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Pursuant to the provisions of California Governor’s Executive Order N-29-20, issued on March 17, 2020, to prevent
the spread of COVID-19, this meeting will be held by virtual teleconference only, with no physical location. The
meeting will be broadcast on Cable TV Channel 26, live on Midpen Media Center at https://midpenmedia.org.
Members of the public who wish to participate by computer or phone can find the instructions at the end of this
agenda.
I. ROLL CALL
II. AGENDA REVIEW AND REVISIONS
III. 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.
IV. APPROVAL OF THE MINUTES
Approval of the Minutes of the Utilities Advisory Commission Meeting held on December 2, 2020
V. UNFINISHED BUSINESS - None
VI. UTILITIES DIRECTOR REPORT
VII. NEW BUSINESS
1. Discussion of Projected Electrification Impacts on Gas Utility System Average Rates Discussion
2. Discussion and Update on Lifecycle Emissions for Gasoline, Natural Gas and Electricity Discussion
Consumed in Palo Alto
VIII. COMMISSIONER COMMENTS and REPORTS from MEETINGS/EVENTS
IX. FUTURE TOPICS FOR UPCOMING MEETINGS: February 03, 2021
SUPPLEMENTAL INFORMATION - The materials below are provided for informational purposes, not for action or
discussion during UAC Meetings (Govt. Code Section 54954.2(a)(3)).
Informational Reports 12-Month Rolling Calendar Public Letter(s) to the UAC
UTILITIES ADVISORY COMMISSION – SPECIAL MEETING
WEDNESDAY, January 6, 2021 – 4:00 P.M.
ZOOM Webinar
Chairman: Lisa Forssell Vice Chair: Lauren Segal Commissioners: Michael Danaher, Donald Jackson, A.C. Johnston, Greg Scharff, and Loren Smith Council Liaison: Alison Cormack
MATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE COMMISSION AFTER DISTRIBUTION OF THE AGENDA PACKET ARE
AVAILABLE FOR PUBLIC INSPECTION IN THE UTILITIES DEPARTMENT AT PALO ALTO CITY HALL, 250 HAMILTON AVE. DURING NORMAL BUSINESS
HOURS.
AMERICANS WITH DISABILITY ACT (ADA)
Persons with disabilities who require auxiliary aids or services in using City facilities, services or programs or who would like information on the City’s
compliance with the Americans with Disabilities Act (ADA) of 1990, may contact (650) 329-2550 (Voice) 24 hours in advance.
• Informational Report on Annual Review of the City’s Renewable Procurement Plan,
Renewable Portfolio Standard Compliance, and Carbon Neutral Electric Supplies for 2019
• Informational Update on City of Palo Alto Utilities Electric Vehicle Programs
MATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE COMMISSION AFTER DISTRIBUTION OF THE AGENDA PACKET ARE
AVAILABLE FOR PUBLIC INSPECTION IN THE UTILITIES DEPARTMENT AT PALO ALTO CITY HALL, 250 HAMILTON AVE. DURING NORMAL BUSINESS
HOURS.
AMERICANS WITH DISABILITY ACT (ADA)
Persons with disabilities who require auxiliary aids or services in using City facilities, services or programs or who would like information on the City’s
compliance with the Americans with Disabilities Act (ADA) of 1990, may contact (650) 329-2550 (Voice) 24 hours in advance.
PUBLIC COMMENT INSTRUCTIONS
Members of the Public may provide public comments to teleconference meetings via email,
teleconference, or by phone.
1. Written public comments may be submitted by email to UACPublicMeetings@CityofPaloAlto.org.
2. Spoken public comments using a computer will be accepted through the teleconference meeting.
To address the Commission, click on the link below for the appropriate meeting to access a Zoom-
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Utilities Advisory Commission Minutes Approved on: Page 1 of 8
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF DECEMBER 2, 2020 MEETING
CALL TO ORDER
Chair Forssell called the meeting of the Utilities Advisory Commission (UAC) to order at 4:02 p.m.
Present: Chair Forssell, Vice Chair Segal, Commissioners Danaher, Jackson, Johnston, Scharff and
Smith
Absent:
AGENDA REVIEW AND REVISIONS
None.
ORAL COMMUNICATIONS
None.
APPROVAL OF THE MINUTES
Commissioner Scharff moved to approve the minutes of the November 04, 2020 meeting as presented. Vice
Chair Segal seconded the motion. The motion carried 7-0 with Chair Forssell, Vice Chair Segal, and
Commissioners Danaher, Jackson, Johnston, Scharff, and Smith voting yes.
UNFINISHED BUSINESS
None.
UTILITIES DIRECTOR REPORT
Dean Batchelor, Utilities Director, delivered the Director's Report.
• Staffing Trends
Difficulty in Maintaining Staff
Recruitment Process:
Since Jan, we’ve had 43 regular vacancies. We have hired 12 new employees and promoted 10 employees to
fill these vacancies. As of today, we have 37 regular vacancies and 30 of them are actively being recruited.
The non-active recruitment vacancies are either because they’re frozen, pending business decision (i.e. Fiber
Telecom Manager, Sr. Business Analyst), or under rotation/WOC (i.e. Mgr. Electric Operations, AD
Engineering).
DRAFT
Utilities Advisory Commission Minutes Approved on: Page 2 of 8
• Clean Fuel Reward Program - Effective November 17, all Palo Alto residents purchasing electric
vehicles are eligible for a Clean Fuel Reward point-of-sale rebate of up to $1,500 at participating car
dealerships. CPAU has contributed Low Carbon Fuel Standard (LCFS) funds towards this new
statewide initiative, which was approved by City Council in May 2020. CPAU expects to contribute
$300-400,000 annually for the next 10 years. All auto dealerships in Palo Alto will be notified of this
opportunity to lower the cost of new electric vehicles.
• CALeVIP - The California Energy Commission’s California Electric Vehicle Infrastructure Project
(CALeVIP), which aims to develop and implement regional incentives to support statewide adoption
of EVs, has partnered with five local energy agencies to launch a $55.2 million dollar rebate project
for the installation of public access electric vehicle (EV) charging stations throughout Santa Clara and
San Mateo counties. CPAU has committed $1 million dollars of LCFS funds to receive $1 million in
grant funding for the Peninsula-Silicon Valley Project. These funds will become available to all eligible
Palo Alto commercial customers to install Level 2 or Level 3 fast chargers over the next 2 years and
will help install approximately 200 new chargers in Palo Alto. After a prelaunch webinar on December
2nd, applications for incentives can be submitted beginning on Wednesday, December 16, 2020.
• Genie Virtual Assessment - The Home Efficiency Genie is now offering a new virtual assessment
platform which provides residents with a remote evaluation of their home for energy and water
efficiency. Due to the COVID-19 safety protocols, the Genie program has been unable to offer the
comprehensive in-home assessments that it had been providing since 2015. For a $49 subsidized fee,
this new virtual, phone and video-based platform allows residents to walk through their home with
guidance from the Genie technician to review and uncover inefficiencies, comfort concerns, and even
health and safety issues. For no additional charge, the virtual program also offers participants an
electrification readiness evaluation as well as energy saving products like LED bulbs and a smart
power strip.
• Fiber Expansion Project - Staff working on the citywide fiber expansion project has completed all but
one of its internal fiber needs assessment interviews. Departments assessed include: Field
Operations, Libraries, Office of Emergency Services, Commercial Fiber, Information Technology,
Utilities Engineering, SCADA and others. A gap analysis has been created for the City fiber network in
anticipation of a full system field audit. The audit will show system maintenance and capacity needs.
Fiber Management Systems, which is a network tracking, planning, maintenance and production data
hub, are being compared and reviewed for City use.
• Upcoming Events
o Tuesday, December 8, 6:30-8:00 PM - The Importance of the Natural Environment in
Meeting Our Sustainability Goals Webinar. Register here or online at
cityofpaloalto.org/climateaction
Utilities Advisory Commission Minutes Approved on: Page 3 of 8
In response to Commissioner Danaher’s inquiry about how many vacant positions are office positions and
how many are field operation positions, Batchelor confirmed that the majority are field operation positions.
In reply to Commissioner Scharff’s question regarding Level 2 chargers for residents, Batchelor explained that
commercial and multi-dwelling facilities will be subsidized for installing Level 2 and Level 3 fast chargers.
Vice Chair Segal confirmed that the next Sustainability and Climate Action Plan (S/CAP) community webinar
is Tuesday, December 8, 2020.
NEW BUSINESS
ITEM 1: DISCUSSION: Discussion on Comparison of Water Rates and Average Bills Among Cities Supplied by
San Francisco Public Utilities Commission.
Dean Batchelor, Director of Utilities introduced Lisa Bilir who presented to the Commission.
Lisa Bilir, Acting Senior Resource Planner, reported that the analysis was conducted to answer the question
posed by the Finance Committee of why the City’s rates are higher than surrounding Cities who use the same
supplier. Including the City of Palo Alto, there were 16 other Cities and entities that receive 100 percent of
their water from the San Francisco Public Utilities Commission (SFPUC) and who are members of the Bay Area
Water Supply and Conservation Agency (BAWSCA). Nine of these are cities, including Palo Alto. Residential
water bills within Palo Alto are approximately 9 percent higher than the typical group of comparison utilities
and commercial customers water bills are on average 4 to 7 percent higher than the typical comparison group
of utilities. Among the nine cities that obtain 100% of their water from SFPUC, Palo Alto’s rates are on the
low end. Six of the Cities that receive 100 percent of their water from SFPUC have less than half as many
customers as Palo Alto and those Cities have higher rates than Palo Alto. Redwood City has a similar number
of customers, the City of Hayward has double the number of customers compared to Palo Alto, and those
two Cities are the only two Cities that have lower rates than Palo Alto. Two significant factors for the
increased rates was consistently higher water infrastructure investments made by the City of Palo Alto and
Palo Alto’s residential customer class has higher usage and accounts for a higher portion of the potable water
usage than the residential customer class in the City of Hayward. Also, Hayward’s non-residential customer
class usage has increased over the last ten years while Palo Alto’s non-residential customer class usage has
decreased which puts more upward pressure on Palo Alto’s rates.
In response to Commissioner Johnston’s query regarding rate tiers, Bilir explained that the City has a two-tier
water rate system that is based on a measure of average use and more tiers would result in a different service
rate cost structure. Palo Alto’s rate structure is based on the results of the cost of service and the same is
true for the other cities where they have a different number of tiers. Commissioner Johnston suggested that
the Utilities Advisory Commission (UAC) review the City’s tier system next time water rates are discussed.
In answer to Commissioner Scharff’s questions regarding infrastructure and if the City is making the right
investment, Bilir confirmed that other Cities across the county are underinvesting in their infrastructure.
Jonathan Abendschein, Assistant Director of Utilities, believed that the City does not over or under-invest in
infrastructure projects. The reservoirs and the wells provide an appropriate level of emergency response
investment. He added that the amount of storage in the reservoirs is the right amount for the existing
infrastructure, but the location of them in the Foothills adds to the cost. Commissioner Scharff predicted that
main replacements done in the City of Hayward would cost a similar amount that the City was paying for its
replacements. In response to his inquiry of do all the reservoirs need to be updated, Abendschein commented
that staff continues to explore ways to make the reservoirs more cost-efficient.
In reply to Commissioner Smith’s query of why the City’s commercial average is not higher than the City of
Hayward, Bilir answered that the City of Hayward does have a tiered rate for their commercial customers and
Palo Alto charges a flat volumetric rate. In response to his additional questions, Bilir confirmed that
commercial customers pay a flat service charge depending on meter size. She clarified that some water
Utilities Advisory Commission Minutes Approved on: Page 4 of 8
meters are upsized for residential uses for fire prevention and the shape of the customer’s service and as
part of the cost of service study, the meter sizes were consolidated for 1” meter and smaller. There is no rate
consolidation for commercial customers as there is for residential customers because commercial customers
have to have a separate fire meter. The cost of service study closely studied costs and usage to set rates
appropriately for each customer class in Palo Alto. Commissioner Smith believed that more investigation is
needed to understand the flat volumetric rate that the City charges commercial customers.
