridge St. garage 327.8 Almost complete
UUCPA (505 E. Charleston) 227.4 Almost complete
HP Technologies 1,327.1 Under development
TOTAL 2914.5
Remaining capacity @ $0.165/kWh rate 85.5
• Solar Group-Buy Program Update
Palo Alto joined Bay Area cities, counties, and companies for the third consecutive year in 2017
as an outreach partner for the Bay Area SunShares solar group-buy program,10 a regional effort
administered by the non-profit organization Business Council on Climate Change (BC3). The
solar group-buy program (aka group-discount or SunShares) has proven to be a successful
means for providing clarity on market prices of rooftop solar systems, driving down costs by
aggregating purchasing and simplifying the process of solar adoption across the community.
Palo Alto was the top outreach partner, both in terms of the number of solar contracts signed
and kilowatts (kW) of solar capacity installed through the program both in 2015 and 2017. 11
Overall, over 500 residents have registered to receive program information in the past three
years with 88 residents signing contracts for 420 kW of the rooftop solar capacity.
7 These modifications include installing bidirectional meters, programming meter reading devices, training meter reading staff,
modifying the format of electric Utilities bills, and revising electric usage billing calculations, the City’s Interconnection
Agreement, and Utility Rules and Regulations.
8 Council approval of 25 year Lease Agreement with Komouna Energy for i). Construction and operation of solar systems under
CLEAN program and ii). Installation of city-owned EV chargers and infrastructure (Staff Report 6535)
9 Refer to Palo Alto CLEAN program webpage for additional information on contract terms and pricing
10 Refer to Bay Area Sun Shares program webpage
11 In 2015, 54 Palo Alto residents signed contracts for 236 kW of rooftop solar capacity. In 2017, 29 Palo Alto residents signed
contracts for a total of 157 kW of rooftop solar.
6
Given the success of the program, staff plans to continue participating in future regional group-
buy efforts. There has also been increasing interest to make such group-buy programs available
for other customer energy investment options such as electric vehicle chargers.
• Community Solar (in evaluation phase, not yet finalized)
Under the LSP, a community solar program was envisioned to enable home owners, renters or
businesses without good solar access to experience and derive the benefits from local solar
deployment, even if they are unable to install solar at their own premises. So far, this program
has proven to be difficult to get started. Staff initially attempted to seek a turnkey partner to
implement the program and issued a request for proposal (RFP) in July 2014. However, this
turnkey proposal did not materialize due to the City’s need for transparency being at odds with
the business model of the third-party vendor, and the RFP was terminated.12
Thereafter, Staff has evaluated other approaches to providing a community solar option,
including utilizing a municipal facility to host such projects. Staff shared a preliminary program
design proposal with the UAC in June 2017 and subsequently provided market research and
cost-effectiveness information.13 Preliminary market research showed considerable interest in
a community solar program from homeowners without good solar access (for example,
rooftops with tree shading). However, following UAC discussions the question remains as to
whether the City should prioritize offering new solar programs given other City priorities such
as facilitating electric vehicle adoption or heat pump based beneficial electrification programs,
as envisioned under the City’s Sustainability and Climate Action Plan.14
Staff is currently developing a DER Plan and conducting customer outreach to understand what
new DER technologies our customers are considering purchasing (e.g. EVs, home control
systems, rooftop solar, battery storage) and what services CPAU could provide to overcome
barriers to adoption of these technologies. The survey would also provide insights into the
relative importance customers place on a community solar program compared to other
customer programs. Staff plans to bring these findings to the UAC by summer 2018. In addition,
CPAU is initiating a discussion of resiliency in the context of the Utilities Strategic Plan.15 This
discussion could provide additional insights into the kind of resiliency the City should plan for
and the role that a community solar project paired with storage could play.
12 August 2015, Informational Report to Council: Community Solar Program Development Update and Redirection of Efforts
(Staff Report 5953)
13 Refer to June 2017 UAC discussion of community solar program design and September 2017 discussion of community solar
survey results. Cost-effectiveness analysis was shared with the UAC via a staff email in November 2017.
14 On December 11, 2017 City Council approved the 2018-2020 Sustainability Implementation Plan (SIP). The SIP
outlines proposed measures in four areas: energy, mobility, electric vehicles, and water.
15 Refer to February 2018 UAC discussion of 2018 Utilities Strategic Plan and CPAU’s Role in Community Resiliency
7
• Solar Donation Program (evaluated, unlikely to be undertaken)
Under the LSP, a Solar Donation program was envisioned to support building solar systems on
schools and other non-profit facilities. The projects could be funded by donations from
participants through monthly contributions (e.g., $5 to $10 per month) on their utility bills.
Staff analyzed the list of non-profit buildings in Palo Alto, including initial discussions with the
Palo Alto Unified School District (PAUSD), to gauge the potential for adding solar capacity
through a solar donation program. Finding suitable non-profits to participate in a solar donation
program remains a potential challenge. Most non-profits in Palo Alto are in rental buildings and
have less control over installing onsite solar. PAUSD opted to participate in the City’s NEM 1
program and will not be considering participation in a solar donation program. Moreover,
recent solar market research results indicate only modest interest from potential donors. Given
these considerations, staff is not considering offering a solar donation program proactively in
the near future, unless a compelling project comes about.
Status of Local Solar Installations
Figure 1 shows cumulative solar PV installations in Palo Alto through December 31, 2017 and
system reservations for 2018. In CY 2013, Palo Alto had about 0.7% of its electrical energy
needs met by local solar with 6 MW of solar capacity installed. Currently, 1.4% of the City’s
electricity needs are met by local solar with over 10 MW of solar capacity installed by 1000
customers. Moreover, a significant number of solar capacity reservations exist under the NEM 1
and CLEAN programs. By the end of CY 2018, the City could have 15 MW of installed local solar
capacity, meeting 2.2% of its electrical energy needs with local solar. This progress has been
achieved by realizing full participation in past programs (PV Partners rebate program),
continuing to implement ongoing programs (CLEAN, NEM, and group-buy), and facilitating
rooftop solar adoption by streamlining processes and providing trusted information.
8
Figure 1: Cumulative Solar PV Installed through Dec 31, 2017, and 2018 Reservations
Notes:
• These solar system capacities are reported in kW CEC-AC
• BTM represents Behind-the-Meter customer sited rooftop solar or parking lot solar canopies
Going forward, however, it is uncertain whether the City will achieve the LSP goal of meeting
4% of the City’s total electrical energy needs from local solar by 2023. Details of the 2030 local
solar forecast and progress towards 2023 goals are discussed in Attachment C.
NEXT STEPS
Staff will continue to expend a baseline effort to manage ongoing programs that support
existing solar customers and facilitate solar adoption by new customers. Staff is seeking UAC
input on revisions to the LSP goal and priorities for new solar program initiatives. Outlined
below are some possible alternatives to facilitate discussion at the meeting.
• Alternative 1: Continue following the direction provided by the Council-approved LSP.
Devote sufficient resources (additional resources if needed) to achieve the LSP goal of
having 4% of the City’s electrical energy supply come from local solar by 2023. This will
likely include promotion of new solar programs (like community solar) and increasing
solar program access to new customers.
• Alternative 2: Facilitate customer adoption of local solar at the current level· of effort
(facilitating local solar installations under the NEM Successor program, organizing solar
group-buy programs, and administering the CLEAN program}. Discontinue or revisit the
LSP goal for local solar penetration. Evaluate any new solar-related customer program
initiatives within the framework of the DER Plan.
Based on UAC's input, staff expects to come back with an updated LSP and/or a new DER Plan
for approval by this summer.
RESOURCE IMPACT
There is no change to budgets, planned expenditures or staff resources as a result of the Local
Solar Plan progress update. Administering of the ongoing solar program requires dedicated staff
resources. At present, approximately one and a half full-time equivalent (FTE} of staff time and
an additional $100,000 per year of expenses are incurred by CPAU to administer existing solar
programs and meet existing and future solar customers' needs.
POLICY IMPACT
The Local Solar Plan is consistent with Palo Alto's Mission of 'providing safe, reliable,
environmentally sustainable and cost-effective services.' The plan meets Palo Alto's statement
of strategic destination of ' ... ensuring a sustainable and resilient Palo Alto.' Local solar PV
systems, coupled with energy storage, could enable a more sustainable and resilient Palo Alto.
ENVIRONMENTAL IMPACT
The UAC's consideration of the Local Solar Plan update does not meet the California
Environmental Quality Act's (CEQA} definition of a "project" under California Public Resources
Code Sec. 21065, thus no environmental review is required.
ATTACHMENTS
A. Overview of Local Solar Programs in Palo Alto Since 1999
B. Local Solar Plan Implementation -Strategic Efforts Update
C. Local Solar PV Systems Forecast
D. FY 2017 City Auditor's Performance Report: National Citizens Survey, Question 13
PREPARED BY: SONIKA CHOUDHARY, Resource Planner 5:5:::-·
LISA BENATAR, Utilities Marketing Program Manager:;J.t.. f>
SHIVA SWAMINATHAN, Senior Resource Planner ~
REVIEWED BY: ~N ABENDSCHEIN, Assistant Director, Resource Managemen~
2-~, APPROVED BY: ...
EDSHIKADA
General Manager of Utilities
9
ATTACHMENT -A
1
Attachment – A
Overview of Palo Alto Local Solar Programs
Palo Alto has offered a number of local solar photovoltaics (PV) programs over the past two
decades. These programs have undergone changes over time to comply with state laws and to
meet Palo Alto customer needs. Figure A-1 summarizes the City of Palo Alto Utilities’ (CPAU) local
solar programs offered over time.
Figure A-1 Overview of Palo Alto Local Solar PV Programs Offered Since 1996
PV Partners
In 1999, the City launched its first solar PV system rebate program called PV Partners to
encourage residents and businesses to install solar PV systems. In 2006, California adopted SB1,
the “Million Solar Roofs” bill, which requires that all load serving entities such as CPAU provide
incentives in the form of rebates to meet the goal of installing 3,000 megawatts (MW) of solar
PV systems in California by 2017. The City’s proportionate share of the statewide goal is 6.5 MW
by 2017. To meet the SB1 requirements, CPAU set a budget of $13 million over ten years, with
proportions of the funding allocated across four customer classes: residential, small and medium
commercial, large commercial and non-profit/public sector. Table A-1 provides a summary of the
solar PV installations through the PV Partners program through December 2017.
Table A-1 PV Partners Program Summary
PV Partners Program Capacity (MW)
Installed Between
1999 and 2006
(Prior to SB1)
Installed
Under SB1 as
of 12/31/17
Pending Projects/
Reserved
Capacity
Unreserved
Capacity
Total PV
Partners
Program
Residential 0.62 1.92 0.01 - 2.55
Commercial 0.31 5.08 0.82 - 6.21
TOTAL 0.93 7.01 0.82 - 8.76
ATTACHMENT -A
2
As of December 31, 2017, 7.94 MW of solar PV has been installed1 on 740 customer sites. All
residential funds were reserved in August 2014, while commercial funds were reserved in April
2016. No new applications are being accepted into the program at this time, and installations are
expected to be completed by May 2018.
Net Energy Metering (NEM)
In 1996, California state law Senate Bill 656 required all electric utilities to offer Net Energy
Metering (NEM) to eligible customers on a first-come, first-served basis up to a maximum cap
based on the utility’s aggregate customer peak demand. The NEM billing arrangement provided
a bill credit to customers with eligible solar or other generation technologies to receive a full
retail rate for the electricity generated by their system.
In 2015, Palo Alto set its NEM 1 cap to 9.5 MW or 5% of the City’s 2006 peak electric demand
(Staff Report 6139). In 2016, the NEM 1 cap was modified to 10.8 MW or 5% of the City’s 2006
non-coincident peak along with the Council approval of the NEM transition policy and NEM
Successor Program (NEM 2) (Staff Report 7150, Staff Report 7346). The latest Council approval
updated the NEM cap to 10.8 MW or until December 31, 2017, whichever occurs later (Staff
Report 8716). Palo Alto reached its NEM Cap on December 31, 2017 with 9.5 MW installed and
2.4 MW reserved under NEM program.
Beginning in January 2018, new solar customers will be connected under the city-directed NEM
Successor Program (NEM 2), and they will be compensated for electricity they export at a rate
based on avoided cost. 2 This change in the rate lowers the financial payback for customers
installing new PV systems and thus could dampen the growth of customer solar adoption. Palo
Alto has also started collecting interconnection fees for NEM 2 customers to recover cost;
according to state law, no fee could be charged under the original NEM 1 program.
CLEAN
In 2012, the City launched the Palo Alto Clean Local Energy Access Now (CLEAN) program (Staff
Report 2548, Resolution 9235), a feed-in tariff program. Through Palo Alto CLEAN, building
owners may lease their rooftops to solar developers, or develop solar themselves, and sell the
energy and renewable attributes to the City under a standard Power Purchase Agreement (PPA).
This program has undergone several updates since the launch and has been available to non-
solar renewable technologies since 2015 (Staff Report 5428, Staff Report 7604, Staff Report
7943). The current CLEAN PPA price is $0.165 per kilowatt -hour (kWh) for a 15, 20- or 25- year
contract term for up to a maximum of 3 MW of solar PV capacity. After the 3 MW cap, the
contract price will drop to the published avoided costs ($0.088 to $0.091/kWh)3.
