HomeMy WebLinkAbout2023-02-01 Utilities Advisory Commission Agenda PacketMATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE COMMISSION AFTER DISTRIBUTION OF THE AGENDA
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UTILITIES ADVISORY COMMISSION – REGULAR MEETING
FEBRUARY 1, 2023 – 6:00 PM
Council Chambers / ZOOM Webinar
NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956
Supporting materials are available online at https://www.cityofpaloalto.org/gov/boards/uac/default.asp on Thursday, 5 days
preceding the meeting.
Join Zoom Webinar Here Meeting ID: 966 9129 7246 Phone: 1 (669) 900-6833
Pursuant to AB 361 Utilities Advisory Commission meetings will be held as “hybrid” meetings with the
option to attend by teleconference or in person. To maximize public safety while still maintaining
transparency and public access, members of the public can choose to participate from home or attend in
person. Members of the public who wish to participate by computer or phone can find the instructions
at the end of this agenda. Masks are strongly encouraged if attending in person. The meeting will be
broadcast on Cable TV Channel 26, live on Midpen Media Center at https://midpenmedia.org, and live
on YouTube at https://www.youtube.com/c/cityofpaloalto. 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 6:00 pm – 6:05 pm
II. AGENDA REVIEW AND REVISIONS 6:05 pm – 6:10 pm
III. ORAL COMMUNICATIONS 6:10 pm – 6:25 pm
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 6:25 pm – 6:30 pm
Approval of the Minutes of the Utilities Advisory Commission Meeting Held on December 7,
2022
V. UNFINISHED BUSINESS
None
VI. UTILITIES DIRECTOR REPORT 6:30 pm – 6:45 pm
Chairman: Lauren Segal Vice Chair: A.C. Johnston Commissioners: John Bowie, Lisa Forssell, Phil Metz, Greg Scharff, and Loren Smith Council Liaison: Ed Lauing
• CITY OF
PALO
ALTO
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.
VII. NEW BUSINESS
1. Staff Recommend the Utilities Advisory Commission Recommend the City Council Approve
and Authorize the City Manager or Their Designee to Execute a Third Phase Agreement
With Northern California Power Agency for the Purchase of up to 87,600 Megawatt Hours
per Year of Geothermal Energy From Calpine Corporation's Geysers Power Company, LLC
Over a Term of up to 12 Years for a Total Not to Exceed Amount of $76.2 Million (ACTION
6:45 pm – 7:30 pm) Staff: James Stack, PhD and Micah Babbitt
2. Discussion and Status Update on the One Water Plan (DISCUSSION 7:30 pm – 8:30 pm) Staff:
Lisa Bilir
3. Staff Recommends the UAC Accept a Verbal Presentation on State Public Policy Actions and
Recommend the City Council Approve the 2023 Utilities Legislative Guidelines (ACTION 8:30
pm – 9:00 pm) Staff: Heather Dauler
VIII. COMMISSIONER COMMENTS and REPORTS from MEETINGS/EVENTS 9:00 pm – 9:10 pm
INFORMATIONAL REPORTS
Informational Utilities Quarterly Report Update for Q1 of FY2023
IX. FUTURE TOPICS FOR UPCOMING MEETING March 1, 2023
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)).
12-Month Rolling Calendar Public Letter(s) to the UAC
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
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1. Written public comments may be submitted by email to
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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
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Meeting ID: 966-9129-7246
City of Palo Alto (ID # 15050)
Utilities Advisory Commission Staff Report
Meeting Date: 2/1/2023 Report Type: IV. APPROVAL OF THE MINUTES
City of Palo Alto Page 1
Title: Approval of the Minutes of the Utilities Advisory Commission Meeting
Held on December 7, 2022
From: Director of Utilities
Lead Department: Utilities
Recommended Motion
Staff recommends that the UAC consider the following motion:
Commissioner ______ moved to approve the draft minutes of the December 7, 2022 meeting
as submitted/Amended.
Commissioner ______ seconded the motion.
Attachments:
• Attachment A: Draft Minutes
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CITY OF
PALO
ALTO
Utilities Advisory Commission Minutes Approved on: Page 1 of 13
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF DECEMBER 7, 2022 SPECIAL MEETING
CALL TO ORDER
Chair Segal called the meeting of the Utilities Advisory Commission (UAC) to order at 6:03 p.m.
Present: Chair Segal, Vice Chair Johnston, Commissioners Bowie, Forssell, Metz, and Smith
Absent: Commissioner Scharff
AGENDA REVIEW AND REVISIONS
None.
ORAL COMMUNICATIONS
None.
APPROVAL OF THE MINUTES
Chair Segal invited comments on the October 12, 2022 and November 2, 2022 UAC draft meeting
minutes.
Commissioner Johnston moved to approve the draft minutes of the October 12, 2022 meeting as
presented.
Commissioner Metz seconded the motion.
The motion carried 6-0 with Chair Segal, Vice Chair Johnston, and Commissioners Bowie, Forssell, Metz,
and Smith voting yes.
Commissioner Scharff absent.
Commissioner Smith moved to approve the draft minutes of the November 2, 2022 meeting as
presented.
Vice Chair Johnston seconded the motion.
The motion carried 6-0 with Chair Segal, Vice Chair Johnston, and Commissioners Bowie, Forssell, Metz,
and Smith voting yes.
Commissioner Scharff absent.
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UNFINISHED BUSINESS
None.
UTILITIES DIRECTOR REPORT
Dean Batchelor, Utilities Director, delivered the Director's Report.
Hydroelectric Update: As of December 5, precipitation totals for Northern California are about 80% of
average for this time of year and in Central California about 120%. Most of this precipitation has been in
the form of snow. The snowpack levels are about 160% of average in Northern and Central California.
Reservoir levels remain very low due to the past several years of drought. Projections for 2024 are very
low, about 56% of our long-term average levels of hydro output. Since hydro was much lower and the
price for electric went up, the Finance Committee unanimously decided on a $0.48 increase, which will
go to the Consent Calendar for the December 19 meeting for hopeful passage. Once approved by
Council, the report will be brought back to the UAC.
High Natural Gas Prices This Winter: CPAU anticipates natural gas prices will be much higher than usual
this winter due to market changes, supply and demand as well as weather, gas production and storage
levels. CPAU purchases gas at market price on a monthly basis and has a pass-through cost to the
customer. With the cold weather, there has been increased usage from customers.
Cityofpaloalto.org/efficiencytips has energy efficiency tips to keep utility costs down.
AMI Project Update: CPAU will soon begin deploying approximately 1,800 electric, gas and water
Advanced Metering Infrastructure (AMI) meters from January through March 2023. This a beta test for
comparison of meter reads to AMI data, quality assurance of the AMI meters and systems, as well as
provide an opportunity to look at some of our base load. We are going to deploy these in all-electric
homes to look at the load shapes and transformer loading, which is essential for grid modernization.
Approximately two weeks ago, 15 customers on a block had an outage because the transformer was
overloaded. Of the 15 homes served off that transformer, 10 had electric vehicles (EVs) and some
electrification had gone into the homes.
EV Programs Update: Stanford Medicine has successfully completed the installation of 15 new EV
charging ports at the Hoover Pavilion garage off Quarry and Palo Alto roads. Stanford is in the permitting
phase for installing EV chargers at two other garages. Our Communications team is coordinating a
ribbon-cutting event with Stanford for middle to late January. The UAC will be apprised of the date and
are welcome to attend.
Responsible Appliance Disposal (RAD) Award: CPAU recently earned a Champion Award from the U.S.
EPA through the RAD program. CPAU was recognized for its refrigerator recycling program and reducing
ozone and greenhouse gas emissions through insulation foam recovery.
One Water Plan: The One Water Plan is evaluating long-term water resource needs to make the City’s
water supply more resilient. The City held its second One Water Plan Community Workshop on
December 6 to discuss water supply, conservation options and draft evaluation criteria. A recording of
the workshop will be available on our website at cityofpaloalto.org/workshops. Staff will provide an
update to the UAC on the One Water Plan in February 2023.
Water Supply Update: The San Francisco Public Utilities Commission (SFPUC) continues to call for
voluntary water use reductions for the Regional Water System. Palo Alto’s cutback level is 8%. The City
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Utilities Advisory Commission Minutes Approved on: Page 3 of 13
has taken measures to continue water-saving efforts, including increasing education and outreach
programs. We have implemented water restrictions such as limiting irrigation to two days per week.
These actions seem to be making an impact. For the billing months of July through November 2022, Palo
Alto reduced its water usage by 10% compared to the baseline of 2020.
Commissioner Forssell asked for clarification on the deployment of 1800 meters as part of the AMI beta
test going out to electric homes, if there were 1800 all-electric homes. Mr. Batchelor responded no, the
beta phase is not just in electric homes. Staff is looking at where they think there is going to be
electrification by using records of homes that are 100% electric and permit history for heat pump water
heaters or electric heating. One area has 4 kV instead of a 12 kV system and is most likely the area that
needs to be upgraded the most, so that will probably be part of the beta phase.
Chair Segal commented we do not have great visibility into who has EVs, which is important to know.
There was a recent outage because of too many EVs on one transformer. Chair Segal wondered if there
was a way to get EV information voluntarily from customers or through DMV records to have some of
the beta homes in those areas. Mr. Batchelor thinks the information can be found through the
Development Center or EV permit history.
NEW BUSINESS
ITEM 1: ACTION: Adoption of a Resolution Authorizing Use of Teleconferencing for Utilities Advisory
Commission Meetings During Covid-19 State of Emergency
In response to Commissioner Forssell’s query if we know when the State of Emergency was scheduled to
end, Tabatha Boatwright, Utilities Administrative Assistant, responded that the State of Emergency
would end in February 2023.
ACTION: Vice Chair Johnston moved Staff recommendation that the Utilities Advisory Commission (UAC)
Adopt a Resolution (Attachment A) authorizing the use of teleconferencing under Government Code
Section 54953(e) for meetings of the Utilities Advisory Commission (UAC) and its committees due to the
COVID-19 declared state of emergency.
Seconded by Commissioner Smith.
Motion carries 6-0 with Chair Segal, Vice Chair Johnston, and Commissioners Bowie, Forssell, Metz, and
Smith voting yes.
Commissioner Scharff absent.
ITEM 2: DISCUSSION: Discussion of Costs and Reliability of Different Back-Up Electricity Technologies
Hamilton Hitchings stated the the recent attack on the North Carolina Substation where 35,000 people
are still without electric power puts a spotlight on the vulnerability of the electric grid. On April 16, 2013,
a sniper attack disabled the PG&E Transmission Substation in San Jose, which included accessing an
underground vault to disable phone lines beforehand. We should ensure our existing substations and
the PG&E Delivery Station are hardened particularly from domestic terrorism but also from flood and
earthquake, including ample alarms, security cameras, barbed wire, electrified fences and on-site
security at the Colorado Ave site. He recommended doing a security audit to ensure existing
mechanisms are working properly and adding additional ones as deemed appropriate. He thinks critical
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Utilities Advisory Commission Minutes Approved on: Page 4 of 13
infrastructure such as the Public Safety building should have microgrids to have the ability to go for one
or two weeks after a major earthquake if there was no electric versus three days on their generator.
Subsidizing batteries for residential use dramatically lowers the amount of electricity going in and out of
the house from solar and can be used to lower peak hour supply during the summer. The ultimate
solution is to have electric cars provide two-way charging.
Lena Perkins, PhD, Senior Resources Planner, delivered a slide presentation. The cost of different
technologies for single-family residence back-up power was based on July 2022 but current prices are
higher for natural gas, batteries and solar.
In reply to Chair Segal’s question if the calculations included the assumption of air conditioning in the
summer, Dr. Perkins answered yes.
In response to Commissioner Smith’s inquiry on how capital costs were annualized, Dr. Perkins replied
they were based on the 20-year net present value, batteries had to be replaced at 10 years and
everything else was expected to last 20 years.
Commissioner Smith commented on the first slide. He suggested comparing the annualized cost to the
current CPAU annualized cost to help customers make the decision to completely solar panel their
house, put in an inverter and new battery. Dr. Perkins explained this was in addition to your bill, so it
takes into account the bill savings. The uncertainty bar on the graph represents the degree you are able
to offset your own usage versus exporting to the grid. The chart represents a 7-kilowatt solar system.
Commissioner Metz commented on the data Dr. Perkins shared with him. A mixed-fuel (gas and electric)
house with no EV is 7500-kilowatt hours per year. An all-electric house with no EV is an additional 4200
kilowatt hours per year. EV is assumed 2000 kilowatt hours per year.
Commissioner Smith asked if there was a compelling argument for doing solar on mixed-fuel homes with
no EV. Dr. Perkins thinks the costs are similar without a battery for a mixed-fuel home with a 5-kilowatt
system. The costs are similar to the first yellow bar representing solar PV where you can potentially save
money by offsetting your electric usage and largely net out close to zero additional cost by adding solar.
Commissioner Metz asked for an explanation on what was represented by the width of the bars on
Table 2. Dr. Perkins explained if an outage occurred at night in the wintertime, you have different
reliability from solar without storage. Therefore, an average was calculated across seasons and times to
give a rough representation of the different reliability they can provide. The noise level, CO and CO2
emissions are qualitative. Several stakeholders and the Stanford professors who were involved in the
project thought it was important to demonstrate gasoline generators and natural gas generators had
health and safety drawbacks solar did not have. In answer to Commissioner Metz’s query if red was bad,
meaning noise or emissions, Dr. Perkins answered yes. Commissioner Metz asked if the width
represented reliability. Dr. Perkins responded that the left four columns were reliability and the other
two columns were noise level and dangerous CO2 and CO emissions. A nontrivial amount of CO
poisoning occurs during broad outages and some of it is from portable generators.
Chair Segal asked for further explanation regarding what the wide green represents for the noise level,
CO and CO2 emissions. Dr. Perkins explained it was a qualitative representation in order to represent
drawbacks which were not adequately captured by only looking at cost and reliability. Not having
substantial noise and emissions is meaningful especially to health and safety. In response to Chair
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Utilities Advisory Commission Minutes Approved on: Page 5 of 13
Segal’s query if the emissions width represented avoided emissions, Dr. Perkins replied it is
representative of CO, NOx and SOx emissions rather than CO2 emissions because it is from a health and
safety perspective instead of avoided emissions.
Commissioner Smith remarked that if the majority of Palo Alto single-family residences are gas and
electric but transformers were overloaded from homes functioning on PV, we need time to replace our
grid. Commissioner Smith wanted to know the benefits of offering subsidies on PVs and battery storage
systems, if it would buy us time and give the CPAU an opportunity to rebalance the load appropriately.
Dr. Perkins replied it depends on how the battery is wired into the system, if it was an additional route
to dump power into the system and back-feeding onto the grid. Commissioner Smith stated he was not
suggesting that homes feed the grid as if selling our power back to PG&E or self-generation. If a
homeowner charges their EV on a solar-powered battery, it takes the load off the grid and transformer.
Dr. Perkins explained the issues when people install batteries is if they are satisfied with not back-
feeding onto the grid or it could be wired differently after it is permitted and interconnected.
Modifications after inspection can cause hot elements and safety issues if things are not appropriately
upsized. Commissioner Smith suggested that the City manage the installation in exchange for a subsidy,
the City can set the installation rules and place padlocks on the associated panels. Dean Batchelor,
Utilities Director, agreed that City subsidies should include being involved with how the house panel
looked and how the system was wired.
Mr. Batchelor commented it would be helpful if we knew there were quite a few EVs on one particular
transformer. If neighbors knew exactly when they were going to charge, it would not create the outage
we saw in the last couple weeks and it buys us some time. This needs to be part of the community
education and communication for people who have EVs.
Dr. Perkins noted that if everyone was operating within their permit, not modifying things after
inspection and permitting, then technology such as SPAN Smart Panels could be helpful for the
homeowner to operate within the capacity of their electrical equipment. The question is whether our
Engineering team is comfortable planning around that or whether it would be taken into account with
the planned grid modernization. It would be beneficial if everyone were to flatten their loads as
theycharge. If grid modernization was $80 million minimum, Commissioner Smith thought if we buy
more time, perhaps that $80 million can be $40 million initially and then we will work on the rest but we
would not have such an urgent issue if homeowners were taking responsibility for their own generation.
Regarding subsidizing battery storage, Commissioner Forssell stated she would be very surprised if
locating energy storage at the granular level of single-family homes was cost effective. She thinks the
much lower hanging fruit is an educational campaign around when to charge your car since that is the
most shiftable load. If a block wanted to buy time for their transformer, coordinating their EV charging
costs considerably less than subsidizing power walls on single-family homes that have a very limited
ability to serve the community.
If there is a further iteration, Commissioner Forssell would be very interested in holding the period of
power outage fixed and looking at different load requirements for the average single-family home as
there seemed to be an assumption that the home was going to require everything it required as if it was
a nonemergency situation. Commissioner Forssell would be very interested in what is the minimum
required electrical output for a household with maybe a variation of 2-person, 4-person and a huge
family, assuming they need a refrigerator, cooktop, some number of lumens of light, some number of
gallons of hot water, internet and medical equipment.
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Commissioner Forssell asked if part of this goes beyond the UAC, such as Utility marketing of the options
or we will work with you or here is an informational pamphlet. Dr. Perkins stated one discussion they
had with OES and others is if there is a major earthquake or giant power outage, not everyone will burn
through their battery or tank of gas. The baseline for critical loads was 25% to 30% of average, which is
part of the reason they represented the percentage of loads on Figure 3. It was capped at 48 hours
because many technologies (other than battery) reach equilibrium after 48 hours, so two weeks looks
similar to 48 hours, depending on weather and availability of natural gas and gasoline. In response to
where does work on resiliency go after this, Dr. Perkins thinks there are high-level discussions with the
S/CAP Committee. OES is interested in having some public education but in terms of the Utility staff time
needed to create those public messaging campaigns, Dr. Perkins thinks we have many priorities
competing for our limited Engineering resources. In response to Commissioner Forssell asking for
clarification that this was not a preview of a currently planned campaign but just a conversation, Dr.
Perkins replied this was not a preview although there were some discussions.
Vice Chair Johnston encouraged staff to think about putting this information out in a way that the
community can grasp it because he thinks that people developing more resiliency would provide many
benefits. Particularly if we were encouraging people to electrify, we want to encourage them to have a
back-up plan. The available back-up plans as well as pros and cons of each is useful information and
should be accessible to people in the community, maybe not a whole campaign but at least putting it on
the Utility website and letting people know this information is available. Mr. Batchelor thinks this
reliability and resilience plan is moving forward into the Council’s Ad Hoc Sustainability and part of the
work plan for the Council. Customer and community education is important.
Council Liaison Cormack, who sits on one of the ad hoc teams, stated there is a tradeoff between the
City providing sufficient reliability to give people the confidence they can move over to electricity
completely but just in case, you might want to spend a whole lot of extra money on something that will
work for a little period. It is a tough message, although this information should be provided. We do not
want people using a generator. From a policy perspective, it is interesting to think about our twin goals
and one is to make sure the whole system is reliable so everyone feels comfortable moving and another
is to be sure that in situations where people cannot tolerate an hour of outage that they have the
information they need to make that decision. Staff was asked to come back and describe what it might
look like if we created a commission around our climate work. There is an overlap of the climate work
with the UAC and there is a lot of work to be done in both areas.
Chair Segal asked if the costs for using a library or community center as a community power backup in a
major power outage would be similar to a multifamily community room. Dr. Perkins replied that an
analysis would need to be performed but she thinks there would be less savings day to day because the
utilization would be lower.
Commissioner Metz commented that having specs for what a system needs to enable somebody to stay
afloat and communicating that to PV system owners and perhaps a clearinghouse to provide resources
for owners and installers would be low cost and high value.
Chair Segal noted that the OES website has a list of what to have for an emergency. Even though much
of this is beyond the purview of the UAC or the Utility but to get the conversation going is helpful. She
worries that people with solar do not realize they will not have it when the system is down. She does not
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think it is realistic to have a refrigerator running for two weeks when needed supplies include canned
food and pasta.
ACTION: None.
ITEM 3: DISCUSSION: Presentation and Update on the City’s Electric Grid Modernization Analysis
Hamilton Hitchings commented he is not convinced on the cost benefit of undergrounding except in the
foothills where it is much more expensive and harder to diagnosis where problems are and fix them. He
thinks we should accelerate electric poles, which are more resilient than our regular poles and do not
catch fire. There is a disproportionate cost sharing on fiber as opposed to electric for the poles and so if
that was switched around to make sure electric is paying for the appropriate cost, it may make the
financials for fiber more attractive. Utility policies and fees on electric panel upgrades strongly
discourage residential electrification. You can upgrade to 225 amps. Upgrading to 400 amps has a
$10,000 fee and a much longer cycle. If you are a double-working family and want to charge two electric
cars quickly, you need 50 amps per electric car. Most houses in Palo Alto will want 300 amps. He has
three recommendations: (1) As fast as possible, remove the $10,000 residential fee. (2) Preorder
transformers because it takes one to two years to receive them. (3) Change from 225 to 300 amps.
Sherry Listgarten remarked she is not convinced anybody needs more than 200 amps. We all need to be
more cognizant of our power usage and have low, steady amounts of power, so some education on not
running every high-powered appliance at the same time would be useful. A couple years ago, JuiceBox
gave free chargers to utilities for their customers. There must be software to coordinate EV charging
that would cost a fraction of whatever everything else is costing and people could be incentivized with a
free charger for opting into it. If they need to charge in an emergency, they can opt out. Otherwise, it
keeps everybody at 20 or 10 amps and it adjusts who is charging when. She suggested calling Enel-X who
owns JuiceBox or there may be a company in San Jose.
David Coale echoed Ms. Listgarten’s comments but disagreed with the first speaker. There is plenty of
room in a 200-amp panel to electrify a house. Having a steeper cost would help people stay within a
reasonable electric budget. EV chargers do not have to be 50 amps to be sufficient for almost all
people’s driving. Whether it is for resiliency or supporting the grid, there are 250 megawatt hours in EV
battery storage already paid for by the residents that is not being used. If the Utility is going to subsidize
anything, it should be vehicle-to-grid bidirectional chargers because they substantially reduce the load
on transformers in problem neighborhoods. You could run a house for days with a minimum load of
about 1 kilowatt for the refrigerator, some lights and the internet, so the calculations should be redone
based on that. All these things will get cheaper with the Inflation Reduction Act, which he thinks was not
factored into the cost in the previous item or grid electrification upgrades.
Tomm Marshall, Assistant Director Electric Utilities, showed slides for the grid modernization update.
The Electric Infrastructure Analysis draft report was received last week. The focus of the first portion of
the report was grid capacity and update recommendations. Costs are significantly higher than before to
upgrade the grid. Staff will come back to the UAC with details. The main changes needed are upgrading
distribution transformers and the secondary system serving customers, converting older substations
from 4 kV to 12 kV as well as upgrading capacity at a couple of our substations. There were peak
diversified load recommendations, which is about where we originally estimated at 6 KVA per home. We
are designing this system for peak demand to have enough capacity to serve customers during
emergency or unusual conditions.
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We see the impacts of electrification in new building applications and panel replacements. About two-
thirds of new panels are 400 amps, one-third are 225 amps. There are a number of 600 amp requests
from customers with large homes and large loads such as heat pumps for swimming pools. We are
seeing more transformer upgrades. We recently received 23 larger transformers from an order placed
last year, which are currently in the yard. We have placed orders for next year. Many of these new
homes are in the beginning process, so the upgrades to 400 amps are probably not going to show up on
the system until middle or late next year. More load is going on the system that we do not have visibility
in because they are permitted over the counter, such as electric-resistive water heating or having
multiple units in the house. The Electric Utility does not review them unless it results in a panel upgrade.
More EVs are coming on the system and impacting other customers. A lot of battery storage systems are
coming on, so we have to plan for batteries charging off the utility system in the future. Since water
heating fails regularly in homes, we are encouraging people to move to E-pumps because it has the least
impact on the grid since they are not large loads.