In reply to Chair Forssell’s question regarding why the comparison did not include other BAWSCA partners
that are not Cities, Bilir shared that the Finance Committee had specifically requested that surrounding Cities
be included in the comparison. Chair Forssell requested that a future study highlight inflection points showing
the usage level above which one city’s bills become more than another city’s.
In answer to Vice Chair Segal’s inquiry of why the study used the average of 9 centum cubic feet (CCF) when
the City’s average is 11 CCF, Bilir mentioned that historically the average bill comparison study used 9 CCFs
and that was used for consistency and predicted that the report would not change much if 11 CCF was used.
Vice Chair Segal wanted to understand what the report would be if the true average volume metric was used.
In response to Councilmember Cormack’s inquiry of when the report will come back to the Finance
Committee, Bilir believed it would come with the Financial Plan for the Water Utility to the new Finance
Committee.
ACTION: None.
ITEM 2: ACTION: Staff Recommendation That the Utilities Advisory Commission Recommend the City Council
Decline to Adopt Energy Storage System Target and Received the 2020 Energy Storage Report.
Jonathan Abendschein, Assistant Director of Utilities, introduced Lena Perkins who presented the item to the
UAC.
Lena Perkins, Senior Resource Planner shared that the Energy Storage Report will be submitted to the
California Energy Commission (CEC) and it shows that the City has investigated the cost-effectiveness of
energy storage and examined setting targets for energy storage within the City. CPAU is required to
investigate energy storage every 3-years and in 2011, 2014, or 2017, CPAU did not choose to set energy
storage targets. The 2020 CPAU and Smart Energy Power Alliance (SEPA) analysis showed that energy storage
is not yet cost-effective for the City. For this reason, CPAU will not be setting energy storage targets for 2020
but will continue to look at opportunities and align incentives. Batteries can be used to lower carbon
emissions as well as leverage distributed batteries for society and improve resiliency in catastrophic events.
The overbuilding of renewables at the utility-scale was still less costly than batteries and there is no carbon
price in the State of California that is enough to make batteries more cost-effective. Batteries that are
installed at a residence that has solar panels are not saving the owner money. A commercial customer could
use a battery to provide demand charge mitigation and they could save money, but there is no benefit to the
utility because peak demand for a commercial is not in alignment with grid peak demand. Staff suggests
starting a pilot project that uses electric heat-pumps as distributed thermal storage as a less expensive
alternative.
In answer to Commissioner Jackson’s query regarding using smart devices to leverage flexible demand
response programs, Perkins explained that differing smart electrical vehicle (EV) charging stations to be used
past 10:00 pm could be valuable to the utility, wholesale market, and the grid at large. Commissioner Jackson
disclosed that incentive-based communications should be sent to residential customers about what should
and should not be happening as a way to encourage behavioral changes.
In reply to Commissioner Danaher’s questions, Perkins confirmed that Staff continues to explore any storage
that is competitively priced. In the next Energy Integrate Resource Plan for the Electric Utility, there is a
comparison between solar storage and other renewables in storage compared to the full share of the
Utilities Advisory Commission Minutes Approved on: Page 5 of 8
Western Base Resource Contract. In regards to Assembly Bill (AB) 2514, the bill addresses both utility and
customer energy storage.
In answer to Vice Chair Segal’s question regarding time of use, Perkins confirmed that is it hard to
communicate with customers in a way that benefits the utility on how storage is used without time of use. It
is easier to make sure there are no misalignment incentives once the time of use is implemented.
In reply to Chair Forssell’s queries, Perkins disclosed that she explored water pumped hydro storage and
found out that there are a lot of operational and operator constraints in how the system is managed
currently. Abendschein added that the amount of water storage within the Foothills is very small, but there
is an opportunity to replace the pressure reducing values with a turbine to capture power. In regards to the
Self Generation Incentive Program (SGIP) Fund, Perkins noted that the fund is only available to investor-
owned utilities. In response to Chair Forssell’s question regarding is there a carbon price at which point
storage would become effective, Perkins confirmed that $200 a ton is the price carbon would have to be for
it to be cost-effective for residential, but it could be already cost-effective in terms of EV chargers.
ACTION: Commissioner Johnston moved, seconded by Commissioner Jackson that the Utilities Advisory
Commission (UAC) recommend that Council accept staff recommendation to adopt no energy storage targets
in 2020 under AB2514. The motion carried 7-0 with Chair Forssell, Vice Chair Segal, and Commissioners
Danaher, Jackson, Johnston, Scharff, and Smith voting yes.
The UAC took a 5-minute break at 5:34 pm.
ITEM 3: DISCUSSION: Discussion and Update on the FY 2022 Preliminary Utilities Financial Forecast and Rate
Projections.
Eric Keniston, Senior Resource Planner reported that it would be beneficial if the Gas Utility and Waste Water
Collection Utility receive a 3 percent rate increase for FY 2022.
Lisa Bilir, Acting Senior Resource Planner disclosed that a 3 percent increase would result in a $1.24 per month
increase for residential customers and a $0.24 per CCF of winter average usage increase for commercial
customers. The drivers for the rate increase was due to large infrastructure projects on the 5-year horizon
for the Waste Water Treatment Plant as well as the ongoing Capital Improvement Projects (CIP) for the
collection system. The rate trajectory will likely not require any cost cuts during the 5-year forecast period,
however, there is uncertainty in the timing of treatment cost increases and cost cuts may be needed even
with the 3 percent increase in FY 2022. The Alternate proposal is zero percent increase for FY 2022 and 5
percent increase in each subsequent year. Under this scenario, $3 to $4.5 million cost cuts would be needed
between now and FY 2026 in order to keep reserves above minimum levels.
In response to Commissioner Scharff’s question regarding residential customers averages, Bilir explained that
the wastewater rate for a residential dwelling unit is a flat monthly charge and the 9 ccf average is the median.
Staff continued with their presentation. A Cost of Service Study is underway for the Waste Water Collection
Utility with an outside consultant and the results will be presented to the UAC in early 2021. The Regional
Water Quality Control Plant (RWQCP) treats sewage from six communities and is managed by the City’s Public
Works Department. The City pays roughly 36 percent of the Waste Water Treatment Fund expenses with the
other five partners paying the remainder. Treatment costs were predicted to increase steeply due to
rehabilitation work being done to the RWQCP and collection costs were increasing at an inflationary level.
The Long-Range Facility Plan that was completed in 2012 identified key maintenance projects that needed to
take place at the RWQCP. Those projects include the replacement of the sedimentation tank which costs $17
million, outfall pipeline costing $11 million, laboratory/operation center costing $59 million, and secondary
treatment upgrades costing roughly $88 million. Key drivers involved in the rate increase for wastewater
collection included salary and benefits costs for existing staff as well as large CIPs every other year.
Utilities Advisory Commission Minutes Approved on: Page 6 of 8
In answer to Commissioner Smith’s question about if staff’s model included the projection for the sale of
effluent to the Santa Clara Valley Water District, Karin North, Assistant Director of Public Works clarified that
no revenue would be received from Santa Clara Valley Water District for the sale of effluent until after the
Regional Purification Center is built. The City continues to make investments at the RWQCP to meet current
National Pollutant Discharge Elimination System (NPDES) permit requirements. In reply to his inquiry
regarding if the Regional Purification Center project is reflected in the year on/year off replacement plan,
North confirmed that it is included in the long-range projections for the Wastewater Utility, but the City will
pay only a small portion of the costs. Abendschein clarified that the orange bars on the chart showing the
on/off year replacement plan are costs for the collection system, not for the treatment plant.
Staff continued with their presentation and moved to the Wastewater Operation Reserve. The Wastewater
Operation Reserve will be brought close to a minimum balance in FY 2026 due to capital costs needed on the
collection side as well as increased costs on the treatment side. Staff moved to the Water Utility where Staff
proposed a zero percent increase in FY 2022. The FY 2020-year end Operation Reserve was above guideline
levels and projected to be at target levels by year-end of FY 2022. In the most recent Financial Plan, Council
approved a plan to make more active use of the Water Utilities CIP Reserve. Staff projected there to be a 5
percent annual increase in the Water Utility beginning in FY 2023 to FY 2026 due to a series of wholesale cost
increases anticipated to begin in FY 2023. The City receives its water from the Hetch Hetchy system and
included in the water supply cost is the upkeep of that system. The City has its own distribution system within
the City that is operated and maintained by the City. The supply cost for the Water Utility is roughly 40
percent of the total cost with distribution making up the remaining 60 percent. The long-term cost trends
show that the distribution system cost will increase 3 percent annually and the supply costs are predicted to
increase by 6 percent annually. The largest cost driver for increased supply costs is the Water System
Improvement Program (WSIP) but the program benefits the City by making sure the water supply system is
seismically sound.
Keniston continued the presentation by presenting the Electric Utility. He reported that a $10 million loan
was taken from the Electric Special Project Reserve to help the Operations Reserve maintain its target level.
One $5 million payment has already been made but Staff suggested to not make another payment until FY
2022 or FY 2023 due to COVID-19 impacts.
In response to Chair Forssell’s questions regarding what the Electric Special Project Reserve is used for and if
there are upcoming projects, Keniston answered that the reserve pays for large projects that would otherwise
need to be bond-financed. One project in the pipeline is the Smart Grid Project.
In reply to Vice Chair Segal’s inquiry of if undergrounding utilities can use the Electric Special Projects Reserve,
Keniston answered no. Abendschein mentioned that the UAC and Council have a policy role in setting the
use of the Electric Special Project Fund and undergrounding could be included in the list of approved uses.
Keniston continued the presentation and declared that reserve margins are at the minimal level. Some
combination of reserve withdrawals, cost reductions, or rate increases may become necessary if sales
continue to decline. Overhead costs have decreased, transmission costs continue to increase, and as
renewable projects come online, the long-term generation costs should remain stable. Distribution costs
drivers include medical and retirement benefits, increased CIPs due to an aging system, underground
construction continues to be more expensive than above-ground utilities, and additional line crew expenses.
Customer electric bills continue to be below Pacific Gas and Electric (PG&E)’s bills by 34 percent. If a 5 percent
rate increase is not adopted for subsequent years, the Electric Supply Operating Reserve will fall below the
minimum mark. Moving to the Gas Utility, it was mentioned that the cost of maintaining the distribution
system is the main driver in the rate increase. Staff recommended a 3 percent rate increase for the Gas Utility
for FY 2022. If a zero percent increase were adopted, $5.4 million would be needed for as one-time cost
reduction in FY 2023 and FY 2024 to keep reserves above the minimum. Staff has been seeing lower sales in
the Gas Utility than was predicted.
Utilities Advisory Commission Minutes Approved on: Page 7 of 8
In answer to Commissioner Johnston’s query about where the additional $5.4 million reductions would come
from, Keniston predicted that there would be delays in CIPs most likely.
Continuing with the presentation, Keniston noted that the Gas Utility served roughly 20,000 customers
through 18,000 service lines and 205 gas mains which were all fixed costs. Roughly 60 percent of the Gas
Utility cost structure is fixed cost and the other 40 is related to supply costs. Long -term predictions indicated
that the utility will increase due to inflation and market-driven costs. Distribution costs were trending at an
increase of 2- to 3-percent over the next 5-years. Customer’s gas bills were still falling below PG&E at 8
percent on average.
In reply to Vice Chair Segal’s query about defaults on bills, Keniston concurred that delinquent payments
continue to rise. Dave Yuan, Strategic Business Manager added that there have been more bankruptcy filings,
but in terms of residential installment plans, staff has requested that customers call back when the local
emergency has been called off so that staff knows the true outstanding balance.
Keniston reiterated that gas sales have been drastically lowering than what was predicted and with a 3
percent increase, staff believed that the gas sale estimates will return to recovery mode in FY 2023. Staff
continues to monitor the utility.