1 This total includes the 0.93 MW installed under PV Partners prior to SB -1.
2 This rate is 7.485 cents/kWh in 2018. Refer to Utility Rate Schedule E-EEC-1 for more details.
3 Refer to CPAU’s CLEAN webpage for contract pricing and terms
ATTACHMENT -A
3
Solar Group-Buy
The 2014 Local Solar Plan included the program initiative to offer a solar group-buy program for
Palo Alto residents. Since 2015, CPAU has participated for three consecutive years in the
regional group-buy programs.
o 2015 Peninsula SunShares: The Peninsula SunShares program was launched in May 2015.
This group-buy program was initiated by Foster City and included 12 other cities located
in San Mateo County. Vote Solar, the program administrator, facilitated the selection of
two qualified solar contractors. The program offered discounted PV installation prices
that were 25% lower than Palo Alto’s average residential, before-rebate price and 13%
lower than the after-rebate price.
o 2016 Bay Area SunShares: The Bay Area SunShares program was launched in August 2016.
This group-buy program was administered by the non-profit Business Council on Climate
Change (BC3) which facilitated the selection of three qualified solar contractors for
residential solar installations through a competitive selection process. For the 2016
program, two zero emission vehicles were available at reduced purchase or lease prices.
The program offered discounted PV installations that were 25% lower than Palo Alto’s
average residential price in 2014.
o 2017 Bay Area SunShares: The 2017 Bay Area SunShares program was launched in August
2017 and registration was open through November 30, 2017. The program was
administered for the second year in a row by the non-profit Business Council on Climate
Change (BC3) which facilitated the selection of three qualified solar contractors through
a competitive selection process. For the 2017 program, two zero emission vehicles were
available at reduced purchase or lease prices.
Cumulative SunShares Program Results: 2015-17
TOTAL - Bay Area Palo Alto
PV Contract Count 496 88
Total Solar PV kW 2,303 421
For the three years that Palo Alto has participated in the Bay Area SunShares program, Palo Alto
accounts for 18% of PV capacity installed through the program.
ATTACHMENT -B
1
Attachment – B
The Local Solar Plan (LSP) laid out a set of diverse strategies to meet local solar goals and
objectives.1 The Goals and Objectives of the Plan are outlined below. Table B-1 below provides
an update of achievements to date for each of the seven strategies of the LSP.
Goal
To increase the installation of local solar photovoltaic facilities to provide 4% of the City’s total
electrical energy needs by 2023.
Objectives
1. Facilitate the development of local, safe and cost‐effective solar in Palo Alto to meet the
diverse needs of the community
2. Reduce the cost of installing solar in Palo Alto and become a leader in promoting renewable
distributed generation through solar installations
3. Understand the community’s solar potential and diverse needs and develop solar programs
accordingly
4. Remove internal obstacles to minimize cost and achieve greater solar potential
5. Promote solar installations in a cost-effective and safe manner
6. Leverage industry resources to the extent possible
7. Deploy industry best practices
Table B-1: LSP Strategy-by-Strategy Update
Strategy Achievements to Date (2014 - 2017)
Strategy 1: Remove internal
system and institutional
barriers which increase “soft”
costs and may impede
adoption of solar in Palo Alto
Pre-dating the Local Solar Plan, Development Services
implemented a streamlined permitting process for
residential solar PV systems. Palo Alto received the 2014 Best
Solar Collaboration Award at the Annual Solar Power
Generation USA Congress for the improved permitting
process.2
Staff is publicizing the streamlined permitting process and
solar decision-making tool on an ongoing basis.
CPAU launched new improved solar webpages in 2017.
(www.cityofpaloalto.org/solar)
Staff coordinated extensively with several City departments
for streamlined permitting, inspection, and interconnection
processes for the NEM Successor Program launch in January
2018.
Strategy 2: Develop proper
policies, incentives, price
Staff evaluated increasing the funding for PV Partners beyond
compliance obligations and recommended not expanding the
1 Refer to Local Solar Plan Strategies and Actions -
https://www.cityofpaloalto.org/civicax/filebank/documents/45036
2 https://www.cityofpaloalto.org/civicax/filebank/documents/39289
ATTACHMENT -B
2
Strategy Achievements to Date (2014 - 2017)
signals and rates to encourage
solar installation
program (Staff Report 6449). PV Partners program provided
$13 million in total incentives over 10 years and supported 8
MW of solar in residential, small and medium commercial,
large commercial and non-profit/public sectors in Palo Alto.
Staff incorporated local solar considerations in the electric
rate analysis discussions (Electric COSA, Staff Report 6061)
and subsequently proposed a NEM Successor Program, where
customer generators will receive a compensation rate for net
energy exports at an avoided cost3.
Solar considerations are being incorporated in the ongoing
discussions for adopting new billing and customer
information systems.
Staff coordinates with the Northern California Power Agency
(NCPA) and the California Municipal Utilities Association
(CMUA) on an ongoing basis on effective rules, regulations,
and legislation to promote cost-effective and fair solar
development.
Staff evaluated a joint local solar procurement proposed by
NCPA and chose not to join the program due to the high
costs for the potential project sited in Palo Alto.
Strategy 3: Assess technical
and market potential of solar in
Palo Alto
Completed a GIS-based solar technical potential assessment
for rooftops and published a map of the potential online for
interested community members4
Completed the economic and market potential assessment
and incorporated these findings in the 2030 local solar
forecast under the Distributed Energy Resources (DER) Plan
A solar decision making tool – PV Watt Plan - is now available
on CPAU’s solar website. This tool assesses solar potential
and provides initial cost-effectiveness.
Staff conducted a preliminary assessment study of
distribution system impacts from high penetrations of solar
and EV in the summer of 2017.
Strategy 4: Implement policies
and programs to increase solar
system installations on CPAU
customer sites with good solar
Staff continues to implement ongoing local solar programs
including CLEAN, NEM and Group-Buy. These programs help
CPAU customers with good solar access sites to go solar.
Since the adoption of the LSP, the number of solar customers
has increased from 500 to over 1000, and by end of 2018,
3 This rate is 7.485 cents/kWh in 2018. Refer to Utility Rate Schedule E-EEC-1 for more details.
4 Refer to City’s rooftop technical potential map at - https://cityofpaloalto.org/solarmap. Customers can perform
their own rooftop solar technical and economic assessment using solar WattPlan tool
ATTACHMENT -B
3
Strategy Achievements to Date (2014 - 2017)
access approximately 2.2% of Palo Alto’s energy needs are
projected to be met from local resources.
NEM Program: Palo Alto’s state-mandated NEM 1 program,
where customers’ generation was compensated at full retail
rates, ended in December 2017. Beginning January 2018, all
new solar customers are part of the NEM 2 program and will
be compensated for electricity they export at a rate based on
the utility’s avoided cost.5 Currently, 9.5 MW of PV capacity
has been installed under NEM 1 by over 1000 customers, and
an additional 2.4 MW of capacity is under reservation by
about 100 customers. These projects are expected to meet
1.6% of the City’s electrical energy needs.
CLEAN Program: As discussed in the report, staff has made
progress in attracting six CLEAN projects that will meet 0.5%
of the City’s electricity needs. Currently, the 3 MW of
program capacity available at the $0.165 per kWh contract
price is close to full subscription. This program will remain
available to new projects at published avoided costs ($0.088
to $0.091/kWh)6, once the capacity at $0.165/kWh price is
fully subscribed.
Group-Buy Program: As discussed in the report, the City has
successfully partnered with adjoining communities for three
consecutive years for the solar Group-Buy program (aka Bay
Area SunShares). The SunShares program administrator
acknowledged Palo Alto as a top outreach partner in 2015
and 2017. Overall, over 500 residents have registered for
evaluations with 88 residents signing contracts for 420 kW of
rooftop solar capacity in the past three years.
Strategy 5: Facilitate and/or
develop new programs to
encourage new participants to
develop local solar installations
Staff provided support to PAUSD and the Sustainable Schools
Committee in their efforts to evaluate the costs and benefits
of solar PV installations on school facilities. The school
recently signed contracts to install solar at a number of
school sites.
Staff shared a community solar design proposal with the UAC
in June 2017 and subsequently provided market research
and cost-effectiveness information.
Staff has done preliminary research on a solar donation
5 Utility Rate Schedule E-EEC-1;This rate reflects avoided cost or value of customer solar in Palo Alto including, compensation
for the energy, avoided capacity, avoided transmission and ancillary service charges, avoided transmission and distribution
(T&D) losses, and renewable energy credits (RECs), or environmental attributes.
6 CLEAN webpage
ATTACHMENT -B
4
Strategy Achievements to Date (2014 - 2017)
program.
Strategy 6: Maximize solar
installations on City-owned
facilities
The City leased the top levels of four downtown City multi-
level parking structures and contracted to develop over 1.3
MW of solar PV parking structures through the Palo Alto
CLEAN feed-in tariff program. Currently, two of these four
projects are operational. The remaining two projects are
close to completion and will become operational soon.
The City considers including local solar in designs of new
construction projects. For example, the City is considering
the costs and benefits of including solar canopies for two
new parking garage projects.7 The new public safety building
is also being evaluated for the inclusion of solar.
Strategy 7: Educate the
community on the benefits of
solar through information and
demonstration projects
Pre-dating the Local Solar Plan, in 2008 the City installed
solar demonstration projects at the Municipal Service
Center, Baylands Interpretive Center, and Cubberley
Community Center.
The Mitchell Park Library has a 55kW solar system and
provides a display of generation for patrons.8
CPAU continues to host workshops on a variety of topics,
including customer-sited solar energy. The last solar energy
workshop was hosted in September 2017, as part of the Bay
Area SunShares program. Over 50 residents registered to
attend the workshop.
Staff routinely evaluates innovative solar technologies
through the Program for Emerging Technologies (PET). CPAU
provided a letter of support to SLAC’s DOE application for
SolarChainX project (a research project seeking blockchain
application to enable peer-to-peer energy markets on
distribution systems, controlling inverters, and for
decentralized financial transactions).
Staff seeks regular technical and non-technical assistance
from the Solar Electric Power Association and ESource to
adopt industry best practices to inform customers and
provide trusted solar information. (Ongoing)
7 https://www.infrastructure.cityofpaloalto.org/
8 https://www.cityofpaloalto.org/gov/depts/utl/residents/resources/pcm/pv_on_city_facilities.asp
ATTACHMENT - C
1
Attachment – C
Local Solar Forecast and Progress towards Local Solar Plan Goals
Staff developed a 2030 local solar forecast along with other Distributed Energy Resources (DER)
forecasts for the Integrated Resources Plan (IRP) and DER planning purposes.1 Local solar forecast
is based on technical and economic potential, with Behind the Meter (BTM)2 solar adoption
growing steadily.
Figure C-1 shows the cumulative local solar forecast by cumulative capacity installed and
percentage of electrical energy needs met by local solar by 2030.3 These projections include BTM
installations in residential and commercial sectors and installations up to 3 MW from the CLEAN
program. These projections do not assume any installation through new solar programs such as
community solar or additional new installations under the CLEAN program at a lower contract
price. The forecast captures the likely slowing down of the adoption of rooftop solar in the
residential sector in 2018 due to the transition to the lower NEM 2 compensation rate. The
compensation for electricity export under NEM 2 is based on CPAU’s avoided cost, not the full
retail rate as under the state-mandated NEM 1 program. However, BTM solar in the commercial
sector will less likely be impacted. Most commercial customers tend to have relatively small
onsite electricity generation by solar systems compared to their loads and thus they export very
little to the distribution grid. In the longer term, with declining solar costs and new polices such
as Zero Net Energy (ZNE) building requirements,4 Palo Alto will likely observe increasing adoption
of BTM solar.
Given existing incentives and programs, it is uncertain whether the City will achieve the LSP goal
of meeting 4% of the City’s total electrical energy needs from local solar by 2023. Table C-1 shows
all installed, planned and forecasted local solar by 2023. After accounting for 12 MW from the
BTM installations (supported by PV Partners rebates, NEM, and group-buy), 3 MW through the
CLEAN program and 5 MW from new BTM solar installations (supported by NEM 2), about 8 MW
of additional solar capacity would be required to meet the 2023 LSP goal. The City could achieve
1 UAC November, 2017 DER Plan discussion, Attachment B, Technical Addendum for Distributed Energy Resource
(DER) Projections
2 Behind the Meter (BTM) solar represents customer- sited rooftop solar and some solar canopies in parking lots.
Solar generation is netted against onsite energy demand (behind customer’s electric meter) before exporting it to
the distribution grid.
3 Percentage of electric energy needs met by local solar is estimated by dividing the energy generated by local solar
capacity with the calendar year City gate electricity purchases. Energy generation by local solar assumes a 18%
capacity factor with annual degradation factor of 0.8%.
4 ZNE buildings are energy-efficient buildings where, on a source energy basis, the actual annual consumed energy
is less than or equal to the on-site renewable generated energy. The state has an ambitious plan for all new
residential construction to be ZNE by 2020 and new commercial construction be ZNE by 2030. The California
Energy Commission (CEC) is still developing the ZNE implementation plan and these considerations are included in
the updates to the 2019 Building Energy Efficiency Standards.