Next year, we will probably run our first trial project on grid upgrades. The key is getting transformers,
we are trying to order in advance but the lead times are about a year or a little more.
We are continuing to recruit staff but we are having difficulty finding experienced engineers who want
to work in Palo Alto. Three recent graduates have come into the Department, so we are spending a lot
of time getting new staff up to speed. We have three experienced engineers on staff, so we are very
short on experienced staff. We have a backlog of infrastructure projects from pole replacements and
two customer requests for large amounts of power, which requires rebuilding existing substations. We
are very short on staff in operations as well. As we move into grid modernization, we need to have
increases in staffing to manage the contracting work.
Staff has to coordinate between the programs going out into the community and the places where we
are trying to incent people to switch to electrification. As we start developing the upgrade plans, we
need to match them to where we have customers who want to electrify and coordinate in those
neighborhoods to incent people to move to electrification in the areas where we have capacity.
Regarding staffing, Commissioner Metz asked how the UAC could help, such as having proposed
solutions or partial solutions that the UAC might be able to advance to City Council. Mr. Marshall
responded that the City is in the middle of a negotiation process with the unions and staff.
Compensation and other things that are competitive in this area are important to us being able to
attract and retain employees.
Commissioner Metz commented that the grid of tomorrow that we are planning and building is going to
be different from the grid of today, particularly in having local resources for management, including
bidirectional charging with EVs but that had not been discussed. Commissioner Metz asked if those were
going to be increasingly important factors in designing the grid and if so, what were we doing about it.
Mr. Marshall remarked that the next part of the study was expected to include the integration of more
sophisticated systems to run the distribution network, including how to integrate batteries into the
system as well as advanced protection schemes to make the grid more reliable. The capacity piece is
moving ahead because it has to start as early as possible since it takes the longest time to implement.
Mr. Marshall explained that some of these other things we are talking about is immature technology, it
is starting to come into the marketplace and some people are running pilot programs around these but
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he does not know if they are ready for full deployment to relieve the need for capacity on the grid. Even
though the technology is not ready, we are planning to incorporate that into the grid design and how we
are going to do that will come in the next part of the study. There is some complex data analysis and
communication needed to run these systems on a grid-wide basis, which is probably coming not too far
in the distant future but it is not ready to implement on a full utility basis today.
Commissioner Smith requested further clarification on how solar homes can reduce demand. Mr.
Marshall explained that demand is an instant in time. Many things drive demand on the system, such as
plugging in vehicle chargers at the same time or everything coming on at the same time after a system
outage. We plan for those times when the system is stressed. Commissioner Smith commented that if a
7000-kilowatt hour solar PV array on a home was used for a significant portion of the load, it reduces
the assumption on an individual basis and it reduces the peak if that was applied to 26,000 residences.
Mr. Marshall responded that battery storage could offset some of it. Solar is not operating when there is
no sun, especially in winter, so it depends when the peak demand is happening.
Commissioner Smith pointed out we need to be creative in terms of how we design our new system
when we are talking about spending this amount of money and time to implement these necessary
improvements. Technology can help us with respect to spreading and managing load as well as
education on when neighbors charge their car or managing their car charging time. Mr. Marshall stated
that we need to think about how we would manage such a system and whether customers are willing to
have the Utility control their load.
Regarding the three large customers with big power demands that require reengineering a substation
and is placing demand on our limited engineering resources, Commissioner Forssell asked how the
Utility prioritizes what the limited staff spends its time on and if there was a conscious decision that
these three customers can use all the engineering time versus grid modernization efforts. Mr. Marshall
responded that typically the focus is first on customer requests. We do not have staff to do CIP. We are
using more contractors. In one of these cases, we are working with the customer for them to do the
engineering and installation for a large substation upgrade but that still takes staff time. Commissioner
Forssell reminded the UAC that we tend to be very focused on residential customers but commercial
customers are 80% or 90% of our load.
Mr. Marshall responded to Chair Segal’s question on over-the-counter permits not being captured into
the demand on transformers and if there was an easy fix such as a monthly report. With the limited
staff, there is no time to review everything that happened over the counter at the Development Center.
There is state legislation that will require battery storage systems over the counter as well.
Chair Segal suggested that staff talk to Permitting. There should be a simple tool if it is computerized,
such as an added box on the permit for load or a weekly report that totals the load. This will likely be a
bigger problem down the road as there is more over the counter. Mr. Marshall commented that
connecting the systems would take time to develop programming, aggregate things and associate them
with the proper transformer. With more staff, they may be able to do that task. Dean Batchelor, Utilities
Director, added that we do not know what is loaded on a transformer unless we physically go out and
look at it, which we do not have the staff time to do. As we move forward with modernizing the grid,
AMI will help us. Some technology is coming out that would be able to pull a report or look at the load
on a transformer similar to looking at your home meter.
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Chair Segal had questions regarding load assumptions when estimating peak demand, such as how many
homes will be electrified, how many EVs per home and whether businesses were electrifying. Mr.
Marshall replied that we are planning for full residential electrification as well as figuring out increases
from businesses electrification. Typically, we would install a new transformer to supply vehicle charging
for a large commercial customer. Businesses electrification is not as impactful as residential because
there is usually more capacity.
Mr. Marshall confirmed Chair Segal’s assumption that the main reason it is hard to get engineers to
work in Palo Alto is due to the high cost of living in Palo Alto.
Council Liaison Cormack wanted to know if there was a connection between 6 kVA and the 600-amp
panels that people were putting in. Mr. Marshall explained that 6 kVA was not a large load, probably less
than 100 amps. It had to do with the aggregation and diversity of load on the system. You can have 10
people on a transformer. You could have somebody using 20 and four or five people using 1 or 2 kVA.
Today, we use 2 to 3 but we believe it is going to be around 6 in the future.
Council Liaison Cormack felt strongly that we should not be maximizing any system. She asked if other
municipal utilities were assuming 6 kV. Mr. Marshall replied that part of the data used was a large study
done by the Los Angeles Department of Power and our numbers are very similar. Roseville uses 6 kVA
per home before electrification because they have large air conditioning loads. We have to design for
the worst case and 6 kVA per home is not thought to be excessively high.
In response to Council Liaison Cormack’s question regarding Slide 6 indicating there is no staffing to
manage this program, Mr. Marshall answered they are looking to fill positions and we will need
additional staff to manage the work when we get into the system capacity increases. Since there is a
mid-year budget coming and then there will be a new budget, Council Liaison Cormack hoped the
Utilities Department will ask for all the positions they need to make progress on this.
Mr. Marshall addressed Council Liaison Cormack’s query regarding the timeframes for the
modernization steps on Slide 5. The expectation is that the data will be received in the first part of next
year, maybe March. In reply to Council Liaison Cormack’s question if the priority of the feeders and
substations would be known, Mr. Marshall answered yes.
Council Liaison Cormack asked about the duration to complete the program. Mr. Marshall believed the
residential neighborhoods would be done within five years. Mr. Batchelor thought it was a five-year
program, maybe starting the first or second quarter of 2025 and the electrification portion could be
completed in the residential areas by 2030.
ACTION: None.
The UAC took a break at 8:01 p.m. and resumed at 8:12 p.m.
ITEM 4: DISCUSSION: Discussion of City of Palo Alto Utilities’ Long-Term Electric Load Forecast through
2045
David Coale commented he is hoping that modernization of the grid as well as vehicle to grid was taken
into account in the long-term forecasts and that future loads would probably be substantially less than
predicted even with electrification.
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Hamilton Hitchings stated he is on the Housing Element Working Group for the City. Their plan would
add 6000 new housing units in the next eight years. He questioned whether the model anticipated the
new houses. All the houses will be electric.
Lena Perkins, PhD, Senior Resources Planner, made a slide presentation including low, mid and high load
forecasts demonstrating additional EV load as well as building electrification load and additional
commercial loads (largely new data center loads). There are many uncertainties in all forecasts and this
was a snapshot in time. As housing is permitted and constructed, there is lead-time to procure sufficient
electricity that meets out carbon-neutral electric portfolio standards. The long-range forecasts are
updated every five years.
In reply to Commissioner Forssell’s question regarding gas packs on Figure 2 for Building Load
Assumption, Dr. Perkins responded that a gas pack is a rooftop heating unit that can be easily replaced
by a heat pump.
Dr. Perkins explained that knowing what our hourly load shape is now and then breaking it into groups
of EV, building electrification and additional commercial load, helps us modify those hourly load shapes
for the whole city going forward. Vice Chair Johnston stated he is looking forward to discussing how we
are going to meet these loads.
Commissioner Metz noted that traditional loads are flat to a little down on the chart on Figure 3, so the
new load is coming from electrification, EVs and data centers. He asked if there was a plan to guide the
loads in the future to make it easier and less costly to modernize the grid, such as pricing or time of day.
Dr. Perkins replied that a time-of-use rate would be the primary mechanism for influencing the hourly
shape of the loads. In response to Commissioner Metz’s query if demand management would be a part
of that, Dr. Perkins answered yes. There is a state program for customers to opt-in to an ISO-managed
demand response program that can benefit the grid, which we may opt-in in the next couple years. In
general, our load factor is quite high as a city, so the shaping is more important for the distribution
system than it is for the wholesale markets. The hourly shape of the whole city is much flatter than the
hourly shape of the residential sections, so the residential sections are where demand management
could be helpful in the short term. Once you average the residential and commercial sectors, we have a
favorable relatively flat load shape, so there is limited value in lowering our demand in certain hours.
In response to Commissioner Bowie’s question if the EV load curve projections included transient or
commuter loads, Dr. Perkins replied yes but the EV load forecast has the most uncertainty because we
do not have an inventory of EVs commuting in and how much they are charging. Research says 80% of
charging happens at home. With longer-range batteries, more charging could stay or shift to home,
although there is debate over whether that is preferable since daytime charging is cleaner.
Commissioner Bowie asked if the projections took into account that the EV market is rapidly changing
and increasing as more affordable vehicles come online. Dr. Perkins explained it was a forecast. The
S/CAP goals for EVs were represented in blue for the high scenario. The mid scenario assumed 75% of
S/CAP goals. All EVs coming into Palo Alto and living in Palo Alto are currently using 10 gigawatt hours
per year, which was multiplied by a factor of 13 according to the table. One out of every three new
vehicles we have is an EV, so there will be high penetrations of EVs in the future for commuter and
residential vehicles.
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Dr. Perkins addressed Commissioner Forssell’s query if there was any insight as to why people were
choosing Palo Alto. SBP (City of Santa Clara’s municipal utility) was projecting their load going up 250%,
largely driven by data centers. Dean Batchelor, Utilities Director, thought that real estate was causing
some of the push with companies buying properties and rebuilding or expanding. Mr. Batchelor wished
more data centers would come to Palo Alto because it is a 24/7 non-manned operation and are great
loads because revenues exceed costs. Dr. Perkins explained it can be thought of as wires being a fixed
cost and how much the wires are used is revenue.
Council Liaison Cormack remarked that this might fit in our Economic Development Group. A consultant
was working on what industries we might want to target and what economic development programs we
might want to implement. She encouraged staff to speak with Steve Guagliardo and the consultant as
well as include this topic in the next S/CAP meeting.
ACTION: None.
COMMISSIONER COMMENTS and REPORTS from MEETINGS/EVENTS
Chair Segal attended the One Water Community Meeting last night. Among the participants, water
quality and equity were high priorities. Karla Dailey, Acting Assistant Director Utilities Resource
Management, remarked that participants maybe had more of an environmental primary interest, so
cost ranked lower relative to other criteria in terms of importance. There were about 15 members of the
public but she wishes every Palo Alto resident could provide their input.
FUTURE TOPICS FOR UPCOMING MEETINGS
Vice Chair Johnston thought the informational update on the electric supply portfolio was interesting.
He noticed we retained a consultant to model and analyze the economics and portfolio fit of the
options. He was curious as to when staff thought the results would be ready to be presented because he
thought it would fit very well with February’s topics regarding the geothermal contract, Western Base
Resource and COTP since they are all potential resource changes. Jim Stack, PhD, Senior Resources
Planner, has been working on the load analysis and portfolio rebalancing. The discussions in February on
the geothermal contract, Western and COTP will be preliminary overviews of those topics. A consultant
was recently engaged to do a more rigorous analysis of the rebalancing options, which was expected to
be done around March and hopefully presented to the UAC around April.
Commissioner Metz requested an update, perhaps in the next quarter, on Director Batchelor’s
September 2022 discussion on outages and maintenance. Dean Batchelor, Utilities Director, stated that
the quarterly reports would include a graph and Staff can talk about it at that time.
Commissioner Forssell requested an informational report be included the next time it is an agenized
item. For the February meeting when specific contracts are discussed, maybe the Brown Act can be
included in the reading material as an exhibit so commissioners can comment on. Mr. Batchelor
suggested bringing this report back as a separate item because he is not sure it can mix in with the
geothermal contract and Western Base. Chair Segal clarified that she appreciates that staff thinks of
these as individual contracts but the UAC thinks of them collectively as our resources, so she requests to
have that bigger context when individual contracts are discussed.
NEXT SCHEDULED MEETING: January 4, 2023
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Commissioner Smith moved to adjourn. Commissioner Forssell seconded the motion. The motion
carried 6-0 with Chair Segal, Vice Chair Johnston, and Commissioners Bowie, Forssell, Metz, and Smith
voting yes.
Commissioner Scharff absent.
Meeting adjourned at 8:48 p.m.
Respectfully Submitted
Tabatha Boatwright
City of Palo Alto Utilities
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City of Palo Alto (ID # 14678)
Utilities Advisory Commission Staff Report
Meeting Date: 2/1/2023 Report Type: VII. NEW BUSINESS
City of Palo Alto Page 1
Title: Staff Recommend the Utilities Advisory Commission Recommend the
City Council Approve and Authorize the City Manager or Their Designee to
Execute a Third Phase Agreement With Northern California Power Agency for
the Purchase of up to 87,600 Megawatt Hours per Year of Geothermal Energy
From Calpine Corporation's Geysers Power Company, LLC Over a Term of up
to 12 Years for a Total Not to Exceed Amount of $76.2 Million
From: Director of Utilities
Lead Department: Utilities
RECOMMENDATION
Staff recommends that the Utilities Advisory Commission (UAC) recommend that City Council:
1. Authorize the City Manager, or their designee, to execute a Third Phase Agreement
(Attachment A) with the Northern California Power Agency (NCPA) to purchase up to
87,600 MWh of renewable energy/year from a portfolio of geothermal projects owned
by Calpine Corporation’s Geysers Power Company, LLC, over a period of 12 years, at a
total cost not to exceed $76.2 million;
2. Authorize the City Manager, or their designee, to execute on behalf of the City all
related documents or agreements necessary to administer the Third Phase Agreement
that are consistent with the Palo Alto Municipal Code and City Council approved
policies, including, but not limited to, collateral assignment agreements; and take any
and all actions as are necessary or advisable to implement and administer the Third
Phase Agreement;
3. Authorize the City Manager, or their designee, to approve and execute amendments to
the Third Phase Agreement, as may be required from time to time, so long as the
contract price and length of the agreement remain unchanged; and
4. Waive the application of the anti-speculation requirement of Section D.1 of the City’s
Energy Risk Management Policy as it may apply to surplus electricity purchases resulting
from the City’s participation in the Calpine contract, due to the variability of the City’s
hydroelectric resources and uncertainty around the City’s long-term load forecast.
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CITY OF
PALO
ALTO
City of Palo Alto Page 2
Background
SB 100 & Carbon Neutral Plan goals
As part of ongoing efforts to meet the City’s Carbon Neutral Plan requirements, as well as to
comply with the state Renewable Portfolio Standard (RPS) mandate of providing at least 60% of
sales from qualifying renewable resources by 2030, staff pursued a power purchase agreement
(PPA) opportunity presented by Calpine to NCPA. Calpine is offering to sell power from a
geothermal1 power plant, which qualifies as an in-state “Bucket 1” renewable resource under
the state’s RPS requirements.
Existing RPS portfolio
Over the past three years, the City has had an average RPS level of 63%2 and is projected to
maintain a high percentage of its power from renewable resources well into the future. Figure 1
below shows Palo Alto’s projected RPS requirements along with the City’s existing supply
resources. Starting in 2029, the City is projected to have a deficit relative to its RPS requirement
level (depending on the amount of large hydroelectric output the City receives 3).
1 Geothermal power plants have a small amount of carbon emissions associated with their operations from the
natural release of greenhouse gases from the geysers
2 This value refers to the total renewable energy content of the City’s supply portfolio, including all of its in -state
(“Bucket 1”) renewable resources and its unbundled, out-of-state (“Bucket 3”) renewable energy credits (RECs).
For state RPS reporting purposes, the volume of Bucket 3 RECs that can be counted is limited; under this more
restrictive framework the City’s reported RPS level has averaged 31% over the last three years.
3 Under the state’s RPS law, utilities that receive significant amounts of generation from certain large hydroelectric
facilities are able to satisfy their RPS requirements with a lower RPS level than is required of other utilities. Such
utilities are only required to achieve an RPS level equal to the difference between their total retail sales volume
and the amount of generation they receive from qualifying large hydro facilities.
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City of Palo Alto Page 3
Figure 1: Palo Alto’s Existing RPS Supplies and RPS Requirement Levels
Discussion
The Market for Renewable Resources in California
The pricing and availability of renewable resources in California has evolved significantly over
the past decade as state and federal policies have shifted the market landscape. While the
trend over the last decade has been the declining cost of renewable PPAs, the last two years
has seen increasing challenges to developing and building renewable projects resulting from
material shortages, supply chain issues, inflation, labor shortages, and ta riffs. Before 2020, the
market would generally have been described as a buyer’s market, however, in the last two and
a half years, this characterization has shifted to a seller’s market as there are more renewable
buyers, increasing challenges to completing projects, and as a result PPA prices have risen from
record lows.
While the downward trend in renewable energy pricing has reversed in the last couple of years,
staff expects the generous subsidies included in the Inflation Reduction Act (IRA), which w as
signed into law August 16th, 2022, to eventually push renewable energy prices lower again.
There are many details in the IRA that are being outlined by the Treasury Department, and the
initial feedback from developers is that it is still too early to understand the net impact this law
will have on Palo Alto’s renewable resource options. Ultimately staff expects the IRA to reduce
the cost of renewables. However, the consensus view in the California market is that it will
likely be several years before these cost reductions materialize, given the extent of the current
supply-demand imbalance and the various development challenges.
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While the market prices for intermittent renewable resources such as solar and wind, and
energy storage systems have fluctuated in recent years, the price for baseload firm renewable
resources such as geothermal energy has remained relatively steady. The price for energy from
geothermal resources is relatively high, reflecting its higher cost of development and its higher
value to the electrical grid.
Results of Palo Alto’s Renewable RFP (2022 RFP)
As staff discussed at the June UAC meeting, staff issued a Request for Proposals of new
renewable and/or carbon-free generating resources and energy-storage resources. Staff’s
evaluation of the four conforming project proposals (all of which were for solar resources)
indicated that their “green premiums” (i.e. their net cost to the City – their total value less their
total cost) ranged from $3/MWh to -$18 /MWh. In comparison, the Calpine geothermal
project’s net cost is estimated at -$3/MWh (see below for more detail on this analysis). But in
the course of reviewing the four responsive proposals, staff (1) became aware of efforts at the
federal level to pass significant new clean energy legislation (in what became the IRA), and (2)
learned about the Calpine geothermal project proposal. As a result of these two events, staff
decided to reject the four conforming proposals received through this RFP.
Calpine Geothermal Project Summary
In May 2020, Calpine submitted a proposal to NCPA’s4 Renewables RFP for the sale of energy
and associated attributes from Calpine’s5 existing portfolio of geothermal projects located in
The Geysers area of Northern California. At the time Calpine submitted its proposal, NCPA
members were evaluating other lower-cost project proposals. But shortly thereafter, the price
of renewable projects started to significantly increase, due to the confluence of factors noted
above. So in September 2021, NCPA requested proposal updates from Calpine and the other
RFP respondents to see if their projects were still available and if there were any changes in
price and/or terms initially offered. Section 2.30.340(d) of the City’s Municipal Code permits the
City to procure wholesale utility commodities and services through public agencies, including
NCPA. After receiving the updated information, NCPA and member utility staff6 reviewed and
analyzed the projects again and determined the geothermal output from Calpine would best
diversify their renewable energy portfolios, aid them in achieving California RPS requirements,
help meet their sustainability goals, and meet the needs of their expected load growth.
4 NCPA is a not-for-profit Joint Powers Agency whose membership includes municipalities, a rural electric
cooperative, and other publicly owned entities, including the City of Palo Alto. The mission of NCPA is to provide
members cost effective wholesale power, energy-related services, and advocacy on behalf of public power
consumers through joint action.
5 Calpine Corporation (Calpine) was founded in 1984 and, through its wholly-owned subsidiary GPC, is the largest
owner of geothermal plants in The Geysers area in Northern California, with 725 MW of green energy capacity
operating around the clock. The Geysers area is known as the world’s largest geothermal field spanning an area of
30 square miles in Sonoma, Lake, Mendocino, Marin, and Napa counties.
6 The City of Alameda, City of Biggs, City of Gridley, City of Lodi, City of Lompoc, Port of Oakland, and City of Santa
Clara are all expected to sign onto the Third Phase Agreement to receive output from this project.
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Over the course of 2022, NCPA staff led negotiation of a PPA with Calpine for renewable energy
and RA from Calpine’s Geysers geothermal facilities on behalf of the interested NCPA members.
To enable NCPA to enter into the PPA with Calpine, participating NCPA members must execute
a Third Phase Agreement with NCPA, which specifies the rights and obligations of NCPA and
participating members regarding governance and administration of the PPA. The Third Phase
Agreement also obligates the participating members to pay their assigned contract percentage
share of all project costs (outlined in Exhibit A of the attached Third Phase Agreement),
including but not limited to, administrative services costs, scheduling coordination costs, and all
other costs related to the PPA.
Santa Clara, as the initial project participant, executed the Third Phase Agreement on
December 23, 2022, which enabled NCPA to execute renewable energy and RA Agreements
with Calpine for output from the Geysers geothermal facilities. As described in Exhibit A of the
attached Third Phase Agreement, participating member s become project participants by
exercising their right to accept a transfer of a portion of the project participation percentage
from Santa Clara by April 30, 2023.
In total, NCPA members have expressed interest in purchasing up to 100 MWs of generatin g
capacity from Calpine for a term of 12 years. Palo Alto requested up to 20 MW of this capacity,
but given the demand from NCPA members, has only been allocated 10 MW, with 5 MW
starting in 2025, and 5 additional MW starting in 2027. This total geothermal capacity is
expected to generate up to 876,000 MWh annually, of which Palo Alto would receive up to
87,600 MWh/year. This project will increase and further diversify Palo Alto’s renewable energy
portfolio in accordance with the City’s adopted Integrated Resource Plan and RPS Procurement
Plan. The proposed 10 MW share of the Calpine geothermal output is equivalent to 10.6% of
Palo Alto’s 2021 retail energy sales.
Due to increased demand for renewable energy generation resources, Calpine is limiting the
amount of time it will reserve the quantity, price and terms of a PPA for prospective buyers.
Therefore, staff recommends authorizing the City Manager to enter into the aforementioned
Third Phase Agreement with NCPA. The benefits of the Calpine project are: (1) the units are
fully constructed and are already in operation; (2) geothermal resources are baseload
generators, meaning they produce a nearly uniform level of energy on a 24 -hour basis; and (3)
the units provide local resource adequacy (RA) capacity, of which the City has a significant
shortage. Unlike many other new renewable energy projects, this project doesn’t carry any
development risk.