Councilmember Cormack reported that Council had a wide-range business recovery discussion and it was
discovered that it could take up to 4-years to recover economically from the COVID-19 pandemic. There was
also a discussion regarding a hybrid option of employees working half a week in the office and the other half
at home.
Keniston continued that with a 3 percent increase for FY 2022 following by a 5 percent increase in subsequent
years, the Gas Operating Reserve is projected to drop down to the minimum mark in FY 2023 and will not
recover until FY 2025 and FY 2026. With a zero percent increase in FY 2022, that would result in a $5.4 million
cost cut to keep the reserve above minimums.
In answer to Chair Forssell’s question regarding rapid escalating construction costs, Yuan confirmed that
construction costs continue to go up steadily but not as fast as it was. Batchelor concurred that construction
cost increases are still taking place over all the utilities.
In reply to Commissioner Danaher's questions, Keniston disclosed that staff always projects an average water
year and there is a Hydroelectric Stabilization Reserve within the Electric Utility that is used during drought
years. There was roughly $12 million in the Hydroelectric Stabilization Reserve.
In response to Commissioner Smith’s queries, Keniston confirmed that the increase that was adopted for the
Renewable Energy Certificates (REC) was included in the projections.
In answer to Chair Forssell’s inquiries, Keniston restated that with a zero percent rate increase in the Electric
Utility, the cost cuts would most likely come from CIPs. Bachelor confirmed that the main replacement project
was already reduced in size to keep reserves at a healthy level. Another possible project to find cost cuts is
to postpone the cross-bore project for another year. Chair Forssell supported a 3 percent increase for FY 2022
for the Gas and Wastewater Utilities.
Commissioner Danaher also supported a 3 percent increase for the Gas and Wastewater Utilities.
Commissioner Johnston announced his support of staff’s recommended increases to the Gas and Wastewater
Utilities.
Vice Chair Segal concurred with her colleague’s support of the increase and believed that a no rate increase
would result in a delay of critical CIPs and most likely make them more expensive in later years.
Utilities Advisory Commission Minutes Approved on: Page 8 of 8
Commissioner Scharff affirmed his support for staff’s recommended 3 percent increase for both utilities.
ACTION: None
ITEM 4: ACTION: Selection of Budget Subcommittee
Commissioner Jackson, Commissioner Smith, and Vice Chair Segal volunteered to be on the Budget
Subcommittee.
ACTION: None
REPORTS FROM COMMISSIONER MEETINGS/EVENTS
None.
FUTURE TOPICS FOR UPCOMING MEETINGS: January 02, 2021
Chair Forssell requested that Commissioners disclosed if the item they wish to see come before the
Commission is a discussion item or an informational item.
Commissioner Danaher appreciated the upcoming update on EV charging developments. In response to his
question about what the Development Center presentation is, Batchelor confirmed that it will be a
presentation regarding home electrification and the permit process. Commission Danaher requested an
informational item each month regarding billing trends and user trends. Chair Forssell agreed with that
suggestion.
Commissioner Smith wanted to see a financial forecast and cost presentation on the dark fiber network.
Batchelor reported that an update on underground utilities will be brought forward to the Commission in
possibly February or March of 2021. Commissioner Scharff wanted staff to include in that report the total
cost, possible rate increases, and timeframe to underground all utilities in the whole City. Batchelor disclosed
that a previous study was done and the study predicted it would cost roughly $300 million to underground
all utilities within 3 years. Another factor for underground utilities was if the City had strong wills to move to
full electrification and if so, that may be an opportunity to move utilities underground.
NEXT SCHEDULED MEETING: January 02, 2021
Vice Chair Segal moved to adjourn. Commissioner Jackson seconded the motion. The motion carried 7-0 with
Chair Forssell, Vice Chair Segal, and Commissioners Danaher, Jackson, Johnston, Scharff, and Smith voting
yes. Meeting adjourned at 6:52 p.m.
Respectfully Submitted
Tabatha Boatwright
City of Palo Alto Utilities
City of Palo Alto (ID # 11751)
Utilities Advisory Commission Staff Report
Report Type: New Business Meeting Date: 1/6/2021
City of Palo Alto Page 1
Summary Title: Gas Rate Impacts of Electrification
Title: Discussion of Projected Electrification Impacts on Gas Utility System
Average Rates
From: City Manager
Lead Department: Utilities
Recommendation
This report is submitted to the Utilities Advisory Commission (UAC) for informational and
discussion purposes only. No action is required.
Executive Summary
This report estimates impacts to the gas utility’s system average rate in three electrification
scenarios. The “system average rate” is the total gas utility revenue divided by total gas utility
sales (therms). This analysis is very preliminary and high level and is not intended to reflect any
final cost allocation or cost of service determinations. Underlying costs may change significantly
from this initial estimation and will vary significantly for individual customers. This analysis is
intended to be a first estimate to identify areas where future analysis and investigation is
needed. The scope of this analysis is limited to examining utility costs and it excludes customer
costs of electrification; those costs will be presented later as part of the Sustainability and
Climate Action Plan (S/CAP) update.
Table 1 summarizes the three electrification scenarios considered in this analysis. Scenario 1
and 2 illustrate two different paths to achieve the City’s 80% by 2030 Goal – Scenario 1 assumes
all Single-family Residential (SFR) customers are disconnected by 2030, and all other customers
also reduce their gas usage, meaning the remaining gas distribution system would be smaller.
Scenario 2 assumes customers collectively cut back their gas usage enough to achieve the City’s
80% by 2030 Goal but remain connected to the gas utility. Scenario 3 studies the midway point
to the 2030 goal: in FY 2025 while the utility is assumed to be transitioning towards
electrification and SFR customers are disconnecting from the gas system.
The table shows the estimated percentage by which gas rates in each scenario differ from a
“business as usual” scenario in 2025 or 2030. The comparison is done based on the gas utility
system average rate, rather than rates for individual customer classes. Assumptions for each
Staff: Lisa Bilir
City of Palo Alto Page 2
scenario are shown in Table 2, later in this report. However, each scenario assumes multi-family
and business customers reduce their gas usage as well as the assumed reductions in gas usage
from the single-family residential class; multi-family and business customers reduce gas usage
by the amount needed to meet or be on track to meet the City’s 80 by 2030 Goal.
Table 1: Summary of Electrification Scenarios
Scenario Number 1 2 3
Short Description All SFR* Electrified
& Disconnected
90% Reduction in
SFR* Use, No
Disconnections
On Track to Electrify
and Disconnect all SFR*
by FY 2030
Year FY 2030 FY 2030 FY 2025
Estimated System Average
Rate Impact
-16% 52% 17%
* SFR refers to single-family residential customers
** 80% by 2030 Goal refers to the City Council’s adopted goal to reduce the community’s
greenhouse gas emissions to 80% below 1990 levels by 2030
This analysis uses approximate calculations and simplifying assumptions to estimate the system
average rate impacts and notes several areas that will need additional investigation to give a
more accurate view of the impacts. This analysis defers the issue of why or how customers will
cut back or disconnect (i.e., through voluntary or mandatory requirements) and focuses
narrowly on the system average rate impacts of each scenario. This report does not examine the
customer-class specific impacts, which will be determined by a cost of service analysis.
Background
In April 2016, the City Council adopted the ambitious goal to reduce the community’s
greenhouse gas emissions to 80% below 1990 levels by 2030 (80% by 2030 goal). The
Sustainability and Climate Action Plan (S/CAP) serves as the road map for achieving Palo Alto’s
sustainability goals.
At the UAC meeting on September 2, 2020, the Utilities Department presented an overview of
utility electrification impacts that provided a summary of analyses the department was pursuing
to assess the impacts of building and vehicle electrification on the gas and electric utilities.
On November 4, 2020, the Utilities Department presented an electrification impact study to the
UAC that estimated utility cost and staffing impacts of electrification of all single-family
residential customers on the City of Palo Alto’s electric and gas distribution systems.
This report analyzes the system-wide average rate impacts of reducing gas use in buildings
enough for the building sector to contribute appropriately to meeting the 80% by 2030 goal.
According to the November 2016 S/CAP Framework,1 gas use in buildings is one of the primary
1 City of Palo Alto Sustainability and Climate Action Plan Framework, Principles, Guidelines, Goals & Strategies,
November 2016, https://www.cityofpaloalto.org/civicax/filebank/documents/60858
City of Palo Alto Page 3
sectors together with mobility measures that needs additional GHG reductions for the City to
meet the 80% by 2030 goal.2 Reducing emissions from buildings can be accomplished in a
variety of ways. One method is to target electrification of all SFR customers. Staff has identified
this as a proposed key action in the S/CAP update. Staff estimates GHG emissions reductions
from natural gas could be as high as a 60% reduction from 1990 levels by 2030; this analysis
assumes 60% reduction in GHG emissions reductions by 2030 from natural gas . The policy
question of how much reduction to target from each sector is being examined as part of the
broader S/CAP update. In this report, Scenario 1 assumes electrification of all single-family
residential gas customers together with usage reductions across all remaining gas customer
classes, and Scenario 2 assumes customers achieve usage reduction goals while remaining
connected to the gas system.
As noted above, this analysis estimates system average rate impacts for remaining gas utility
customers, not customer class-specific rate impacts. The starting point for this analysis is the
cost and revenue trajectory outlined in the FY 2021 Gas Utility Financial Plan approved by the
City Council on June 22, 2020.
Gas Bill Overview
City of Palo Alto gas bills have both a Service and volumetric charge. Current and past
commodity and volumetric rates are listed on the website including links to the rate schedules
showing service charges. The volumetric charge depends on each customer’s consumption and
has five components: 1) Commodity Rate, 2) Cap and Trade Compliance Charge, 3)
Transportation Charge, 4) Carbon Offset Charge, and 5) Distribution Charge. The rate for
components 1 through 4 varies monthly based on the current price of gas. More information
about these charges is available on the website listing of monthly retail gas charges.
The Distribution Charge together with the Service charge represent the costs to physically
maintain and operate Palo Alto’s gas distribution system; compared to the other charges which
represent supply (commodity) purchase costs, the costs to transport that commodity to the
City’s customers, as well as regulatory compliance and administrative costs. These distribution
cost components are the focus of this analysis. However, in order to estimate the system
average rate impacts, this analysis uses a forecasted price per therm for each of the other four
volumetric components. By using this simplifying assumption, the calculation approximates the
system average rate impacts associated with electrification-related costs. However, the actual
impacts will vary depending on market effects on commodity rates, cap and trade costs, carbon
offset and transportation charges.
Discussion
Table 2 shows the assumptions embedded in each scenario alongside the estimated system
average rate impact. As noted above, the table shows the estimated percentage by which gas
2 The S/CAP Framework estimated that 97,200 MT of CO2e of emissions reductions could come from
natural gas use reductions.
City of Palo Alto Page 4
rates in each scenario differ from a “business as usual” scenario in 2025 or 2030. The
comparison is done based on the gas utility system average rate.
Table 2: Summary of Electrification Scenarios
Scenario Number 1 2 3
Short Description All SFR* Electrified
& Disconnected
90% Reduction in
SFR* Use, No
Disconnections
On Track to Electrify
and Disconnect all SFR*
by FY 2030
Year FY 2030 FY 2030 FY 2025
80% by 2030 Goal** Met? Yes Yes On Track
SFR* Gas Use Reduction 100% 90% 44%
SFR* Disconnections Yes No Yes
Multi-Family and Business Gas
Use Average Reduction
17% 22% 8%
Estimated System Average
Rate Impact
-16% 52% 17%
* SFR refers to single-family residential customers
** 80% by 2030 Goal refers to the City Council’s adopted goal to reduce the community’s
greenhouse gas emissions to 80% below 1990 levels by 2030
Scenario 1 and 2 examine FY 2030 assuming the 80% by 2030 greenhouse gas (GHG) reduction
goal has been met. Both scenarios assume the same total emissions reduction from gas
customers collectively – enough to meet the 80% by 2030 GHG emissions reductions goal. For
the purposes of this report, gas consumption in 2030 equals 14,641,509 therms, which is
approximately a 60% reduction from the 1990 level. Scenario 3 estimates how many customers
have disconnected and gas usage at the 2025 midway point by linear interpolation between
actual FY 2020 and the FY 2030 goal.