ATTACHMENT - C
2
the 2023 goals if new solar programs (such as community solar) are offered or ther e is higher
than expected BTM solar adoption.5
Figure C-1: Local Solar Forecast by 2030 and Local Solar Plan Goal
Table C-1: Installed, Planned, and Forecast Solar PV by 2023 and Local Solar Plan Goal
Status as of January 2018 Capacity
(MW)
Energy
(MWh/yr)
% of City’s
Electricity Use
BTM Solar: Installed and Reserved (under PV Partners
Rebate, NEM 1, Group-Buy)
12 15,200 1.6%
CLEAN Program: Installed and Planned 3 4,500 0.5%
Anticipated BTM installations (NEM 2, Group Buy) 5 7,500 0.8%
Total Solar Penetration by 2023 20 27,200 2.9%
Additional Solar PV to Meet Local Solar Plan Goal 8 10,500 1.1%
Solar Penetration Goal in 2023 28 37,700 4.0%
5 High BTM solar adoption is unlikely given the changes to the CPAU NEM program that increased the payback
period and other trends in the solar industry including imposing additional import tariffs on solar panels. However,
a few large commercial projects could increase the BTM solar adoption to significantly higher than the current
forecasted level.
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h
i
c
S
u
b
g
r
o
u
p
R
e
s
u
l
t
s
Pe
r
c
e
n
t
r
a
t
i
n
g
"
e
x
c
e
l
l
e
n
t
"
o
r
"
g
o
o
d
"
No
r
t
h
/
S
o
u
t
h
Ar
e
a
Ov
e
r
a
l
l
No
r
t
h
So
u
t
h
Ar
e
a
1
Ar
e
a
2
Ar
e
a
3
Ar
e
a
4
Ar
e
a
5
Ar
e
a
6
Th
e
v
a
l
u
e
o
f
s
e
r
v
i
c
e
s
f
o
r
t
h
e
t
a
x
e
s
p
a
i
d
t
o
P
a
l
o
A
l
t
o
64
%
58
%
65
%
57
%
66
%
54
%
52
%
66
%
61
%
Th
e
o
v
e
r
a
l
l
d
i
r
e
c
t
i
o
n
t
h
a
t
P
a
l
o
A
l
t
o
i
s
t
a
k
i
n
g
44
%
46
%
44
%
47
%
53
%
41
%
41
%
45
%
45
%
Th
e
j
o
b
P
a
l
o
A
l
t
o
g
o
v
e
r
n
m
e
n
t
d
o
e
s
a
t
w
e
l
c
o
m
i
n
g
c
i
t
i
z
e
n
i
n
v
o
l
v
e
m
e
n
t
56
%
55
%
59
%
53
%
56
%
57
%
50
%
55
%
56
%
Ov
e
r
a
l
l
c
o
n
f
i
d
e
n
c
e
i
n
P
a
l
o
A
l
t
o
g
o
v
e
r
n
m
e
n
t
48
%
50
%
53
%
48
%
53
%
50
%
40
%
49
%
49
%
Ge
n
e
r
a
l
l
y
a
c
t
i
n
g
i
n
t
h
e
b
e
s
t
i
n
t
e
r
e
s
t
o
f
t
h
e
c
o
m
m
u
n
i
t
y
48
%
54
%
51
%
55
%
54
%
51
%
37
%
50
%
51
%
Be
i
n
g
h
o
n
e
s
t
61
%
61
%
60
%
62
%
60
%
60
%
48
%
66
%
61
%
Tr
e
a
t
i
n
g
a
l
l
r
e
s
i
d
e
n
t
s
f
a
i
r
l
y
56
%
57
%
61
%
63
%
61
%
48
%
36
%
58
%
56
%
Ta
b
l
e
6
0
:
Q
u
e
s
t
i
o
n
1
2
-
B
e
n
c
h
m
a
r
k
C
o
m
p
a
r
i
s
o
n
s
Av
e
r
a
g
e
r
a
t
i
n
g
Ra
n
k
Nu
m
b
e
r
o
f
c
o
m
m
u
n
i
t
i
e
s
f
o
r
c
o
m
p
a
r
i
s
o
n
Co
m
p
a
r
i
s
o
n
t
o
b
e
n
c
h
m
a
r
k
Va
l
u
e
o
f
s
e
r
v
i
c
e
s
f
o
r
t
h
e
t
a
x
e
s
p
a
i
d
t
o
P
a
l
o
A
l
t
o
54
12
3
39
2
Si
m
i
l
a
r
Ov
e
r
a
l
l
d
i
r
e
c
t
i
o
n
t
h
a
t
P
a
l
o
A
l
t
o
i
s
t
a
k
i
n
g
44
24
0
30
8
Si
m
i
l
a
r
Jo
b
P
a
l
o
A
l
t
o
g
o
v
e
r
n
m
e
n
t
d
o
e
s
a
t
w
e
l
c
o
m
i
n
g
c
i
t
i
z
e
n
i
n
v
o
l
v
e
m
e
n
t
53
11
8
30
8
Si
m
i
l
a
r
Ov
e
r
a
l
l
c
o
n
f
i
d
e
n
c
e
i
n
P
a
l
o
A
l
t
o
g
o
v
e
r
n
m
e
n
t
48
14
0
22
4
Si
m
i
l
a
r
Ge
n
e
r
a
l
l
y
a
c
t
i
n
g
i
n
t
h
e
b
e
s
t
i
n
t
e
r
e
s
t
o
f
t
h
e
c
o
m
m
u
n
i
t
y
48
14
8
22
4
Si
m
i
l
a
r
Be
i
n
g
h
o
n
e
s
t
55
99
21
7
Si
m
i
l
a
r
Tr
e
a
t
i
n
g
a
l
l
r
e
s
i
d
e
n
t
s
f
a
i
r
l
y
51
12
4
22
2
Si
m
i
l
a
r
Qu
e
s
t
i
o
n
1
3
Ta
b
l
e
6
1
:
Q
u
e
s
t
i
o
n
1
3
-
R
e
s
p
o
n
s
e
P
e
r
c
e
n
t
a
g
e
s
a
n
d
N
u
m
b
e
r
o
f
R
e
s
p
o
n
d
e
n
t
s
Pl
e
a
s
e
r
a
t
e
h
o
w
i
m
p
o
r
t
a
n
t
,
i
f
a
t
a
l
l
,
y
o
u
t
h
i
n
k
i
t
i
s
f
o
r
t
h
e
P
a
l
o
A
l
t
o
c
o
m
m
u
n
i
t
y
t
o
f
o
c
u
s
o
n
ea
c
h
o
f
t
h
e
f
o
l
l
o
w
i
n
g
i
n
t
h
e
c
o
m
i
n
g
t
w
o
y
e
a
r
s
:
Es
s
e
n
t
i
a
l
Ve
r
y
im
p
o
r
t
a
n
t
So
m
e
w
h
a
t
im
p
o
r
t
a
n
t
No
t
a
t
a
l
l
im
p
o
r
t
a
n
t
To
t
a
l
Ov
e
r
a
l
l
f
e
e
l
i
n
g
o
f
s
a
f
e
t
y
i
n
P
a
l
o
A
l
t
o
48
%
N=
2
8
1
31
%
N=
1
8
1
17
%
N=
1
0
1
3%
N=
1
7
10
0
%
N=
5
8
0
Ov
e
r
a
l
l
e
a
s
e
o
f
g
e
t
t
i
n
g
t
o
t
h
e
p
l
a
c
e
s
y
o
u
u
s
u
a
l
l
y
h
a
v
e
t
o
v
i
s
i
t
37
%
N=
2
1
2
42
%
N=
2
4
1
20
%
N=
1
1
4
2%
N=
9
10
0
%
N=
5
7
7
Qu
a
l
i
t
y
o
f
o
v
e
r
a
l
l
n
a
t
u
r
a
l
e
n
v
i
r
o
n
m
e
n
t
i
n
P
a
l
o
A
l
t
o
35
%
N=
2
0
3
43
%
N=
2
4
8
20
%
N=
1
1
5
1%
N=
8
10
0
%
N=
5
7
4
Ov
e
r
a
l
l
"
b
u
i
l
t
e
n
v
i
r
o
n
m
e
n
t
"
o
f
P
a
l
o
A
l
t
o
(
i
n
c
l
u
d
i
n
g
o
v
e
r
a
l
l
d
e
s
i
g
n
,
b
u
i
l
d
i
n
g
s
,
p
a
r
k
s
a
n
d
tr
a
n
s
p
o
r
t
a
t
i
o
n
s
y
s
t
e
m
s
)
38
%
N=
2
1
8
37
%
N=
2
1
3
22
%
N=
1
3
0
3%
N=
1
5
10
0
%
N=
5
7
6
ATTACHMENT D
Th
e
N
a
t
i
o
n
a
l
C
i
t
i
z
e
n
S
u
r
v
e
y
™
Pl
e
a
s
e
r
a
t
e
h
o
w
i
m
p
o
r
t
a
n
t
,
i
f
a
t
a
l
l
,
y
o
u
t
h
i
n
k
i
t
i
s
f
o
r
t
h
e
P
a
l
o
A
l
t
o
c
o
m
m
u
n
i
t
y
t
o
f
o
c
u
s
o
n
ea
c
h
o
f
t
h
e
f
o
l
l
o
w
i
n
g
i
n
t
h
e
c
o
m
i
n
g
t
w
o
y
e
a
r
s
:
Es
s
e
n
t
i
a
l
Ve
r
y
im
p
o
r
t
a
n
t
So
m
e
w
h
a
t
im
p
o
r
t
a
n
t
No
t
a
t
a
l
l
im
p
o
r
t
a
n
t
To
t
a
l
He
a
l
t
h
a
n
d
w
e
l
l
n
e
s
s
o
p
p
o
r
t
u
n
i
t
i
e
s
i
n
P
a
l
o
A
l
t
o
23
%
N=
1
3
4
38
%
N=
2
1
8
34
%
N=
1
9
3
5%
N=
2
7
10
0
%
N=
5
7
2
Ov
e
r
a
l
l
o
p
p
o
r
t
u
n
i
t
i
e
s
f
o
r
e
d
u
c
a
t
i
o
n
a
n
d
e
n
r
i
c
h
m
e
n
t
29
%
N=
1
6
6
38
%
N=
2
1
5
29
%
N=
1
6
3
5%
N=
2
6
10
0
%
N=
5
7
0
Ov
e
r
a
l
l
e
c
o
n
o
m
i
c
h
e
a
l
t
h
o
f
P
a
l
o
A
l
t
o
35
%
N=
2
0
2
41
%
N=
2
3
5
21
%
N=
1
2
1
3%
N=
1
6
10
0
%
N=
5
7
4
Se
n
s
e
o
f
c
o
m
m
u
n
i
t
y
30
%
N=
1
7
2
40
%
N=
2
2
6
27
%
N=
1
5
5
3%
N=
1
8
10
0
%
N=
5
7
1
Re
d
u
c
i
n
g
c
o
m
m
u
n
i
t
y
g
r
e
e
n
h
o
u
s
e
g
a
s
e
m
i
s
s
i
o
n
s
27
%
N=
1
5
4
31
%
N=
1
7
9
28
%
N=
1
6
3
13
%
N=
7
7
10
0
%
N=
5
7
3
Co
n
t
i
n
u
i
n
g
t
o
s
u
p
p
l
y
1
0
0
%
c
a
r
b
o
n
n
e
u
t
r
a
l
e
n
e
r
g
y
30
%
N=
1
7
2
30
%
N=
1
7
5
26
%
N=
1
5
1
13
%
N=
7
6
10
0
%
N=
5
7
4
In
c
r
e
a
s
i
n
g
l
o
c
a
l
s
o
l
a
r
g
e
n
e
r
a
t
i
o
n
c
a
p
a
c
i
t
y
w
i
t
h
i
n
c
i
t
y
b
o
u
n
d
a
r
i
e
s
28
%
N=
1
5
9
29
%
N=
1
6
8
27
%
N=
1
5
1
16
%
N=
9
3
10
0
%
N=
5
7
1
Ex
p
a
n
d
i
n
g
n
o
t
i
f
i
c
a
t
i
o
n
s
y
s
t
e
m
s
(
s
u
c
h
a
s
o
n
l
i
n
e
,
m
o
b
i
l
e
o
r
e
m
a
i
l
)
f
o
r
b
i
l
l
i
n
g
i
s
s
u
e
s
,
e
f
f
i
c
i
e
n
c
y
ti
p
s
,
o
u
t
a
g
e
i
n
f
o
r
m
a
t
i
o
n
)
19
%
N=
1
0
7
29
%
N=
1
6
5
40
%
N=
2
2
3
12
%
N=
7
0
10
0
%
N=
5
6
5
Ta
b
l
e
6
2
:
Q
u
e
s
t
i
o
n
1
3
-
H
i
s
t
o
r
i
c
a
l
R
e
s
u
l
t
s
Pe
r
c
e
n
t
r
a
t
i
n
g
p
o
s
i
t
i
v
e
l
y
(
e
.
g
.