Economic Assessment of Calpine Geo Contract
The Calpine Geothermal PPA is expected to provide good value to CPAU customers while also
reducing the supply portfolio’s seasonal energy and RA capacity deficits, thereby reducing
budget uncertainty. The geothermal project provides three valuable products to the electric
portfolio: energy, resource adequacy, and renewable energy credits (RECs). If the sum of these
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three values is greater than the cost of the power purchase agreement, then the City will see a
net monetary benefit from this contract.
The primary value provided by this PPA is from the baseload energy output t hat the geothermal
resource produces. Based on forward energy curves as of December 12, 2022, the average
value of this energy is $71.80/MWh between 2025 and 2030.7
In addition to the energy component, each MWh of geothermal generation qualifies as a
“Bucket 1” renewable energy credit (REC), which historically has been valued between $12 -
$18/MWh. Recently, Palo Alto sold surplus RECs for as much as $20/MWh.
Finally, the geothermal plant capacity qualifies as local RA, which the City can count towards its
annual local and system RA requirements. RA is typically transacted and priced on a $/kW -
month basis and has ranged between $6/kW-month to $8/kW-month recently, which would
translate to approximately $8 to $11/MWh for the geothermal project. Staff transac ted for
system RA at a price around $15/MWh in October 2022, well above historical RA prices. The
increase in RA prices is driven by increasing system RA requirements and reduced qualifying
capacity of solar resources, leading to a market shortage of RA in high load summer months.
These benefits of the geothermal PPA in aggregate are estimated to range between $92 to
$101/MWh against a PPA price of $79/MWh.
With each of these revenue streams, there is a large degree of uncertainty around what will
happen to future prices from changes to macro-economic conditions, regulations,
interdependent regional power markets, and overall market uncertainty. That said, forward
pricing curves project off-peak power prices to become more valuable than on-peak prices
within the next few years, and proposed changes to the RA market rules would reward
generators that produce in times of the grid’s greatest need. Furthermore, under the state’s
RPS legislation, all load serving entities are required to increase their share of renewable energy
in their portfolios (to 60% by 2030), so there is increasing demand for RECs. All of these trends
support the expected long-term value of the geothermal project, given its ability to generate
renewable energy around the clock. The geothermal project’s inability to reduce output during
the sunshine hours will expose it to some lower prices, but these downsides are expected to be
offset by the other trends mentioned. Staff conservatively estimates the geothermal project
will provide a net benefit of at least $3/MWh8, with the potential for significant upside if
market prices stay high and there are further challenges to bringing new resources onto the
grid in the coming 5-10 years.
7 Note that all energy prices in California have increased sharply over the past two years, not just those of
renewable energy projects: Two years ago, forward energy curves pegged the value of this product at $33/MWh,
and even three months ago its value was projected to be just $54/MWh.
8 The conservative net value estimate of $3/MWh is based on the lower-end estimates of the value of the project’s
RPS and RA products ($12/MWh and $8/MWh, respectively) and an energy value of $62/MWh instead of
$71.80/MWh. The lower energy value estimate is equivalent to the energy value estimate of a few months ago,
before the recent run-up in power and gas market prices.
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Risk Management Assessment
Given this project is an existing power plant, there is no development risk, and instead only
operational risk. There are some unique operational risks to running a geothermal power plant,
but NCPA, who owns and manages an existing geothermal plant nearby, has confidence in
Calpine’s history of managing their steam fields and the plant’s ability to reliably produce
power over the term of the agreement.
In general, businesses in the renewable industry lack extensive financial and operational track
records, and because of the capital-intensive nature of these projects, they tend to be highly
leveraged as well. In contrast to most of the City’s renewable energy suppliers, Geysers Power
Company, LLC (the wholly-owned subsidiary of Calpine that controls its geothermal assets) is an
investment-grade company (BBB/stable credit rating), as determined by KBRA, a nationally
recognized statistical rating organization (NRSRO), approved by the Securities and Exchange
Commission (SEC). While Calpine has a higher projected default rate than the City’s ot her (non-
renewable) electric and gas suppliers, Calpine does have an excellent track record of operating
a large portfolio of geothermal projects in the Geysers area over many years. And the output
for this project will come from a collection of Calpine’s resources in this area, so even if there
are problems with one or two resources there is very little risk that the City will not receive the
contracted volumes of output. To further mitigate this risk, in the event of a credit downgrade
event, Calpine will provide collateral (in the form of cash or a letter of credit), in the amount of
$2.5 million for the first two years of the contract and $5.0 million for the remainder of the
contract, which would protect the City and the other PPA offtakers in a scenari o where the
facilities are unable to produce the contracted output and the market price of the replacement
renewable power is higher than the price of the Calpine PPA. And perhaps most importantly,
under the terms of the proposed PPA the City is not at risk for paying for output that is not
delivered. As with all of the City’s PPAs, the City will make no payments under the PPA until
energy from the project is delivered.
Palo Alto’s Energy Portfolio with Calpine Geo
Under the City’s Energy Risk Management Procedures, staff regularly develops procurement
plans for the prompt 36-month period to mitigate the City’s market price exposure. Given the
supply portfolio’s heavy concentration of hydroelectric and solar resources, these procurement
plans typically result in staff buying market energy in the fall/winter months and selling surplus
energy during the spring/summer months. Furthermore, within any given day, the supply
portfolio is routinely short during off-peak (nighttime) and long during on-peak (daytime)
periods. This PPA would reduce the need for market purchases and increase the opportunity for
market sales in the spring and summer months, depending on the level of output from the
City’s hydroelectric resources.
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The existing supply portfolio9 is projected to have an overall surplus position from 2025 through
2028 even without entering an agreement for the geothermal project, as shown in Figure 2
below. The load forecast shown in Figure 2 is based on the mid -range scenario presented at the
December UAC meeting, which includes modest load growth from data centers, electric
vehicles, and building electrification. The hydro generation estimates are based on long term
historical averages, which have been significantly higher than actual generation in the last few
years during the drought. However, as noted in the December UAC meeting discussion, there is
significant uncertainty around both the load and hydro generation projections shown here.
Staff recently learned about commercial development plans that could result in significantly
greater data center load within the next few years; meanwhile, the impacts of climate change
are likely to significantly reduce the long-term level of hydro generation. Combined, these two
factors could flip the portfolio’s overall surplus positions of the next few years to deficit
positions—which is why staff recommends waiving the anti-speculation requirement of the
City’s Energy Risk Management Policy for this agreement.
Figure 2: Projected Annual Load-Resource Balance, 2025-2045
9 All six of the City’s solar PPA extend to 2040 or later, while the landfill gas PPAs expire between 2026 and 2034.
The City has one remaining wind PPA which expires in June 2028. Furthermore, the City can renew the Western
Base Resource contract for a new 30-year term that would start in 2025, and for planning purposes it is currently
included in the supply portfolio baseline assumptions. Lastly, the City owns its share of the Calaveras project and it
is therefore expected to remain in the portfolio indefinitely.
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While the supply portfolio, on average, has an overall surplus position in any given year, the
portfolio is short during the 1st and 4th quarters of the calendar year given the seasonal
generation from hydro and solar. Additionally, the portfolio is generally short during the non-
solar (off-peak) hours. Monthly and daily load resource balance charts are shown in
Attachments B and C. The geothermal project is a baseload power plant that produces
electricity evenly across the day and year. Given the portfolio is currently projected to have
surplus positions during the first few years of the geothermal PPA as shown above, staff is
currently monitoring the City’s actual load levels closely and evaluating whether to sell solar
energy during the 2nd and 3rd quarters (an amount equal to the total purchase amount from the
Calpine project) to hedge being overly long on energy, while also improving the daily load -
resource balance. Figure 3 below shows a monthly load-resource balance for the City’s portfolio
with both the Calpine purchase and solar energy sales included. This would balance the
portfolio supply and demand more evenly across the seasons within any given year. While the
City’s risk management policies don’t prescribe a specific load -resource balance level, staff tries
to minimize the portfolio’s overall exposure to the market in either direction to mitigate large
supply cost fluctuations from market pricing volatility.
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Figure 3: Monthly Load-Resource Balance with Geothermal Energy Purchase and Q2/Q3 Solar
Energy Sale Included
Palo Alto’s Resource Adequacy Portfolio with Calpine Geo
Resource adequacy (RA) is another market that the City is required to participate in as a load
serving entity in the California Independent System Operator (CAISO) bala ncing authority. The
CAISO RA requirements dictate required levels of generating capacity the City must own or
procure to meet local, system, and flexible resource requirements on an annual and monthly
basis. Currently, staff manages the City’s RA requirem ents by utilizing its own resources,
participating in NCPA’s Capacity Pool Program, and through bilateral transactions with other
market participants.
The geothermal plant would qualify as local RA for the City, and it would also count towards the
City’s system RA requirements. As Figures 4 and 5 below indicate, the City has local RA deficits
of approximately 50-80 MW per month, but surpluses of system RA that average approximately
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80 MW. This PPA would reduce the city’s Local RA deficit by 10 MW and would increase the
System RA surplus by an equivalent amount.10
Figure 4: Annual Average Local RA Balance Forecast, 2025 -2036
10 While the City would retain the geothermal capacity in its own portfolio to help satisfy its local RA requirements,
the addition of this contract would free up capacity from other resources (which do not qualify as local RA) that
the City could sell to generate additional revenue and reduce its system RA surplus positions.
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Figure 5: Annual Average System RA Balance Forecast, 2025 -2036
Palo Alto’s RPS Portfolio with Calpine Geo
The PPA will also increase the City’s share of power being generated by renewable resources, as
required by the state’s RPS regulations. The City is already on track to meet state RPS targets
without the geothermal PPA, so this is not a driving factor for this deal, but it would further
increase the amount of Bucket 1 RECs the City is able to swap for lower-cost Bucket 3 RECs
through its REC Exchange Program. In addition, increasing the City’s RPS level provides further
flexibility in the future if the City pursues a smaller sha re of the Western Base Resource
contract.
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Figure 6: Palo Alto’s Existing RPS Supplies and RPS Requirement Levels, with the Calpine
Project
Next Steps
The NPCA Commission approved Purchase Agreements Between Geysers Power Company, LLC
and Northern California Power Agency, and the Third Phase Agreement for Purchase
Agreements with Geysers Power Company, LLC at its December 1, 2022 meeting. Since then,
NCPA, with input from attorneys representing participating members, completed PPA
negotiations with Calpine. Santa Clara has executed the Third Phase Agreement with NCPA,
and as the initial project participant has been allocated the full PPA output. Once Palo Alto and
other participating members obtain their governing board approvals and execute the Third
Phase Agreement as well, Santa Clara will assign shares of the PPA’s energy, RECs and RA
capacity to participating members, adding those members to the Third Phase Agreement
between NCPA and Santa Clara. Santa Clara has asked all participating members to execute
the Third Phase Agreement by April 2023. If the UAC recommends approval, staff will present
the Third Phase Agreement to the Finance Committee and then to the City Council for approval.
Resource Impact
If Council approves the execution of this Third Phase Agreement with NCPA, the City will
purchase up to 87,600 MWh/year for a total not-to-exceed amount of $6.93 million/year during
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the 12-year contract term (2025-2036). Funding for the purchase of the renewable energy will
be included in the Electric Utility Fund budget beginning in FY 2025.
Policy Impact
Approval of the proposed Third Phase Agreement is in conformance with the City’s
Sustainability and Climate Action Plan (S/CAP), Integrated Resource Plan, Carbon Neutral Plan,
and RPS Procurement Plan, specifically the City’s Renewable Portfolio Standard to meet at least
60% of the City’s electric sales from renewable energy.
Environmental Review
The UAC’s recommendation to approve the Third Phase Agreement does not meet the
definition of a project under the California Environmental Quality Act (CEQA), pursuant to
Public Resources Code Section 21065.
Attachments:
• Attachment A: NCPA Third Phase Agreement
• Attachment B: Monthly Load-Resource Balance for 2021 with the Calpine Geothermal
Included
• Attachment C: Daily Load-Resource Balance for 2021 with the Calpine Geothermal
Included
• Attachment D: Presentation
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THIRD PHASE AGREEMENT
FOR
PURCHASE AGREEMENTS
WITH
GEYSERS POWER COMPANY, LLC
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
TABLE OF CONTENTS
Section 1. Definitions .................................................................................................... 3
Section 2. Purpose ......................................................................................................... 9
Section 3. Sale and Purchase of Product .................................................................... 9
Section 4. Billing and Payments ................................................................................ 10
Section 5. Security Deposit Administration............................................................. 13
Section 6. Cooperation and Further Assurances ..................................................... 18
Section 7. Participant Covenants and Defaults ....................................................... 19
Section 8. Administration of Agreement ................................................................. 22
Section 9. Transfer of Rights by Participants ........................................................... 23
Section 10. Term and Termination .............................................................................. 24
Section 11. Withdrawal of Participants ...................................................................... 25
Section 12. Settlement of Disputes and Arbitration ................................................. 25
Section 13. Miscellaneous ............................................................................................. 25
EXHIBIT A. Project Participation Percenages ............................................................ 38
EXHIBIT B. PPA .............................................................................................................. 40
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
This THIRD PHASE AGREEMENT (“this Agreement”) is dated as of
______________, 20__ by and among the Northern California Power Agency, a joint
powers agency of the State of California (“NCPA”), and the signatories to this Agreement
other than NCPA (“Participants”). NCPA and the Participants are referred to herein
individually as a “Party” and collectively as the “Parties”.
RECITALS
A. NCPA has heretofore been duly established as a public agency pursuant to
the Joint Exercise of Powers Act of the Government Code of the State of California and,
among other things, is authorized to acquire, construct, finance, and operate buildings,
works, facilities, and improvements for the generation and transmission of electric
capacity and energy for resale.
B. Each of the Participants is a signatory to the Joint Powers Agreement which
created NCPA and therefore is a Member.
C. Each of the Participants to this Agreement have executed the Amended and
Restated Facilities Agreement, dated October 1, 2014, which establishes the framework
under which Project Agreements are created for the development, design, financing,
construction, and operation of specific NCPA Projects.
D. The Participants desire NCPA to enter into the following two agreements
with Geysers Power Company, LLC (“Seller”) for the benefit of the Participants’
December 22 22
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
customers: (1) Western Systems Power Pool Agreement Confirmation between Northern
California Power Agency and Geysers Power Company, LLC, to purchase electric capacity
(individually, “RA Agreement”); and (2) Western Systems Power Pool Agreement
Confirmation between Geysers Power Company, LLC and Northern California Power
Agency, to purchase renewable energy (individually, “RPS Agreement”). The RA
Agreement and the RPS Agreement are collectively referred herein as the Purchase
Agreements, attached hereto as Exhibit B.
E. Each Participant is authorized by its Constitutive Documents to obtain
electric capacity and energy for its present or future requirements, through contra cts with
NCPA or otherwise.
F. To enable NCPA to enter into the Purchase Agreements on behalf of the
Participants, pursuant to the terms and conditions of the Amended and Restated Facilities
Agreement, NCPA and the Participants wish to enter into this Agreement to provide all
means necessary for NCPA to fulfill obligations incurred on behalf of NCPA and the
Participants pursuant to the Purchase Agreements, and to enable and obligate the
Participants to take delivery of and pay for such electric capacity and energy and to pay
NCPA for all costs it incurs for undertaking the foregoing activities.
G. Upon full execution of this Agreement, NCPA will enter into the Purchase
Agreements on behalf of the Participants, and such Purchase Agreements shall be deemed
a NCPA Project by the Commission.
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
H. Each of the Parties intends to observe the provisions of this Agreement in
good faith and shall cooperate with all other Parties in order to achieve the full benefits of
joint action.
I. The Parties desire to equitably allocate costs of NCPA’s provision of services
under this Agreement among the Participants.
J. The Participants further desire, insofar as possible, to insulate other
Members who are not Participants, from risks inherent in the services and transactions
undertaken on behalf of the Participants pursuant to this Agreement.
NOW, THEREFORE, the Parties agree as follows:
Section 1. Definitions.
1.1 Definitions. Whenever used in this Agreement (including the Recitals
hereto), the following terms shall have the following respective meanings, provided,
capitalized terms used in this Agreement (including the Recitals hereto) that are not
defined in Section 1 of this Agreement shall have the meaning indicated in Section 1 of the
Power Management and Administrative Services Agreement, dated October 1, 2014:
1.1.1 “Administrative Services Costs” means that portion of the NCPA
administrative, general and occupancy costs and expenses, including those costs and
expenses associated with the operations, direction and supervision of the general
affairs and activities of NCPA, general management, treasury operations, accounting,
budgeting, payroll, human resources, information technology, facilities management,
1.a
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
salaries and wages (including retirement benefits) of employees, facility operation and
maintenance costs, taxes and payments in lieu of taxes (if any), insurance premiums,
fees for legal, engineering, financial and other services, power management services,
general settlement and billing services and general risk management costs, that are
charged directly or apportioned to the provision of services under this Agreement.
Administrative Services Costs as separately defined herein and used in the context of
this Agreement is different and distinct from the term Administrative Services Costs as
defined in Section 1 of the Power Management and Administrative Services
Agreement.
1.1.2 “Agreement” means this Third Phase Agreement, including all
Exhibits attached hereto.
1.1.3 "All Resources Bill” has the meaning set forth in the Power
Management and Administrative Services Agreement.
1.1.4 “CAISO” means the California Independent System Operator
Corporation, or its functional successor.
1.1.5 “CAISO Tariff” means the duly authorized tariff, rules, protocols
and other requirements of the CAISO, as amended from time to time.
1.1.6 "Commission” has the meaning set forth in the Power
Management and Administrative Services Agreement.
1.a
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
1.1.7 “Constitutive Documents” means, with respect to NCPA, the Joint
Powers Agreement and any resolutions or bylaws adopted thereunder with respect to
the governance of NCPA, and with respect to each Participant, the California
Government Code and other statutory provisions applicable to such Participant, any
applicable agreements, charters, contracts, or other documents concerning the
formation, operation or decision making of such Participant, including, if applicable, its
city charter, and any codes, ordinances, bylaws, and resolutions adopted by such
Participant’s governing body.
1.1.8 “Defaulting Participant” has the meaning set forth in Section 7.2.
1.1.9 “Electric System” has the meaning set forth in the Power
Management and Administrative Services Agreement.
1.1.10 “Event of Default” has the meaning set forth in Section 7.2.
1.1.11 “General Operating Reserve” means the NCPA General Operating
Reserve created through resolution of the Commission, as the same may be amended
from time to time.
1.1.12 “NCPA” has the meaning set forth in the Recitals hereto.
1.1.13 “Participant” has the meaning set forth in the Recitals of this
Agreement.
1.1.14 “Power Management and Administrative Services Agreement”
means the NCPA Power Management and Administrative Services Agreement, dated
1.a
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
as of October 1, 2014 between NCPA and the Members who are signatories to that
agreement by which NCPA provides Power Management and Administrative Services.
1.1.15 “Products” means collectively the RA Product and the Renewable
Product.
1.1.16 “Purchase Agreements” have the meaning set forth in Recital D of
this Agreement. Upon final execution of the Purchase Agreements, the Purchase
Agreements shall be deemed a NCPA Project in accordance with the Amended and
Restated Facilities Agreement, and therefore be referred to herein as the “Project”.
1.1.17 “Project Costs” means all costs charged to and paid by NCPA
pursuant to the Purchase Agreements.
1.1.18 “Project Participation Percentage” has the meaning set forth in the
Power Management and Administrative Services Agreement, and are set forth in
Exhibit A of this Agreement.
1.1.19 “Party” or “Parties” has the meaning set forth in the preamble
hereto; provided that “Third Parties” are entities that are not Party to this Agreement.
1.1.20 “RA Product” means the resource adequacy capacity products
described in Article 3 of the RA Agreement.
1.1.21 “Renewable Product” means renewable energy product and
associated attributes which are defined as “Product” in the RPS Agreement.
1.a
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
1.1.22 “Revenue” means , with respect to each Participant, all income,
rents, rates, fees, charges, and other moneys derived by the Participant from the
ownership or operation of its Electric System, including, without limiting the generality
of the foregoing: (a) all income, rents, rates, fees, charges or other moneys derived from
the sale, furnishing and supplying of electric capacity and energy and other services,
facilities, and commodities sold, furnished, or supplied through the facilities of its
Electric System; (b) the earnings on and income derived from the investment of such
income, rents, rates, fees, charges or other moneys to the extent that the use of such
earnings and income is limited by or pursuant to law to its Electric System; (c) the
proceeds derived by the Participant directly or indirectly from the sale, lease or other
disposition of all or a part of the Electric System; and (d) the proceeds derived by
Participant directly or indirectly from the consignment and sale of freely allocated
greenhouse gas compliance instruments into periodic auctions administered by the
State of California under the California Cap-and-Trade Program, provided that such
proceeds are a permitted use of auction proceeds, but the term Revenues shall not
include (i) customers' deposits or any other deposits subject to refund until such
deposits have become the property of the Participant or (ii) contributions from
customers for the payment of costs of construction of facilities to serve them.
1.1.23 “Scheduling Protocols” means the applicable provisions of the
Amended and Restated Scheduling Coordination Program Agreement, and any other
1.a
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contractual or other arrangements between NCPA and the Participants concerning the
scheduling, delivery and metering of the Purchase Agreements.
1.1.24 “Security Deposit” means the account established by NCPA and
funded by the Participants in accordance with Section 5, the funds of which are
available for use by NCPA in accordance with the terms and conditions hereof.
1.1.25 “Seller” means Geysers Power Company, LLC, as set forth in
Recital D of this Agreement, or as otherwise set forth in the Purchase Agreements.
1.1.26 “Term” has the meaning set forth in Section 10.
1.1.27 “Third Party” means an entity (including a Member) that is not
Party to this Agreement.
1.2 Rules of Interpretation. As used in this Agreement (including the Recitals
hereto), unless in any such case the context requires otherwise: The terms “herein,”
“hereto,” “herewith” and “hereof” are references to this Agreement taken as a whole and
not to any particular provision; the term “include,” “includes” or “including” shall mean
“including, for example and without limitation;” and references to a “Section,”
“subsection,” “clause,” “Appendix”, “Schedule”, or “Exhibit” shall mean a Section,
subsection, clause, Appendix, Schedule or Exhibit of this Agreement, as the case may be.
All references to a given agreement, instrument, tariff or other document, or law,
regulation or ordinance shall be a reference to that agreement, instrument, tariff or other
document, or law, regulation or ordinance as such now exists and as may be amended
1.a
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from time to time, or its successor. A reference to a “person” includes any individual,
partnership, firm, company, corporation, joint venture, trust, association, organization or
other entity, in each case whether or not having a separate legal personality and includes
its successors and permitted assigns. A reference to a “day” shall mean a Calendar Day
unless otherwise specified. The singular shall include the plural and the masculine shall
include the feminine, and vice versa.
Section 2. Purpose. The purpose of this Agreement is to: (i) set forth the terms and
conditions under which NCPA shall enter into the Purchase Agreements on behalf of the
Participants, (ii) authorize NCPA, acting on behalf of the Participants, to engage in all
activities related to that basic purpose, and (iii) specify the rights and obligations of NCPA
and the Participants with respect to the Purchase Agreements.
Section 3. Sale and Purchase of Products. By executing this Agreement, each
Participant acknowledges and agrees to be bound by the terms and conditions of the
Agreement, and that the Agreement is written as a “take-or-pay” agreement. Any
Products delivered to NCPA under the Purchase Agreements shall be delivered to each
Participant in proportion to such Participant’s Project Participation Percentage as set forth
in Exhibit A, and each Participant shall accept and pay for its respective percentage of such
Products. To the extent a Participant is unable to accept such deliveries in full, NCPA
shall dispose of such surplus in its sole discretion, in such a manner to attempt to
maximize Participant value and that Participant shall reimburse to NCPA any costs
1.a
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
incurred by NCPA in doing so. Notwithstanding the above, NCPA may allocate Products
procured through the Purchase Agreements among the Participants in such percentages as
NCPA may, in its reasonable discretion, determine are necessary, desirable, or
appropriate, in order to accommodate Participant transfer rights pursuant to Section 9.