Scenario 1 assumes all single-family residential homes have been electrified and disconnected
and that all the disconnections have been completed and fully paid for (or funded externally) by
FY 2030. Single-family residential customer usage in FY 2020 represented approximately 34% of
total customer usage. Under Scenario 1, system average rates for remaining gas system
customers in FY 2030 are reduced by 16% compared to the 2020 system average rate.
Scenario 2 assumes no customers are disconnected; customers remain connected to the gas
utility but reduce their usage to meet the 80% by 2030 GHG reduction goal. For example, if
single-family residential customers reduce their usage by 90% while all other customers reduce
their usage by 22% on average, this will equate to the usage reductions assumed in Scenario 2.
The costs are high in Scenario 2 because there is no reduction in the size of the gas distribution
system and no associated cost savings. System average rates for gas system customers in FY
2030 under Scenario 2 would increase by 52% compared to the 2020 system average rate.
City of Palo Alto Page 5
The difference between these two scenarios relates entirely to the costs associated with gas
distribution and gas utility operational costs. In Scenario 1, the utility would only maintain 87
miles of gas main compared to 211 miles today. The reduction in gas line miles lowers system
operational and maintenance costs, as well as the need for capital investment. These reductions
are not necessarily in direct proportion to the number of miles of main reduced, but there still
would be a reduction. In addition, due to the smaller size of the utility, fewer administrative
overhead and customer service costs would be allocated to this uti lity. The smaller gas
distribution system would not necessarily mean fewer administrative and customer service
costs, but these are shared services, and could be reallocated to other utilities those services
are needed by the other utilities. This could result in increased costs to those other utilities,
something not estimated in this report.
The significant potential rate difference between these two scenarios illustrates the need for
careful study of rate and customer impacts if large-scale electrification proceeds. As shown
above, widespread electrification without a “pruning” of the gas utility distribution system
could increase the system average rate by 52%, which would most certainly include significant
rate increases for the remaining customers across customer classes. If gas rates increased, it
could incentivize remaining single-family customers who could afford the conversion costs to
disconnect. Multi-family buildings and small businesses could find it more difficult to electrify.
This would lead to a disproportionate economic impact to lower-income Palo Altans and
renters, who are more represented in multi-family dwellings, and to small businesses with fewer
resources to devote to building electrification. Thus, one result of this preliminary analysis
suggests that the City should look closely at single-family residential disconnections and relative
costs per class when setting electrification goals.
Scenario 3 is a snapshot of FY 2025, part way toward reaching FY 2030 under Scenario 1 and
part way toward reaching the 80% by 2030 GHG reduction goal. It is intended to give a rough
estimate of whether there might be gas rate increases for non-electrified customers during the
transition to a smaller gas system. Rate increases during that period could result from reduced
revenues combined with cost savings that have not yet been realized from operating and
maintaining a smaller distribution system.
The study suggests that the system average rate increase in Scenario 3 would increase 17%,
largely due to the cost of disconnecting single-family homes from the gas system as they
electrify. This is a significant utility cost that was estimated at $6 million per year in a prior
study.3 The system average rate increase could also conceivably be higher if the transition to a
smaller gas utility involved a period during which many single-family homes reduced but did not
eliminate their gas use. The City may wish to explore electrification incentives for users like
3 The cost of disconnection was estimated using the high-end cost estimate in the electrification impact
study ($53.7 million) divided over nine years, or approximately $6 million per year. The electrification
impact study can be found in the November 4, 2020 Utilities Advisory Commission Staff Report #11639
“Discussion of Electrification Cost and Staffing Impacts on the City of Palo Alto’s Electric and Gas
Distribution Systems.”
City of Palo Alto Page 6
renters and lower-income Palo Altans in multi-family dwellings, and for small businesses during
the transition. This could be a subject for a ballot measure related to the S/CAP.
Next Steps
Staff will refine these estimates as needed as the City further develops its sustainability
implementation plans in the 2020 S/CAP update. A cost of service study will be necessary to
develop the actual rates applicable under the various electrification scenarios.
Resource Impacts
There are no immediate resource impacts resulting from this analysis. The costs of additional
studies of this topic are expected to come from existing resources at this time. Any actual
changes to gas rates would take place only after an additional cost of service study and would
require approval by Council. The actual gas rates implemented would likely differ from the
estimates in this report.
Environmental Review
The UAC’s review of staff’s estimation of system average rate impacts of the S/CAP 80% by
2030 goals is not a project under the California Environmental Quality Act, under Public
Resources Code section 21065.
Attachments:
• Attachment A: Analysis Method and Assumptions
• Attachment B: Presentation
Attachment A
System Average Rate Impact Analysis Method and Assumptions
Scenario 1 and 2 illustrate two different paths to achieve the City’s 80% by 2030 Goal – Scenario
1 assumes all Single-family Residential (SFR) customers are disconnected by 2030, and all other
customers also reduce their gas usage, meaning the remaining gas distribution system would be
smaller. Scenario 2 assumes customers cut back their gas usage but remain connected to the gas
utility. Scenario 3 studies the midway point to the 2030 goal: in FY 2025 while the utility is
assumed to be transitioning towards electrification and SFR customers are disconnecting from
the gas system.
Tables 3 and 4 show the assumed changes in the cost and revenue categories that are typically
used to develop gas rates. Tables 3 and 4 show the system average rate and percentage change
on line 2. The paragraphs below describe key assumptions used to derive the estimated system
average rate impacts.
Table 3: FY 2030 Scenarios 1 and 2 Compared to FY 2030 Baseline ($000)
Baseline
Scenario 1 (All SFR
Electrified &
Disconnected)% Change
Scenario 2
(90% Reduction in SFR
Use, no Disconnections)% Change
1 Number of Customers 23,388 8,482 -64% 23,388 0%
2 System Average Rate ($/Therm)1.73$ 1.46$ -16%2.64$ 52%
3 Revenue Cap & Trade Revenue (Bill Offset)3,727$ 3,727$ 0%3,727$ 0%
4 Sales (Thousand Therms)25,345 14,642 -42%14,642 -42%
5 Revenue Utilities Retail Sales Revenue 47,652$ 25,064$ -47%42,403$ -11%
6 Revenue Other Revenues 7,792$ 4,234$ -46%4,234$ -46%
7 Revenue Total Sources of Funds 55,444$ 29,298$ -47%46,636$ -16%
8 Cost Purchase of Utilities 20,672$ 11,942$ -42%11,942$ -42%
9 Cost Administration 3,629$ 852$ -77%3,629$ 0%
10 Cost Customer Service 2,177$ 511$ -77%2,177$ 0%
11 Cost Demand Side Management 701$ 369$ -47%624$ -11%
12 Cost Engineering (Operating)536$ 429$ -20%536$ 0%
13 Cost Operations and Maintenance 6,816$ 2,801$ -59%6,816$ 0%
14 Cost Resource Management 559$ 352$ -37%559$ 0%
15 Cost Debt Service Payments - -$ 0%-$ 0%
16 Cost Rent 936$ 936$ 0%936$ 0%
17 Cost Transfers to General Fund 9,003$ 4,854$ -46%9,003$ 0%
18 Cost Other Transfers Out 868$ 868$ 0%868$ 0%
19 Cost Capital Improvement Programs 8,940$ 5,000$ -44%8,940$ 0%
20 Cost Total Uses of Funds 55,444$ 29,298$ -47%46,636$ -16%
Table 4: FY 2025 Scenario 3 Compared to FY 2025 Baseline ($000)
Cap and Trade Revenue from Auction of Allowances
Cap and trade revenue from auction of allowances is segregated in a reserve for future use. It can
be returned to customers provided it is not returned volumetrically. This analysis assumes that all
the projected cap and trade revenue is returned to customers each year (see line 3 of Tables 3
and 4). This reduces the system average rate both under the baseline and end state for each
scenario.
Utilities Retail Sales Revenue
As discussed further in the Reserve Impacts section, this analysis assumes there are no available
funds from reserves, and that revenues must be set to meet expenses each year. Tables 3 and 4,
line 5 shows Utilities Retail Sales Revenue and this is calculated in each scenario to ensure that
revenues equal expenses.
Greenhouse Gas Reductions
In order to contribute to achieving the 80% by 2030 goal, this report assumes a 60% reduction in
gas use from the 1990 level by 2030. This means that greenhouse gas emissions from the gas
utility need to be less than 77,600 metric tons of carbon dioxide equivalent (MT) which is
equivalent to a total use of 14,641,509 therms by 2030 (see line 4 in Table 3). For reference, this
is approximately 45% lower than FY 2020 gas consumption. This analysis conservatively applies
the calendar year 2030 goal to FY 2030 to provide an approximation.
Baseline
Scenario 3 (On Track
to Electrify and
Disconnect All SFR
by 2030)% Change
1 Number of Customers 23,388 16,763
2 System Average Rate ($/Therm)1.55$ 1.82$ 17%
3 Revenue Cap & Trade Revenue (Bill Offset)2,302$ 2,302$ 0%
4 Sales (Thousand Therms)26,652 21,121 -21%
5 Revenue Utilities Retail Sales Revenue 43,657$ 40,687$ -7%
6 Revenue Other Revenues 4,886$ 3,104$ -121%
7 Revenue Total Sources of Funds 48,543$ 43,791$ -128%
8 Cost Purchase of Utilities 15,982$ 12,666$ -21%
9 Cost Administration 3,189$ 2,105$ -34%
10 Cost Customer Service 1,891$ 1,248$ -34%
11 Cost Demand Side Management 623$ 581$ -7%
12 Cost Engineering (Operating)473$ 431$ -9%
13 Cost Operations and Maintenance 5,954$ 4,395$ -26%
14 Cost Resource Management 486$ 406$ -16%
15 Cost Debt Service Payments 799$ 799$ 0%
16 Cost Rent 832$ 832$ 0%
17 Cost Transfers to General Fund 7,901$ 6,283$ -20%
18 Cost Other Transfers Out 1,468$ 868$ -41%
19 Cost Capital Improvement Programs 8,337$ 12,670$ 52%
20 Cost Total Uses of Funds 48,543$ 43,791$ -10%
There are many ways to get to the City’s GHG emissions goal. The City is in the process of updating
its S/CAP and one of the proposed key actions is to target electrification of all single-family
residences. The Utility Department has calculated preliminary cost estimates and observed that
it is likely operationally possible to run a gas system that serves only commercial and some multi-
family customers. For these reasons Scenario 1 examines disconnection of all single-family
residential customers by 2030 as well as assuming the necessary additional reductions to
contribute to meeting the overall 80 by 2030 goal. Approximately 17% overall reductions in gas
use among multi-family residential and non-residential customers from FY 2020 levels would be
needed in addition to disconnection of all single-family residential customers, shown in Table 5.
Table 5: Gas Consumption Reduction Needed from Actual FY 2020 Levels to Meet the 80% by 2030
Goal
Reduction
FY 2020
Consumption
(Therms)
FY 2030
Consumption
(Therms)
Therms % MT (CO2e)
Single-Family
Residential
9,027,878 0 (9,027,878) (100%) (47,848)
Multi-Family
Residential and
Non-Residential
17,582,027 14,641,509 (2,940,518) (17%) (15,585)
Total 26,609,905 14,641,509 (11,968,396) (45%) (63,433)
Staff’s preliminary estimate for how these additional reductions could be achieved include the
key actions shown in Table 6. Table 6 summarizes the preliminary estimate of the GHG savings
from each key action to add up to the total needed reduction from calendar year 2018 to 2030.
These are preliminary estimates made in early 2020. Staff is working to refine these estimates as
part of the S/CAP and they are included in this report for illustrative purposes only.