,
e
s
s
e
n
t
i
a
l
/
v
e
r
y
i
m
p
o
r
t
a
n
t
)
20
1
7
r
a
t
i
n
g
co
m
p
a
r
e
d
t
o
2
0
1
6
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
Ov
e
r
a
l
l
f
e
e
l
i
n
g
o
f
s
a
f
e
t
y
i
n
P
a
l
o
A
l
t
o
NA
NA
NA
NA
NA
NA
NA
NA
84
%
82
%
80
%
80
%
Si
m
i
l
a
r
Ov
e
r
a
l
l
e
a
s
e
o
f
g
e
t
t
i
n
g
t
o
t
h
e
p
l
a
c
e
s
y
o
u
u
s
u
a
l
l
y
h
a
v
e
t
o
v
i
s
i
t
NA
NA
NA
NA
NA
NA
NA
NA
82
%
82
%
80
%
79
%
Si
m
i
l
a
r
Qu
a
l
i
t
y
o
f
o
v
e
r
a
l
l
n
a
t
u
r
a
l
e
n
v
i
r
o
n
m
e
n
t
i
n
P
a
l
o
A
l
t
o
NA
NA
NA
NA
NA
NA
NA
NA
81
%
81
%
84
%
79
%
Lo
w
e
r
Ov
e
r
a
l
l
"
b
u
i
l
t
e
n
v
i
r
o
n
m
e
n
t
"
o
f
P
a
l
o
A
l
t
o
(
i
n
c
l
u
d
i
n
g
o
v
e
r
a
l
l
d
e
s
i
g
n
,
bu
i
l
d
i
n
g
s
,
p
a
r
k
s
a
n
d
t
r
a
n
s
p
o
r
t
a
t
i
o
n
s
y
s
t
e
m
s
)
NA
NA
NA
NA
NA
NA
NA
NA
80
%
80
%
82
%
75
%
Lo
w
e
r
He
a
l
t
h
a
n
d
w
e
l
l
n
e
s
s
o
p
p
o
r
t
u
n
i
t
i
e
s
i
n
P
a
l
o
A
l
t
o
NA
NA
NA
NA
NA
NA
NA
NA
65
%
61
%
65
%
62
%
Si
m
i
l
a
r
Ov
e
r
a
l
l
o
p
p
o
r
t
u
n
i
t
i
e
s
f
o
r
e
d
u
c
a
t
i
o
n
a
n
d
e
n
r
i
c
h
m
e
n
t
NA
NA
NA
NA
NA
NA
NA
NA
71
%
67
%
70
%
67
%
Si
m
i
l
a
r
Ov
e
r
a
l
l
e
c
o
n
o
m
i
c
h
e
a
l
t
h
o
f
P
a
l
o
A
l
t
o
NA
NA
NA
NA
NA
NA
NA
NA
80
%
78
%
82
%
76
%
Lo
w
e
r
Se
n
s
e
o
f
c
o
m
m
u
n
i
t
y
NA
NA
NA
NA
NA
NA
NA
NA
72
%
71
%
73
%
70
%
Si
m
i
l
a
r
Re
d
u
c
i
n
g
c
o
m
m
u
n
i
t
y
g
r
e
e
n
h
o
u
s
e
g
a
s
e
m
i
s
s
i
o
n
s
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
58
%
NA
Co
n
t
i
n
u
i
n
g
t
o
s
u
p
p
l
y
1
0
0
%
c
a
r
b
o
n
n
e
u
t
r
a
l
e
n
e
r
g
y
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
60
%
NA
In
c
r
e
a
s
i
n
g
l
o
c
a
l
s
o
l
a
r
g
e
n
e
r
a
t
i
o
n
c
a
p
a
c
i
t
y
w
i
t
h
i
n
c
i
t
y
b
o
u
n
d
a
r
i
e
s
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
57
%
NA
Ex
p
a
n
d
i
n
g
n
o
t
i
f
i
c
a
t
i
o
n
s
y
s
t
e
m
s
(
s
u
c
h
a
s
o
n
l
i
n
e
,
m
o
b
i
l
e
o
r
e
m
a
i
l
)
f
o
r
bi
l
l
i
n
g
i
s
s
u
e
s
,
e
f
f
i
c
i
e
n
c
y
t
i
p
s
,
o
u
t
a
g
e
i
n
f
o
r
m
a
t
i
o
n
)
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
48
%
NA
Tab
l
e
6
3
:
Q
u
e
s
t
i
o
n
1
3
-
G
e
og
r
a
p
h
i
c
S
u
b
g
r
o
u
p
R
e
s
u
l
t
s
Pe
r
c
e
n
t
r
a
t
i
n
g
"
e
s
s
e
n
t
i
a
l
"
o
r
"
v
e
r
y
i
m
p
o
r
t
a
n
t
"
No
r
t
h
/
S
o
u
t
h
Ar
e
a
Ov
e
r
a
l
l
No
r
t
h
So
u
t
h
Ar
e
a
1
Ar
e
a
2
Ar
e
a
3
Ar
e
a
4
Ar
e
a
5
Ar
e
a
6
Ov
e
r
a
l
l
f
e
e
l
i
n
g
o
f
s
a
f
e
t
y
i
n
P
a
l
o
A
l
t
o
77
%
82
%
84
%
84
%
88
%
75
%
79
%
73
%
80
%
Ov
e
r
a
l
l
e
a
s
e
o
f
g
e
t
t
i
n
g
t
o
t
h
e
p
l
a
c
e
s
y
o
u
u
s
u
a
l
l
y
h
a
v
e
t
o
v
i
s
i
t
79
%
79
%
84
%
75
%
83
%
78
%
75
%
77
%
79
%
Qu
a
l
i
t
y
o
f
o
v
e
r
a
l
l
n
a
t
u
r
a
l
e
n
v
i
r
o
n
m
e
n
t
i
n
P
a
l
o
A
l
t
o
78
%
79
%
83
%
75
%
88
%
77
%
74
%
77
%
79
%
Ov
e
r
a
l
l
"
b
u
i
l
t
e
n
v
i
r
o
n
m
e
n
t
"
o
f
P
a
l
o
A
l
t
o
(
i
n
c
l
u
d
i
n
g
o
v
e
r
a
l
l
d
e
s
i
g
n
,
b
u
i
l
d
i
n
g
s
,
p
a
r
k
s
a
n
d
t
r
a
n
s
p
o
r
t
a
t
i
o
n
sy
s
t
e
m
s
)
76
%
74
%
85
%
66
%
72
%
81
%
78
%
72
%
75
%
He
a
l
t
h
a
n
d
w
e
l
l
n
e
s
s
o
p
p
o
r
t
u
n
i
t
i
e
s
i
n
P
a
l
o
A
l
t
o
61
%
62
%
69
%
56
%
72
%
61
%
58
%
57
%
62
%
Ov
e
r
a
l
l
o
p
p
o
r
t
u
n
i
t
i
e
s
f
o
r
e
d
u
c
a
t
i
o
n
a
n
d
e
n
r
i
c
h
m
e
n
t
64
%
70
%
76
%
69
%
74
%
69
%
56
%
59
%
67
%
Ov
e
r
a
l
l
e
c
o
n
o
m
i
c
h
e
a
l
t
h
o
f
P
a
l
o
A
l
t
o
75
%
77
%
78
%
78
%
73
%
80
%
79
%
72
%
76
%
Se
n
s
e
o
f
c
o
m
m
u
n
i
t
y
69
%
70
%
72
%
67
%
72
%
70
%
72
%
68
%
70
%
Re
d
u
c
i
n
g
c
o
m
m
u
n
i
t
y
g
r
e
e
n
h
o
u
s
e
g
a
s
e
m
i
s
s
i
o
n
s
59
%
57
%
61
%
53
%
59
%
58
%
53
%
61
%
58
%
Th
e
N
a
t
i
o
n
a
l
C
i
t
i
z
e
n
S
u
r
v
e
y
™
Pe
r
c
e
n
t
r
a
t
i
n
g
"
e
s
s
e
n
t
i
a
l
"
o
r
"
v
e
r
y
i
m
p
o
r
t
a
n
t
"
No
r
t
h
/
S
o
u
t
h
Ar
e
a
Ov
e
r
a
l
l
No
r
t
h
So
u
t
h
Ar
e
a
1
Ar
e
a
2
Ar
e
a
3
Ar
e
a
4
Ar
e
a
5
Ar
e
a
6
Co
n
t
i
n
u
i
n
g
t
o
s
u
p
p
l
y
1
0
0
%
c
a
r
b
o
n
n
e
u
t
r
a
l
e
n
e
r
g
y
65
%
56
%
71
%
58
%
54
%
56
%
64
%
62
%
60
%
In
c
r
e
a
s
i
n
g
l
o
c
a
l
s
o
l
a
r
g
e
n
e
r
a
t
i
o
n
c
a
p
a
c
i
t
y
w
i
t
h
i
n
c
i
t
y
b
o
u
n
d
a
r
i
e
s
63
%
51
%
70
%
54
%
52
%
49
%
59
%
61
%
57
%
Ex
p
a
n
d
i
n
g
n
o
t
i
f
i
c
a
t
i
o
n
s
y
s
t
e
m
s
(
s
u
c
h
a
s
o
n
l
i
n
e
,
m
o
b
i
l
e
o
r
e
m
a
i
l
)
f
o
r
b
i
l
l
i
n
g
i
s
s
u
e
s
,
e
f
f
i
c
i
e
n
c
y
t
i
p
s
,
o
u
t
a
g
e
in
f
o
r
m
a
t
i
o
n
)
53
%
43
%
57
%
41
%
49
%
42
%
45
%
53
%
48
%
Be
n
c
h
m
a
r
k
s
w
e
r
e
n
o
t
c
a
l
c
u
l
a
t
e
d
f
o
r
q
u
e
s
t
i
o
n
1
3
a
s
i
t
i
s
n
o
n
e
v
a
l
u
a
t
i
v
e
.
Qu
e
s
t
i
o
n
s
1
4
t
h
r
o
u
g
h
2
5
a
r
e
c
u
s
t
o
m
q
u
e
s
t
i
o
n
s
,
t
h
e
r
e
f
o
r
e
b
e
n
c
h
m
a
r
k
s
w
e
r
e
n
o
t
c
a
l
c
u
l
a
t
e
d
.
G
e
o
g
r
a
p
h
i
c
s
u
b
g
r
o
u
p
r
e
s
u
l
t
s
a
r
e
i
n
c
l
u
d
e
d
f
o
r
q
u
e
s
t
i
o
n
s
1
4
t
h
r
o
u
g
h
1
7
.
Qu
e
s
t
i
o
n
1
4
Ta
b
l
e
6
4
:
Q
u
e
s
t
i
o
n
1
4
-
R
e
s
p
o
n
s
e
P
e
r
c
e
n
t
a
g
e
s
a
n
d
N
u
m
b
e
r
o
f
R
e
s
p
o
n
d
e
n
t
s
i
n
c
l
u
d
i
n
g
"
D
o
n
'
t
K
n
o
w
"
R
e
s
p
o
n
s
e
s
Pl
e
a
s
e
r
a
t
e
t
h
e
f
o
l
l
o
w
i
n
g
a
s
t
h
e
y
r
e
l
a
t
e
t
o
P
a
l
o
A
l
t
o
U
t
i
l
i
t
i
e
s
'
s
e
r
v
i
c
e
s
:
Ex
c
e
l
l
e
n
t
Go
o
d
Fa
i
r
Po
o
r
Do
n
'
t
k
n
o
w
To
t
a
l
Re
l
i
a
b
i
l
i
t
y
o
f
u
t
i
l
i
t
y
s
e
r
v
i
c
e
s
58
%
N=
3
3
5
34
%
N=
1
9
8
4%
N=
2
2
0%
N=
3
4%
N=
2
1
10
0
%
N=
5
7
8
Af
f
o
r
d
a
b
i
l
i
t
y
o
f
u
t
i
l
i
t
y
s
e
r
v
i
c
e
s
20
%
N=
1
1
4
39
%
N=
2
2
6
25
%
N=
1
4
6
8%
N=
4
6
7%
N=
4
1
10
0
%
N=
5
7
4
Va
l
u
e
r
e
c
e
i
v
e
d
f
r
o
m
t
h
e
C
i
t
y
o
w
n
i
n
g
a
n
d
o
p
e
r
a
t
i
n
g
i
t
s
o
w
n
m
u
n
i
c
i
p
a
l
u
t
i
l
i
t
y
s
e
r
v
i
c
e
s
33
%
N=
1
8
7
33
%
N=
1
8
7
12
%
N=
6
9
4%
N=
2
2
18
%
N=
1
0
3
10
0
%
N=
5
6
7
Ut
i
l
i
t
i
e
s
C
u
s
t
o
m
e
r
S
e
r
v
i
c
e
29
%
N=
1
6
5
33
%
N=
1
9
1
8%
N=
4
5
2%
N=
1
4
27
%
N=
1
5
5
10
0
%
N=
5
7
1
Ut
i
l
i
t
i
e
s
'
c
o
n
c
e
r
n
f
o
r
t
h
e
e
n
v
i
r
o
n
m
e
n
t
30
%
N=
1
6
8
35
%
N=
1
9
7
8%
N=
4
5
1%
N=
8
26
%
N=
1
5
1
10
0
%
N=
5
6
9
Pr
o
v
i
d
i
n
g
o
p
p
o
r
t
u
n
i
t
i
e
s
f
o
r
e
n
e
r
g
y
a
n
d
w
a
t
e
r
e
f
f
i
c
i
e
n
c
y
a
t
h
o
m
e
o
r
b
u
s
i
n
e
s
s
25
%
N=
1
4
4
39
%
N=
2
2
5
11
%
N=
6
4
2%
N=
1
4
22
%
N=
1
2
3
10
0
%
N=
5
7
0
Wo
r
k
i
n
g
h
a
r
d
t
o
k
e
e
p
u
t
i
l
i
t
i
e
s
p
r
i
c
e
s
c
o
m
p
e
t
i
t
i
v
e
17
%
N=
9
7
27
%
N=
1
5
1
15
%
N=
8
6
10
%
N=
5
9
31
%
N=
1
7
3
10
0
%
N=
5
6
8
Va
l
u
e
o
f
a
l
l
t
h
e
s
e
r
v
i
c
e
s
P
a
l
o
A
l
t
o
U
t
i
l
i
t
i
e
s
p
r
o
v
i
d
e
s
f
o
r
t
h
e
p
r
i
c
e
y
o
u
p
a
y
20
%
N=
1
1
6
38
%
N=
2
1
8
19
%
N=
1
0
9
8%
N=
4
8
14
%
N=
8
0
10
0
%
N=
5
7
1
Ea
s
e
o
f
o
b
t
a
i
n
i
n
g
i
n
f
o
r
m
a
t
i
o
n
o
r
p
e
r
f
o
r
m
i
n
g
a
t
r
a
n
s
a
c
t
i
o
n
t
h
r
o
u
g
h
t
h
e
C
i
t
y
'
s
w
e
b
s
i
t
e
15
%
N=
8
7
29
%
N=
1
6
2
18
%
N=
1
0
1
5%
N=
3
1
33
%
N=
1
8
4
10
0
%
N=
5
6
5
Pa
l
o
A
l
t
o
U
t
i
l
i
t
i
e
s
'
c
o
m
m
u
n
i
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1
4
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 12, 2018
SUBJECT: Assessment of CPAU’s Distribution System to Integrate Distributed Energy
Resources
RECOMMENDATION
This is an informational report to the Utilities Advisory Commission (UAC) to provide an update
on CPAU’s continuing study of distributed energy resources. No action is requested at this time.