3.1 Scheduling. Products delivered from Seller shall be scheduled for and to the
Participants in accordance with Scheduling Protocols, and the terms and conditions of the
Purchase Agreements.
Section 4. Billing and Payments
4.1 Participant Payment Obligations. Each Participant agrees to pay to NCPA
each month its respective portion of the Project Costs, Administrative Services Costs,
scheduling coordination costs, and all other costs for services provided in accordance with
this Agreement and the Amended and Restated Facilities Agreement. In addition to the
aforementioned monthly payment obligations, each Participant is obligated to fund: (i)
any and all required Security Deposits calculated in accordance with Section 5, and (ii) any
working capital requirements for the Project maintained by NCPA as determined,
collected and set forth in the Annual Budget.
4.2 Invoices. NCPA will issue an invoice to each Participant for its share of
Project Costs, Administrative Services Costs, scheduling coordination costs, and all other
costs for services provided in accordance with this Agreement and the Amended and
Restated Facilities Agreement. Such invoice may be either the All Resources Bill or
1.a
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separate special invoice, as determined by NCPA. At NCPA’s discretion, invoices may be
issued to Participants using electronic media or physical distribution.
4.3 Payment of Invoices. All invoices delivered by NCPA (including the All
Resources Bill) are due and payable thirty (30) Calendar Days after the date thereof;
provided, however, that any amount due on a day other than a Business Day may be paid
on the following Business Day.
4.4 Late Payments. Any amount due and not paid by a Participant in accordance
with Section 4.3 shall be considered late and bear interest computed on a daily basis until
paid at the lesser of (i) the per annum prime rate (or reference rate) of the Bank of America
NT&SA then in effect, plus two percent (2%) or (ii) the maximum rate permitted by law.
4.5 Billing Disputes. A Participant may dispute the accuracy of any invoice
issued by NCPA under this Agreement by submitting a written dispute to NCPA, within
thirty (30) Calendar Days after the date of such invoice; nonetheless the Participant shall
pay the full amount billed when due. If a Participant does not timely question or dispute
the accuracy of any invoice in writing, then the invoice shall be deemed to be correct.
Upon review of a submitted dispute, if an invoice is determined by NCPA to be incorrect,
then NCPA shall issue a corrected invoice and refund any amounts that may be due to the
Participant. If NCPA and the Participant fail to agree on the accuracy of an invoice within
thirty (30) Calendar Days after the Participant has disputed it, then the General Manager
shall promptly submit the dispute to the Commission for resolution. If the Commission
1.a
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and the Participant fail to agree on the accuracy of a disputed invoice within sixty (60)
Calendar Days after its submission to the Commission, then the dispute may then be
resolved under the mediation and arbitration procedures set forth in Section 12 of this
Agreement; provided, however, that prior to resorting to either mediation or arbitration
proceedings, the full amount of the disputed invoice must be paid by the Participant.
4.6 Billing/Settlement Data and Examination of Books and Records.
4.6.1 Settlement Data. NCPA shall make billing and settlement data
available to the Participants in the All Resources Bill, or other invoice, or upon request.
NCPA may also, at its sole discretion, make billing and settlement support information
available to Participants using electronic media (e.g. electronic data portal).
Procedures and formats for the provision of such electronic data submission may be
established by the Commission from time to time. Without limiting the generality of
the foregoing, NCPA may, in its reasonable discretion, require the Participants to
execute a non-disclosure agreement prior to providing access to the NCPA electronic
data portal.
4.6.2 Examination of Books and Records. Any Participant to this
Agreement shall have the right to examine the books and records created and
maintained by NCPA pursuant to this Agreement at any reasonable, mutually agreed
upon time.
1.a
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Section 5. Security Deposit Administration
5.1 Security Deposit Requirements. Each Participant agrees that any funds
deposited at NCPA to satisfy Participant’s Security Deposit requirements pursuant to this
Agreement shall be irrevocably committed and held by NCPA in the General Operating
Reserve, and that such funds may be used by NCPA in accordance with Section 5.1.3.
Each Participant’s Security Deposit will be accounted separately from and in addition to
any other security accounts or deposits maintained pursuant to any other agreement
between NCPA and the Participant, or any other such security account or deposits
required of Members. In connection with fulfilling the Security Deposit requirements of
this Agreement, Participant may elect to use its uncommitted funds held in the General
Operating Reserve to satisfy in whole or in part its Security Deposit required under
Section 5. If Participant chooses to satisfy in whole or in part its security requirements
using its uncommitted funds held in the General Operating Reserve, then Participant is
required to execute and deliver to NCPA an Irrevocable Letter of Direction, directing
NCPA to utilize Participant’s uncommitted General Operating Reserve funds for such
purposes, and the designated funds will thereafter be irrevocably committed and held by
NCPA to satisfy the requirements of this Agreement.
5.1.1 Initial Amounts. No later than November 1, 2024, each Participant
shall ensure that sufficient Security Deposit funds have been deposited with and are
held by NCPA in an amount equal to the highest three (3) months of estimated Project
1.a
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Costs for the initial term from January 2025 through December 2026, as estimated by
NCPA.1 No later than November 1, 2026, each Participant shall adjust the Security
Deposit to an amount equal to the highest three (3) months of estimated Project Costs
for the period January 2027 through December 2036, as estimated by NCPA.2 Such
Security Deposit requirement may be satisfied by Participant in whole or part either in
cash, through irrevocable commitment of its uncommitted funds held in the General
Operating Reserve in accordance with Section 5.1, or through a clean, irrevocable letter
of credit satisfactory to NCPA’s General Manager.
5.1.2 Subsequent Deposits. Periodically, and at least quarterly, NCPA
shall review and revise its estimate of Project Costs for which Participant shall be
obligated to pay under this Agreement. Following such review, NCPA shall determine
whether each Participant has a sufficient Security Deposit balance at NCPA. To the
extent that any Participant’s Security Deposit balance is greater than one hundred and
ten percent (110%) of the amount required herein, NCPA shall credit such amount as
soon as practicable to the Participant’s next following All Resources Bill, or by separate
special invoice. To the extent that any Participant’s Security Deposit balance is less
than ninety percent (90%) of the amount required herein, NCPA shall add such amount
1 The Security Deposit fund requirement for the initial term is structured to avoid a Downgrade Event to
Buyer as such terms are defined in RPS Agreement.
2 The Security Deposit fund requirement is increased in November of 2026 to reflect the increased contract
quantity beginning on January 1, 2027, and is structured to avoid a Downgrade Event to Buyer as such terms
are defined in RPS Agreement.
1.a
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
as soon as practicable to such Participant’s next All Resources Bill, or as necessary, to a
special invoice to be paid by Participant upon receipt. Credits or additions shall not be
made to Participants who satisfy these Security Deposit requirements in whole through
the use of a letter of credit; provided, that the amount of the letter of credit shall be
adjusted, as required from time to time, in a like manner to assure an amount not to
exceed the highest three (3) months of estimated Project Costs is available to NCPA, as
determined by NCPA.
5.1.3 Use of Security Deposit Funds. NCPA may use any and all
Security Deposit funds held by NCPA (or utilize a letter of credit provided in lieu
thereof) to pay any costs it incurs hereunder, including making payments to Seller,
without regard to any individual Participant’s Security Deposit balance or
proportionate share of Project Costs, and irrespective of whether NCPA has issued an
All Resources Bill or special invoice for such costs to the Participants or whether a
Participant has made timely payments of All Resources Bills or special invoices.
Should Participant have satisfied its Security Deposit requirements in whole or part
through a letter of credit, NCPA may draw on such letter of credit to satisfy
Participant’s obligations hereunder at NCPA’s sole discretion. Notwithstanding the
foregoing, if any Participant fails to pay any costs incurred by NCPA pursuant to this
Agreement, NCPA shall first use that non-paying Participant’s Security Deposit and
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
shall not use any other Participants’ Security Deposit until such non-paying
Participant’s Security Deposit has been exhausted.
5.1.4 Accounting. If Security Deposit funds or a letter of credit are used
by NCPA to pay any costs it incurs hereunder as described in Section 5.1.3, then NCPA
will maintain a detailed accounting of each Participant’s shares of funds withdrawn,
and upon the collection of all or a part of such withdrawn funds, NCPA will credit
back to each non-defaulting Participant the funds collected in proportion to such non-
defaulting Participant’s share of funds initially withdrawn.
5.1.5 Emergency Additions. In the event that funds are withdrawn
pursuant to Section 5.1.3, or if the Security Deposit held by NCPA is otherwise
insufficient to allow for NCPA to pay any invoice, demand, request for further
assurances by Seller, or claims, NCPA shall notify all Participants of the deficiency. In
conjunction with such notice, NCPA shall send a special or emergency assessment
invoice to the Participant or Participants that caused or are otherwise responsible for
the deficiency. Each Participant of such an invoice shall pay to NCPA such assessment
when and if assessed by NCPA within two (2) Business Days of the invoice date of the
assessment, or shall consent to and direct NCPA to draw on any existing letter of credit
Participant has established for such purposes. In the event that the Participant or
Participants that caused or are otherwise responsible for the deficiency canno t, does
not or will not pay to NCPA the special or emergency assessment within two (2)
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Business Days after the invoice date, NCPA shall immediately submit a special or
emergency invoice to all remaining Participants, and such remaining Participants shall
pay to NCPA such assessment within two (2) Business Days after the invoice date of
the assessment, or shall consent to and direct NCPA to draw on any existing letter of
credit that Participant has established for such purposes.
5.1.6 Security Deposit Interest. NCPA shall maintain a detailed
accounting of each Participant’s Security Deposits, and withdrawals of such funds,
held by NCPA. Security Deposits held by NCPA shall be invested by NCPA in
accordance with the General Operating Reserve policies and investment policies
adopted by the NCPA Commission. Interest earned on the Security Deposit funds
shall be proportionately credited to the Participants in accordance with their weighted
average balances held therein. Any Security Deposit losses caused by early
termination of investments shall be allocated among the Participants in accordance
with the General Operating Reserve provisions and guidelines approved by the
Commission, as the same may be amended from time to time; provided, however, to
the extent that either the General Operating Reserve provisions and guidelines do not
apply or the Security Deposit is not adequate to cover the losses, then such losses shall
be allocated among the Participants in accordance with their proportionate Security
Deposit balances.
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
5.1.7 Return of Funds. Upon termination or a permitted withdrawal of
a Participant in accordance with this Agreement, the affected Participant may apply to
NCPA for the return of their share of Security Deposit funds ninety (90) days after the
effective date of such termination or withdrawal. However, NCPA shall, in its sole but
reasonable discretion, as determined by the NCPA General Manager, estimate the then
outstanding liabilities of the Participant, including any estimated contingent liabilities
and shall retain all such funds, if any, until all such liabilities have been fully paid or
otherwise satisfied in full. After all such liabilities have been satisfied in full, as
determined by NCPA’s General Manager, any remaining balance of the Participant’s
share of the Security Deposit will be refunded to the Participant within sixty (60) days
thereafter.
Section 6. Cooperation and Further Assurances. Each of the Parties agree to provide
such information, execute and deliver any instruments and documents and to take such
other actions as may be necessary or reasonably requested by any other Party which are
consistent with the provisions of this Agreement and which do not involve the assumption
of obligations other than those provided for in this Agreement, in order to give full effect
to this Agreement and to carry out the intent of this Agreement. The Parties agree to
cooperate and act in good faith in connection with obtaining any credit support required
in order to satisfy the requirements of this Agreement.
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Section 7. Participant Covenants and Defaults
7.1 Each Participant covenants and agrees: (i) to make payments to NCPA, from
its Electric System Revenues, of its obligations under this Agreement as an operating
expense of its Electric System; (ii) to fix the rates and charges for services provided by its
Electric System, so that it will at all times have sufficient Revenues to meet the obligations
of this Agreement, including the payment obligations; (iii) to make all such payments due
NCPA under this Agreement whether or not there is an interruption in, interference with,
or reduction or suspension of services provided under this Agreement, such payments not
being subject to any reduction, whether by offset or otherwise, and regardless of whether
any reasonable dispute exists; and (iv) to operate its Electric System, and the business in
connection therewith, in accordance with Good Utility Practices.
7.2 Events of Default. An Event of Default under this Agreement shall exist
upon the occurrence of any one or more of the following by a Participant (the “Defaulting
Participant”):
(i) the failure of any Participant to make any payment in full to NCPA when
due;
(ii) the failure of a Participant to perform any covenant or obligation of this
Agreement where such failure is not cured within thirty (30) Calendar Days following
receipt of a notice from NCPA demanding cure; provided, that this subsection shall not
apply to any failure to make payments specified by subsection 7.2 (i));
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(iii) if any representation or warranty of a Participant material to the services
provided hereunder shall prove to have been incorrect in any material respect when made
and the Participant does not cure the facts underlying such incorrect representation o r
warranty so that the representation or warranty becomes true and correct within thirty
(30) Calendar Days after the date of receipt of notice from NCPA demanding cure; or
(iv) if a Participant is in default or in breach of any of its covenants or
obligations under any other agreement with NCPA and such default or breach is not cured
within the time periods specified in such agreement.
7.3 Uncontrollable Forces. A Party shall not be considered to be in default in
respect of any obligation hereunder if prevented from fulfilling such obligation by reason
of Uncontrollable Forces; provided, that in order to be relieved of an Event of Default due
to Uncontrollable Forces, a Party affected by an Uncontrollable Force shall:
(i) first provide oral notice to the General Manager using telephone
communication within two (2) Business Days after the onset of the Uncontrollable Force,
and provide subsequent written notice to the General Manager and all other Parties within
ten (10) Business Days after the onset of the Uncontrollable Force, describing its nature
and extent, the obligations which the Party is unable to fulfill, the anticipated duration of
the Uncontrollable Force, and the actions which the Party will undertake so as to remove
such disability and be able to fulfill its obligations hereunder; and
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
(ii) use due diligence to place itself in a position to fulfill its obligations
hereunder and if unable to fulfill any obligation by reason of an Uncontrollable Force such
Party shall exercise due diligence to remove such disability with reasonable dispatch;
provided, that nothing in this subsection shall require a Party to settle or compromise a
labor dispute.
7.4 Cure of an Event of Default. An Event of Default shall be deemed cured only
if such default shall be remedied or cured within the time periods specified in Section 7.2
above, as may be applicable, provided, however, upon request of the Defaulting
Participant the Commission may waive the default at its sole discretion, where such
waiver shall not be unreasonably withheld.
7.5 Remedies in the Event of Uncured Default. Upon the occurrence of an Event
of Default which is not cured within the time limits specified in Section 7.2, without
limiting other rights or remedies available under this Agreement, at law or in equit y, and
without constituting or resulting in a waiver, release or estoppel of any right, action or
cause of action NCPA may have against the Defaulting Participant, NCPA may take any
or all of the following actions:
(i) suspend the provision of services under this Agreement to such
Defaulting Participant; or
(ii) demand that the Defaulting Participant provide further assurances to
guarantee the correction of the default, including the collection of a surcharge or increase
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
in electric rates, or such other actions as may be necessary to produce necessary Revenues
to correct the default.
7.6 Effect of Suspension.
7.6.1 Generally. The suspension of this Agreement will not terminate,
waive, or otherwise discharge any ongoing or undischarged liabilities, credits or
obligations arising from this Agreement until such liabilities, credits or obligations are
satisfied in full.
7.6.2 Suspension. If performance of all or any portion of this Agreement
is suspended by NCPA with respect to a Participant in accordance with subsection
7.5(i), then such Participant shall pay any and all costs incurred by NCPA as a result of
such suspension including reasonable attorney’s fees, the fees and expenses of other
experts, including auditors and accountants, or other reasonable and necessary costs
associated with such suspension and any portion of the Project Costs, scheduling and
dispatch costs, and Administrative Services Costs that were not recovered from such
Participant as a result of such suspension.
Section 8. Administration of Agreement
8.1 Commission. The Commission is responsible for the administration of this
Agreement. Each Participant shall be represented by its Commissioner or their designated
alternate Commissioner (“Alternate”) pursuant to the Joint Powers Agreement. Each
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Commissioner shall have authority to act for the Participant represented with respect to
matters pertaining to this Agreement.
8.2 Forum. Whenever any action anticipated by this Agreement is required to be
jointly taken by the Participants, such action shall be taken at regular or special meetings
of the NCPA Commission.
8.3 Quorum. For purposes of acting upon matters that relate to administration
of this Agreement, a quorum of the Participants shall consist of those Commissioners, or
their designated Alternate, representing a numerical majority of the Participants.
8.4 Voting. Each Participant shall have the right to cast one vote with respect to
matters pertaining to this Agreement. A unanimous vote of all Participants shall be
required for action regarding: (i) any transfer of rights to a Third Party as described in
Section 9 of this Agreement; and (ii) for matters related to any of the following actions as
provided for in the Purchase Agreements: (a) exercising any early termination provisions
as set forth in the Purchase Agreements, and (b) exercising any assignment rights as set
forth in the Purchase Agreements. For all other matters pertaining to this Agreement, a
majority vote of the Participants shall be required for action.
Section 9. Transfer of Rights by Participants
9.1 A Participant has the right to make transfers, sales, assignments and
exchanges (collectively “transfers(s)”) of any portion of its Project Participation Percentage
and rights thereto, subject to the approval provisions in Section 8.4 of this Agreement,
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provided that the transferee satisfies all applicable criterion in the Purchase Agreements.
If a Participant desires to transfer a portion or its entire share of the Project for a specific
time interval, or permanently, then NCPA will, if requested by such Participant, use its
best efforts to transfer that portion of the Participant’s share of the Project.
9.2 Unless otherwise set forth in this Agreement, before a Participant may
transfer an excess Project share pursuant to Section 9.1 to any person or entity other than a
Participant, it shall give all other Participants the right to purchase the share on the same
terms and conditions. Before a Participant may transfer an excess Project share pursuant
to section 9.1 to any person or entity other than a Member, it shall give all Members the
right to purchase the share on the same terms and conditions. Such right shall be
exercised within thirty (30) days of receipt of notice of said right.
No transfer shall relieve a Participant of any of its obligations under this
Agreement except to the extent that NCPA receives payment of these obligations from a
transferee.
9.3 The provisions of this Section 9 do not apply to the Exhibit A, unless
expressly set forth therein.
Section 10. Term and Termination. This Agreement shall become effective when it has
been duly executed by all Participants, and delivered to and executed by NCPA (the
“Effective Date”). NCPA shall notify all Participants in writing of the Effective Date. The
Term of this Agreement shall be coterminous with the Purchase Agreements, and shall
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commence on the Effective Date, and shall continue through the term of the Purchase
Agreements.
Section 11. Withdrawal of Participants. No Participant may withdraw from this
Agreement except as otherwise provided for herein.
Section 12. Settlement of Disputes and Arbitration. The Parties agree to make best
efforts to settle all disputes among themselves connected with this Agreement as a matter
of normal business under this Agreement. The procedures set forth in Section 10 of the
Power Management and Administrative Services Agreement shall apply to all disputes
that cannot be settled by the Participants themselves; provided, that the provisions of
Section 4.5 shall first apply to all disputes involving invoices prepared by NCPA.
Section 13. Miscellaneous
13.1 Confidentiality. The Parties will keep confidential all confidential or trade
secret information made available to them in connection with this Agreement, to the extent
possible, consistent with applicable laws, including the California Public Records Act.
Confidential or trade secret information shall be marked or expressly identified as such.
If a Party (“Receiving Party”) receives a request from a Third Party for access to, or
inspection, disclosure or copying of, any other Party’s (the “S upplying Party”) confidential
data or information, which the Receiving Party has possession of (“Disclosure Request”),
then the Receiving Party shall provide notice and a copy of the Disclosure Request to the
Supplying Party within three (3) Business Days after receipt of the Disclosure Request.
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Within three (3) Business Days after receipt of such notice, the Supplying Party shall
provide notice to the Receiving Party either:
(i) that the Supplying Party believes there are reasonable legal grounds for
denying or objecting to the Disclosure Request, and the Supplying Party requests the
Receiving Party to deny or object to the Disclosure Request with respect to identified
confidential information. In such case, the Receiving Party shall deny the Disclosure
Request and the Supplying Party shall defend the denial of the Disclosure Request at its
sole cost, and it shall indemnify the Receiving Party for all costs associated with denying
or objecting to the Disclosure Request. Such indemnification by the Supplying Party of the
Receiving Party shall include all of the Receiving Party’s costs reasonably incurred with
respect to denial of or objection to the Disclosure Request, including but not limited to
costs, penalties, and the Receiving Party’s attorney’s fees; or
(ii) that the Receiving Party may grant the Disclosure Request without any
liability by the Receiving Party to the Supplying Party.
13.2 Indemnification and Hold Harmless. Subject to the provisions of Section
13.4, each Participant agrees to indemnify, defend and hold harmless NCPA and its
Members, including their respective governing boards, officials, officers, agents, and
employees, from and against any and all claims, suits, losses, costs, damages, expenses
and liability of any kind or nature, including reasonable attorneys’ fees and the costs of
litigation, including experts, to the extent caused by any acts, omissions, breach of
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contract, negligence (active or passive), gross negligence, recklessness, or willful
misconduct of that Participant, its governing officials, officers, employees, subcontractors
or agents, to the maximum extent permitted by law.
13.3 Several Liabilities. No Participant shall, in the first instance, be liable under
this Agreement for the obligations of any other Participant or for the obligations of NCPA
incurred on behalf of other Participants. Each Participant shall be solely responsible and
liable for performance of its obligations under this Agreement, except as otherwise
provided for herein. The obligation of each Participant under this Agreement is, in the
first instance, a several obligation and not a joint obligation with those of the other
Participants.
Notwithstanding the foregoing, the Participants acknowledge that any debts
or obligations incurred by NCPA under this Agreement on behalf of any of them shall be
borne solely by such Participants in proportion to their respective Project Participation
Percentages, and not by non-Participant Members of NCPA, pursuant to Article IV,
Section 3(b) of the Joint Powers Agreement.
In the event that a Participant should fail to pay its share of the debts or
obligations incurred by NCPA as required by this Agreement, the remaining Participants
shall, in proportion to their Project Participation Percentages, pay such unpaid amounts
and shall be reimbursed by the Participant failing to make such payments.
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
13.4 No Consequential Damages. FOR ANY BREACH OF ANY PROVISION OF
THIS AGREEMENT FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES
IS PROVIDED IN THIS AGREEMENT, THE LIABILITY OF THE DEFAULTING PARTY
SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION, AND ALL OTHER
DAMAGES OR REMEDIES ARE HEREBY WAIVED. IF NO REMEDY OR MEASURE OF
DAMAGE IS EXPRESSLY PROVIDED, THE LIABILITY OF THE DEFAULTING PARTY
SHALL BE LIMITED TO ACTUAL DAMAGES ONLY AND ALL OTHER DAMAGES
AND REMEDIES ARE HEREBY WAIVED. IN NO EVENT SHALL NCPA OR ANY
PARTICIPANT OR THEIR RESPECTIVE SUCCESSORS, ASSIGNS, REPRESENTATIVES,
DIRECTORS, OFFICERS, AGENTS, OR EMPLOYEES BE LIABLE FOR ANY LOST
PROFITS, CONSEQUENTIAL, SPECIAL, EXEMPLARY, INDIRECT, PUNITIVE, OR
INCIDENTAL LOSSES OR DAMAGES, INCLUDING LOSS OF USE, LOSS OF
GOODWILL, LOST REVENUES, LOSS OF PROFIT OR LOSS OF CONTRACTS EVEN IF
SUCH PARTY HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES, AND
NCPA AND EACH PARTICIPANT EACH HEREBY WAIVES SUCH CLAIMS AND
RELEASES EACH OTHER AND EACH OF SUCH PERSONS FROM ANY SUCH
LIABILITY.