Table 6: Preliminary Estimate of Example Group of Key Actions to Meet the 80% by 2030 Goal (For
Illustrative Purposes Only)
Reduction by 2030 from 2018 level
MT C02e Therms
Electrify 100% SF Homes 49,000 9,217,709
Electrify 100% of gas wall furnaces in MF
buildings to heat pumps
5,600 1,056,350
Electrify 100% of all K-12 school facilities 3,300 627,504
Electrify 100% of rooftop gas packs on
nonresidential buildings
1,100 201,500
Mandate all-electric commercial new
construction projects
2,300 432,478
Reduce GHG emissions from city-owned
facilities by 40%
2,700 1,291,000
Reduce GHG emissions from commercial
buildings above 25,000 sq. ft. by 20%
8,100 1,520,000
Total 72,100 14,346,541
Costs That Vary By Gas Use
Commodity purchase costs, transportation costs and cap and trade compliance costs vary with
gas use (see line 8 in Tables 3 and 4). This analysis assumes that for each unit of customer load
reduction, there would be one unit of supply cost reduction. Gas use is assumed to reduce in
Scenario 1 and 2 by the same quantity by 2030 that is estimated to be needed to meet the 80%
by 2030 greenhouse gas reduction goal described above. For this reason, the commodity
purchase cost in Scenario 1 and 2 in 2030 are the same even though the goal is achieved in
different ways.
Costs That Vary By Full Time Equivalent
Certain costs are allocated to each utility by percent of total Full Time Equivalents (FTE). Utilities
administration and customer service costs are examples of costs allocated by FTE (see lines 9 and
10 of Tables 3 and 4). FTEs are not expected to change under Scenario 2 but for Scenario 1, a
preliminary estimate is a reduction of 77% in FTE. This estimate is based on the need for one crew
of 4 for emergency response and customer connections, 1 supervisor, 2 office staff, 1 FTE for
management supervision, 2 cathodic protection techs, 2 meter techs for a total of 12 FTE. Some
of the allocated costs (such as human resources, accounting, finance) would not be expected to
be reduced for the utilities department overall as much as the reduction in the FTEs in the gas
utility. These costs might be reallocated to other utilities if needed, which could increase the costs
and rates associated with the other utilities. This would be further analyzed to assess the full
customer impact. Scenario 3 assumes 4 out of 9 years of progress toward full electrification of
single-family residential customers in Scenario 1 so it assumes 4 / 9 x 77% or 34% reduction in
FTE by FY 2025.
Costs That Vary By Number of Customers
Communications and Resource Management costs are allocated to each utility based upon
number of customers. Communications costs are a component of line 9 and Resource
Management is shown separately in line 14 of Tables 3 and 4.
Costs Related to Capital Investment
The Electrification Impact Study estimated the gas mains by material that would be sealed if all
single family homes were disconnected from the gas system. The total percent of mains the study
estimated would be sealed is 59%. In Scenario 1, where single family residential customers have
all been disconnected from the gas system, this analysis assumes annual ongoing main
replacement costs, which make up approximately 75% of the CIP budget, are reduced by 59% (for
a total reduction of 75% x 59% = 44% or $4 million per year on average) shown on line 19 of Table
3 and 4. There may be additional CIP reductions for the other 25% of the CIP budget that should
be fully explored in a further analysis. However, to be conservative for this analysis, the remaining
25% of CIP other than main replacement is assumed to continue under these three electrification
scenarios. Line 19 of Table 3 and 4 shows the total combined Capital Improvement Program
Estimated Budget. In Scenario 3 the CIP costs increase to reflect the assumption that utility costs
of disconnection are funded through revenues in level annual payments from FY 2022 through
2030. This adds approximately $6 million annually.
Additionally, this analysis assumes the operations and maintenance costs are reduced by the size
of the main distribution system, which is a reduction of 59% in Scenario 1 with full disconnection
of all single-family residential customers (shown in line 13 of Table 3 and 4). However, a full
analysis of the remaining system would need to be conducted to examine safety and engineering
issues to determine the actual budget reductions.
Engineering operating costs, however, would be reduced by 20% or less (see line 12 of Tables 3
and 4). This is because similar engineering oversight would be required for the operations and
maintenance tasks of the new system, even if it were smaller. Many other similar costs would
remain, such as responding to emergencies and annual valve maintenance.
General Fund Transfer
Per a methodology adopted by the Council in 2009, (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) this analysis calculates the general fund transfer
methodology by applying the estimated percent reduction in net fixed assets (see line 17 of Tables
3 and 4). Net fixed assets are approximately 50% distribution mains and 44% meters and services
(in FY 2020). With the disconnection of all single-family residential customers, approximately 59%
of the distribution mains and 37% of the meters and services assets would be abandoned. The
total percentage of net assets estimated to be abandoned in Scenario 1 by FY 2030 is 46%, which
is used to estimate the reduction in the general fund transfer. Scenario 3 assumes 4 years of
progress toward this disconnection goal have been made out of the 9 year period from FY 2022
through FY 2030 and reflects 4/9 of the abandonment has occurred (46% x 4 / 9 = 20.4% of the
net assets). This estimate uses simplifying assumptions and a full analysis that includes the age of
each asset would need to be conducted.
Fixed Costs
Certain costs such as rent and debt service are fixed costs and do not vary with changing number
of customers or size of the gas utility (see lines 15 and 16 of Tables 3 and 4)
Reserve Impacts
This analysis is based on the financial plan forecasts in the FY 2021 Gas Financial Plan. That plan
estimated the operations reserve to remain within guideline levels throughout the 10-year
forecast period (through FY 2030). This analysis assumes that no additional funds are available
from reserves or transferred to reserves to supplement customer rates. As costs increase or
decrease, this analysis increases or decreases revenues to match the costs in the forecasted year.
For this analysis, no reserve impact is assumed from the abandonment of assets (mains that have
been disconnected due to electrification) based on a preliminary accounting analysis. However,
an expanded analysis of this would need to be conducted to gain a full understanding of the
expected impacts on the gas utility reserves from asset abandonment.
January 2021 www.cityofpaloalto.org
GAS UTILITY SYSTEM AVERAGE RATE IMPACTS OF ELECTRIFICATION
Staff: Lisa Bilir
2
SUMMARY OF SCENARIOS
•Scenario 1 & 2
•FY 2030
•Two different paths to achieve 80% by 2030 Goal
•Scenario 1 all single-family residential disconnected
•Scenario 2 single-family residential cut back use by
90% but no disconnections
•Scenario 3
•FY 2025
•On track to achieve 80% by 2030 Goal and disconnect all
single-family residential
3
SUMMARY OF SCENARIOS AND RATE IMPACTS
* SFR refers to single-family residential customers
Scenario Number 1 2 3
Short Description All SFR*
Electrified &
Disconnected
90% Reduction
in SFR* Use, No
Disconnections
On Track to
Electrify and
Disconnect all
SFR* by FY 2030
Year FY 2030 FY 2030 FY 2025
80% by 2030 Goal
Met?
Yes Yes On Track
Estimated System
Average Rate Impact
-16%52%17%
4
KEY INSIGHTS
•Widespread electrification without a “pruning” of the gas utility
distribution system could increase the system average rate by 52%
•Rate increases for remaining customers (e.g., multi-family and small
businesses)
•Disproportionate economic impact
•Transition rate impacts on remaining customers may be significant due
to disconnection costs
•Rate impact could be higher if many single-family homes reduced
but did not eliminate gas use
•The City may wish to explore electrification incentives for users like
renters and lower-income Palo Altans in multi-family dwellings, and for
small businesses during the transition
City of Palo Alto (ID # 11778)
Utilities Advisory Commission Staff Report
Report Type: New Business Meeting Date: 1/6/2021
City of Palo Alto Page 1
Summary Title: Upstream Emissions Report Update
Title: Discussion and Update on Lifecycle Emissions for Gasoline, Natural Gas
and Electricity Consumed in Palo Alto
From: City Manager
Lead Department: Utilities
RECOMMENDATION
This report is provided for information and discussion, staff is not recommending any action by
the Utilities Advisory Commission (UAC).
EXECUTIVE SUMMARY
This report is an estimate of lifecycle and upstream1 emissions for gasoline, natural gas, and
electricity consumed within Palo Alto in response to the July 2020 UAC informational request
and May Colleague’s Memo (UAC Report ID # 11336). In the July UAC meeting staff discussed
the merits of using total GHG emissions, including lifecycle emissions, to appropriately prioritize
and incentivize the highest-impact greenhouse gas reduction actions.
a.Task: Estimate the approximate greenhouse gas impact of the upstream emissions
associated with Palo Alto’s electricity, natural gas, propane, and liquid fuels using both a 20-
year and 100-year time horizon Global Warming Potential (GWP).
b.Key Findings: To provide a sense of scale, including lifecycle emissions with a GWP100 would
increase the emissions shown in the 2018 S/CAP emissions inventory by approximately 34%,
49%, and 5% for transportation, natural gas, and electricity, respectively. Staff does not
recommend modifying the S/CAP accounting methodology, but could consider the total
emissions, including lifecycle emissions, when calculating the impact of programs.
1 Upstream emissions are those emissions associated with the extraction, production, transportation, and
distribution of products, in addition to any emissions from combustion or operations and eventual disposal.
Staff: Lena Perkins
CITY OF
PALO
ALTO
City of Palo Alto Page 2
BACKGROUND
In their memo, UAC Commissioners Segal and Forssell highlighted that both a) including
upstream emissions and b) using the 20-year GWP2 show the greenhouse gas emissions due to
natural gas consumption within the City to be much higher than how they are currently
reported in the S/CAP. The Commissioners sought to prompt a discussion about whether
including these additional factors would more closely reflect the actual emissions and
subsequent global warming impact of natural gas transported to and consumed in Palo Alto.
Upstream emissions are an important part of total emissions accounting sometimes called
“lifecycle emissions accounting”. Upstream emissions reflect the overall greenhouse gas
emissions associated with the extraction, production, refining, transportation, and distribution
of fuels, which along with the direct emissions at their point of use constitute the full lifecycle
emissions. Upstream and lifecycle emissions are substantial, and required to be accounted for
in many other standards,3 but are currently “strongly encouraged” rather than required for
community climate inventories.4 Climate inventories for cities typically only report direct or
combustion emissions from within the community, such as the S/CAP, while upstream
emissions are sometimes reported alongside adopted climate inventory goals.5
An example of lifecycle emissions accounting is the California Air Resources Board (CARB) Low
Carbon Fuel Standard (LCFS) calculation shown below.6
2 While 20-year GWP is relevant to many discussions, 100-year GWP is used by both CARB
https://ww2.arb.ca.gov/emission-inventory-activities and the EPA
https://www.epa.gov/ghgemissions/understanding-global-warming-potentials.
3 For example U.S. EPA requires all upstream and lifecycle emissions to be included for the US Renewable Fuel
Standard Program under the Clean Air Act, as detailed here: https://www.epa.gov/renewable-fuel-standard-
program/lifecycle-analysis-greenhouse-gas-emissions-under-renewable-fuel.
4 The U.S. ICLEI Community protocol encourages inclusion full lifecycle accounting of major emissions sources,
while a full consumption-based inventory is “strongly encouraged” ICLEI, 2012, p.16).
5 Several entities report some upstream emissions, also known as Scope 3 emissions, alongside annual climate
inventory reporting. One example is the Scope 3 emissions reported annually by Stanford University here:
https://sustainable.stanford.edu/sites/default/files/Scope3_Emissions_2018.pdf.