EXECUTIVE SUMMARY
Staff undertook an assessment of the City of Palo Alto Utilities (CPAU’s) electric distribution
system to understand system capabilities to accommodate customer adoption of distributed
energy resources (DERs)1 and to identify constraints. In Palo Alto, Electric Vehicles (EVs) and local
solar (PV) are two DER technologies projected to have significant penetration by 2030 and the
potential to impact distribution system operations. At the system level, there is sufficient
capacity to accommodate DER growth for the next five years. However, there are some sub-
components of the system that require further assessment and monitoring (e.g. residential
distribution transformers). Implementation of Advanced Metering Infrastructure (AMI) by 2022
will greatly enhance the visibility into distribution system operational characteristics and further
enable the integration of DERs by offering new customer programs (such as, time varying rates).
Although no major immediate strategic shifts are needed to accommodate DERs, staff has
identified a number of tasks that can be undertaken in the next three years to better position the
City to manage longer-term potential impacts. These tasks are:
a) review and update the city’s mapping of customer meters to the distribution transformer
serving them to enable better assessment of distribution transformer loading,
b) identify distribution transformers that have potential to overload due to the high
adoption of EVs, and upgrade them as needed,
c) better understand non-technical impacts of potential distribution system changes, such
as the impact of larger distribution transformers on neighborhood aesthetics,
1 DERs are electrical energy resources connected to the CPAU distribution grid that can significantly change the
location, timing, and magnitude of the CPAU’s electric loads. DERs in Palo Alto include but are not limited to:
distributed renewable generation resources such as solar photovoltaics (PV), energy efficiency (EE), energy storage
(ES), electric vehicles (EV), and demand response (DR) technologies, as well as grid interactive and flexible
resources such as EV smart chargers, smart thermostats, heat-pump water heaters (HPWH), and heat-pump space
heaters (HPSH).
2
d) evaluate a standardized policy and fee for residential customers requesting electrical
panels larger than 200 Ampere panels and implement if feasible, and
e) explore the potential to integrate smart inverter capabilities into distribution system
operations.
An interdisciplinary team of staff members from Utilities Engineering, Operations, Resource
Management, and Customer Service will continue to work on these areas in FY 2019 and FY 2020.
Staff is coordinating these actions with the development of the DER Plan and planning for AMI
investment. Staff continues to seek collaborative opportunities with industry partners and ways
to learn from industry best practices in these areas as well.
BACKGROUND
CPAU procures electricity from carbon-neutral resources located throughout California.2
Electricity is physically received in Palo Alto at the Colorado Power (COP) substation, through high
voltage transmission lines. CPAU’s Distribution System Network is a combination of wires,
substations, and distribution transformers, and is used to deliver electricity to customers.
Figure 1. below provides an overview of the CPAU’s electricity supply chain.
DERs in Palo Alto are mostly customer-sited resources and connected to the distribution system.
Higher penetration of DERs may impact the reliability and operation of the distribution system.
This report shares the findings of a distribution system assessment that was undertaken to
evaluate whether the current system can accommodate and effectively integrate the growth of
DERs.
Figure 1. Electricity supply chain from supply resources to end-customers
CPAU’s distribution system consists of the following major components: transmission services,
a sub-transmission network, substations, feeder lines, distribution transformers, Supervisory
2 These resources are scheduled in the California energy markets (CAISO) by the Northern California Power Agency
(NCPA) on behalf of CPAU. NCPA also schedules Palo Alto’s city-gate load to the CAISO markets.
3
Control and Data Acquisition (SCADA) and other control and protection devices 3. Attachment –
B provides details of these components, their observed performance, and asset value. In
summary, Palo Alto’s electric distribution system consists of:
• Transmission line services
• 19 miles of sub-transmission network connecting substations
• 9 substations accommodating step-down transformers, protective equipment, and
sending electricity to feeders
• 68 medium voltage feeders with 300 miles in length and connecting to 3,150
distribution transformers
• About 25,500 residential and 4,000 commercial electric meters
Overall, the distribution system is designed to serve the predicted peak load and maintain
electrical safety of the system and public by ensuring:
Normal capacity of any equipment is not exceeded under normal conditions
Emergency capacity of any equipment is not exceeded under emergency conditions
Voltage levels are kept within required limits
System problems are isolated as quickly as possible
The draft DER Plan presented by Staff to the UAC in November 2017 included nine strategies to
integrate DERs. These included strategies to lower barriers to adoption, offer customer
programs, implement advanced AMI and rate structures, enhance distribution system planning,
and incorporate DERs into electric supply planning. The DER plan goal is to enhance the value of
DERs to all members of the Palo Alto community while avoiding or mitigating any potential
negative impacts from DER growth.4 The distribution system assessment results provided in this
report are used to develop the distribution system planning strategy of the DER Plan. Table 1
below recaps the distribution system planning strategies and actions from the draft DER Plan.
The actions described in this report specifically address action item b) requirements “Performing
a Distribution System Assessment at regular intervals… ”.
3 Attachment A provides a summary of the technical terms used in this report.
4 Discussion of Proposed Distributed Energy Resources Plan, UAC November 2017 -
https://www.cityofpaloalto.org/civicax/filebank/documents/61748
4
Table 1. Distribution System Planning Strategy and Actions to Accommodate the Growth of DERs at the
Lowest Cost while Maintaining System Reliability to all Customers 5
DISCUSSION
This report discusses the following topic areas:
A) Benefits and challenges of DERs in distribution system operations
B) Industry trends in distribution system planning and DER integration
C) Findings on the Impact of DERs on Palo Alto’s distribution system
A) Benefits and Challenges of DERs in Distribution System Operations
DERs may have disparate impacts and benefits on the distribution system depending on size,
type, technology, location, engineering practices, and penetration level. The list below is
explained in more detail in Attachment C.
Well-integrated DERs could provide benefits to the distribution system such as:
+ Voltage support (especially toward the end of the feeders)
+ Peak shaving (potential for investment deferral)
+ Loss reduction
+ Potential for intentional islanding (microgrid) to enhance reliability
5 Draft DER Plan, Strategy #6 for Distribution System Planning, UAC November 2017
https://www.cityofpaloalto.org/civicax/filebank/documents/61748
a. Integrating the impact of DERs into long-term distribution system planning and considering
the cost-effectiveness of DERs to strengthen distribution infrastructure;
b. Performing a Distribution System Assessment at regular intervals that assesses the available
capacity for additional DERs throughout the distribution system within the context of
planned upgrades and projected DER growth;
c. Evaluating the response of the distribution systems for various stresses in the system (e.g.
concentrated locational DER growth, sudden loss of local PV generation due to cloud cover,
operation of protective relays and fault currents, etc.);
d. Evaluating and implementing DER programs that can enhance distribution system reliability
after the implementation of AMI;
e. Re-evaluate the interconnection fee structure and its impact on sizing electric services to
accommodate EVs and all-electric homes;
f. Creating an implementation plan for a Conservation Voltage Reduction (CVR) program upon
implementation of the AMI system when upgrading the substation transformer controllers;
g. Developing tools and processes to estimate interconnection fees of large DERs as part of the
initial permitting process.
5
At the same time, challenges in integrating DERs in the distribution system include:
- Thermal rating violations (or overloading)
- Voltage increase or fluctuations
- Protection issues, load masking, wear and tear of circuit apparatus (tap changers and
switches)
- Complaints on electric system conditions from adjacent customers
The objective of distribution system planning in the context of DERs is to maximize the value of
DERs to the community while mitigating any adverse impacts and to provide the lowest cost
electric distribution service, maintaining system reliability, and enabling customers to adopt
these technologies.
B) Industry Trends in Distribution System Planning and DER Integration
Distribution system planning for DERs is getting increased attention in the electric industry due
an increase in installations/use and the issues listed above.6 Various state regulations or planning
goals have driven utility planning efforts, as well as operational realities created by high
penetration of DERs in certain utility jurisdictions. California’s Integrated Demand-Side Resources
(IDSR) proceeding, New York’s Reforming the Energy Vision (REV) initiative, and Hawaii’s
Integrated Grid Planning are some of the prominent industry initiatives to integrate DERs.
These early industry efforts have primarily been focused in the following areas:
i. Conducting integration capacity analysis to determine the capability of the
distribution system to integrate DERs; and
ii. Demonstration projects to defer distribution infrastructure upgrades.
Integration capacity analysis presents the ability of individual distribution circuits to
accommodate additional DERs without requiring significant upgrades in order to ensure system
safety and reliability.7 Demonstration projects are being undertaken to affirm if targeted
incentives to guide DER deployment could provide grid benefits and defer needs for upgrades.8
The findings of this report are related to the integration capacity analysis for CPAU’s distribution
system. Future efforts by City staff will focus on demonstration projects, among other things.
6 Smart Electric Power Alliance Research, Beyond the Meter: Planning the Distributed Energy Future: Emerging
Electric Utility Distribution Planning Practices for Distributed Energy Resources
7 For example, refer to SCE’s Integration Capacity Analysis maps and user guide
8 For example, refer to PG&E’s 2017 Distributed Resources Plan Request For Offers (RFO)
6
C) Impact of DERs on the CPAU Distribution System
CPAU’s current annual electrical energy sales (960,000 MWh) and annual peak demand (180 MW)
are approximately 15% lower than in the year 2000. The exit of electricity-intensive commercial
customers from Palo Alto, increases in energy-efficient appliances and building energy codes,
changes in customer behavior, and the installation of solar PV on rooftops are some of the reasons
for the decreased electricity loads served by the distribution system. As illustrated in Attachment
E, CPAU expects relatively little load growth through 2030. DERs such as energy efficiency and
solar PV are expected to decrease the load, whereas EVs and other electrification initiatives will
increase the load. Moreover, DER load impact would be unevenly realized amongst sub-
components of the distribution system and in different seasons and times of the day. These
potential impacts and mitigations are discussed in this section.
o Electric Vehicles – Impact on Distribution System
Palo Alto has one of the highest EV ownership rates. In 2016, 22% of new vehicles registered in
Palo Alto were electric, the highest market share in any city in the United States.9 The City’s
Sustainability Implementation Plan (SIP) calls for actively encouraging its residents and non-
resident commuters to adopt EVs through policies, incentives, and provision of EV charging
infrastructure.10 The current EV forecast is to have about 6,000 residential EVs in Palo Alto by
2020 and about 19,000 by 2030. In addition, there are estimated to be approximately 5,900 and
20,000 commuter EVs in 2020 and 2030 respectively. While residential and commuter EVs are
expected to account for approximately 5% of the total electrical load by 2030, the load increase
will be unevenly distributed among customer types as well as by location. Residential sections of
the distribution grid will have significantly more load growth, with demand increasing up to 30%
by 2030.
After examining various components of the distribution system, distribution transformers
located in residential neighborhoods were found to be most vulnerable to increased EV loads.