The Parties acknowledge that California Civil Code section 1542 provides that: “A general
release does not extend to claims which the creditor does not know or suspect to exist in
his or her favor at the time of executing the release, which if known by him or her must
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
have materially affected his or her settlement with the debtor.” The Parties waive the
provisions of section 1542, or other similar provisions of law, and intend that the waiver
and release provided by this Section of this Agreement shall be fully enforceable despite
its reference to future or unknown claims.
13.5 Waiver. No waiver of the performance by a Party of any obligation under
this Agreement with respect to any default or any other matter arising in connection with
this Agreement shall be effective unless given by the Commission or the governing body
of a Participant, as applicable. Any such waiver by the Commission in any particular
instance shall not be deemed a waiver with respect to any subsequent performance,
default or matter.
13.6 Amendments. Except where this Agreement specifically provides otherwise,
this Agreement may be amended only by written instrument executed by the Parties with
the same formality as this Agreement.
13.7 Assignment of Agreement.
13.7.1 Binding Upon Successors. This Agreement shall inure to the
benefit of and shall be binding upon the respective successors and assignees of the
Parties to this Agreement.
13.7.2 No Assignment. Neither this Agreement, nor any interest herein,
shall be transferred or assigned by a Party hereto except with the consent in writing of
the other Parties hereto, which consent shall not be unreasonably withheld.
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
13.8 Severability. In the event that any of the terms, covenants or conditions of
this Agreement or the application of any such term, covenant or condition, shall be held
invalid as to any person or circumstance by any court having jurisdiction, all other terms,
covenants or conditions of this Agreement and their application shall not be affected
thereby, but shall remain in force and effect unless the court holds that such provisions are
not severable from all other provisions of this Agreement.
13.9 Governing Law. This Agreement shall be interpreted, governed by, and
construed under the laws of the State of California.
13.10 Headings. All indices, titles, subject headings, section titles and similar items
are provided for the purpose of convenience and are not intended to be inclusive,
definitive, or affect the meaning of the contents of this Agreement or the scope thereof.
13.11 Notices. Any notice, demand or request required or authorized by this
Agreement to be given to any Party shall be in writing, and shall either be personally
delivered to a Participant’s Commissioner or Alternate, and to the General Manager, or
shall be transmitted to the Participant and the General Manager at the addresses shown on
the signature pages hereof. The designation of such addresses may be changed at any
time by written notice given to the General Manager who shall thereupon give written
notice of such change to each Participant. All such notices shall be deemed delivered
when personally delivered, two (2) Business Days after deposit in the United States mail
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
first class postage prepaid, or on the first Business Day following delivery through
electronic communication.
13.12 Warranty of Authority. Each Party represents and warrants that it has been
duly authorized by all requisite approval and action to execute and deliver this Agreement
and that this Agreement is a binding, legal, and valid agreement enforceable in accordance
with its terms. Upon execution of this Agreement, each Participant shall deliver to NCPA
a resolution of the governing body of such Participant eviden cing approval of and
authority to enter into this Agreement.
13.13 Counterparts. This Agreement may be executed in any number of
counterparts, and each executed counterpart shall have the same force and effect as an
original instrument and as if all the signatories to all of the counterparts had signed the
same instrument. Any signature page of this Agreement may be detached from any
counterpart of this Agreement without impairing the legal effect of any signatures thereon,
and may be attached to another counterpart of this Agreement identical in form hereto but
having attached to it one or more signature pages.
13.14 Venue. In the event that a Party brings any action under this Agreement, the
Parties agree that trial of such action shall be vested exclusively in the state courts of
California in the County of Placer or in the United States District Cour t for the Eastern
District of California.
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
13.15 Attorneys’ Fees. If a Party to this Agreement brings any action, including an
action for declaratory relief, to enforce or interpret the provisions of this Agreement, then
each Party shall bear its own fees and costs, including attorneys’ fees, associated with the
action.
13.16 Counsel Representation. Pursuant to the provisions of California Civil Code
Section 1717 (a), each of the Parties were represented by counsel in the negotiation and
execution of this Agreement and no one Party is the author of this Agreement or any of its
subparts. Those terms of this Agreement which dictate the responsibility for bearing any
attorney’s fees incurred in arbitration, litigation or settlement in a manner inconsistent
with the provisions of Section 13.2 were intentionally so drafted by the Parties, and any
ambiguities in this Agreement shall not be interpreted for or against a Party by reason of
that Party being the author of the provision.
13.17 No Third Party Beneficiaries. Nothing contained in this Agreement is
intended by the Parties, nor shall any provision of this Agreement be deemed or construed
by the Parties, by any third person or any Third Parties, to be for the benefit of any Third
Party, nor shall any Third Party have any right to enforce any provision of this Agreement
or be entitled to damages for any breach by the Parties of any of the provisions of this
Agreement.
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IN WITNESS WHEREOF, NCT A and each Participant have, by the signature of its
duly authorized representative shown below, executed and delivered a counterpart of this
Agreement.
NORIBERN CALIFORNIA
POWER AGENCY
651 Commerce Drive
Rose ille, CA 95678
By: Randy . Howard
Title: General Manager
Date: t'1,./z3/z2-~,
Approved as to form:
.{a l'u ( ,~(!r'(/01//1
Attestation (if applicable):
,=:;;,,t_--:z.;_
By: ~\-S ~ :7:, nM d2-:
Its: A:S$T. -S~'i2£TA'?i 0~ C~tSSi>t(
Date: I 2. -1-~ -2.0'2..2.
CITY OF SANTA CLARA
1500 Warbtuton Avenue
Santa Clara, CA 95050
MAeu<,tt ewi* ....._ ,,_u._,, .... 11'1.11
By: Manuel Pineda
Title: Assistant City Manager
Date: Dec 22, 2022
Approved as to form:
By: Daniel Ballin
Its: Oty Attorney
Date: Dec22,2022
33
THIRD PHASE AGREEMENT FOR GEYSERS POWER CO:MP ANY PROJ r
-----~
34
THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
CITY OF ALAMEDA
2000 Grand Street
Alameda, CA 94501
_____________________________
By:__________________________
Title: ________________________
Date:
Approved as to form:
_____________________________
By:__________________________
Its: City Attorney
Date:
Attestation (if applicable)
_____________________________
By:__________________________
Its:
Date:
CITY OF BIGGS
465 C Street
Biggs, CA 95917
_____________________________
By:__________________________
Title: ________________________
Date:
Approved as to form:
_____________________________
By:
Its: City Attorney _________________
Date:
Attestation (if applicable)
_____________________________
By:__________________________
Its:
Date:
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35
THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
CITY OF GRIDLEY
685 Kentucky Street
Gridley, CA 95948
_____________________________
By:__________________________
Title: ________________________
Date:
Approved as to form:
_____________________________
By:
Its: City Attorney _________________
Date:
Attestation (if applicable)
_____________________________
By:__________________________
Its:
Date:
CITY OF LODI
221 W. Pine Street
Lodi, CA 95240
_____________________________
By:__________________________
Title: ________________________
Date:
Approved as to form:
_____________________________
By:
Its: City Attorney _________________
Date:
Attestation (if applicable)
_____________________________
By:__________________________
Its:
Date:
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
CITY OF LOMPOC
100 Civic Center Plaza
Lompoc, CA 93436
_____________________________
By:__________________________
Title: ________________________
Date:
Approved as to form:
_____________________________
By:
Its: City Attorney _________________
Date:
Attestation (if applicable)
_____________________________
By:__________________________
Its:
Date:
CITY OF PALO ALTO
160 Palo Alto Avenue
Palo Alto, CA 94301
_____________________________
By:__________________________
Title: ________________________
Date:
Approved as to form:
_____________________________
By:
Its: City Attorney _________________
Date:
Attestation (if applicable)
_____________________________
By:__________________________
Its:
Date:
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37
THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
CITY OF OAKLAND, acting
by and through its
Board of Port Commissioners
530 Water Street
Oakland, CA 94607
_____________________________
By:__________________________
Title: ________________________
Date:
Approved as to form:
_____________________________
By:
Its: City Attorney _________________
Date:
Attestation (if applicable)
_____________________________
By:__________________________
Its:
Date:____________________________
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THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
EXHIBIT A
PROJECT PARTICIPATION PERCENTAGES
On the Effective Date of the Agreement the initial Participant (“Initial Participant”) who is
signatory to this Agreement, and its respective initial Project Participation Percentage
share of the Project is set forth in Table 1 of this Exhibit A (“Initial Project Participation
Percentage”). The process set forth below is not subject to the requirements of Section 9 of
this Agreement, except as set forth below.
Thereafter, a Member who is not a Participant may exercise a right to accept a transfer of a
portion of the Initial Project Participation Percentage of the Initial Participant in an amount
no greater than the amount set forth in Table 2 of this Exhibit A, no later than April 30,
2023 (the “Transfer Completion Deadline”), unless the Initial Participant otherwise agrees
in writing to extend the Transfer Completion Deadline. The right to transfer described in
this Exhibit A shall be exercised in writing (1) addressed to NCPA and the Initial
Participant, and (2) by a Member’s execution of this Agreement by the Transfer
Completion Deadline. For purposes of this Exhibit A only, that Member who becomes a
Participant shall be referred to as a “Table 2 Participant.” Notwithstanding the foregoing,
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Tabl e 1
Initial Pro j ect Participation Pe rcentag e s
Pro je ct Pro j ect
Pro j e ct Participation Participa t ion
Participation MW MW
Member Pe rcentag e s (2025 -2026) (2027 -2037)
City o f Sa nt a Clara 100 .0 % 5 0 .00 10 0 .00
T otal : 100 .0% SO.OD 100 .00
39
THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
the Transfer Completion Deadline applies only to the intended assumption of the Project
Participation Percentage described in Table 2 of this Exhibit A, and shall not limit or
reduce a Participant’s rights set forth in Section 9 of this Agreement. Upon written notice
and execution of this Agreement , the Table 2 Participant will assume all rights and
obligations set forth in this Agreement for the portion of the Project Participation
Percentage share of the Project as set forth in Table 2 of this Exhibit A. If any Members
exercise their right to accept a transfer of a share of the Project Participation Percentage,
the Parties shall add to this Exhibit A by preparing a Table 3 to reflect the Final Project
Participation Percentage shares of the Project. NCPA shall prepare Table 3 after the
Transfer Completion Deadline to reflect the Final Project Participation Percentages of each
Participant, and such Table 3 will be added to this Exhibit A as an amendment to this
Agreement once adopted by the Commission. In the event an intended Table 2 Participant
does not become a Table 2 Participant by the Transfer Completion Deadline, the Initial
Participant shall retain the Project Participation Percentage of the intended Table 2
Participant as described in Table 2 of this Exhibit A, and such will be reflected in Table 3.
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Table 2
Draft Final Project Participation Percentages
Proj ect Project
Pro j ect Participation Participation
Participation MW MW
Member Percentages (2025 -2026) (2027 -2037)
City of Alameda 5 .0% 2.50 5.00
City of Biggs 0.4% 0 .20 0.40
City of Gridley 0.6% 0 .30 0.60
City of Lodi 10.0% 5 .00 10.00
City of Lompoc 1.7% 0 .85 1.70
City of Palo Alto 10.0% 5 .00 10.00
Port of Oakland 2.3% 1.15 2.30
City of Sant a Clara 70.0% 35 .00 70.00
Total : 100.0% 50.00 100.00
40
THIRD PHASE AGREEMENT FOR GEYSERS POWER COMPANY PROJECT
EXHIBIT B
Purchase Agreements
Western Systems Power Pool Agreement Confirmation between Northern
California Power Agency and Geysers Power Company, LLC , to purchase electric
capacity attached to this Exhibit B.
Western Systems Power Pool Agreement Confirmation between Geysers Power
Company, LLC and Northern California Power Agency, to purchase renewable energy
attached to this Exhibit B.
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Attachment B
Monthly On-Peak and Off-Peak Load-Resource Balances for CY 2021
Figure A-1: Monthly On-Peak Load-Resource Balance for CY 2021, with Potential Calpine Geothermal
Output Included
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120,000
100,000
80,000
i o,ooo
:;;
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20,000
0
Jan-25
On Peak Load-Resource Balance
Feb-25 Ma r-25 Apr-25 May-25 Jun-25 Jul-25 Aug-25
-Solar -Western -Calaveras -Landfillgeneration -Wind
Sep-25 Oct-25 Nov-25 Dec-25
Geothermal --LOAD: ON-P EAK
Attachment B
Figure A-2: Monthly Off-Peak Load-Resource Balance for CY 2021, with Potential Calpine Geothermal
Output Included
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Off Peak Load -Resource Balance
Feb-25 Mar-25 Ap r-25 May-25 Jun-25 Jul-25 Aug-25
-Sola r -Western -Calave ras -Landfill generation -Wind
Sep-25 Oct-25 Nov-25 Dec-25
Geothermal --LOAD: OFF-P EAK
Attachment C
Daily Load-Resource Balances for CY 2021 (January, April, July, and October)
Figure B-1: Average Hourly Load-Resource Balance for January 2021, with Potential Calpine
Geothermal Output Included
Figure B-2: Average Hourly Load-Resource Balance for April 2021, with Potential Calpine Geothermal
Output Included
1.c
Packet Pg. 76
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2SO
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Average of Net ll.esout~:!. MWh
-Aver.a e of LOAD_ w
Avetaite Calp ine GEO Bt1t11.i te
1]34561
Values
9 10 11 1~ 1:l 1'1 15 l!i 17 1!! 19 20 H n 23 H
I\W.ri!ge of Net Fl,e'!.1CurCE!!.MWl1 Aw rage ol Calpine G~O E!.l ima1e
-AY~1age f LOAD_MWH
Attachment C
Figure B-3: Average Hourly Load-Resource Balance for July 2021, with Potential Calpine Geothermal
Output Included
Figure B-4: Average Hourly Load-Resource Balance for October 2021, with Potential Calpine
Geothermal Output Included
1.c
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-Av rage O Nl!!t El:e-sc,UILE!~MWh
-AVl'rilR ot LOAD MWH
Calpine Geothermal Contract
Utilities Advisory Commission
February 2023
1.d
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Discussion Outline
1.Overview of the current electric supply portfolio
2.Palo Alto electric load projections through 2045
3.Projection of California energy market dynamics through 2045
4.Calpine geothermal deal characteristics and economics
•5-10 MW purchase over 12 years starting in 2025 @ $79/MWh
5.Preliminary IRP analysis findings
1.d
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~CITY OF
~PALO ALTO
Monthly On Peak and Off Peak Energy Balance
1.d
Packet Pg. 80
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100,000
80.000
~.ooo
40.
20.000
0
On Peak Load -Resource Balance
feb-25 Mar l5 Api-25 May-25 Jim-25 Jul-25 Aug-25
-Solar -Western la lave,as -Landfi ll generation -Wind
~CITY OF
~PALO ALTO
Seri-25 Oct-25 Nov-25
Ge01hem1al -LOAD: ON -PEAK
Doc-25
1,0,000
100,000
80,000
~60,000
2
40,000
20,000
0
Jan-25, Feb-25 Ma,-25
Solar -We~tern
Off Peak Load-Resource Balance
May-.25 Jun 25 JUl-25 Aug-25 Sep-25 Oct-25 Nov-25 D
Ulave,as -Landfillgenerntion -Wind Geothermal -LOAD: OFF-PEAK
Average Local and System Capacity Balances
1.d
Packet Pg. 81
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90
80
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60
50
40
30
20
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2025 2026 2027 2028
Annua l Average
Local RA Ba l ance Forecast
2029 2030 2031 2032 2033 2034 2035
Geothermal -Local Requirement
~CITY OF
~PALO ALTO
2036
250
lOO
150
100
so
0
2025 2026 2D'2J
Annua l Average
System RA Balance Forecast
2028 1.029 2030 2032. 2033 203S 2036
Wmd -Lan!JftllGas So4ar Geothermal -System Requiremenr
Average Seasonal 24-Hour Balance –Q4/Q1 Winter
Q4 Q1
1.d
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MONTH ~
Average of LOAD_MWH Average of Net Resources MWh Average of Ca lpine GEO Estimate
250
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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Values
-Average of Net Resources MWh
-Average of LOAD_MWH
HOUREND_SEQ ~
~CITY OF
~PALO ALTO
Average of Calpine GEO Estimate
MONTH ~
Average of LOAD_MWH Average of Net Resources MWh Average of Calpine GEO Estimate
250
200
150
100
50
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Values
-Average of Net Resources MWh Average of Calpine GEO Estimate
-Average of LOAD_MWH
HOUREND_SEQ ~
Average Seasonal 24-Hour Balance –Q2/Q3 Summer
Q2 Q3
1.d
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MONTH ~
Average of LOAD_MWH Average of Net Resources MWh Average of Ca lpi ne GEO Estimate
250
200
150
100
50
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Values
-Average of Net Resources MWh
-Average of LOAD_MWH
HOUREND_SEQ ~
~CITY OF
~PALO ALTO
Average of Calpine GEO Estimate
MONTH ~
Average of LOAD_MWH Average of Net Resources MWh Average of Ca lp ine GEO Estimate
300
250
200
150
100
50
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Values
-Average of Net Resources MWh Average of Calpine GEO Estimate
-Average of LOAD_MWH
HOUREND_SEQ ~
Annual Load-Resource Balance through 2045
1.d
Packet Pg. 84
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1,200,000
1,000,000
800,000
.c :s 600 ,000
~
400,000
200,000
~CITY OF
~PALO ALTO
Annual Load-Resource Balance
--.. ---..... ----"" ~ ~ ' ... -,,
II • • -i !
I I I I I I I I -
• I :1 I. l ~
•-1•
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
-Western Calaveras -Landfill W i nd Solar -Load -Mid Projection
Palo Alto Electric Load Projections Through 2045
1.d
Packet Pg. 85
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I.. >--
Low Projection (w/ Tota l EV Energy)
,400
1,200
• Low-Other loads
• Low-EV Total
Low-Bldg Elec
-Low -Total
~ 1,000
~
>
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2020 2025 2030 2035 2040 2045
~CITY OF
~PALO ALTO
.._
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Mid Projection (w/ Total EV Energy)
1,400
1,200
-M id -Other Loads
Mld -Datacenter
-Mid -EV Total
Mid -Bldg Ele c
-Mid -Total
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....
>---
High Projection w/ Total EV Energy
1,400
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-High -Other Loads
H igh-Datacenter
-High-EV Tota l
High -Bldg Elec
-High -Total
3 1,000
~
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Projection of California Energy Market Dynamics through 2045
1.O
Before Diablo Canyon Extension
Before Diablo Canyon Extension
1.d
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CAISO is gaining large quantities of intermittent resources while losing base oad
and flexible capacity
200
180
-1 60 :;:
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2021 2026 2031
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-Renewab le Fuels ••• •• Peak Loa d
-De ma rnd Response -W fn d
S h ort-d u ra t io n storage -Lo ng~du ration storage
20 16 20 18 2020 2022 2024 Z026 2028 20.30 2032 2034 2036 2038 2040 2042 2044
■ W 1n d ■ So lar ■ Geothe rmal ■ Biomass ■ N uc lea r ■ Imports ■ Hyd ro ■ Gas ■ Re newab le Fue ls
• Capacity equa l to ~20% of peak load may be retiring over the next 10 years
• ~6 GW of announced retirements (lower right)
• ~25 GW of potential economic and legislative retirements
• Low-cost renewables comb in ed with stakeholder pressure and corporate demand
wiU result in even higher renewable penetration than required by po li cy
• Storage deployments are outpaced by the continued addition of intermittent
resources and thermal retirements
3,500
~ 3 ,000
~
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2022 2023 2024
■ Hydro ■ Nucl ea r ■ Gas
Copy.right Ascend Analytics. Do not duplicate or distribute without written permission
2025 -------=-~
As~ ~
1.O
Projection of California Energy Market Dynamics through 2045 1.d
Packet Pg. 87
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On -Peak is the New Off-Peak
•
•
On -peak and ,off-peak power prices are inverting with increasing
solar deployment
o Power prices are now converg i ng i n 2023, severa years earlie r t h an
previously expected , with s0 1l a r depressing prices during on-pea k hours
and curtailment leading to frequent zero/negative on -peak prices
o Off -peak renewable generat i on is expensive and limited, while off-peak
non-renewable generation variable cost rises w i th carbon and gas prices
Carbon p,rice forecast has been raised, with recent prices above
the price f loor and increasing activism toward raising the floor.
o H i g h carbon prices and renewab l e fuels in the mid-2030s wi ll dr i ve
marginal power prices up before decl i ning again w i t h dee ining costs
$80
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:l:
~ $60
i1J
~~ $50
c..
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., $30 l!
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202 1 2026
----Off-Peak Ave -----On.-Peak Ave
2031 2036
-Off-Pea k Ave (+C O2)
2041
-On-Pea k A v e (+CO2)
::, ....
QQ :::: :::: ---V),,
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$12.00
$1 0.00
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$200.00
B $1 50.00 ---·~
8
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M N N M M m m m m m m ,...
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M N N M N N N N N N N N ------------------------------~ ~ ~ ~ ~ ...... ~ ~ ~ ~ ~ ~ ---er, N ,... '° er, N ,... i.o a, N m U) .... .... ....
-.. -Re newa b le Fue l Cost -SoCa lG as
2025 2030 2035 2040
Copyright Ascend Analytics. Do not duplicate or distribute without written permiss;on
er, 0 N m ..,. Ll"I ,..., g 8 8 3 g 0
N N N N N N --------------......
---~ ~ ~ ~ ~ er, N ,... 0.0 er, N ...... ....
204,,,._s __ ... 20 ... s ... o.__ ____ "',·
I
Projection of California Energy Market Dynamics through 2045
Resource Adequacy Price Forecast
1.d
Packet Pg. 88
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250
$200
L
>
~
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~CITY OF
~PALO ALTO
2015 Q:20 2025
.l. Hi st o ical -Fu l I IRA
20 30
RA
2040
... ·• :3 .2 F!.illl RA
204 5
.3 .2 . r RA
2MO
Copy.right Ascend Analytics. Do not du.plicate o.r distribute with10 1ut writt:en .Permission
Calpine Geothermal Deal Characteristics and Economics
•Power Purchase Agreement between Calpine and NCPA for 100 MW of Geothermal
•Project starts at 50 MW in 2025 and increases to 100 MW in 2027
•Palo Alto share 5 then 10 MW and 43,800 then 87,600 MWh/year
•12-year term, January 2025 –December 2036
•PPA price of $79/MWh (annual cost to Palo Alto: $6.9M)
•Around-the-clock market energy prices: $62-85/MWh for CY25-CY31 over the past month
•Bucket 1 REC Prices: $14-20/MWh
•Local RA Value: $8-13/kW-mo or $8-11/MWh
•Total Benefits: $84-116/MWh
•Net Value: $5 to $37/MWh
1.d
Packet Pg. 89
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~CITY OF
~PALO ALTO
IRP -Preliminary Findings
1.Portfolio fit for a baseload (Geo)resource
•Given the possibility of new baseload (data center) customer loads, a
geothermal resource would be a good fit.
•More closely aligning the City’s loads and resources will reduce portfolio cost
uncertainty.
2.As forward market prices inch up, the $79/MWh Geo price looks increasingly
attractive,especially given the projections that on-peak prices will drop below off-
peak prices.