6 CARB uses the total carbon footprint including lifecycle emissions to reflect carbon emissions for LCFS and other
programs as shown here for 2017. Page 17 https://ww2.arb.ca.gov/sites/default/files/2020-09/basics-notes.pdf
City of Palo Alto Page 3
It is important to note that there are substantial upstream emissions for not only natural gas in
Palo Alto, but also other types of energy consumed by the Palo Alto community, notably
gasoline and other liquid fuels.7 One of the important aspects of upstream emissions is that
combined with direct emissions and other lifecycle emissions, they reflect a community’s total
overall carbon footprint, whereas the direct emissions are used for goal setting by local
governments as they center on aspects the local government can control. Palo Alto is quite
unique in that it also controls and operates it’s own municipal electricity and natural gas
utilities, and therefore has more direct control over these energy emissions than a typical local
government. Beyond the upstream emissions of certain energy consumption shown here, there
are a number of tools and inventories available for the public to view the total emissions of the
community8 or calculate their personal carbon footprint,9 all of which reflect direct emissions
and all other indirect emissions.
Using a 20-year time horizon for GWP
With respect to using a 20-year GWP, there is currently an academic trend of reporting the 20 -
year GWP impact alongside the 100-year GWP to help communicate the near-term radiative
7 https://www.eenews.net/assets/2020/04/23/document_ew_03.pdf
8 A research group from UC Berkeley has published complete emissions inventory by census block that can be
found here: https://coolclimate.org/maps-2050.
9 The U.S. EPA household personal carbon footprint calculator is one of many, and can be found here:
https://www3.epa.gov/carbon-footprint-calculator/.
City of Palo Alto Page 4
forcing from gases which trap much more heat than CO2 during their initial decades in the
atmosphere.10 While neither metric fully accounts for the radiative forcing (i.e. carbon budget)
perfectly, reporting the 20-yr GWP alongside the 100-yr GWP can reflect the impacts of
increased methane leakage, for example.
There are a number of complications associated with including lifecycle emissions in the
community’s emissions inventory at this time, or using them in utility planning or policy
activities in the near term. However, communities are “strongly encouraged” in the ICLEI
Community Protocol to track these emissions alongside their emissions inventory to help
provide the community carbon footprint and to provide a foundation for longer-term
discussions about the use of upstream emissions for these activities.
DISCUSSION
Staff used publicly available models to estimate the lifecycle emissions associated with gasoline,
natural gas, and electricity. The Argonne National Laboratory maintains a robust lifecycle
emissions model mostly centered around transportation fuels where GREET_2020 is the most
current model. CARB uses the most recent version of GREET that was modified for California
(CA_GREET_3.0) for the LCFS program. Staff used both models and compared the results, and
since the results were fairly similar only the results consistent with the CARB values using
CA_GREET_3.0 are shown below. Propane is not shown here but can be found in the
CA_GREET_3.0 model.
The CARB methane leakage assumptions are from the CA_GREET_3.0 model, which are
consistent with the CARB numbers used for LCFS assumptions. The recommended assumptions
are shown in the first column, GWP100, using the CARB Methane Leakage assumptions in order
to be consistent with current 2020 CARB accounting. The modeler can also choose to use
different factors for global warming potential, such as impact over 100 years or over 20 years ,
so as requested by the UAC the GWP20 using a 20-year time horizon is shown in the second
column.
Table 1. Total emissions per unit of energy consumed for gasoline, natural gas, and
electricity, including all lifecycle emissions
Fuel Source
Total Emissions
(gCO2e/MJ)
GWP100 GWP20
CA Gasoline 96 114
10 An explanation of GWP by the U.S. EPA can be found here: https://www.epa.gov/ghgemissions/understanding-
global-warming-potentials. A recent Nature Paper recommends the use of more complex calculations than the 20-
year GWP to reflect the cumulative radiative forcing: https://www.nature.com/articles/s41612-018-0026-8.
Changing to 20-year GWP as the only metric is not recommended, as explained here:
https://climateanalytics.org/briefings/why-using-20-year-global-warming-potentials-gwps-for-emission-targets-is-
a-very-bad-idea-for-climate-policy/.
City of Palo Alto Page 5
CA Natural Gas 77 104
CA Electricity11 83 101
Table 2. Percentage increase in emissions by including lifecycle emissions rather than only
direct combustion emissions
Fuel Source
% Increase
GWP100 GWP20
CA Gasoline12 34% 60%
CA Natural Gas13 37% 80%
CA Electricity 22% 50%
Table 3. Increase from 2018 S/CAP emissions if including lifecycle emissions14
Fuel Source
Increase Above S/CAP
Emissions
GWP100 GWP20
CA Gasoline 34% 60%
CA Natural Gas 49% 101%
CA Electricity15 +5% +11%
In Table 3, it is worth noting that the GREET model results showed a larger increase in S/CAP
emissions in natural gas than would be accounted for just due to the inclusion of lifecycle
emissions. This is because previous GHG inventories were using the emissions factors from the
Intergovernmental Panel on Climate Change (IPCC) Second Assessment Report , rather than the
most current Fifth Assessment Report, which increased the GWP of leaked methane. The
combination of the most recent IPCC GWP values and including lifecycle emissions increases
the total emissions from natural gas by 49% relative to the emissions reported in the 2018
S/CAP emissions inventory.
It is also worth noting that a small amount of emissions is shown for the Palo Alto electricity
portfolio when including upstream emissions. This is because transmission and distribution
losses are not covered by carbon-free electricity purchases, which results in the small residual
emissions shown in Table 3.
11 https://ww2.arb.ca.gov/sites/default/files/classic//fuels/lcfs/fuelpathways/comments/tier2/elec_update.pdf
Also modeled using the CA_GREET_3.0 model for year 2020, downloaded and modeled in December 2020.
12 This is assuming 0.71lbsCO2/mile as the number used in the City’s 2018 GHG inventory, which is from the 2016
Palo Alto transportation study used in the S/CAP.
13 Direct combustion emissions taken to be 56gCO2e/MJ as modeled in CA_GREET_3.0
14 2018 is the most recent inventory that has been completed by the City of Palo A lto. The City is in the process of
completing the 2019 GHG inventory.
15 Since CPAU only enters into long-term contracts for electricity generation which is deemed carbon free by the
CEC, these emissions are due to transmission and distribution system losse s, which staff assumes to be California
average grid electricity.
City of Palo Alto Page 6
Lastly, staff used gasoline to approximate transportation emissions, since the last
transportation study concluded that around 95% of the vehicle miles were using gasoline. Total
emissions, including lifecycle/upstream emissions were approximately 34% greater than the
tailpipe emissions reported in the 2018 S/CAP.
In order to provide a sense of scale, Figure 1, below, shows ratio of S/CAP emissions to lifecycle
emissions. This figure uses GWP100 for upstream emissions. Staff recommends using GWP100 for
consistency since most GHG inventory protocols use the 100-year timeframe, while
understanding that this metric likely underestimates the true warming impact of leaked
methane. Staff considers the use of GWP100 EPA factors most effective for measuring progress,
but is considering taking the GWP20 and recent methane leakage research findings into
consideration when setting voluntary incentives. This is because several of the most recent
vetted studies (both in research funded by EDF and others) have found much higher rates of
methane leakage than the current EPA values. The EPA periodically updates their average
leakage values and may integrate the recent research in the future.
Figure 1. Total 2018 Palo Alto Energy Emissions, including S/CAP emissions and additional lifecycle emissions.
NEXT STEPS
Staff will consider using total emissions (including lifecycle emissions) for both 20-year GWP and
100-year GWP in setting incentives based on avoided GHG emissions and making other internal
policy and investment decisions.
RESOURCE IMPACT
Updating and implementing the approximate greenhouse gas impact of the total emissions
(including lifecycle emissions) associated with Palo Alto’s electricity, natural gas, and gasoline
using both a 20-year and 100-year time horizon GWP will take approximately one week of staff
City of Palo Alto Page 7
time once a year. Staff could consider updating every two to three years instead of annually,
and simply maintaining the ratio of lifecycle emissions to combustion emissions between
updates.
ENVIRONMENTAL REVIEW
The Utilities Advisory Commission’s discussion of the City’s carbon accounting methodology
does not meet the definition of a project under Public Resources Code 21065 and therefore
California Environmental Quality Act (CEQA) review is not required.
Attachments:
• Attachment A: Presentation
UPSTREAM EMISSIONS FROM
ENERGY IN PALO ALTO
Lena Perkins, PhD
Senior Resource Planner
January 06, 2021 www.cityofpaloalto.org
Staff: Lena Perkins
What are upstream (or lifecycle) emissions?
2
1.Emissions from extraction,
transport, refining and use
2.CO2e from energy used and
direct leakage of heat-
trapping gases (methane,
nitrous oxide, refrigerants…)
3.CA uses full lifecycle
emissions for the Low-Carbon
Fuel Standard program
3
Impact on reported emissions varies some between fuels
Fuel
% Increase Above S/CAP
Emissions Reported
GWP100 GWP20CA Gasoline 34%60%
CA Natural Gas 48%101%
CA Electricity +5%+11%
4
Next steps & timeline
Utilities staff will internally explore ways to:
1.Consider total emissions when setting incentives
for voluntary programs
2.Consider calculating total emissions reductions by
programs and projects
3.Consider collaborating with other organizations to
help community understand the full carbon impact
of different actions
End of Presentation
Supplemental slides may follow
Questions: Lena.Perkins@CityOfPaloAlto.org
www.cityofpaloalto.orgJanuary 06, 2021
3
Detailed Results:
Fuel
Total Emissions gCO2e/MJ
GWP100 GWP20CA Gasoline 96 114
CA Natural Gas 77 104
CA Electricity 83 101
Fuell
% Increase From Including Lifecycle Emissions
GWP100 GWP20
CA Gasoline 34%60%
CA Natural Gas 37%80%
CA Electricity 22%50%
Fuel
% Increase Above S/CAP Emissions Reported
GWP100 GWP20CA Gasoline 34%60%
CA Natural Gas 48%101%
CA Electricity +5%+11%
City of Palo Alto (ID # 11785)
Utilities Advisory Commission Staff Report
Report Type: New Business Meeting Date: 1/6/2021
City of Palo Alto Page 1
Council Priority: Climate/Sustainability and Climate Action Plan
Summary Title: Informational Report on 2019 Renewable and Carbon Neutral
Electricity Supplies
Title: Informational Report on Annual Review of the City’s Renewable
Procurement Plan, Renewable Portfolio Standard Compliance, and Carbon
Neutral Electric Supplies for 2019
From: City Manager
Lead Department: Utilities
Recommendation
This report is for information only. No action is required.
Executive Summary
The attached report (Staff Report 11677), which was delivered to the City Council on December
7, 2020, is for the Utilities Advisory Commission’s (UAC’s) information. This report provides an
update on the City’s accomplishments with respect to its Renewable Portfolio Standard (RPS)
and Carbon Neutral Plan objectives—including an assessment of the City’s electric utility
emissions calculated using the recently adopted hourly emissions accounting methodology.
Further, the report satisfies the reporting requirements of the City’s RPS Enforcement Program.
As the report describes, the City continues to meet its objectives under the RPS Procurement
Plan and the Carbon Neutral Plan, and achieved an RPS level of 37% in 2019 —exceeding the
state’s 31% procurement mandate for the year. And although the switch to the hourly carbon
accounting approach did not go into effect until 2020, it is interesting to note that even though
the City had a net surplus of carbon neutral generation in 2019, on an annual basis, under the
hourly accounting approach the City’s electric supply portfolio is found to be responsible for a
net positive amount of GHG emissions: 8,085 metric tonnes of CO2 equivalent.
Attachments:
•Attachment A: Staff Report 11677
Staff: Jim Stack
CITY OF
PALO
ALTO
City of Palo Alto (ID # 11677)
City Council Staff Report
Report Type: Informational Report Meeting Date: 12/7/2020
December 07, 2020 Page 1 of 4
(ID # 11677)
Council Priority: Climate/Sustainability and Climate Action Plan
Title: Informational Report on 2019 Renewable and Carbon Neutral Electricity
Supplies
Subject: Annual Review of the City’s Renewable Procurement Plan, Renewable
Portfolio Standard Compliance, and Carbon Neutral Electric Supplies for 2019
From: City Manager
Lead Department: Utilities
Executive Summary
Like all electric utilities in California, Palo Alto is subject to the state’s Renewable Portfolio
Standard (RPS) mandate of 60% by 2030. The City has also adopted a Carbon Neutral Plan,
which led to the achievement of a carbon neutral electric supply portfolio starting in 2013 (and
which was updated by Council in August 2020). In 2011, in compliance with state RPS
regulations, the Council also formally adopted an RPS Procurement Plan and an RPS
Enforcement Program that recognize certain elements of the state’s RPS law applicable to
publicly-owned utilities. The RPS Enforcement Program requires the City Manager, or their
designee, the Utilities Director, to conduct an annual review of the Electric Utility’s compliance
with the procurement targets set forth in the City’s RPS Procurement Plan.