Overall at the system level (sub-transmission network, substations, feeders), CPAU has sufficient
capacity to integrate EV load.11 Unmanaged EV charging could potentially overload distribution
transformers serving the residential neighborhoods (last mile delivery point of the distribution
system).
Staff performed a review of the City’s distribution transformer inventory, the methodology for
sizing transformers, and the potential impact of EV load growth. Attachments B and D provide
9 ICCT Briefing, California’s Electric Vehicle Market Update, May 2017 -
https://www.theicct.org/sites/default/files/publications/CA-cities-EV-update_ICCT_Briefing_30052017_vF.pdf
10 Palo Alto Sustainability Implementation Plan (2018 - 2020) Key Actions -
https://www.cityofpaloalto.org/civicax/filebank/documents/63141
11 Large EV charging projects, such as DC fast charger stations undergo case-by-case basis review. Any distribution
system upgrade costs are paid by the project developer.
7
details of these reviews. This review was somewhat limited absent additional AMI data and some
mapping accuracy updates at the individual parcel level. About one-third of total CPAU
distribution transformers are rated at or lower than 25 kVA and serve about 7 to 8 residential
customers. These lower-rated transformers are most vulnerable to the impacts of EV load
growth. The upper limit of economic impact, if all of these transformers had to be replaced over
the next ten to fifteen years, is approximately $5 million.12 However, the utility may be able to
avoid transformer replacements by incentivizing smart charging behavior with time-varying rate
structures or other managed charging options.
To improve its assessment, staff plans to undertake a comprehensive analysis of EV impacts on
distribution transformers. While complete AMI data will not be available for several years, staff
can establish a range of potential EV loading profiles based on other sources available. These load
profiles would take into account evolving EV charging patterns due to the availability of long-
range electric cars and the increasing installation of higher power chargers (Level-2)13 at homes.
Detailed modeling of the operations and financial impact would guide the development of new
strategic programs and incentives under the DER Plan. To support this analysis, staff also plans
to closely review and update the electric system map to validate the mapping of distribution
transformers to customer meters. CPAU’s current mapping of distribution transformers to
customer meters needs further review for accuracy. In the long term, AMI meters would be
effective in predicting distribution transformer operating conditions with accurate customer
meter mapping.
If the City finds that distribution transformers need to be upgraded to accommodate load growth,
particularly in residential areas, there may be other impacts that need to be addressed. In a
recent underground district rebuilding project, for example, staff has been evaluating the
possibility of increasing the size of transformers in that area to accommodate future electric
vehicles and other loads. However, the aesthetic issues created by the larger transformers
present challenges that would have to be overcome in any long-term effort to increase
transformer sizes proactively to accommodate load growth.
A parallel effort in the area for EV integration includes re-evaluating the utility’s policies regarding
home electric panel upgrades. For many homeowners, adding an EV or multiple EVs could require
a panel upgrade. CPAU currently charges a fixed fee for panels of up to 200 amperes (A), but a
variable fee for connection requests greater than 200 A. If a utility transformer requires an
12 Assuming $5,000 to upgrade a 25 kVA pole-top distribution transformer. See Attachment D for Distribution
Transformer Sizing and Installation Economics
13 Level 1 charging is typically plugged into a standard 120V outlet and has load up to 1.9 kW (120 V @ 16 Amps).
Level 2 chargers are sold separately from the car, plugged into a 240V outlet, and has load up to 19 kW (240V @ 80
Amps).
8
upgrade due to a greater than 200A panel being installed, that cost is currently assessed to the
homeowner.14 CPAU currently has a Utility Service Capacity Fee Rebate program to help residents
install EV chargers and be eligible for a rebate up to $3000 for these system costs.15 Staff needs
to re-evaluate the interconnection fee structure and its impact on sizing electric services to
accommodate EVs and all-electric homes.
o Solar PV – Impact on Distribution System
Palo Alto has observed a steady growth of local solar PV systems for the past two decades.
Currently, CPAU has over 1000 solar systems installed with 10 MW of capacity that meet 1.6% of
the City’s electrical energy needs. CPAU’s forecast is to have about 2,500 solar systems by 2030,
with 35 MW of cumulative capacity and meeting 5% of the City’s energy needs.
At the system level, CPAU has sufficient capacity to accommodate solar PV growth. However,
sub-components of the distribution system, particularly balancing at the feeder level, could be
impacted by unmanaged PV system growth. Potential challenges could include the risk of reverse
power flow16 and short-term voltage fluctuations that could adversely impact adjacent
customers, the protection devices, and cause wear and tear on circuit apparatus (tap changers
and switches).
CPAU has a total of 68 feeder lines with most rated at 12 kV, and 8 feeders rated at 4 kV. Feeders
with a 4 kV rating and with insufficient customer loads may not be able to connect a large solar
system without risking undesired reverse flow into the substation. CPAU has an existing long-
term capital improvement plan (CIP) to upgrade 4 kV feeder lines to 12 kV. With these planned
upgrades, CPAU’s system will even be more robust and able to integrate additional local solar
capacity. Attachment B provides details of the CPAU feeders with observed maximum, minimum
loading and already interconnected solar capacity by the feeder. In theory, maintaining the solar
interconnected capacity below the minimum load of the feeder at all times of the year will
prevent any risks of reverse power flow. Considering this constraint and past minimum loading
of feeders, staff’s rough estimate is that CPAU’s distribution system could accommodate an
additional 50 MW of new solar capacity.
One other problem utilities experience, besides reverse power flow, is drops in voltage. CPAU’s
feeders are relatively short in length and therefore do not experience a large voltage drop at the
end of the feeder line. However, concentrated cumulative solar capacity on a feeder line can
make it susceptible to voltage fluctuations due to cloud cover and other intermittent changes in
the PV system generation. CPAU Rule 27 incorporates the latest smart inverter standards as
14 CPAU electric service connection fees, Rate Schedule E-15
https://www.cityofpaloalto.org/civicax/filebank/documents/8083
15CPAU Capacity Fee Rebate program; this program has been funded by revenues from the state’s Low Carbon Fuel
Standards program. CPAU receives these credits as result of supplying clean electricity fuel to electric cars.
16 Reverse power flow in a distribution network can be problematic due to overvoltage and protection devices
inability to operate under these conditions. See Attachment- C for more details.
9
required by IEEE 1547 to reduce voltage fluctuation.17 Staff continues to monitor industry
standards for smart inverter capabilities and will explore including additional standards as part
of the utility’s interconnection requirements if they will contribute to effectively operating the
system.
NEXT STEPS
Based on the current assessment of the distribution system, Staff plans to work on the following
tasks in FY 2019 and FY 2020:
a) review and update the city’s mapping of customer meters to the distribution transformer
serving them to enable better assessment of distribution transformer loading,
b) identify distribution transformers that have potential to overload due to the high
adoption of EVs, and upgrade them as needed,
c) better understand non-technical impacts of potential distribution system changes, such
as the impact of larger distribution transformers on neighborhood aesthetics,
d) evaluate a standardized fee to connect residential customers requesting services greater
than 200 Ampere panels and implement if feasible, and
e) explore the potential to further integrate smart inverter capabilities into the distribution
system operations.
Staff will also continue to seek collaborative opportunities with industry partners and learn from
industry best practices in these areas.
RESOURCE IMPACT
Other than the AMI project, no major electric distribution system capital projects are needed to
accommodate DER growth in the next 5 years. CPAU has assembled an interdisciplinary team
using existing staff and resources to continue to analyze and implement distribution system level
projects to facilitate the adoption of DERs. Any additional resources required for the DER plan
implementation, including changes to distribution planning strategy, will be discussed in the
context of the DER Plan adoption, and will be included in annual budgets as appropriate.
POLICY IMPLICATIONS
The distribution system assessment and follow-up tasks are consistent with the 2018 Utilities
Strategic Plan (Strategic Plan). The Strategic Plan has identified implementation of sustainable
and resilient electric system as a key priority: “Achieve a sustainable and resilient energy and
water supply to meet community needs.” Specifically, this initiative conforms to action #2 under
this Strategic Plan priority. The action specified is to: “Establish and implement a Distributed
Energy Resources plan to ensure local generation, storage, EVs, and controllable loads (like heat
pump water heaters) are integrated into the distribution system in a way that benefits both the
customer and the broader community.”
17 CPAU Rule 27, Smart Inverter Generating Facility Design and Operation Requirements -
https://www.cityofpaloalto.org/civicax/filebank/documents/28893. These requirements include controls for
voltage and frequency ride-through and ramp rate and re-connect ramp rate controls.
ENVIRONMENTAL REVIEW
The Utilities Advisory Commission's discussion of the Distributed Energy Resources integration
does not meet the definition of a project under Public Resources Code 21065, and therefore
California Environmental Quality Act (CEOA) review is not required.
ATTACHMENTS
A. Summary of Technical Terms Used in the Report
B. Outline of CPAU Distribution System & Components
C. Literature Review of Benefits and Challenges of DERs in Distribution System Operations
D. Approach to Distribution Transformer Sizing and Installation Economics
E. Technical Addendum for DER Projections
PREPARED BY: SONIKA CHOUDHARY, Resource Planner J:::.-,/
JIMMY PACHIKARA, Senior Electrical Engineer?
MIKE MINTZ, Senior Electrical Engineer U.U~lll-\
SHIVA SWAMINATHAN, Senior Resource Planner
REVIEWED BY: JONATHAN ABENDSCHEIN, Assistant Director Resource Managegi_ent
TOM TING, Engineering Manager, Electric ~
APPROVED BY: ~
EDSHIKADA
General Manager of Utilities
10
Attachment - A
1
ATTACHMENT –A
Summary of Technical Terms Used in the Report
Below is a list of definitions and explanations of basic electrical engineering terms and concepts
used in this report.
• Units of Measurement: Many distribution system components are described according
to their ability to handle electrical potential, measured in Volts (V) or kilovolts (kV),
instantaneous flow of electrical charges or currents, measured in Amperes (Amps), and
power, measured in MegaVolt-Amperes (MVA) or MegaWatts (MW). These equipment
ratings are important as they represent the amount of electrical capacity the component
can handle without negative consequences (like sparking) and how much power can
instantaneously flow through the component before it is overloaded and potentially
damaged.
o Electrical Potential or Voltage (Volts): It represents electrical pressure applied to
electrons which forces flow of charge through the circuit. Transmission level
electrical potential is measured in the hundreds of kilovolts (115 kV in Palo Alto),
sub-transmission components are in the 60 kV range in Palo Alto, and distribution
level components handle electric potential in the tens of kilovolts. A building will
typically have less than one kV of electric potential inside. Typical house voltage is
120 volts, or 0.120 kV. Electric potential can be considered analogous to water
pressure in the water distribution system network.
o Current (Amperes) – It represents instantaneous flow rate of charge or analogues
of water flow rate in the water distribution system. Most electrical panels for
residential customers are rated at 200 Amps or less.
o Power: Power is measured in MVA or kVA. One MVA equals one thousand kVA.
One MVA is similar to one megawatt (MW) and one kVA is similar to one kilowatt
(kW), but MVA and kVA are used in scenarios like distribution planning where the
engineer is trying to account for both the real productive power running through
the system as well as the non-productive power flow (also known as “reactive
power”) that can result from inductive loads like motors. MW is used more
frequently for peak load planning or demand response, when the important
measurement is the amount of real productive power being demanded by
customers at any moment of the day. In theory, power is equal to the product of
the voltage and current, or P = IV.
o Power vs. Energy: Power is measured in MVA or MW, and is the amount of energy
flow at any instant. Total energy delivered over time is measured in Megawatt-
hours (MWh) or kilowatt-hours (kWh) and is the total energy delivered over a
defined amount of time. One MW of power running continuously for one hour
results in one MWh of energy being delivered or 1000 kWh. 1 kWh can light a 100
Attachment - A
2
watt incandescent light bulb for 10 hours, a 23 watt compact florescent bulb for
43 hours, or a 14 watt LED bulb for 71 hours. A 300 watt (50”) plasma television
uses one kWh every three hours. Average monthly usage for a Palo Alto residential
customer is about 500 kWh and peak load of 3 kW.
• Components of the Electrical System:
o Electricity Supply Chain: The structure of electricity delivery can be categorized into
three functions: generation, transmission, and distribution, all of which are linked through
key assets known as substations.
Figure A.1: Conceptual Flow Chart of the Electricity Supply Chain
Source: United States Electricity Industry Primer by Office of Electricity Delivery and Energy Reliability U.S. DOE
o Distribution Substation: A substation is a major node in the distribution system
which connects the transmission or sub-transmission network to medium voltage
distribution networks, houses equipment such as step-down transformers and
other protective devices and where power can be switched from one line to
another and lines can be shut off as needed. The figure A2. below illustrates the
flow of electricity through a distribution substation.
Figure A.2: Flow of Electric Power Through a Distribution Substation
Source: United States Electricity Industry Primer by Office of Electricity Delivery and Energy Reliability U.S. DOE
o Feeders: A feeder is a smaller distribution line running from a substation to
residential or commercial customers. Each feeder will have a number of small
Attachment - A
3
distribution transformers on it, and each small distribution transformer will
typically serve several homes or businesses.
o Transformers: They are used in the distribution system to change from one voltage
to another voltage. When voltage is reduced in the direction of power flow, the
transformer is a “step-down” transformer. When it is increased, it is a “step-up”
transformer. Smaller size distribution transformers can be accommodated on the
pole top. Larger size transformers are mostly mounted on a concrete pad.