1.d
Packet Pg. 90
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~CITY OF
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Next Steps –Geothermal Transaction
1.City of Santa Clara already has Council approval to take the full contract volume
•Initially Santa Clara will be the 100% off-taker, until other members get
their council approvals
•When other members get approvals, Santa Clara will assign them a share
2.NCPA staff has completed contract negotiations with Calpine –December 2022
3.UAC/Finance/Council approval –February to April 2023
4.Contract starts January 2025 (ends 2036)
1.d
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~CITY OF
~PALO ALTO
Micah Babbitt
Resource Planner
micah.babbitt@cityofpaloalto.org
(650) 329-2680
1.d
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CITY OF
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Issuing RFP to Rebalance portfolio via seasonal Buy-Sell transactions; plus Geo purchase
Seeking Transaction of Following Products (to balance out 5-10MW Geo purchase)
1.Sell 5-10 MW of Geo output during Q2/Q3 period
2.Sell 20 to 40 MW of Solar PV output during Q2/Q3 period
1.d
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~CITY OF
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Annual Load-Resource Balance through 2045 (with 10MW Geo + PV Sale)
* Load projections include
~70,000 MWh of data
center load expected to
arrive in 2024-25
1.d
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~CITY OF
~PALO ALTO
Annual Load -Resource Balance
2025 2026 2027 2028 2029 2030 203 1 2032 2033 2034 2035 2036 2037 2038 2039 2040 204 1 2042 2043 2044 2045
-Weste rn -Calave ras -Landfill -Wind -Solar after Sale Geothermal -Load -Mid Project ion
Summer Load-Resource Balance after (Geo + PV Sale)
Q2 Q3
1.d
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MONTH y
Ave rage of LOAD_MWH Average of Net Resources less Rosamond Q2/Q3 (MWh)
250
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Va lues
-Average of Net Resources less Rosamond 02/03 (MWh)
HOUREND_SEQ ~
~CITY OF
~PALO ALTO
-Average of LOAD_MWH
MONTH y
Average of LOAD_MWH Average of Net Resources less Rosamond Q2/Q3 (MWh)
250
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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Values
-Average of Net Resources less Rosamond 02/03 (MWh) -Average of LOAD_MWH
HOUREND_SEQ y
City of Palo Alto (ID # 14974)
Utilities Advisory Commission Staff Report
Meeting Date: 2/1/2023 Report Type: VII. NEW BUSINESS
City of Palo Alto Page 1
Title: Discussion and Status Update on the One Water Plan
From: Director of Utilities
Lead Department: Utilities
This item is for discussion and no action is requested.
Staff seeks input from the Utilities Advisory Commission (UAC) on progress to date developing
the One Water Plan for Palo Alto. Staff will use this input to guide the development of its water
supply and conservation options and the process of screening and packaging those options into
potential water supply portfolios.
The attached presentation (Attachment A) provides an overview of the One Water Plan, water
supply and conservation options, screening process, draft evaluation criteria and community
survey results, and water supply portfolio themes. Attachment B provides a detailed list of
water supply and conservation options.
Staff plans to return to the UAC during a joint meeting with the Stormwater Management
Oversight Committee to present initial results in the second quarter of 2023.
Attachments:
• Attachment A: Presentation
• Attachment B: Supply Options
2
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CITY OF
PALO
ALTO
February 1, 2023 www.cityofpaloalto.org
One Water Plan Update
Utilities Advisory Commission
Staff: Lisa Bilir
2.a
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2 www.cityofpaloalto.org
Outline
•One Water Plan Overview
•Discussion: One Water Plan Strategic Direction
•Supply & Conservation Options and Screening Process and UAC Ideas for
Additional Options
•Evaluation Criteria and Engagement Meetings Results
•Discussion: Portfolio Themes
•Next Steps
2.a
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3 www.cityofpaloalto.org
One Water Plan: Roadmap in an Uncertain
Future
The One Water Plan:
•Is a Key Action in Sustainability and Climate Action Plan
•Is a long-term 20-year (through 2045) Water Supply Plan
•Addresses future uncertainty such as SFPUC supply reliability,
droughts,and climate change
•Includes robust and meaningful stakeholder engagement
•Is being completed by an outside consultant Carollo Engineers, a
National One Water Thought Leader
•Builds on existing plans/work
What the One Water Plan does not directly address:
•Current ongoing drought
•Short-term emergencies such as earthquakes and wildfires –
addressed under separate emergency plans
2.a
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TITLE 40 FONT BOLD
Subtitle 32 font
4 www.cityofpaloalto.org
One Water Plan Project Overview
2.a
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Data
Gathering
Water Supply
Conservation
Option
Community Needs
and Priorities
{Sept 2022)
Assessment
of unknowns
Sharing Initial
Results
(-Feb 2023)
Supply &
Conservation
Portfolios
I Funding
Strategy
•
CITY OF
PALO ALTO
Recommended
Supply strategy
Trigger-based
Implementation
Strategy
Supply
Options
Screening
Evaluation
Criteria
Exploring Water
Supply Options
(Dec 2022)
TITLE 40 FONT BOLD
Subtitle 32 font
5 www.cityofpaloalto.org
Water Conservation Regional Comparison
2.a
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Average Residential Water Use in BAWSCA Region in FY 2012/ 13
was 71 GPCD
BAWSCA Member Agency SFPUC Purchase
and Residential Capita Per Day Use in FY 2012/2013
O Si1sbane1GMID
u •SS F o llayward
Weflboroogn 0
0 s..n Bnmo
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SFPUC Purchases
0 1 mgd
Q 2 .5 mgd
Q 5m9d
0 10 mgd
Residential Per Capita Use
• > 75GPCD
65-75 GPCD
48-65 GPCO
e <48 GPCD
e NA
-
PaJoAl!o 0 M,lplta•
San Jose
Slan!ordQ Mounta1nVieW 0
Source: 8 AWSCA-FY 20 12/2013 Anm.tal Servey
24133
0 • •SantaClora .P~ngslffla HHls
Sun,,yval
Sources : BAWS CA FY 2020/2 1 A1111ua l Survey and SFPU C 2020 UW M P
1".
0 2.5 5 10 Mites !
'-----'"1~1 -1~~~-•-I A,
• No agencies usi ng < 48 GPCD
• 9 agencies us i ng 48 -65 GPCD
• 12 agencies using > 75 GPCD
• 49 GPCD SF Retail Residential
Use (avg.)
TITLE 40 FONT BOLD
Subtitle 32 font
6 www.cityofpaloalto.org
Water Conservation Regional Comparison
2.a
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Average Residential Water Use in BAWSCA Region in FY 2020/21
was 66 GPCD
BAWSCA Member Agency Sf PUC Purchase
and Residential Capita Per Day Use in FY 2020/2021
Daly Crty
• 0 Brisbano/GMID
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SFPUC Purchases
0 1 mgd
Q 25 mgd
0 5mgd
0 10 mgd
Residential Per Capita Use
• > 75 GPCD
65-75GPCD
48-65GPCD
• <48GPCD
• NA
-
PoloA~o Milpitas
Sen Jo5"
Stanford O "'°"ntalo View • Q
Source: BAWSCA-FY 20201202, Aonual Survey
25133
0 0 Q Santa Clora
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Sources: BAWSCA FY 2020 /2 1 Annual Survey and SFPUC 2020 UWM P
N
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• 9 agencies us ing< 48 GPCD
• 8 agencies using 48-65 GPCD
• 4 agencies using> 75 GPCD
• 42 GPCD SF Retail Residential
Use (avg.)
TITLE 40 FONT BOLD
Subtitle 32 font
7 www.cityofpaloalto.org
Discussion: Recommended One Water
Strategic Direction
1.Prioritize actions that reduce Palo Alto's Water Demand without compromising tree
canopy health
2.Develop sustainable, resilient water supply portfolios to meet the remaining
demand
2.a
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8 www.cityofpaloalto.org
Supply and Conservation Option Screening
2.a
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CITY OF
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Potential Water Supply
and Conservation Options
Themed
Project Portfolios
Recommended
Implementation
Strategy
□ ■ ■ D □
•• ■
■ ■ □• -□□□ •• ■
■ □•
~25 options
■ Ongoing/Already
Planned
■ Not feasible jUJ:ljJ ,
time
■ Moving forward
□ ■ ■ -□□ ••• ■
□•
...-15 options
■ Estimated Yield (afy)
■ Life Cycle Costs ($/acre-ft)
■ Increases supply reliability
in drought years?
■ Other?
A 8 C D "C "
4 portfolios 1 supply portfolio
■ Supply Availability
■ Supply Resilience
■ Community Benefits
■ Environmental Benefits
■ Life Cycle Cost
■ Ease of Implementation
9 www.cityofpaloalto.org
Supply Option Pre-Screening
2.a
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Ongoing or
already
planned
Not feasible
at_this _time
■ Planned/ongoing conservation
Advanced metering program
Distribution system water loss reduction
■ Non-potable reuse
■ SFPUC imported water supply
Deemed Infeasible in Previous Studies
• Temporary dewatering sites
• lnteragency transfer agreement
• Excessive Cost or Complexity
• Blackwater capture and reuse
• Atmospheric water generators
• Local surface water reservoir
• Valley Water treated water (via new pipeline)
Outside of City Control
• Indirect potable reuse at Lake Lagunita
(groundwater recharge)
• Regional storage
•
CITY OF
PALO ALTO
10 www.cityofpaloalto.org
Supply Option Pre-Screening
2.a
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■ New conservation actions
■ Converting emergency supply wells
■ City park groundwater irrigation
■ Direct potable reuse (via regional facility or City facility)
■ Indirect potable reuse via groundwater injection
■ Expanded non-potable reuse
■ Permanent dewatering (as part of reuse options)
■ Graywater capture and reuse
■ Stormwater capture (residential/commercial-scale or GSI)
■ Multi-source below-ground storage ( . stormwater detention)
■ Desalination
■ Other ideas from today: _________ _
•
CITY OF
PALO ALTO
.~ERE?-nuw! WHO?
Wtll!'N• ?~1'"1111
'WHATI llOW? WHY?
~H.QW?F
11 www.cityofpaloalto.org
Evaluation Criteria
2.a
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Supply Availability
• Normal year reliability
• Dry year reliability
enefits
• Wa t er quality
• Wa t er equity
• Vu lnerabi llity risk score
(resiilience to
uncertainties)
Environmental Benefits
• Tree canopy health
• Sustainab le water
suppl ies
• Waters h ed health
•
CITY OF
PALO ALTO
Life Cycle Cost
• $/acre-foot cost of each
portfolio
• Implementation timeline
• Ope rationa l complexity
• Alignment with other
efforts
• Publ ic acce pt ance
• Regu latory comp lex iity
• Funding opportunities
12 www.cityofpaloalto.org
Evaluation Criteria Survey –Community
Results
2.a
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CITY OF
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Scale these criteria on relative importance. Mentimeter
Supply Availability
Supply Resilience
Life Cycle Cost
Community Benefits
Environmental Benefits
----------e.s
Ease of Implementation
7.3
~WJ!ERE?~ HUW!WHO? ---1'' WHAT? llOW? WHY? '2!HOW?~ ---
13 www.cityofpaloalto.org
Discussion: Proposed Portfolio Themes
2.a
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Baseline
Portfo lio
Business as
usual, only
implementing
already
planned
projects and
programs .
Baseline for
Portfolio
comparison
I
Minimize
Cost
What mix of
options will
have the
lowest
combined
supply cost?
Maximize
Local
Supplies
What mix of
options
further
increase t11e
City's local
water
supplies the
most?
Requesting your input!
I
Maximize
Drought
Resi lience
What mix of
options
enable the
C:ity to best
mitigate the
in1pact of
droughts?
•
CITY OF I
PALO ALTO
Sustainab le
Water
Supplies
What mix of
options are
renewable ,
equitable,
and protect
the
environment
the most?
♦
Other
T hemes
14 www.cityofpaloalto.org
Next Steps
1.Stakeholder Engagement –Initial Results
2.UAC Initial Results/ Stormwater Oversight Committee Joint Meeting
3.City Council Initial Results –Information Only
4.UAC Final One Water Plan
5.City Council Final One Water Plan
March 2023
Q2 2023
Q2 2023
Fall 2023
Fall 2023
2.a
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CITY OF
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Palo Alto One Water Supply Plan
Draft - Supply Options Matrix
November 2022
Category #Supply Option Description
1 Planned/Ongoing Conservation
Continuation of ongoing water conservation programs that
will continue to meet state efficiency legislation. Includes
customer rebate programs for implementing efficiency
measures.
Includes continuing to implement AMI (advanced metering
infrastructure) for water meters to detect and reduce water
leaks. Program is ongoing and expected to be complete in
2024-2025.
2 Enhanced conservation
Conservation efforts that go above and beyond current
conservation measures. Could include more aggressive
building codes and/or alternatives for serving the needs of
Foothills Nature Preserve, including irrigation and filling of
Boronda Lake.
Includes customer side water loss reduction. Outdoor
conservation mechanisms could include incentives for
transitioning to native, drought tolerant trees; banning or
reducing lawns, while maintaining tree canopy.
3 Converting emergency supply wells Converting the 8 wells constructed/rehabbed in 2015 from
emergency to potable use.
4 City park groundwater irrigation Construct new small wells to irrigate city parks.
Conservation
Groundwater
DRA
F
T
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Palo Alto One Water Supply Plan
Draft - Supply Options Matrix
November 2022
Category #Supply Option Description
5 Expanded NPR
NPR Phase 3 pipeline extended into the foothills and Los
Altos Hills (Northwest County Recycled Water Strategic Plan,
Option A2)
6 Direct potable reuse (City facility)
AWPF constructed near the RWQCP to provide a local DPR
source. (Northwest County Recycled Water Strategic Plan,
Option D1)
7 Direct potable reuse (regional facility)Send water to Valley Water’s regional facility (tertiary treated
wastewater) in exchange for purified water.
8 Indirect potable reuse (groundwater
injection)
AWPF constructed near the RWQCP to provide a local IPR
source. AWPF water would be conveyed to five injection well
sites to augment groundwater supply (Northwest County
Recycled Water Strategic Plan, Option C1)
9 Indirect potable reuse (Lake Lagunita
groundwater recharge)
Send IPR treated water to Lake Lagunita on Stanford campus
to percolate into aquifer to augment groundwater supply.
10 Graywater Capture and Reuse
On-site use of graywater (relatively clean wastewater from
baths, sinks, washing machines, other kitchen appliances)
either on a customer-scale or at City facilities.
11 Blackwater Capture and Reuse On-site use of blackwater (wastewater from toilets) either on
a customer-scale or at City facilities.
Water Reuse
DRA
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Palo Alto One Water Supply Plan
Draft - Supply Options Matrix
November 2022
Category #Supply Option Description
12 Residential or commercial-scale
Stormwater/Rainwater Capture
Expand upon current City rain barrel program. Potentially
work with larger sites such as schools to implement larger
scale rainwater capture.
13 Green stormwater infrastructure
Increased implementation of green stormwater infrastructure,
including bioretention areas, pervious pavement, green roofs,
etc. Could include large scale stormwater capture at parks for
reuse.
14 SFPUC supply
Water purchased from San Francisco's Regional Water
System. 85% of this water comes from Hetch Hetchy and
15% from local watersheds in Alameda and San Mateo
Counties.
15 Valley Water treated water
Extend Valley Water treated water pipeline to connect to
SFPUC pipelines and serve Palo Alto at the Page Mill
turnout. Water source undefined.
16 Interagency Transfer Agreement This would include purchasing additional water from another
water agency.
17 Atmospheric water generators (AWGs)
Extract water by condensing humidity from ambient air. This
alternative would consider both home and commercial-scale
AWGs.
18 Local storage This would include building surface storage within the City's
boundaries and/or a local watershed.
19 Regional storage This would include partnering with other agencies in the
region to build or expand surface storage (i.e. Los Vaqueros)
Stormwater Capture
and Use
Imported Water
Other
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Palo Alto One Water Supply Plan
Draft - Supply Options Matrix
November 2022
Category #Supply Option Description
20 Multi-source storage
Storage to store stormwater, recycled water, or dewatering
water (from permanent sites) dependent on time of year and
water source availability. Would be limited to City-owned
facilities.
21 Regional desalination Regional or local desalination project utilizing either brackish
groundwater or bay intake.
22 Temporary dewatering sites Trucking water from temporary dewatering sites (such as
basement construction) to City parks for irrigation.
23 Permanent dewatering sites
Redirect discharge from permanent dewatering sites (Oregon
Expressway and City Hall) to RWQCP to increase flows for
future potable reuse project.
Other
(cont.)
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City of Palo Alto (ID # 14676)
Utilities Advisory Commission Staff Report
Meeting Date: 2/1/2023 Report Type: VII. NEW BUSINESS
City of Palo Alto Page 1
Title: Staff Recommends the UAC Accept a Verbal Presentation on State
Public Policy Actions and Recommend the City Council Approve the 2023
Utilities Legislative Guidelines
From: Director of Utilities
Lead Department: Utilities
Recommendation
Staff recommends that the Utility Advisory Commission:
(1) Accept the staff report regarding state legislation, regulations, and budget items and
(2) Recommend the City Council approve the 2023 guidelines though the following motion:
“Staff and the Utilities Advisory Commission recommend the City Council approve the
2023 Utilities Legislative Policy Guidelines”
Discussion
SUMMARY OF 2022 AND PREVIEW OF 2023
State legislation in 2022
CPAU monitored over 50 state bills this session. While 2022 was a busy year for utilities -related
legislation, none of the bills signed into law are anticipated to significantly affect Palo Alto’s
utilities. This is due to three key reasons: (1) Palo Alto is already well positioned to meet new
laws as a result of the City’s clean energy portfolio and proactive programs, (2) successful
advocacy by the California Municipal Utilities Association (CMUA) and the Northern California
Power Agency (NCPA) led to the mitigation of any bills potentially harmful to the City’s
interests, and (3) legislation that started as mandates to utilities ended as mandates to state
agencies.
A few of the monitored bills signed into law include:
• SB 1157 (Hertzberg) changes the indoor water use standard (one metric used to calculate
overall water efficiency) to reduce usage. Instead of the current 55 gallons per capita day
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City of Palo Alto Page 2
(gpcd) until 2025, 52.5 gpcd between 2025 and 2030, and 50 gpcd starting in 2030, those
numbers will now be 55, 47, and 42 respectively;
• SB 1020 (Laird) sets interim clean energy targets (of 90% by 2035 and 95% by 2040) as the
state works to meet its 100% clean energy goal;1
• AB 847 (Quirk) requires the development of a high voltage test for foil balloons and for the
placement of warning labels regarding the danger of releasing foil balloons that may come
into contact with electric lines;
• AB 2204 (Boerner Horvath) establishes the new position of Deputy Secretary for Climate
within the state’s labor agency – if funded by the Legislature;
• SB 1158 (Becker) requires each publicly owned utility (POU) governing board to review the
GHG emissions of its electric utility and allows the board to evaluate, along with
subsequent procurement plans, if the utility is making adequate progress in meeting its
own GHG emission targets;
• ACR 188 (Holden) is a non-binding resolution that requests the California Independent
System Operator (CAISO) produce a report by February 28, 2023 summarizing recent
studies on the impacts of expanded regional cooperation.
State and federal budgets
With a surplus of over $97 billion, the 2022-2023 state budget provided funding for a wide
variety of climate action-related programs and state agency mandates. These include many
directives to the California Energy Commission (CEC) that could affect POUs, including to:
• Develop, by the end of 2023, approaches on how to determine appropriate planning
reserve margins for POUs;
• Produce a report, by January 2023, on how POUs handled reliability during the past
summer, projecting future reliability challenges, and posing possible solutions to any
concerns;
• Implement a new voluntary demand side grid support program for POUs.
For 2023-2024, the state expects a budget deficit of around $24-25 billion. Currently, there is
no information available regarding how this new projection might impact the above dir ectives
or ongoing energy-related programs. The Governor will release his proposed 2023-2024 budget
in mid-January, which will provide more insight.
In August 2022, President Biden signed into law the Inflation Reduction Act, which among many
other items, provides funding to reduce carbon emissions, invest in clean energy, and continues
funding for residential energy efficiency improvements, including heat pump water heaters.
1 The clean energy goal is to ultimately supply 100% eligible renewable energy resources or zero -carbon resources
to Californians by 2045.
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Regarding the latter item, CPAU’s Resource Management Division has spent time inv estigating
this credit (and similar credits) as we move forward with the City’s heat pump water heater
pilot program. Regarding the former items – and related to the state budget - regulatory action
is required by the agencies tasked with allocating funds.
One example of the agency action needed: The CEC is expecting to disseminate $10 billion in
clean energy funding from the state and federal budgets over the next few years. Broadly, the
agency is considering using some of the money on new and current en ergy efficiency and grid
resilience programs and the rest on long-term energy storage, hydrogen programs, building
decarbonization programs, and the like. There are no details yet about this spending or how
local governments may participate in programs, but we do know that the CEC wants to hire
about 100 more staffers to implement new and expanded programs. Through CMUA and NCPA,
staff will monitor the development of spending allocations and regulatory action to determine
how they might benefit CPAU.
Regulatory activity in 2022
CPAU continued to produce all required reporting to agencies last year and has received
positive feedback in doing so. For example, the Wildfire Safety Advisory Board was
complementary of our 2022 Wildfire Mitigation Plan, offering no suggestions for improvement.
This year, we will submit a revised Plan, pursuant to state law and with an independent
evaluation to ensure the City continues to mitigate risk of electric line-ignited wildfires in the
best manner possible.
On the water side, staff expects revisions to the State Water Resource Control Board’s Lead and
Copper Rule, resulting from changes in the federal Environmental Protection Agency’s rule.
Staff have been tracking potential changes while continuing to comply with the cur rent rule.
Staff also continues to monitor other energy and water-related regulatory action through NCPA
and CMUA.
State legislation in 2023
This year, as the state and country move closer to making inroads in electrification, staff
expects more bills on transmission and resource adequacy. As the state continues to experience
very hot summers and wildfires, bills addressing reliability, demand reduction, and electric-line
ignited wildfire mitigation are also expected. The focus on clean energy and sustainability
remains, especially through the Legislature’s Joint Legislative Committee on Climate Change
Policies, the Senate’s Climate Working Group, and like-minded legislators. Lastly, staff expects
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to soon see a bill related to regionalization2, an issue faced more than once in prior legislative
sessions.
2023 is the beginning of a new two-year session, meaning bills that do not pass in 2023 will
continue on in 2024, absent a legislative decision to stop their progress. CPAU staff continues to
work closely with CMUA, NCPA, and other POUs this year through in -person meetings, virtual
meetings, workgroup calls, and workshops.
APPROVAL OF UPDATED LEGISLATIVE GUIDELINES
CPAU has a document in place that guides staff when determining which of the thousands of
state bills to monitor, and potentially engage with, each year (Attachment A). The UAC first
approved the current legislative guidelines in 2017. They were intended to be perennial, subject
to UAC and Council review, and were approved annually. The last UAC approval was on
November 3, 2021 with Council approval following on February 7, 2022.3 While the guidelines
have served CPAU reasonably well, there is room for improvement. For example, the current
guidelines are action-oriented where action may not be warranted, vague in places, and could
benefit from additional clarity about what is most important to the organization.
A case in point: fiscal stability is a Council priority and important to CPAU but is not specifically
noted in the current guidelines. Rather, three separate guidelines opaquely refer to fiscal
stability: “Where possible, seek funding and program incentives,” “Oppose unnecessary,
unreasonable, impractical, or costly rates or mandates,” and “Advocate for fair cost allocation
and support the principle of beneficiary pays.” These statements can be clarified to specifically
address a range of possible responses to financial policy initiatives, such as: Opposing or
supporting legislation, working with other POUs to inform our trade association’s advocacy,
monitoring regulatory activity, participating in regulatory comments from NCPA or CMUA, and
more.
For 2023, staff suggests a different approach (Attachment B). Rather than statements
presuming possible actions untethered to specific policy initiatives, (i.e.: “oppose,” “advocate”)
staff suggests the guidelines reflect the values and priorities shared by the City and CPAU. The
new draft guidelines do not presume a position or action and as such, allow staff to determine
activities4 based on what is important to CPAU, Council, and the community. While not a
2 The word refers to possible evolution of CAISO into a regional organization of several western states. This
expanded multi-state body rather than a single state operator was initially contemplated in SB 350 (2015).