This staff report satisfies the reporting requirements of the City’s RPS Enforcement Program,
while also providing an update on the City’s compliance with the Carbon Neutral Plan. The City
continues to meet both its RPS and carbon neutrality objectives—even after selling over
200,000 MWh of renewable energy in 2019.
Background
The City currently has two independent procurement targets related to renewable and carbon
neutral electricity:
•RPS Procurement Plan (60% by 2030): The City’s official renewable electricity goal is
contained in the RPS Procurement Plan that the City was required to adopt under
Section 399.30(a) of California’s Public Utilities Code. This was adopted in December
2011 (Staff Report 2225, Resolutions 9214 and 9215) and updated in November 2013
(Staff Report 4168, Resolution 9381) and December 2018 (Staff Report 9761, Resolution
9802)—and is slated to be updated again in December 2020 (Staff Report 11650) . The
Attachment A
December 07, 2020 Page 2 of 4
(ID # 11677)
pending update to the RPS Procurement Plan is designed to bring it into alignment with
the state’s 60% RPS law (SB 100), which was signed into law in 2018.1 The RPS
Procurement Plan and RPS Enforcement Program complement each other: the
Procurement Plan establishes official procurement targets, while the Enforcement
Program specifies the reporting and monitoring that is required of the Utilities Director
while working to achieve those targets.
The procurement requirement in the version of the City’s RPS Procurement Plan being
considered by Council in December is that the City acquire renewable electricity
supplies equal to 60% of retail sales by 2030, which is in line with the state’s current RPS
mandate2. The RPS Procurement Plan also contains interim targets for six separate
periods (2011-2013, 2014-2016, 2017-2020, 2021-2024, 2025-2027, and 2028-2030).
•Carbon Neutral Plan (100% Carbon Neutral Electricity by 2013): The Carbon Neutral Plan
was adopted in March 2013 (Staff Report 3550, Resolution 9322) and updated in August
2020 (Staff Report 11556, Resolution 9913), and requires that the City procure a carbon
neutral electric supply portfolio starting in calendar year (CY) 2013. In general, this goal
is expected to be achieved primarily through purchases made under the City’s long-term
renewable power purchase agreements (PPAs) and output from its hydroelectric
resources. However, when the City Council approved an update to the Carbon Neutral
Plan in August 2020, they also approved a new procurement strategy whereby the City
does not keep all of the output of its long-term, in-state PPAs, but instead exchanges
that output for less expensive out-of-state renewable generation.
Discussion
The City continues to meet its objectives under the RPS Procurement Plan and the Carbon
Neutral Plan, and achieved an RPS level of 37% in 2019—exceeding the state’s 31%
procurement mandate for the year. Below is a summary of CPAU’s progress toward satisfying
its renewable energy and carbon neutral procurement targets, with additional detail provided
in Exhibit A.
RPS Procurement Plan Compliance
In CY 2019, the City initially received 535,145 MWh of renewable energy through its long-term
contracts for wind, solar, landfill gas, and small hydro resources (which represents 62.1% of the
City’s total retail sales for that period). Additionally, the City received 665,359 MWh of large
hydroelectric generation (representing 77.2% of the City’s total retail sales), which is not
classified as eligible renewable generation by the state. Because of the favorable hydro
conditions for the year the City had a large surplus of carbon neutral generation overall, and,
1 Although SB 100 became law in 2018, the California Energy Commission (CEC) has yet to formally adopt
regulations implementing the new law. The pending update to the City’s RPS Procurement Plan is based on the
current RPS regulations, which CEC adopted on Oct. 14, 2015 with an effective date of April 12, 2016; however, it is
possible that the City will need to update its RPS Procurement Plan again in 2021 if the adopted RPS regulations
differ significantly from the draft version of the regulations.
2 CA Public Utilities Code Sec. 330.3(c)(2).
December 07, 2020 Page 3 of 4
(ID # 11677)
based on feedback from the Utilities Advisory Commission, staff decided to sell the majority of
this surplus from the renewable energy supplies (because this generation is more valuable to
other utilities than the large hydro generation). Ultimately the City sold 216,110 MWh of
renewable energy supplies, yielding $3.34 million in sales revenue. Accounting for these sales,
the City’s net renewable energy supplies totaled 319,035 MWh, which represents 37.0% of the
City’s total retail sales for 2019.
For CY 2020, staff has currently contracted to sell about 324,000 MWh of renewable
generation, and projects that the City’s remaining renewable electricity supplies from in-state
resources will equal 26.0% of retail sales. However, after accounting for the purchase of out-of-
state renewable supplies, the City’s total renewable electricity supplies are projected to equal
55.4% of retail sales.
In accordance with the state’s RPS Program requirements, CPAU’s Procurement Plan develops a
renewable electric supply portfolio that balances environmental goals with system reliability
while maintaining stable and low retail electric rates. The state RPS program requires retail
electricity suppliers like CPAU to procure progressively larger renewable electricity supplies
across a series of separate multi-year Compliance Periods. CPAU’s procurement targets, as well
as its actual/projected procurement volumes and RPS levels, for the first three Compliance
Periods are summarized in Table 1 below. For these three compliance periods, the City has
increasingly purchased more renewable electricity supplies than the respective procurement
targets.
Table 1: RPS Compliance Period Procurement Targets and Actual/Projected Procurement
RPS
Compliance
Period
Years
Retail
Sales
(MWh)
Procurement
Target
(MWh)
Actual/Projected
Procurement*
(MWh)
Target % of
Retail Sales
Actual/Projected
% of Retail
Sales
1 2011-2013 2,837,773 567,555 607,740 20% 21.4%
2 2014-2016 2,801,056 605,949 826,855 21.7% 29.5%
3 2017-2020 3,458,925 1,033,933 1,667,716 30% 48.2%
TOTALS 9,097,754 2,207,437 3,102,311 34.1%
*Procurement totals for Compliance Periods 1 and 2 are actuals; procurement totals for Compliance
Period 3 are a combination of actual data (for 2017-2019) and projected data (for 2020), and account for
executed sales of 324,000 MWh of renewable supplies for 2020.
Carbon Neutral Plan
In CY 2019, CPAU achieved its goal, set forth in the Carbon Neutral Plan, of an electric supply
portfolio with zero net greenhouse (GHG) emissions for the sixth consecutive year, without the
need to purchase unbundled renewable energy certificates (RECs) in the market. Carbon
neutrality was achieved in CY 2019 through existing hydro and renewable generation (wind,
solar, and landfill gas). Due to favorable hydro conditions, the City had a large surplus of energy,
allowing for the sale of 216,000 MWh of renewable energy while still maintaining a carbon
neutral supply portfolio (when evaluated using an annual carbon accounting framework).
December 07, 2020 Page 4 of 4
(ID # 11677)
When the City Council approved an update to the Carbon Neutral Plan in August 2020, the
primary change was to adopt an hourly carbon accounting methodology as the basis for
determining whether the City has met its carbon neutrality objective. Although this change did
not apply to the City’s electric supply portfolio for CY 2019, it is interesting to note how the
City’s supply portfolio would have fared under this accounting framework. Under the annual
accounting approach, the City had an overall surplus of 85,569 MWh of carbon neutral
generation compared to its load (equal to 9.4% total load), and thus substantially exceeded the
carbon neutrality standard. However, under the hourly carbon accounting approach,3 the City’s
electric supply portfolio is found to be responsible for a net positive amount of GHG emissions
for CY 2019: 8,085 metric tonnes of CO2 equivalent.
For CY 2020, slightly below average hydro conditions are expected to result in about 46% of the
City’s electric supply needs being supplied by hydroelectric resources, with the remainder
coming from non-hydro renewable energy resources (including purchases of out-of-state
unbundled RECs).
Policy Implications
This report implements Sections 4 and 5 of the City’s RPS Enforcement Program, which require
an annual review of the Electric Utility’s compliance with the CPAU RPS Procurement Plan to
ensure that CPAU is making reasonable progress toward meeting the compliance obligations
established in the CPAU RPS Procurement Plan.
Environmental Review
The Council’s review of this report does not meet the definition of a “project” pursuant to
Public Resources Code Section 21065, thus California Environmental Quality Act review is not
required.
Attachments:
•Exhibit A: Renewable and Carbon Neutral Electricity Supply Procurement Details (PDF)
3 The City’s hourly carbon accounting methodology entails calculating the City’s net surplus or deficit carbon
neutral supply position relative to its load in every hour of the year. The grid average electricity emissions intensity
for each hour is then applied to each of these hourly surpluses or deficits to yield a net emissions contribution (or
reduction) that the City’s electric supply portfolio is responsible for in that hour. These hourly emissions totals are
then summed across the entire year to yield the City’s annual emissions total for the year.
Renewable and Carbon Neutral Electricity Supply Procurement Details
Renewable Energy Goals
In CY 2019, the City initially received 535,145 MWh of renewable energy through its long-term
contracts for wind, solar, landfill gas, and small hydro resources (which represents 62.1% of the
City’s total retail sales for that period). After accounting for the sale of 216,110 MWh of this
generation, the City’s net renewable energy supplies totaled 319,035 MWh, which represents
37.0% of the City’s total retail sales for 2019.
For CY 2020, staff has currently contracted to sell about 324,000 MWh of renewable generation,
and projects that City’s remaining renewable electricity supplies from in-state resources will
equal 26.0% of retail sales. However, after accounting for the purchase of out-of-state renewable
supplies, the City’s total renewable electricity supplies are projected to equal 55.4% of retail
sales.
Table 1 shows the renewable resources currently under contract, the status of the projects,
their annual output in Gigawatt-hours (GWh), and the rate impact of each resource that was
calculated at the time it was added to the electric supply portfolio.
Table 1: Summary of Contracted Renewable Electricity Resources
Resource Delivery
Begins
Delivery
Ends
Annual Generation
(GWh)
Rate Impact
(¢/kWh)
Small Hydro Before 2000 N/A 10.0 0
High Winds Dec. 2004 Jun. 2028 42.7 0.012
Shiloh I Wind Jun. 2006 Dec. 2021 57.3 (0.041)
Santa Cruz Landfill Gas (LFG) Feb. 2006 Feb. 2026 9.0 0.003
Ox Mountain LFG Apr. 2009 Mar. 2029 42.5 (0.040)
Keller Canyon LFG Aug. 2009 Jul. 2029 13.8 (0.020)
Johnson Canyon LFG May 2013 May 2033 10.4 0.064
San Joaquin LFG Apr. 2014 Apr. 2034 27.5 0.127
Kettleman Solar Aug. 2015 Aug. 2040 53.5 0.099
Hayworth Solar Dec. 2015 Dec. 2042 63.7 0.026
Frontier Solar Jul. 2016 Jul. 2046 52.5 0.011
Elevation Solar C Dec. 2016 Dec. 2041 100.8 (0.044)
W. Antelope Blue Sky Ranch B Dec. 2016 Dec. 2041 50.4 (0.002)
CLEAN Program Projects Varies Varies 5.0 0.027
Total Operating Resources 539.0 0.223
Golden Fields Solar III Jan. 2023 Dec. 2047 75.0 (0.056)
Total Non-Operating Resources 75.0 (0.056)
Total Committed Resources 614.0 0.168
EXHIBIT A
RPS Procurement Plan Compliance
Annually, the Utilities Director reviews CPAU’s RPS Procurement Plan to determine compliance
with the state’s RPS Program. Under the state RPS Program, the California Energy Commission
(CEC) developed portfolio balancing requirements, which dictate what percentage of renewable
procurement must come from resources interconnected to a California Balancing Area (as
opposed to an out-of-state transmission grid balancing area). These requirements also determine
the eligibility criteria for renewable resource products as determined by their eligible Portfolio
Content Categories1, found in the CEC Enforcement Procedure RPS (CA Code of Regulations, Title
20, Section 3203). The CEC Enforcement Procedures apply to publicly owned utilities (POUs), such
as CPAU.