Figure A.3 shows typical pole-top vs pad mounted transformers. Figure A.4 shows
example distribution transformers from CPAU inventory: a). Single phase
overhead 37.5 kVA transformer, 2.3 kV primary to 240/120V secondary (can serve
up to 9 residential customers), b). Single phase underground 75 kVA transformer,
12.4 kV primary to 240/120V secondary (can serve up to 25 residential customers)
Figure A.3: Pole-top Vs Pad-mounted Distribution Transformers
Source: United States Electricity Industry Primer by Office of Electricity Delivery and Energy Reliability U.S. DOE
Figure A.4: Example Distribution Transformers from CPAU inventory: a). single phase overhead
37.5 kVA, b). single phase underground 75 kVA
a). 37.5 kVA transformer b). 75 kVA transformer
Attachment – B
1
ATTACHMENT – B
CPAU Distribution System Overview, Observed Performance, and Asset Value
I. Distribution System Overview
CPAU’s distribution system consists of the following major components:
• Transmission Service: CPAU receives electricity from 115 kV transmission lines (rated at
135 MVA). These lines provide a total system capacity of 405 MVA (and 270 MVA even if
one line is taken out of service). These lines have sufficient capacity to meet current peak
load of 185 MW. It is worth noting that CPAU system peaked at 210 MW in the summer
of 2000, illustrating the excess capacity currently available in the transmission lines
serving Palo Alto.
• Sub-transmission Network and Distribution Substations: Electricity from the transmission
substation is distributed via a network of 60 kV sub-transmission lines to nine substations.
The 60 kV network is about 19 miles in length with 12 miles of overhead and 7 miles of
underground. The substations contain 60 kV to 12 kV and 60 kV to 4 kV step down
transformers. CPAU’s engineering practice is to design and operate the substation
transformers at 50% of the rated capacity and these components have sufficient capacity
to carry increased loads.
• Feeder Lines and Distribution Transformers: There are 68 medium-voltage feeder lines
(4 kV and 12 kV) 1 originating from the nine substations. These lines are approximately
300 miles in length, of which about 60% of the line length is underground and about 40%
is overhead. Electricity from these feeders is stepped down to 120/240/480 volts via 3,150
distribution transformers that serve 25,500 residential and 4,000 commercial electric
meters. The capacity of these distribution transformers ranges from 5 kVA to 75 kVA in
residential neighborhoods, with a typical 25 kVA transformer serving 7 to 8 homes on
average. Larger transformers that serve commercial areas are rated up to 2500 kVA.
• Customer Loads: In 2017, CPAU observed a system peak load of 183 MW and annual
energy purchases of 960,000 MWh (at COP substation). About 80% of the electricity was
delivered to commercial customers and 20% to residential customers.
• Supervisory Control and Data Acquisition (SCADA): Sensors and communication
equipment at COP, nine substations, and feeder lines provide visibility of the system via
a SCADA system.2 Upon the implementation of an Advanced Metering Infrastructure
(AMI) system, loading of distribution transformers and voltage along the feeder lines will
1 Feeders are the electrical wires that carry power from sub-stations to customer load. Majority of feeder lines of
CPAU distribution system are rated at 12 kV, with MVA ratings from 5.75 to 10.76.
2 The SCADA system helps CPAU’s planning and operations with the availability of real-time and 5 minute interval
data acquisition.
Attachment – B
2
also become visible to the distribution system operators and will help CPAU to better
integrate DERs.
Figure B.1. below provides a schematic representation of CPAU distribution system.
Figure B.1. Schematic of the CPAU Electric Distribution System
II. Distribution System Observed Performance
• System loading: Figure B.2. represents the maximum and average hourly load profile of
the system observed at COP in calendar year (CY) 2016. CPAU distribution system peaked
in late afternoon hours (2 to 5pm) on weekdays in summer time.
Attachment – B
3
Figure B.2. Maximum and Average Hourly Load Profile at System Level (COP)
Data Source: SCADA data aggregated at COP across 115 kV to 60 kV stepdown transformers
• Substation transformers loading: CPAU substations have two or more stepdown
transformers at each location with a back-up transformer available in most locations.
Cumulative maximum rating across all substation transformers is 452 MVA and 50% of
emergency ratings is about 250 MVA. In CY 2016, CPAU system peaked on September 26
around 4:05 pm with additional capacity of about 85 MVA available (compared to 50%
emergency ratings).
• Feeder Lines Loading: Figure B.3. below represents the feeder lines capacity and
maximum loading observed in CY 2016. Most feeders are currently operating at healthy
margins and not reaching their peak rated capacities. Some feeder lines are reaching close
to the rated capacities (e.g. feeders in substations 7) and these loads could be rebalanced
by shifting loads to lesser loaded feeders.
Attachment – B
4
Figure B.4. below maps minimum load observed on each feeder line in CY 2016 and
existing solar PV capacity installed. Most 12 kV feeder lines have 0.5 MW to up to 3 MW
of available capacity before connected solar capacity reaches a level equivalent to the
minimum feeder load.
Figure B.3. Feeders capacity (MVA) and maximum observed loading (MW) in CY 2016
Figure B.4. Minimum feeder loading (in CY 2016) and existing solar PV capacity (MW)
• Distribution Transformers:
CPAU distribution system has 3,150 distribution transformers serving about 25,500 residential
and 4,000 commercial electric meters. Currently, CPAU does not have visibility in the real-time
loading of these transformers. Staff performs average summer and winter peak load estimation
based on engineering formulae. Staff expects to have better visibility in the real-time loading of
Attachment – B
5
these components, with deployment of AMI and accurate mapping of distribution transformers
to meters served.
Figure B.5. below shows a count of the distribution transformers according to their kVA ratings.
One-third of these distribution transformers are rated at or less than 25 kVA. These are mostly
residential transformers serving an average of 7 to 8 customers. High voltage rating transformers
(> 75kV) serves medium and large commercial customers. The largest distribution transformer
on CPAU system is rated at 2,500 kVA.
Table B.2. below provides count of distribution transformers by their physical location: pad
mount, pole top or underground. Majority of the distribution transformers (1,782) are located
on pole top and represent lower rating (<75 kVA) serving residential neighborhoods.
Figure B.5. Count of distribution transformers and their corresponding rated capacity (kVA)
0
200
400
600
800
1000
1200
5
7.
5 10 15 25 30
37
.
5
45 50 75
10
0
11
2
.
5
15
0
16
7
22
5
30
0
50
0
75
0
10
0
0
15
0
0
20
0
0
25
0
0
(b
l
a
n
k
)
Co
u
n
t
o
f
d
i
s
t
r
i
b
u
t
i
o
n
t
r
a
n
s
f
o
r
m
e
r
s
kVA Rating
Attachment – B
6
Table B.2. Distribution transformers count by their location: padmount, poletop, or underground
III. Distribution System Assets Value
Table B.3. represents acquisition cost and asset book value of various components of the CPAU
electric distribution system. CPAU system has total net asset book value of 165.5 million
(depreciated, net).3 The table illustrates the relative magnitudes of investments in various
distribution components, and provides a broader perspective to the DER integration discussion.
For example, net book value of electric meters in the table is $2.3 million. With the
implementation of AMI, these older meters would be retired and replaced with AMI meters. The
acquisition cost of the AMI meters is estimated at $5 to $ 6 million and will be depreciated over
a 15 to 20 year period.
3 As of June 30, 2017. The City reports this net capital assets position in the annual Comprehensive Annual
Financial Report as well, see p.g 38. https://www.cityofpaloalto.org/civicax/filebank/documents/62344
Distribution Transformer Type Count
Padmount single phase 244
Padmount 3 phase 690
Pole top 1782
Underground Commercial 109
Underground Residential 325
Total 3,150
Attachment – B
7
Table B.3. Capital Asset Value of the Distribution System Components
Electric Capital Assets
Acquisition
Value
(Million $)
Accumulated
Depreciation
(Million $)
Assets Book
Value
(Million $)
ELE - Equipment -Meters 4.8 (2.5) 2.3
ELE-Equip- Street Lighting 10.0 (7.5) 2.5
ELE-Equip- Traffic Signal 12.3 (9.4) 2.9
ELE-Equip- Communicatcation 1.0 (0.6) 0.3
ELE-Equip-Communication underground duct 0.9 (0.9) 0.0
ELE-Equip- Substation 41.3 (19.3) 22.1
ELE-Equip- Underground conduits, manholes and vaults 28.6 (11.0) 17.6
ELE-Equip- Distribution Transformers 20.4 (10.3) 10.1
ELE Equip-Pole, Tower , fixtures 30.8 (14.7) 16.1
ELE-Equip- Overhead Conductor 18.6 (5.4) 13.2
ELE-Equip- Underground Conductor 64.2 (24.4) 39.8
ELE-Equip-Tools, Estimating Software 2.6 (2.4) 0.2
ELE-Bldg.-Gen Plant 4.4 (1.9) 2.5
ELE-Services (all-in costs of performing system services,
not including equipment cost)51.6 (18.6) 33.0
ELE-Equip-Misc. Equipment ( SCADA web portal, vehicles,
GIS workstation, CAD , Utility billing system)19.5 (16.6) 2.9
TOTAL 311.0 (145.5) 165.5
ATTACHMENT – C
Literature Review of Benefits and Challenges of DERs in Distribution System Operations
DERs may have disparate impacts and benefits on the distribution system depending on size,
type, technology, location, engineering practices, and penetration level. Table C.1. below lists
potential benefits of well-integrated DERs whereas Table C.2. illustrates challenges in
integrating DERs growth. These benefits and challenges are listed based on the basis of industry
literature review and may not specially be applicable to the CPAU distribution system.
Table C.1: Potential Benefits of Well integrated DERs to the Distribution System
+ Feeder Voltage
Support (especially
toward the end of
the feeders)
There is a gradual drop in the feeder line voltage depending on the feeder
length and load connected to the line. Commonly, automatically
adjustable On Load Tap Changers (OLTC) or switched capacitors devices
are used to provide voltage support.1 Well-integrated features of
advanced solar PV or ES inverters can also provide the voltage support.2
However, this requires advance communications on the distribution
operations side.
+ Peak Shaving
(potential for
investment
deferral)
Coordinated operations of customer-sited DERs (solar PV, ES, and DR) can
reduce the system or a substation peak demand and hence defer the
need to upgrade major components of the system (such as substation
transformers, feeder lines, and distribution transformers).
+ Loss Reduction
Distributed generation is co-located with customer load, and hence
avoiding transmission and distribution system losses. 3
+ Potential for
Intentional
Islanding
(microgrid) to
Enhance Reliability
Distributed generation along with ES and smart controls can be designed
to operate in a microgrid fashion. It can be disconnected from the
distribution grid in case of emergency and provide backup power to the
host site.
1 OLTC are located at distribution substations and they raise the starting voltage for a feeder under load, so that
points along the feeder have desired voltage levels. Distribution system operators are required to maintain the
feeder and secondary system voltage within certain limits (ANSI voltage limits standards of ±5%).
2 Through reactive power set points or by dynamic volt/var related response. For example, see NREL technical
report on Duke Energy case study: Feeder Voltage Regulation with High-Penetration PV Using Advanced Inverters
and a Distribution Management System
3 Transmission system in California has annual losses of around 2-3% CPAU’s distribution system incurs ~2.5%
losses.
Table C.2: Potential Challenges of Integrating DERs to the Distribution System
– Distribution
Transformers
Thermal Rating
Violations or
Overloading
Transformer overloads can occur when some contingency conditions
occur or if they are already at operating 80%-90% of their full nameplate
rating and extra capacity is needed (especially during hot summer
months). Unmanaged EV charging or other DER loads in the late evening
hours can trigger such overloading. In practice, transformers can be
overloaded to a certain extent to keep the continuity of the load for
economical or reliability reasons. However, this could lead to loss of
useful life of the transformers.4
– Voltage Increase on
a Feeder
Legacy distribution systems are designed for the radial flow of the power
(i.e. power flow in unidirectional from the medium voltage system to the
low voltage system). However, at a high penetration level of distributed
generation, there are instants when the net production on a circuit is
more than the net demand (especially at noon), and as a result, the
direction of power flow is reversed. This reverse flow of power can result
in over voltages along the distribution feeders.5
– Voltage
Fluctuation,
Protection Issues,
Load Masking,
Wear and Tear of
Circuit Apparatus
(tap changers and
switches
Distributed solar PV generation gets impacted by shading due to passing
clouds, temperature, and insolation variations. This results in in
fluctuations in its output power of the PV system. Higher penetration of
PV resources on a given line can cause voltage fluctuations and further
nuisance switching of capacitor banks.6
4 https://www.fleetcarma.com/impact-growing-electric-vehicle-adoption-electric-utility-grids/
5 There are many industry articles documenting this trend. For example refer to, Technical Impacts of Grid-
Connected Photovoltaic Systems on Electrical Networks, Journal of Renewable and Sustainable Energy
6 NREL Technical report on High-Penetration PV Integration Handbook for Distribution Engineers
Attachment - D
1
ATTACHMENT – D
Approach to Distribution Transformer Sizing and Installation Economics
I. Current Practices to Size Distribution Transformer
Engineering staff estimates the size of distribution transformers by taking into account factors
related to the customer load and using the electrical engineering industry best practices for sizing
that have evolved over time. The design factors considered for commercial and residential
demand estimation are different. Traditionally, commercial loads require larger transformer
capacity, hence approach for sizing these devices has been more detailed that the sizing approach
used for residential transformers.