3 As noted below, an additional guideline was added by Council in October 2022.
4 As noted in the draft guidelines, any action taken by CPAU will conform with the City’s Advocacy Process Manual.
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significant shift from the current guidelines, the phrasing of the 2023 draft guidelines allows for
some flexibility while explicitly acknowledging key values and priorities.
Importantly, all the guideline areas from earlier years remain – with one exception. On October
3, 2022, Council added a new workforce-related item. This new 2022 guideline is a result of a
recommendation from Council’s Sustainability and Climate Action Plan Ad Hoc Committee,
reflecting the current and future shortage of skilled labor required to modernize the electric
grid. For 2023, staff recommends retaining the added guideline, but with language
modifications:
Workforce guideline added in 2022 Workforce guideline suggested for 2023
Support government action to expand the
workforce in trades and technical
disciplines necessary to support building
and vehicle electrification and grid
modernization.
A skilled workforce is critical. We support
government action that provides funding,
training, and other resources to increase and
maintain utility staffing levels, especially for
key areas such as our electric utility while we
work to modernize our grid.
The suggested wording for 2023 (1) aligns with the language convention of the draft guidelines,
(2) provides specificity to the word “expand” in the current guidelines (funding, training,
resources), (3) specifically highlights the electric utility and grid modernization in keeping with
Council’s original intent, and (4) broadens the 2022 guideline to provide staff the flexibility to
advocate for a skilled workforce in areas other than electrification and grid modernization. As
per the usual process, once approved by the UAC, the draft 2023 guidelines will appear before
Council with an adoption recommendation. Council then has the opportunity to review any
changes.
Resource Impact
Approval of this report and the 2023 guidelines has no impact on resources.
Environmental Review
The UAC’s review and recommendation on the 2023 Utilities Legislative Policy Guidelines does
not meet the California Environmental Quality Act’s definition of a project, pursuant to Public
Resources Code 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative
activity which will not cause a direct or indirect physical change in the environment ; an
environmental review is not required.
Attachments:
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• Attachment A: Utilities Legislative Policy Guidelines
• Attachment B: 2023 Utilities Legislative Guidelines
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Attachment A
Utilities Legislative Policy Guidelines: 2022 Update
City of Palo Alto Utilities Department (CPAU) staff will use the below guidelines as well as the
City’s guidelines to help determine any advocacy position or action on Utilities-related issues.
Formal advocacy, such as submitting written letters or comments and meeting with
policymakers and/or staff, requires the approval of the Utilities Director or his designee.
1. Seek to preserve local government flexibility, discretion, accountability, and oversight of
matters impacting utility programs, services, activities, and rates. Oppose action that could
hamper or minimize this flexibility or discretion.
2. Where possible, seek funding and program incentives.
3. Advocate for reasonable government action with minimal customer impact that allows for
flexibility and implementation feasibility.
4. Advocate for locally-designed conservation or efficiency programs. Support reasonable State
conservation or efficiency requirements that consider local populations, environment, and
resources.
5. Inform state and federal policymakers about CPAU’s current programs, services, goals, and
reporting requirements.
6. Oppose unnecessary, unreasonable, impractical, or costly rates or mandates.
7. Collaborate with and support the efforts of regional agencies and associations whose goals
align with ours.
8. Advocate for fair cost allocation and support the principle of beneficiary pays.
9. Support efforts to maintain or improve the security and reliability of our infrastructure.
10. Support government action that cost effectively reduces greenhouse gas emissions.
11. Promote locally-designed residential and commercial electrification programs.
12. Support government action allowing CPAU to maintain customer confidentiality.
13. Support government action to expand the workforce in trades and technical disciplines
necessary to support building and vehicle electrification and grid modernization.1
1 Added by Council October 2022
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Draft – subject to UAC and Council approval
2023 CPAU LEGISLATIVE GUIDELINES
SUMMARY
The City of Palo Alto Utilities Department utilizes the following guidelines when determining
whether to monitor or engage in legislation or regulations. These are, in effect, foundational
statements informed by City Council policies, community needs, and existing and planned utilities
programs. They are evergreen by design and subject to annual review, approval, or modification
by the Utilities Advisory Commission and/or the City Council. Any actions taken relating to the
guidelines will adhere to the City of Palo Alto’s Advocacy Process Manual.
GUIDELINES
1. Clean, renewable, affordable energy is vital. We must invest in infrastructure and programs
that support clean energy in an affordable and equitable manner.
2. Adequate supplies of clean, affordable drinking water are imperative. We will work to balance
our water resources with the needs of our community, city policies, and precipitation
conditions.
3. Utilities safety and reliability are essential. We strive to ensure consistent resources while
maintaining our infrastructure in a safe manner.
4. Affordable rates are key. We carefully analyze any proposed government policy that could
lead to an increase in rates.
5. Fiscal stability is a cornerstone of our work. We strive to operate and provide affordable
programs, leveraging grants and government funding where feasible.
6. As a municipal government with locally elected officials and a public commission, we are self-
guided. As such, our local leaders are best positioned to manage our policies, resources, and
programs.
7. Collaborating externally increases our reach. We work with associations and stakeholders to
combine our resources, share our experiences, and advocate for our community.
8. Preserving customer privacy is important. We intend to continue to meet our customers’
expectations in safeguarding their contact and utility usage information.
9. A skilled workforce is critical. We support government action that provides funding, training,
and other resources to increase and maintain utility staffing levels, especially for key areas
such as our electric utility while we work to modernize our grid.
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City of Palo Alto (ID # 14973)
Utilities Advisory Commission Staff Report
Meeting Date: 2/1/2023 Report Type: INFORMATIONAL REPORTS
City of Palo Alto Page 1
Title: Informational Utilities Quarterly Report Update for Q1 of FY2023
From: Director of Utilities
Lead Department: Utilities
Executive Summary
Linked below for the Utilities Advisory Commission’s information is an update on water, gas,
electric, wastewater collection and fiber utilities, efficiency programs, legislative/regulatory
issues, utility-related capital improvement programs, operations reliability impact measures
and a utility financial summary. This updated report (Linked Document) has been prepared to
keep the Council and Utilities Advisory Commission apprised of the major issues that are facing
the water, gas, electric, wastewater collection and fiber utilities. A separate quarterly report on
the financial position is prepared consistent with when the City closes its books.
Items of special interest in this report are summarized below:
COVID-19 Impacts: Behavior changes resulting from COVID-19 continue to impact loads in FY
2022:
• FY 2023 actual electric sales through September 2022 were about 4% lower than
projections, while revenues were about 7% higher than projections. The higher sales
revenues were due to extra revenue from the Electric Hydro Rate Adjuster. Decreased loads
are mostly attributed to the commercial sector. (Section 1.5.1)
• Gas utility demand through September 2022 was 5% lower than forecasted in the FY 2023
Financial Plan. Actual sales revenue was 35% higher than forecasted. The higher revenue
was due to increases in the market price of gas commodity which is passed through to
customers. (Section 2.5.1)
• Water demand through the end of September 2022 was 10% lower than forecasted and
water sales revenues were about 13% lower than forecasted in the FY 2023 financial plan,
mostly due to water conservation from customers responding to the drought. Increased
water conservation may further impact revenue and reserve levels. (Section 3.5.1)
• Wastewater revenues have not been significantly affected by the pandemic.
Vacancies and Staffing – Appendix B
• The Utilities Department has 48 vacant positions out of 253 authorized positions or a 19%
vacancy rate at the end of September 2022
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• The highest number of vacancies are in Electric Operations (20 FTEs) and Electric
Engineering (9 FTEs)
Electric Utility:
Output from the City’s hydroelectric resources is low. Total forecasted hydropower for FY 2022
is 244 GWh, which is 234 GWh (51%) below the long-term average. The current forecast for FY
2023 assumes a small recovery in generation from FY 2022, but is still only projected to provide
56% of generation compared to the long-term average. (Section 1.1.2)
• Sales of renewable energy credits (RECs) for CY 2022 are expected to result in $0.8M in net
revenue. (Section 1.1.3)
• A number of construction projects are in the design phase with construction due to begin in
2022. (Section 1.2)
• Electric sales for the first two quarters of FY22 were about 3% lower than projected, and
revenue was about 5% lower. (Section 1.5)
Gas Utility:
• Gas prices remain high, and customer bills will be impacted over the winter months.
Outreach material will inform the community of these bill impacts and provide energy
saving tips and program information. (Section 2.5.2 and 7)
• A gas main replacement project is currently in progress (GS -13001) and the City is in the
midst of a two year inspection project to find “cross bores.” (Section 2.2)
Water Utility:
• January through March 2022 was the driest on record for the Hetch Hetchy gauge. System
storage is below normal but in better shape than most reservoirs in the state. (Section 3.1)
• On November 10, 2022, Governor Newsom’s senior Water-Policy Officials, the San Francisco
Public Utilities Commission (SFPUC), and the Modesto and Turlock Irrigation Districts
reached agreement on a Memorandum of Understanding to provide greater water flows
and increased habitat for the Tuolumne River. The Bay Area Water Supply and Conservation
Agency (BAWSCA) anticipates that this MOU will become a part of a larger voluntary
agreement for the Sacramento-San Joaquin Delta. (Section 3.1)
• Palo Alto launched the One Water Plan with the goal of Council adoption of a One W ater
supply plan that is a 20-year adaptable roadmap for implementation of water supply and
conservation portfolio alternatives. A number of stakeholder engagement meetings have
occurred and are scheduled to occur. The UAC will receive an update in February or March
of 2023.
On May 24, 2022, Palo Alto’s water supplier, the San Francisco Public Utilities Commission
adopted a systemwide voluntary water use reduction of 11% compared to baseline water use
during FY 2019-2020. For the billing months July 2022 through October 2022, compared with
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the same period from July 2019 to October 2019, the Palo Alto community reduced water
usage by 10%. (Section 3.1)
• Actual water sales volumes through Q1 of FY 2023 were about 10% lower than forecasted in
the FY 2023 financial plan. Staff’s preliminary projection of expected revenues and expenses
together with transfers from the CIP Reserve, estimates the Operations Reserve will reach
approximately target levels by the end of FY 2023. (Section 3.5)
• Construction started on a water main replacement project in April. (Section 3.2)
Wastewater Utility:
• An overview of the status of the Regional Water Quality Control Plant (RWQCP)
rehabilitation projects is provided, including an overview of the financing plan for the
projects. The first project to begin construction will be the primary sedimentation tank
rehabilitation. (Section 4.1)
• A sewer system rehabilitation project (SSR 30) was approved by Council on December 31,
2021. Construction started in March 2022 and is expected to b e complete in January 2023.
(Section 4.2)
• Actual wastewater sales revenues through Q1 of FY 2023 were around expectation, at
about 0.4% higher than forecasted in the FY 2023 Financial Plan. (Section 4.4)
Fiber Utility:
• The City launched the Palo Alto Fiber Market Research Survey and Fiber Deposit program.
3,254 surveys were completed (14.8% response rate) and 703 deposits received as of
August 3, 2022. 28.4% of households are either very dissatisfied or somewhat dissatisfied
with their current internet services. An additional 14.4% are neither satisfied nor
dissatisfied. (Section 5.1)
• On September 19, 2022, City Council and UAC held a joint session to review the internet
survey results and evaluated the feasibility of a new City-owned and City-operated ISP
business. (Section 5.1)
Customer Programs (Section 6):
• The City in partnership with the Bay Area Water Supply and Conservation Agency (BAWSCA)
held three well-attended landscape efficiency workshops in fall 2022. The workshops
covered topics on harvesting rainwater, steps to take to design and convert lawns into
drought-tolerant landscapes, and available rebates.
• On October 6, 2022 the City launched WaterSmart, an online water management tool to
help residents and businesses better understand their wa ter usage and enable them to
conserve water and save money.
• Palo Alto had the highest number of SunShares, a solar and battery storage group -buy
program, sign ups with 161 registered residents by the November 15, 2022 registration
deadline.
• Since the Business Energy Advisor program launched in June 2022, 21 program participation
agreements have been sent to customers, 7 agreements have been signed, and 3 site
assessments have been completed.
Packet Pg. 126
City of Palo Alto Page 4
• For residential customer programs, staff is developing contracts for residential building
electrification, energy and water efficiency programs which includes single family and
multifamily homes as well as income and medically qualified residents.
• The Business Electrification Technical Assessment Program launched in August 2022,
offering no-cost assessments to help nonresidential customers identify electrification
opportunities and free technical assistance to support them with their building
electrification journey. Since the program launched, our partner, CLEAResult, h as
completed 2 site assessments, assisting large commercial customers with potential HVAC
and heat pump water heater projects.
• The City continues to promote its multi-family and workplace EV charger programs.
Communications: A digest of major outreach efforts is provided in Section 7, including outreach
related to drought, the public safety power shutoff program in the Foothills, and utility scams.
Legislative and Regulatory: Major legislative and regulatory items are summarized in Section 8.
Attachments:
• Attachment A: Utilities Quarterly Report FY23-Q1
• Attachment B: CY2021 Gas Utility Asset Management Overview
Packet Pg. 127
Utilities Quarterly Update
First Quarter of Fiscal Year 2023
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1Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Table of Contents
1 ELECTRIC UTILITY 4
1.1 ELECTRICITY SUPPLY AND TRANSMISSION 4
1.1.1 Forecasted Supply Costs (Jim Stack)4
1.1.2 Hydroelectric Conditions (Jim Stack)5
1.1.3 REC Exchange Program (Jim Stack & Eric Wong)6
1.1.4 Renewable Energy Procurement (Jim Stack)6
1.2 6
1.3 7
1.4 8
1.5
CAPITAL IMPROVEMENT PLAN STATUS (PATRICK VALATH)
RATE AND BILL COMPARISONS (ERIC KENISTON)
RELIABILITY (KENNETH SWAIN)
FINANCIAL HEALTH 8
1.5.1 Sales Forecasts vs. Actuals (Eric Wong)8
1.5.2 Financial Position (Eric Keniston)9
2 GAS UTILITY 10
2.1 GAS SUPPLY AND TRANSMISSION (ERIC WONG) 10
2.1.1 Actual and Forecasted Supply Costs (Eric Wong)11
2.1.2 Carbon Neutral Gas Program (Micah Babbitt)11
2.1.3 Cap and Trade Program (Eric Keniston)13
2.1.4 Gas Transmission Line Capacity Valuation (Eric Wong)14
2.1.5 Gas Prepay Valuation (Eric Wong)14
2.2 CAPITAL IMPROVEMENT PLAN STATUS (SILVIA SANTOS) 15
2.3 RATE AND BILL COMPARISONS (ERIC KENISTON) 15
2.4 RELIABILITY (MELISSA SMART) 15
2.5 FINANCIAL HEALTH 16
2.5.1 Sales Forecasts vs. Actuals (Eric Wong)16
2.5.2 Financial Position (Eric Keniston)16
3 WATER UTILITY 18
3.1 WATER SUPPLY AND TRANSMISSION (LISA BILIR) 18
3.2 CAPITAL IMPROVEMENT PLAN STATUS (SILVIA SANTOS) 21
3.3 RATE AND BILL COMPARISONS (LISA BILIR) 21
3.4 RELIABILITY (MELISSA SMART) 22
3.5 FINANCIAL HEALTH 22
3.5.1 Sales Forecasts vs. Actuals (Eric Wong)22
3.5.2 Financial Position (Lisa Bilir)23
4 WASTEWATER UTILITY 24
4.1 WASTEWATER TREATMENT UPDATES AND CAPITAL PLANNING STATUS (LISA BILIR) 24
4.1.1 Treatment Cost Trends (Lisa Bilir)24
4.1.2 Regional Water Quality Control Plant Capital Planning Status (Lisa Bilir)25
4.2 COLLECTION SYSTEM CAPITAL IMPROVEMENT PLAN STATUS (SILVIA SANTOS) 26
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2Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
4.3 RATE AND BILL COMPARISONS (LISA BILIR) 26
4.4 FINANCIAL HEALTH 27
4.4.1 Sales Forecasts vs. Actuals (Eric Wong)27
4.4.2 Financial Position (Lisa Bilir)27
5 FIBER UTILITY 28
5.1 28
5.2 29
5.3 29
5.4
FIBER UTILITY STRATEGIC PLANNING (DAVE YUAN & JOSH WALLACE)
CAPITAL IMPROVEMENT PLAN STATUS (PATRICK VALATH/DAVE YUAN)
RELIABILITY (DAVE YUAN)
FINANCIAL HEALTH 29
5.4.1 Fiber Sales (Dave Yuan) 29
5.4.2 Financial Position (Dave Yuan) 29
6 CUSTOMER PROGRAMS (EFFICIENCY AND SUSTAINABILITY)30
6.1 CUSTOMER PROGRAMS UPDATES 30
6.1.1 Energy and Water Efficiency (Scott, Leanna, Brian, Christine, Linda)30
6.1.2 Building Electrification (Christine Tam, Lisa Benatar, Shelby Sinkler)32
6.1.3 Electric Vehicles (Hiromi Kelty, Shiva Swaminathan and Connie Chu)34
6.2 FUNDING SOURCES FOR EMISSIONS REDUCTIONS 39
6.2.1 Low Carbon Fuel Standard (LCFS) Program (Shiva Swaminathan)39
6.2.2 Cap and Trade Program, Revenue from Allocated Allowances (Eric Keniston)39
6.2.3 Electric Public Benefit Funds (Eric Keniston)39
6.3 INNOVATION AND PILOT PROGRAMS (LENA PERKINS) 40
6.3.1 Academic Collaborations (Lena Perkins) 40
6.3.2 Completed Projects (Lena Perkins) 40
7 COMMUNICATIONS (CATHERINE ELVERT)41
8 LEGISLATIVE AND REGULATORY ACTIVITY 43
8.1 STATE LEGISLATION (HEATHER DAULER) 43
8.2 STATE REGULATORY PROCEEDINGS (HEATHER DAULER) 43
8.2.1 Energy Commission 43
8.2.2 State Water Resources Control Board 43
8.2.3 Air Resources Board 43
8.2.4 Natural Resources Agency 43
9 APPENDIX A: ENERGY RISK MANAGEMENT PROGRAM 45
9.1 OVERVIEW OF HEDGING PROGRAMS (KARLA DAILEY) 45
9.2 OVERVIEW OF ENERGY RISK MANAGEMENT PROGRAM (KARLA DAILEY) 45
9.3 FORWARD DEALS (ERIC WONG) 45
9.4 MARKET EXPOSURE (JIM STACK AND MICAH BABBITT) 46
9.5 TRANSACTION COMPLIANCE (KARLA DAILEY) 46
10 APPENDIX B: STAFFING AND VACANCIES (DAVE YUAN) 47
11 APPENDIX C: GAS UTILITY ANNUAL INFRASTRUCTURE MAINTENANCE AND REPLACEMENT REPORT (SILVIA SANTOS)
48
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3Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figures
FIGURE 1:FY 2022 FINANCIAL PLAN SUPPLY COST FORECAST VS. ACTUALS ................................................................................................5
FIGURE 2:HYDRO GENERATION FY 2021-22 ACTUALS (GWH) ................................................................................................................6
FIGURE 3:RESIDENTIAL MONTHLY ELECTRIC BILL COMPARISON (EFFECTIVE 6/1/2022, $/MO.).....................................................................7
FIGURE 4:ELECTRIC OUTAGE RELIABILITY,FY 2023-Q1 ..........................................................................................................................8
FIGURE 5:ELECTRIC SALES VOLUME (KWH),UP TO FY 2023-Q1 ..............................................................................................................8
FIGURE 6:ELECTRIC SALES REVENUE ($),UP TO FY 2023-Q1 ..................................................................................................................9
FIGURE 7:GAS SUPPLY COMMODITY RATES ($/THERM),FY 2018-23 ....................................................................................................10
FIGURE 8:GAS SUPPLY COSTS ($),ACTUAL VS BUDGET,UP TO FY 2023-Q1 ............................................................................................11
FIGURE 9:OFFSET PORTFOLIO COMPOSITION ......................................................................................................................................12
FIGURE 10:OFFSET PROJECT DESCRIPTIONS ........................................................................................................................................13
FIGURE 11:ESTIMATED CAP AND TRADE COSTS ...................................................................................................................................14
FIGURE 12:RESIDENTIAL NATURAL GAS BILL COMPARISON ($/MONTH) ...................................................................................................15
FIGURE 13:GAS SERVICE INTERRUPTIONS,FY 2023 .............................................................................................................................15
FIGURE 14:GAS SALES VOLUME (THERMS),UP TO FY 2023-Q1 ............................................................................................................16
FIGURE 15:GAS SALES REVENUE ($),UP TO FY 2023-Q1.....................................................................................................................16
FIGURE 16:REGIONAL WATER SYSTEM STORAGE ................................................................................................................................. 19
FIGURE 17:SFPUC WATER DELIVERIES..............................................................................................................................................20
FIGURE 18:RESIDENTIAL WATER BILL COMPARISON ($/MONTH) ............................................................................................................21
FIGURE 19:WATER SERVICE INTERRUPTIONS,FY 2023.........................................................................................................................22
FIGURE 20:WATER SALES VOLUME (CCF),UP TO FY 2023-Q1 .............................................................................................................22
FIGURE 21:WATER SALES REVENUE ($),UP TO FY 2023-Q1 ................................................................................................................23
FIGURE 22:PALO ALTO’S SHARE OF ESTIMATED WASTEWATER TREATMENT EXPENSES (PROJECTION AND PLANNED CIP)..................................25
FIGURE 23:CURRENT RWQCP CAPITAL WORK IN-PROGRESS (INFORMATION FROM RWQCP JUNE 2022 PARTNERS MEETING) .......................26
FIGURE 24:RESIDENTIAL WASTEWATER BILL COMPARISON ($/MONTH) ...................................................................................................27
FIGURE 25:WASTEWATER SALES REVENUE ($),UP TO FY 2023-Q1 .......................................................................................................27
FIGURE 26:EV TECHNICAL ASSISTANCE PROGRAM (EVTAP),CUMULATIVE PROGRESS REPORT (NOVEMBER 2019 - JULY 2022).......................36
FIGURE 27:SCHEDULE OF CPAU WORKSHOPS AND EVENTS, MAY - JULY 2022.........................................................................................37
FIGURE 28:STATUS TO DATE OF ALL APPLICATIONS TO THE PROGRAM FOR EMERGING TECHNOLOGIES............................................................40
FIGURE 29:ELECTRIC RESOURCE ADEQUACY CONTRACTS .......................................................................................................................45
FIGURE 30:ELECTRIC LOAD RESOURCE BALANCE, APRIL 2022 - MARCH 2025..........................................................................................46
FIGURE 31:UTILITIES VACANCIES AND POSITION MOVEMENTS BY DIVISION,UP TO Q3 FY 2022 ..................................................................47
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4Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
1 Electric Utility
The City’s electric utility serves all residential and non-residential gas demands in Palo Alto at a lower cost than
PG&E in surrounding communities. Its electric supply portfolio is 100% carbon neutral. The City maintains and
operates an electric distribution system and one small natural gas generator but does not operate any
transmission lines or any significant generating capacity on its own. Instead, the City belongs to Northern
California Power Agency (NCPA) which operates its Calaveras hydroelectric generating plant and provides power
scheduling services for its other generating resources. This carbon free power is supplied through power purchase
agreements with various generation operators.
1.1 Electricity Supply and Transmission
Below is an update on electricity supply and transmission services.
1.1.1 Forecasted Supply Costs (Jim Stack)
The actual net supply cost for FY 2022 was $95.2 M. This represents a $11.9 M (14%) increase over FY 2021 actuals
and $17.3 M (22%)over the FY 2022 Adopted Budget amount, with the increase primarily driven by higher than
historical forward energy prices, higher resource adequacy requirement levels and market prices, and much lower
than historical average hydro generation levels.