In accordance with the state’s RPS Program requirements, CPAU’s Procurement Plan develops a
renewable electric supply portfolio that balances environmental goals with system reliability
while maintaining stable and low retail electric rates. The state RPS program requires retail
electricity suppliers like CPAU to procure progressively larger renewable electricity supplies
across three separate Compliance Periods, as outlined below.
1. Compliance Period 1 (2011 – 2013)
For Compliance Period 1 (2011-2013) retail electricity providers were required to procure
renewable electricity supplies equaling 20% of total retail sales, which CPAU did. In this period,
CPAU supplied 21.4% of the City’s retail electricity sales volumes from renewable energy sources.
The procurement results for Compliance Period 1 are displayed in Table 2 below:
Table 2: Compliance Period 1 RPS Procurement Details
Year Retail Sales
(MWh)
Procurement
Target (MWh)*
Actual Procurement
(MWh)
% of Retail
Sales
2011 949,517 189,903 207,974 21.9%
2012 935,021 187,004 200,621 21.5%
2013 953,235 190,647 199,145 20.9%
TOTAL 2,837,773 567,555 607,740 21.4%
* Annual procurement targets are “soft” targets. The RPS Procurement Plan requires that the
target be met for the compliance period as a whole, not in each year of the compliance period.
All of the renewable energy procured in Compliance Period 1 came from resources whose
contracts were executed before June 1, 2010. The RPS Procurement Plan considers these
contracts “grandfathered,” and since all of the renewable energy procurement for Compliance
Period 1 was from these types of contracts, there was no need to meet the Portfolio Balancing
Requirements included in Section B.4 of the RPS Procurement Plan.
1 RPS Portfolio Content Categories are defined as follows: Category 1 is energy and RECs delivered to a California
Balancing Authority (CBA) without substituting electricity from another source, Category 2 is energy and RECs that
cannot be delivered to a CBA without substituting electricity from another source, and Category 3 is unbundled RECs.
2. Compliance Period 2 (2014 – 2016)
In Compliance Period 2, renewable procurement must equal or exceed the sum of the three
annual RPS procurement targets described by the following equations:
2014 RPS Target = 20% × (Retail Sales in 2014)
2015 RPS Target = 20% × (Retail Sales in 2015)
2016 RPS Target = 25% × (Retail Sales in 2016)
As shown in Table 3 below, CPAU easily exceeded this mandated procurement level as well.
Renewable electricity procurement equaled 29.5% of retail sales for Compliance Period 2 overall.
Table 3: Compliance Period 2 RPS Procurement Details
Year Retail Sales
(MWh)
Procurement
Target (MWh)*
Actual Procurement
(MWh)
% of Retail
Sales
2014 953,386 190,677 210,250 22.1%
2015 932,922 186,584 241,262 25.9%
2016 914,748 228,687 375,343 41.0%
TOTAL 2,801,056 605,949 826,855 29.5%
* Annual procurement targets are “soft” targets. The RPS Procurement Plan requires that the
target be met for the compliance period as a whole, not in each year of the compliance period.
Also in Compliance Period 2, the RPS Portfolio Balancing Requirements applied to the
procurement levels described above. The specific requirements are: (1) CPAU must procure at
least 65% of its renewable supplies from Portfolio Content Category 1, and (2) no more than 15%
from Portfolio Content Category 3 (unbundled RECs). CPAU easily met the Compliance Period 2
overall procurement requirement and the RPS Portfolio Balancing Requirement, as five new solar
projects came online in 2015 and 2016, and all of these projects are considered Portfolio Content
Category 1 resources.
3. Compliance Period 3 (2017 – 2020)
For Compliance Period 3, CPAU is subject to “soft” targets to supply at least 27% of its retail sales
volume from renewable resources in 2017, with that level increasing by 2% each year until
reaching 33% in 2020, as described by the following four equations:
2017 RPS Target = 27% × (Retail Sales in 2017)
2018 RPS Target = 29% × (Retail Sales in 2018)
2019 RPS Target = 31% × (Retail Sales in 2019)
2020 RPS Target = 33% × (Retail Sales in 2020)
The overall Compliance Period 3 target is equal to the sum of these four annual soft targets. CPAU
is expected to easily comply with the Compliance Period 3 overall procurement requirement, as
well as the Portfolio Balancing Requirement that at least 75% of the renewable electricity
supplies come from Portfolio Content Category 1 and no more than 10% come from Portfolio
Content Category 3. Staff projects that renewable electricity supplies will satisfy nearly 50% of
retail sales for Compliance Period 3, even after accounting for the 540,000 MWh of RPS supplies
sold in 2019 and 2020, and that all of these supplies will come from either Portfolio Content
Category 1 or “grandfathered” resources.
Table 4: Compliance Period 3 RPS Procurement Details
Year Retail Sales
(MWh)
Procurement
Target (MWh)*
Actual/Projected
Procurement (MWh)
% of Retail
Sales
2017 884,422 238,794 554,206 62.7%
2018 888,033 257,530 574,475 64.7%
2019 861,561 267,084 319,035 37.0%
2020** 797,589 263,204 220,000 27.6%
Total 3,431,605 1,026,612 1,667,716 48.6%
* Annual procurement targets are “soft” targets. The RPS Procurement Plan requires that the
target be met for the compliance period as a whole, not in each year of the compliance period.
** Projected annual 2020 data: reflects executed sales of 324,000 MWh.
Finally, as required by the CEC RPS Enforcement Procedures and Section D of the City’s
Procurement Plan, staff reported all of the above information to the California Energy
Commission in August 2020.
Carbon Neutral Plan
In CY 2019, CPAU achieved its goal, set forth in the Carbon Neutral Plan, of an electric supply
portfolio with zero net greenhouse (GHG) emissions for the sixth consecutive year, without the
need to purchase unbundled renewable energy certificates (RECs) in the market. Carbon
neutrality was achieved in CY 2019 through existing hydro and renewable generation (wind, solar,
and landfill gas). Due to favorable hydro conditions, the City had a large surplus of energy,
allowing for the sale of 216,000 MWh of renewable energy while still maintaining a carbon
neutral supply portfolio (when evaluated using an annual carbon accounting framework).
When the City Council approved an update to the Carbon Neutral Plan in August 2020, the
primary change was to adopt an hourly carbon accounting methodology as the basis for
determining whether the City has met its carbon neutrality objective. Although this change did
not apply to the City’s electric supply portfolio for CY 2020, it is interesting to note how the City’s
supply portfolio would have fared under this accounting framework. Under the annual
accounting approach, the City had an overall surplus of 85,569 MWh of carbon neutral generation
compared to its load (equal to 9.4% total load), and thus substantially exceeded the carbon
neutrality standard. However, under the hourly carbon accounting approach, the City’s electric
supply portfolio is found to be responsible for a net positive amount of GHG emissions: 8,085
metric tonnes of CO2 equivalent.
Figure 1 below illustrates the City’s average monthly gross load (total electric consumption as
measured at Citygate) and net load (Citygate load less generation from carbon neutral supply
resources) for 2019.
Figure 1: CPAU Monthly Average Gross & Net Load for 2019
Figure 2 below depicts the average monthly emissions intensities for the California Independent
System Operator (CAISO) grid, as well as the City’s average monthly net electric emissions totals
for 2019. The emissions totals are the result of applying the hourly average CAISO emissions
intensity values to the City’s hourly net load (the monthly average of which is depicted in Figure
1 above).
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For CY 2020, slightly below average hydro conditions are expected to result in about 46% of the
City’s electric supply needs being supplied by hydroelectric resources, with the remainder coming
from non-hydro renewable energy resources (including purchases of out-of-state unbundled
RECs).
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City of Palo Alto (ID # 11860)
Utilities Advisory Commission Staff Report
Report Type: Supplemental Information Meeting Date: 1/6/2021
City of Palo Alto Page 1
Summary Title: Informational Update on EV Charging Programs
Title: Informational Update on City of Palo Alto Utilities Electric Vehicle
Programs
From: City Manager
Lead Department: Utilities
Recommendation
This is an informational report and no action is required.
Executive Summary
The attached presentation slides provide an update on the status of the City of Palo
Alto Utilities’ (CPAU) electric vehicle (EV) charger programs as of December 2020. A
primary focus of the program is the multi-family and non-profit sectors. In these sectors
88 sites (out of roughly 800-900 eligible sites) have expressed interest in the program.
28 technical reports have been provided to site owners representing a potential for 226
new EV charging ports. Two permit applications have been submitted and staff’s
current priority is assisting more customers with submitting permit applications before
expanding the number of sites participating in the program.
CPAU is also promoting its regional EV charger rebate program available to workplaces.
The program is launching in December and is expected to result in approximately 200
new workplace EV chargers and 10 publicly available direct current (DC) fast chargers.
The California Clean Fuel Rewards Program, partially funded by CPAU’s and other
agencies’ Low Carbon Fuel Standard (LCFS) funds, launched November 17 and provides
a $1,500 rebate for new EV purchases at participating dealerships.
Other CPAU EV programs being developed include a curbside charging pilot and an
income-qualified EV rebate program.
Attachments:
•Attachment A: Presentation
Staff: Hiromi Kelty
CITY OF
PALO
ALTO
cityofpaloalto.org/ev
EV Customer Programs
Update
Staff: Hiromi Kelty
~CITY OF
~PALO ALTO
2
NOTABLE PROJECTS COMPLETED IN 2020
Site Level 1 Level 2 DC Fast Charger Total Number of
New Ports
Ellen Fletcher
Middle School 0 18 1 19
Gunn High School 0 14 1 15
Greene Middle
School 0 14 1 15
SAP 0 120 4 124
Bryant Street
Garage 0 6 0 6
Cowper/Webster
Garage 0 14 0 14
Totals 186 7 193
~CITY OF
~PALO ALTO
3
EV CUSTOMER PROGRAMS UPDATE
EV Charger Rebate Program
•Number of applications: 42
•Approved number of rebates: 13
•Total amount of rebates approved: $346,000
•Number of new ports installed: 75
EV Charging Technical Assistance Program (TAP)
•TAP Interested Sites: 88
•Number of Technical Site Visits Complete: 24
•Number of Final Reports Presented: 28
•Proposed Number of New EV Charging Ports: 226 @ 16 multifamily properties, 9 places of worship and 1
non-p rofit
•Number of Permit Applications Submitted: 2 @ 2 multifamily sites for 6 new EV charging ports
•Number of new ports installed: 0
California Clean Fuel Rewards Program Launched on November 17th
•All California residents are now eligible for a $1,500 point of sale EV rebate
•CPAU mandated by CARB to contribute 25% of LCFS funds towards this statewide program
~CITY OF
~PALO ALTO
4
EV CUSTOMER PROGRAMS NEXT STEPS
Curbside Charging Pilot Program
•Resident-driven initiative
•Proposal: Install publicly available curbside chargers at 10 pilot sites with electricity supplied by
resident homes
•Collaborative effort with Public Works, Planning, and Utilities
•Looking at expanding CPAU’s $8,000/port EV charger rebate to proposed residential curbside
chargers
Income Qualified EV Rebate Program
•In research and design phase
CALeVIP (California Electric Vehicle Infrastructure Project) Launch December 16th
•Projection: 200 new Level 2 EV Charging Ports and 10 new DCFC over next 3 years at commercial sites
•CPAU contributed $1M in matching funds and City awarded $1M from the CEC
~CITY OF
~PALO ALTO