• Estimating Commercial and Industrial Demand
Staff utilizes various techniques to estimate the kVA demand of commercial or industrial loads.
Most medium and large commercial customers have summer peaking load and equipment sizes
of 75 kVA or greater. These larger size transformers are mostly pad mounted. Commercial
customer load estimation techniques include:
o Load estimation based on comparable locations: If there exists a similar business
type with similar electrical design, then this approach is effective to estimate the
demand and it provides quite accurate results.
o Load estimation based on connected load: All new connection applications for
electric service are required to complete an electric load sheet. This sheet
summarizes the customer’s connected loads by type. Total demand can be
estimated by applying appropriate demand factor for each load type.
o Load estimation based on building area: Engineering staff use reference tables
listing typical load factors, power factors, and maximum demand by square
footage for various business types.
o Load estimation based on customer electrical panel size: Engineering staff use
reference tables listing typical utilization factors for various business types.
• Estimating Residential Demand
CPAU currently considers two approaches to estimate residential load demand. These sizing
approaches are derived using historic regression for residential customer load and considering
Bay Area weather conditions. Figure D.1. shows the demand estimation by two methods for a
typical household with an average monthly usage of 500 kWh per month per customer. These
approaches imply on an average 2 to 3 kW of demand per residential household. Engineering
staff uses the best judgment to evaluate the results of these approaches and includes
Attachment - D
2
considerations for equipment and labor costs to recommend appropriate equipment size as
needed at the time of upgrades or new connections.
Figure D.1. Demand estimation for sizing residential distribution transformers
Staff is currently reviewing if and how these sizing standards should be updated to consider
increasing Electric Vehicle (EV) load in the residential areas. The current sizing approach is
susceptible to growing electrification load and installations of Level-2 EV chargers at home.1 Staff
plans to undertake a comprehensive review of the existing residential transformers inventory
along with considerations for changing EV loads. With the implementation of AMI capabilities,
CPAU will have additional visibility regarding the real time loading of this equipment.2
II. Distribution Transformers Installation Economics
Distribution transformers installation economics are mainly dependent on two factors: equipment costs
and labor costs. It also depends on how many customers the equipment could serve. Table D.1. below
provides a range of cost estimates for example distribution transformers sizes located at pole-top, vault-
mounted (or underground) and pad-mounted. Please note that these estimates are provided to guide the
discussion of the distribution system assessment and does not necessarily represent CPAU actual costs
for each upgrade. Each upgrade or new connection request may have different installation costs
depending on the case –specific needs.
1 A Level-2 charger can put a peak demand of 7 to 19 kVA.
2 Most California utilities have incorporated monitoring and upgrade alerts for the distribution transformers based
on the real-time AMI data.
0
20
40
60
80
100
0 10 20 30 40
De
m
a
n
d
(
k
W
)
Number of houses
Approach 1
Approach 2
Attachment - D
3
Table D.1 Cost Estimates of Distribution Transformers
Transformer Ratings and Location Equipment Costs ($) Labor Costs ($) Total Costs ($)
5 kVA to 25 kVA Pole top $1,000 - $3,000 $3,000 - $7,000 $4,000 - $10,000
25 kVA Pad-Mounted $3,000 - $7,000 $5,000-$9,000 $8,000 - $16,000
75 kVA Pad-Mounted $7,000 - $12,000 $7,000 - $12,000 $14,000 - $24,000
100 kVA - 750 kVA Vault Mounted
(underground) $7,000 - $20,000
$11,000 - $16,000 $18,000 - $36,000
1000 kVA or 25,000 kVA Pad-Mounted $20,000 - $50,000 $13,000-$20,000 $33,000 - $70,000
III. Illustration of Transformer Sizing and Decision Making Process to Upgrade Distribution
transformers
For example, if a 25kVA transformer is currently serving 7 homes, the estimated loading of the transformer
(assuming 3kVA loading on each home) is 21kVA, below the 25 kVA rating. If three of these homes
purchase EVs that have the potential of charging at between 3 kVA (Level-1 charging) and 7 to 19 kVA
(Level-2 charging), then most likely the 25 kVA transformer would not suffice.
In such a case, CPAU has two options. If another pole is available to mount another 25 kVA transformer,
mount a second transformer and serve 3-4 homes from each transformer. Or the alternate would be to
bring down the 25 kVA transformer and mount a 37.5 or 75 kVA transformer. If the transformer rating
exceeds 75kVA, the weight is too heavy to mount on poles, hence has to be mounted on the ground on a
pad – this tends to be more expensive.
City’s current practice, is to charge the customer who triggered the upgrade to pay for the upgrade cost.
CPAU currently has a Utility Service Capacity Fee Rebate program to help residents install EV chargers and
be eligible for a rebate up to $3000 for these system costs.3
3 CPAU Capacity Fee Rebate program -
https://cityofpaloalto.org/gov/depts/utl/residents/sustainablehome/electric_vehicles/ev_chargers_for_homes/20
17_utility_service_capacity_fee_rebate.asp
Attachment E
1
Technical Addendum for Distributed Energy Resource (DER) Projections
Initial projections for DER technologies were developed to inform both the proposed DER Plan as
well as ongoing work regarding DERs. These projections will be updated as more detailed market
assessments are performed.
The distributed energy resources considered for the purposes of these analyses were:
- Energy Efficiency (EE)
- Solar Photovolatics (PV)
- Electric Vehicles (EV)
- Demand Response (DR)
- Energy Storage (ES)
- Heat-pump Water Heaters (HPWH)
- Heat-pump Space Heaters (HPSH)
1. DER Adoption Projections
Preliminary forecasts of the number of DER systems through year 2030 are shown below in Table
1. The 2030 estimates are highly variable, as they depend on market conditions, technological
innovations, and changing regulations, and therefore these estimates could increase or decrease
by up to 50%.
Table 1: Estimated number of DER systems through 20301
Estimated Number of Systems
DER Technology 2017 (current) 2020 2030
PV 1,000 1,300 2,500
EV 2 2,500 5,900 18,700
EE 40,880 45,000 60,000
DR 8 25 75
ES 11 85 580
HPWH 10 200 2,700
HPSH 0 25 800
Assumptions & Limitations:
These projections were developed for long-term load forecasting and budgeting purposes.
They reflect current realistic estimates of technology adoption rates. The current forecasts do
not achieve S/CAP goals by 2030, but staff will be coordinating with the sustainability team to
1 These estimates represent current base case scenarios. Staff will explore appropriate high and low scenarios in
further modeling.
2 This is the total residential EVs currently registered in Palo Alto. There are also EVs which commute into Palo
Alto, some of which charge while in Palo Alto and add to CPAU electricity sales. In addition to the residential EVs
shown here, there are estimated to be approximately 3,100, 5,900 and 20,000 commuter EVs in 2017, 2020 and
2030 respectively.
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accelerate adoption wherever cost-effective. These forecasts will be updated regularly and
staff will continue to collaborate with other departments to support City sustainability goals.
- EE: Adoption rates for EE are based on the 10-year Energy Efficiency Goals for 2018-2027
which were updated in 2017.3 For the years 2028 through 2030 the assumed savings are
the average of the savings in 2026 and 2027 which is the methodology suggested by the
CEC for estimating savings beyond the 10-year goals.4 More details on the EE
methodology for market potential can be found in Staff Report 7718 from March 6, 2017.
- PV: These projections are based on a technical and economic potential, with adoption
growing steadily, with the growth rate itself plateauing as is typically seen in a maturing
market. These projections include behind the meter installations in residential and
commercial sectors, but do not include a Community Solar installation. These projections
also do not include the feed-in tariff installations from the CLEAN program as these are
counted as supply resources and count towards the electric utility’s Renewable Portfolio
Standard.
- EV: To -date Palo Alto has observed residential EV adoption rates approximately three
times greater than the California statewide average, and this rate for residential adoption
relative to statewide average projections is assumed to continue to 2030. To estimate the
EV adoption rates of commuters into Palo Alto the observed adoption rate from 2017
census data for the entire Bay Area was extended to 2030.
- DR: This forecast is based on modest growth of the current voluntary large commercial
demand response program. Somewhat more robust growth is expected after AMI
implementation in 2023.
- ES: This forecast is based on statewide projections for batteries and CPAU electricity rate
structures.
- HPWH: This forecast is based on historical of PV penetration, market readiness, and CPAU
customer program management experience. Based on this forecast, staff projects a
natural gas load reduction of up to approximately 1% from HPWH by 2030.
- HPSH: This forecast is based on historical of PV penetration, market barriers, and CPAU
customer program management experience. Based on this forecast, staff projects a
natural gas load reduction of up to approximately 1% from HPSH by 2030.
2. DER Load Impact Projections
Table 2 shows the impact of DERs on CPAU’s energy sales based on the number of systems
projected in Table 1. These estimates are also highly variable, as each underlying component
could change by as much as 50% by 2030. Moving forward, the combined impact of all these
DERs is expected to lower energy sales by 2.2% by 2020 and 6.6% by 2030.5 The net effect of
projected DERs coming online after 2017 is to offset other anticipated electricity load growth
throughout CPAU territory,6 leading to essentially flat total CPAU system loads from 2017
3 Although CPAU established our EE goals based on net savings, the energy efficiency savings shown here are on a
gross basis (which includes EE savings due to free-ridership).
4 The extension of savings through 2030 is based on the methodology put forth in the CEC presentation September
7, 2017 which can be found here: CEC presentation on Energy Efficiency Savings from Utility Programs.
5 All percentages are relative to Fiscal Year 2017 electricity retail sales.
6 For budgeting purposes the Northern California Power Agency has developed an econometric regression to
forecast electric sales from 2018 to 2030 with the current level of DERs (in other words assuming no additional
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through 2030. However, a scenario with higher load growth, lower adoption of EE or PV, or
higher adoption of EVs could result in an overall growth of electricity sales.
Table 2: Estimate of the impact of DERs on CPAU retail energy sales
DER Technology 2017 (current) 2020 2030
Contribution to Energy Sales MWh % MWh % MWh %
PV -15,000 -1.6% -18,800 -2.0% -45,200 -4.9%
EV 7,100 0.8% 14,300 1.6% 54,800 6.0%
EE -55,300 -6.0% -78,800 -8.6% -139,200 -15.2%
DR 7 - 23 - 200 0.02%
ES7 - - - - - -
HPWH 9 - 190 0.02% 2,500 0.3%
HPSH - - 90 0.01% 2,800 0.3%
Combined DER Impact: from
2007 -63,200 -6.9% -83,000 -9.1% -124,000 -13.6%
Combined DER Impact: from
2017 - - -19,700 -2.2% -60,900 -6.6%
CPAU Overall System Load
Growth from 20178 - - -3,200 -0.3% -6,900 -0.8%
DERs). The CPAU overall system load growth from 2017 is the combination of this econometric forecast and the
individual DER forecasts.
7 Batteries and other ES devices may result in either net increased energy retail sales (due to battery losses where
commercial customers use batteries to avoid CPAU demand charges) or net decreased energy retail sales (due to
increased onsite consumption of behind the meter solar). For the purpose of these analyses these two effects are
assumed to be roughly the same magnitude and therefore ES systems are not considered to have any net effect on
energy sales.
8 Going forward from 2017 the total CPAU load is forecasted to grow at roughly 0.4% per year if no more DERs
were added to the system. With the addition of new DERs, the total CPAU load is projected to decrease by roughly
0.8% from 2017 electricity sales by the year 2030.
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Figure 1: Projected impact of DERs on annual electricity sales from 2018 through 2030
Another important aspect of DERs is their ability to potentially flatten overall peak demand,
especially due to PV and DR. The impact of the projected DERs on a peak summer day in 2030 is
illustrated in Figure 3, showing that the combined effect is to flatten the overall load shape and
lower the peak demand. This overall flattening of peak demand is anticipated to increase the
overall system annual load factor from 62% in 2016 to 70% in 2030.9 A higher load factor and
flatter loads tend to lower overall CPAU costs.
9 Annual Load Factor is a measure of transmission and distribution system utilization and is defined as the ratio of
average annual energy load to the peak annual energy load. A high load factor means that system capacity is
highly utilized, with average annual usage that is not much lower than the annual peak. A low load factor indicates
that electric use has a high annual peak relative to annual average usage, meaning that substantial additional
system capacity is needed to serve that high annual peak, generally resulting in higher costs due to low utilization.
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Figure 2: Potential change in hourly electric loads on a peak summer day (2017 vs. 2030)10
10 HPSH are included on a peak summer day since there is an expectation that heat-pump space heaters will be
used as air conditioners on the hottest days.