The projected net supply cost for FY 2023 is $94.9 M, which is $9.7 M (11%) greater than the Adopted Budget
amount, but $0.3 M lower than the actual net supply cost for FY 2022. This increase in cost relative to the Adopted
Budget is due to the same factors noted above that explain the deviation in supply cost for FY 2022.
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5Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 1: FY 2022 Financial Plan Supply Cost Forecast vs. Actuals
1.1.2 Hydroelectric Conditions (Jim Stack)
The City takes power from two hydroelectric projects, the Calaveras project and the Western Base Resource
contract for Federal hydropower from the Central Valley Project.1 The watershed for Western hydropower is
primarily in the northern end of California, while the watershed for the Calaveras project is in the Central Sierras.
For water year 2020 to 2021 (October 2020 to September 2021), total precipitation was just below 50% of average
in both watersheds. For water year 2021 to 2022, total precipitation was 63% of average for the Central Sierras
watershed and 81% of average for the Northern Sierras watershed. Total actual hydropower for FY 2021 was 295
GWh, which is 183 GWh (38%) below the long-term average.Total actual hydropower for FY 2022 was 230 GWh,
which is 250 GWh (52%) below the long-term average.2 The current forecast for FY 2023 assumes a small recovery
in generation from FY 2022, but is still only projected to provide 56% of generation compared to the long-term
average.
1 The Calaveras project is a hydropower project located in Calaveras County that is maintained and operated by the Northern
California Power Agency on behalf of the City and other project participants. The City is also one of several public entities
with contracts with the Western Area Power Administration for “Base Resource” electricity, which is the hydroelectric power
available from the Federal Government’s Central Valley Project (operated by the Bureau of Reclamation) after accounting for
power used for Central Valley Project operations and power delivered to certain “preference” customers.
2The long-term average forecast levels for both Western and Calaveras have been revised downward (about 10% each) in
recent years to reflect the impact of climate change. These values may need to be revisited again in the coming years.
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$12,000
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Electric Supply Budget vs Actuals
$120,000
$100,000
$80,000
$60,000
$40,000
$20,000
$-
Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Jan-22 Feb-22 Mar-22 Apr-22 May-22 Jun-22
-Budget Forecast -Actuals/Projected -cumulative Budget Forecast Cumulative Actuals/Projection
"' "C
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6Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 2: Hydro Generation FY 2021-22 Actuals, FY 2023 Projected (GWh)
1.1.3 REC Exchange Program (Jim Stack & Eric Wong)
Under the REC Exchange Program, which was approved by Council in August 2020 (Staff Report #11556), staff has
so far contracted to sell a total of 184 GWh worth of in-state renewable energy (for $2.77M), and purchased 400
GWh worth of out-of-state renewable energy credits (RECs) costing $2.03M in CY 2022. The overall net revenue
(estimated at $0.74M) for CY 2022 will be directed entirely towards the funding of local decarbonization efforts.
Net revenue for the REC Exchange program is projected to be around the same in 2023 than 2022, which were
both significantly lower than previous years due to several factors: (a) the poor hydro outlook, which will lead to
large out-of-state REC purchase volumes, and (b) a narrowing of the in-state versus out-of-state REC price spread.
1.1.4 Renewable Energy Procurement (Jim Stack)
As discussed in Staff Report #14908 (Packet Pg. 74), staff is currently pursuing an opportunity to enter into a 12-
year agreement to procure 10 MW of output from the Calpine Geothermal project, as part of a larger purchase
with other Northern California Power Agency (NCPA) members. Staff is also exploring a sale of some energy during
Q2 and Q3 from one or more of the City’s long-term solar contracts. These combined transactions would more
closely balance the City’s loads and resources on a daily/monthly basis to better hedge market energy price shifts
in the long-term while maintaining the portfolio’s annual energy position close to current levels. Staff plans to
return to the UAC in the coming months to seek a recommendation to take these agreements to the City Council
for approval.
1.2 Capital Improvement Plan Status (Patrick Valath)
The following capital projects are currently in progress or have been recently completed:
EL-17001 (East Meadow Circles 4/12kV Conversion):This project is scheduled to be completed in several
phases. Phase 1 design is complete and released for construction. Phase 2 & 3 (of 6) engineering design is
currently in progress.
EL-11003 (Rebuild Underground 15):This project is in the preliminary stages of engineering design.Project is
delayed due to staffing shortage. This project has been put on hold due to other priorities.
EL-10006 (Rebuild Underground 24):This project is in construction phase and scheduled to be completed in
2022.
EL-16000 (Rebuild Underground 26):This project is in the design phase and to be completed in multiple
phases. First design phase is scheduled to be completed in 2022.
EL-19004 (Wood Pole Replacement):This project is in the design phase with expected completion in
September 2022 and construction starting 2023. The project is delayed this year because of staffing
shortages.CPAU has a contract consultant to work on the design phase of this project.
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FY.2021
Ca I av,e rr as. Actu a l.s/F orr,eca st (GW h) 49
W-e st e n1 Actuals/Fa recast (GWh ) 246
lota l yd ro Forecast (GWh ) 295
OL ~I" I ,... ...,, i""l'I" +r-'1, .... 1,"'V,'T,j ;a, 11 • .rr. !r.:""l n'r-'lo -,-...... +~ ~ t:::1 'L.
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7Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
EL-16003 (Substation Physical Security): This project is scheduled to be completed in several phases.
Substation Security lighting contract was awarded in June 2022. The installation will be completed over a 2-
year period.
EL-17002 (Substation 60kV Breaker Replacement):Currently working on solicitation to procure a contractor
for the next phases.
EL-21001 (Foothills Rebuild):This project will rebuild the approximately 11 miles of overhead line in Foothills
Park, as necessary to mitigate the possibility of wildfire due to overhead electric lines. Staff has completed
7,000 feet of substructure work and design to eliminate the corresponding 26 poles and install new
underground equipment will be completed by June 2022. Staff has started the design for next phase of the
substructure work. Construction is expected to start in July 2022 for the next phase.
EL-14005 (Reconfigure Quarry Feeders):Staff completed the design phase this year. Construction has been
delayed due to shortage of staff.
EL-02011 (Electric Utility Geographic Information System (GIS)):The project scope includes
maintenance/technical support of the existing GIS system and implementation of the new GIS platform (ESRI).
Staff has completed the ESRI ArcGIS Portal, which is a web service for staff to view data and are currently
working on final phase of the electric data migration to ESRI’s Utility Network model.
EL-16002 (Capacitor Bank Installation): This project is a multi-year effort for the procurement, design and
installation of capacitor banks at several substation. Hanson Way and Park Blvd substation work is complete;
Two capacitor banks at Hanover remain to be completed and will be completed in 2022.The capacitor banks
at Maybell have been installed and will be commissioned in the coming months.
1.3 Rate and Bill Comparisons (Eric Keniston)
For the median consumption level, the annual residential electric bill for FY 2022 was $744, about 45% lower than
the annual bill for a PG&E customer with the same consumption and approximately 16% higher than the annual
bill for a City of Santa Clara customer. The bill calculations for PG&E customers are based on PG&E Climate Zone
X, which includes most surrounding comparison communities.
The figure below presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara (Silicon
Valley Power) for several usage levels. Rates used to calculate the monthly bills shown below were in effect as of
November 1, 2022. The rates for Palo Alto include the current Hydro Rate Adjuster of $0.013/kWh.
Over the next several years low usage customers in PG&E territory are expected to continue to see higher
percentage rate increases than high usage customers as PG&E compresses its tiers from the highly exaggerated
levels that have been in place since the energy crisis. This is likely to make the bill for the median Palo Alto
consumer look even more favorable compared to most PG&E customers. Even with the compressed tiers, bills for
high usage Palo Alto consumers are projected to remain substantially lower than the bills for high usage PG&E
customers.
Figure 3: Residential Monthly Electric Bill Comparison (Effective 11/1/2022, $/mo.)
Season Usage (kwh)Palo Alto PG&E Santa Clara
Winter
300 47.24 95.26 39.22
(Median)453 78.57 155.65 59.95
650 121.19 233.40 86.65
1200 240.18 452.61 161.17
Summer 300 47.24 95.03 39.22
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8Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
(Median) 365 59.53 120.68 48.03
650 121.19 233.16 86.65
1200 240.18 454.03 161.17
1.4 Reliability (Kenneth Swain)
CPAU tracks electric outages. A summary chart of these outages can be found below.
Figure 4: Electric Outage Reliability, FY 2023-Q1
Outage Reliability Q1
System Average Interruption Duration Index (SAIDA)81.69
System Average Interruption Frequency Index (SAIFI)0.61
Customer Average Interruption Duration Index (CAIDI)134.77
1.5 Financial Health
Below is a summary of the financial position for the electric utility.
1.5.1 Sales Forecasts vs. Actuals (Eric Wong)
Electric actual sales volumes through Q1 of FY 2023 were about 4% lower than forecasted, while actual sales
revenues were about 7% higher than budgeted in the FY 2023 Financial Plan. The higher sales revenues were due
to extra revenue from the Electric hydro rate adjuster, which was implemented on April 1, 2022. The commercial
sector continues to be impacted from the Covid downturn in Q1 of FY 2023, and it is uncertain when commercial
sales will recover.
Figure 5: Electric Sales Volume (kWh), up to FY 2023-Q1
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FY 2023 Budget Actual Variancf: Variance%
Jul 70,843,075 67,532,107 -3 ,310,968 -4.7%
Aug 72,647 ,339 68,060,0 5 8 -4,587,281. -6-3%
60 /I Sep 73,040,074 73,386,421 346,347 0.5%
Oct 68,469 ,891
No v 70,512,009
Dec 67,009,286
Jan 70,935 ,370
Fe b 66,143 ,772
Mar 6 ,173,286
0 /I 7 Jul -Aug Seµ Oct Nov Dec Jan Feb Mar Apr May Jun
Apr 62,524,419
May 57,946 ,331.
■ Electric, Acrnal Electr i c, Budg e: Jun 63,400 ,963
9Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 6: Electric Sales Revenue ($), up to FY 2023-Q1
1.5.2 Financial Position (Eric Keniston)
The Electric Operations Reserves were at the minimum guideline level at the end of FY 2022 and may drop below
minimum in FY 2023, depending on ongoing increases to purchase costs created by low hydro conditions
(necessitating more expensive market purchases) as well as increasing transmission costs. City Council activated
the Hydro Rate Adjuster in April 2022 to help mitigate these rising costs, but staff is currently proposing to Council
a further increase to the Hydro Adjuster (from $0.013 to 0.048/kWh effective January 1, 2023) to help keep
reserves above minimum in FY 2023.
Through the first quarter of FY 2023, sales and revenues have tracked reasonably well compared to budget, but
ongoing purchase cost increases continue to put pressure on reserves. Overall sales continue to be at levels seen
during the height of COVID, with sales to the commercial sector not recovering appreciably as COVID restrictions
have eased. This lower sales profile, along with projected new capital projects for electrification, may put
additional pressure on FY 2024 rates and beyond.Staff will provide preliminary financial forecast projections in
January 2023.
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FY:Z02~ Buc1get Acrual Variance Varlance%1
- -
Jul
_5M
13,513 ,230 14,355,879 842,649 6.21l
Aug 14,158 ,194 14,807 ,187 648 ,993 4.6%
Sep 14,441,943 15,928,532 1 ,486,589 10.3%
Vl 10M Oct 13,625,567
Ill Nov 13,352,666 !....
ro
o Dec 9,853,529
0
5M Jan 10,31.1 ,382
Feb 9 ,534,373
Mar 9 ,385,476
OM Apr 9 ,031,965
Dec Jan f,20 Mar .J:'' Mc')' Jun May 8 ,856,182
■ Electric, Ac ual Elect ric, Budge J un 12,309,221
10Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
2 Gas Utility
The City’s gas utility serves all residential and non-residential gas demand in Palo Alto. The City maintains and
operates a system of low-pressure gas lines for delivering gas but does not operate any transmission lines. Costs
for the gas utility are split approximately two thirds for the operation, maintenance and one third for the cost of
the gas commodity,PG&E gas transmission, compliance with the State’s Cap and Trade Program and the City’s
Carbon Neutral Gas Program.
2.1 Gas Supply and Transmission (Eric Wong)
Gas Commodity prices were relatively high in latter half of FY 2022 and the first half of FY 2023. A combination of
flat U.S. natural gas production, below-average U.S. natural gas storage levels, high US liquefied natural gas
exports, inflation, supply chain issues, and global geopolitical events have put upward pressure on prices for U.S.
natural gas. Prices are expected to stay around $0.6/therm to $0.8/therm throughout the winter season. The
communications team published an article in our City website and posted in various social media platforms to
inform customers about high gas prices, potential ways to conserve gas usage and encouraged home
electrification.
Figure 7: Gas Supply Commodity Rates ($/Therm), FY 2018-23
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I . . .... "" .. I ........ • .. I . ' " .... . • • • I • I • • • • I • • • • • • •
FY 2018 FY _ozo FY 20Z _ FY 202L FY _023
11Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
2.1.1 Actual and Forecasted Supply Costs (Eric Wong)
Gas actual demand through Q1 of FY 2023 were about 14% higher than forecasted, while actual supply and
transportation costs were about 84% higher than budgeted in the FY 2023 Financial Plan. Gas commodity prices
were much higher than predicted in the FY 2023 financial plan due to reasons mentioned in section 2.1 above.
Figure 8: Gas Supply Costs ($), Actual vs Budget, up to FY 2023-Q1
2.1.2 Carbon Neutral Gas Program (Micah Babbitt)
In December 2020, Council adopted Resolution #9930 maintaining the Carbon Neutral Natural Gas Plan to achieve
carbon neutrality for the gas supply portfolio using high-quality carbon offsets with a cost cap of $19 per ton CO2e.
Offsets are purchased to neutralize emissions equal to those caused by natural gas usage in Palo Alto. Staff
purchased 60,000 carbon offsets for FY 2022 in January 2022 from a mixture of forestry and livestock projects at
an average purchase price of $12.26 per metric ton, nearly double the price of historical average transaction
prices. Staff purchased an additional 60,000 carbon offsets in June 2022 at an average price of $14.51 per ton
CO2e. As a result of the higher offset purchase costs, staff has updated the billing charge for offsets from
$0.04/therm to $0.07/therm. The average purchase price of offsets purchased for the program is $7.66 per ton
CO2e. The figure below shows the composition of offset purchases.Staff is evaluating a process change to expedite
the approval of new Verified Emission Reduction (carbon offset) counterparties and depending on the timing of
this change, will carry out its next offsets purchase in December 2022 or in the beginning of 2023.
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FY2023
■ Bu dget
Commodity
JUI Aug Sep Oa: Nov Dec Jan Fet> Mar Apr May Jun
JUI
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Budget Actual Var ia nce Variance%
667 541 1,039,946 372,40'1 55.B"A
659 dQ9 l,332,201 672 791 102.<n
696 97.;: 1 ,348,782 651,810 93 S<·o
949,560
l,581,034
2 ,387,025
2 ,638,627
2,036,749
1,712,571
1,051,643
a..2,9;:_o
63-236
12Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 9: Offset Portfolio Composition
The following table provides a description of the projects.
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Offsets Purchased by Project Type
■ Livestock
■ Mexican Forest
■ Mine Methane Capture
■ Ozone Depleting Substance
■ U.S. Forest
■ AgMethane
■ Carbon Sequestration
13Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 10: Offset Project Descriptions
2.1.3 Cap and Trade Program (Eric Keniston)
The gas utility has been regulated under California’s greenhouse house (GHG) regulations since January 2015 with
a GHG emissions cap that declines over time. The gas utility receives carbon allowances equal to the emissions
allowed under the cap and is required to auction off a portion of the allowances (55% in 2022, increasing by 5%
annually) through the state Cap and Trade Program. To meet its annual GHG compliance obligation, the City must
purchase allowances based on actual gas use.
The auction floor price to either purchase or sell allowances increases annually by 5% plus inflation. Historically,
allowances have traded at or near the floor price, but the clearing prices for allowances in the auction have
increased significantly. The cost of compliance is anticipated to increase from $1.5 million in FY 2022 to $5.6
million in FY 2030, about an 18% increase per year on average, as shown in the following table:
Project Name Project Type Description
Grotegut Dairy Livestock Grotegut Dairy is a 3,900 milk-cow operation in Newton, Wisconsin with a methane capture system.
Green Trees U.S. Forest
GreenTrees Advanced Carbon Restored Ecosystem is reforestation of agricultural lands into native
hardwood forest in Mississippi, Louisiana, Arkansas, and Illinois
San Juan Lachao Mexican Forest
Protection of forests located in High Biological Value Zones which contain flora and fauna listed in the
Mexican Endangered Species List and the International Union for Conservation of Nature’s Red List of
Threatened Species. Project in San juan Lachao near Palo Alto's Sister City of Oaxaca.
Blandin Forest U.S. Forest Blandin Native American Hardwoods Conservation and Carbon Sequestration project in Minnesota.
Pocosin+U.S. Forest
These projects are all forested land that will not be disturbed by human development. Without this
protection, the forests would be converted to grow wheat or corn. Forest conservation plays a vital
role in protecting freshwater systems like lakes. The forests around the lakes act as natural water
filters and purify the water for all who use it. The projects also support healthy populations of red
wolf, bald eagle, black bear,and various bird species.
Refex ODS Ozone Depleting Substance
The RemTec facility in Bowling Green, Ohio uses an argon arc plasma destruction device to achieve
99.99 percent removal. The majority of refrigerants originated in California,and all were sourced
within the United States.
The RemTec facility uses an argon arc plasma destruction device to achieve the required destruction
and removal efficiency of 99.99 percent. The majority of ODS refrigerants originated in California, and
all were sourced within the United States.
Methane Capture Mine Methane Capture
This project is the first of its kind. Peabody Natural Gas, LLC removed methane from the North
Antelope Rochelle Coal Mine before mining. The methane was compressed and transported to a
natural gas pipeline and distributed to a national gas grid for use as fuel. Before implementation of
the project, all the methane was vented to the atmosphere.
Virginia
Conservation
Forestry Program U.S. Forest
The Virginia Conservation Forestry Program - Clifton Farm and Rich Mountain is a 9000+ acre
improved forest management project in which the timber and carbon ownership and
management rights have been transferred to The Nature Conservancy's Conservation Forestry
Program. The program manages for multiple goals to include:Water quality protection,
habitat diversity, high value forest products, and carbon sequestration.
Co-benefits: Biodiversity, Watershed Protection, Climate Resilience, and Connectivity
Riverview Farm
Anaerobic Digester Livestock
Riverview is a carbon offset project generating emission reductions thought the capture and
destruction of methane at a dairy farm in Minnesota. Under the baseline, manure managed in open
lagoons led to the fugitive emission of methane to the atmosphere. In the project scenario, this
methane is captured by an anaerobic digester and destroyed on site in the production of electricity.
Co-benefits include job creation and the improvement of local air and water quality.
Big River / Salmon
Creek Forests IFM U.S. Forest
The Big River and Salmon Creek Forests are located in Mendocino County, CA and cover 16,000 acres
of redwood and Douglas-fir forest. This project is a conservation-based forest management project.
Co-benefits include the creation of 140 jobs, protection of 37 miles of streams, and improved water
quality for local fish and bird species.
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14Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 11: Estimated Cap and Trade Costs
Revenues from the auction sale of gas utility allowances (currently about $1.2 million per year) must be used
exclusively for the benefit of the ratepayers in that utility in accordance with California Code of Regulations (CCR
Title 17, section 95893). Approved uses are 1) the funding of certain energy efficiency rebates, retrofits, and
demand reduction programs, 2) funding for programs with demonstrated GHG reductions, 3) non-volumetric
return to ratepayers, either on or off bill, and 4) certain administrative, outreach and educational costs related to
items 1-3 above. Council adopted a policy on the use of allowance proceeds (Resolution #9487), generally
mirroring the regulations and requiring additional Council approval for rebates. Per the current regulations, the
utility must either spend or rebate the funds received in any given year within 10 years (for example, funds
received in 2020 must be spent by 2030, etc.).
As of the end of FY 2021, unspent funds related to Cap and Trade revenues were placed in a Cap and Trade reserve,
until such time as they can be utilized per the dictates of applicable regulations. There was $6.7 million in this
reserve available for use at the end of FY 2022.
2.1.4 Gas Transmission Line Capacity Valuation (Eric Wong)
Palo Alto contracts for capacity on the Redwood pipeline, the path from the California-Oregon border to PG&E’s
mid-pressure transmission system, at a cost lower than the market value. During the summer months, Palo Alto
does not need all of the capacity to serve demand. The excess capacity is monetized by purchasing gas at the
California-Oregon border and selling an equal amount of gas at the terminus of the pipeline. The variable cost of
transporting the gas is much less than the gas price difference between the two points. The net benefit to the Gas
Utility through Q1 of FY 2023 was $169K, or a reduction of about 6.2% of the total gas commodity costs.
2.1.5 Gas Prepay Valuation (Eric Wong)
On September 15, 2014, Council adopted Resolution #9451 authorizing the City’s participation in a natural gas
purchase from Municipal Gas Acquisition and Supply Corporation (MuniGas) for the City’s entire retail gas load
for a period of at least 10 years. The MuniGas transaction includes a mechanism for municipal utilities to utilize
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15Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
their tax-exempt status to achieve a discount on the market price of gas. The program has reduced about $113K,
or 4.2% of the total gas commodity costs through Q1 of FY 2023.
2.2 Capital Improvement Plan Status (Silvia Santos)
The following capital projects are currently in progress:
GS-14003 - GMR 24A (Gas Main Replacement 24A): This project will replace approximately 2,450 linear feet
of gas main along Shopping Center Way and Orchard Lane in Stanford Shopping Center. The City coordinated
the schedule with Simon Property Group Inc. (shopping center’s management) for construction work to occur
between 6 AM and 3 PM from 1/2/23 to 3/31/23.
GS-14003 - GMR 24B (Gas Main Replacement 24B): This project will include gas pipes on University from
Webster to 101 and surrounding streets, as well as Geng Rd and Town & Country Village. Staff is waiting for
the federal grant application status which will be available in February 2023.
2.3 Rate and Bill Comparisons (Eric Keniston)
The figure below presents residential bills for Palo Alto and PG&E customers at several usage levels for commodity
rates in effect as of a November 2022 (a recent winter period) and October 2022 (a recent summer period). The
bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which includes the surrounding
communities of Menlo Park, Redwood City, Mountain View, Los Altos and Santa Clara. The annual gas bill for the
median residential customer for FY 2022 was $689, about 11% lower than the annual bill for a PG&E customer
with the same consumption. PG&E’s distribution rates for gas have increased substantially to collect for system
improvements for pipeline safety and maintenance.
Figure 12: Residential Natural Gas Bill Comparison ($/month)
Season
Usage
(therms)Palo Alto PG&E Zone X
% Difference
Winter
(November 2022)
30 $ 59.45 $ 72.13 -17.6%
(Median) 54 97.77 134.32 -27.25%
80 156.76 208.99 -25.0%
150 329.66 410.05 -19.6%
Summer
(October 2022)
10 27.65 23.64 16.9%
(Median) 18 40.54 43.87 -7.6%
30 68.02 77.86 -12.6%
45 105.29 120.35 -12.5%
2.4 Reliability (Melissa Smart)
The City of Palo Alto tracks all gas service interruptions. A summary chart of these interruptions can be found
below. Gas service interruptions are usually due to repairs of broken or damaged gas services and mains. This kind
of damage is often caused by excavation by outside parties digging in the City.
Figure 13: Gas Service Interruptions, FY 2023
Gas Q1
Number of Breaks 9
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16Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Total Minutes 643
Customers Affected 20
2.5 Financial Health
Below is a summary of the financial position for the gas utility.
2.5.1 Sales Forecasts vs. Actuals (Eric Wong)
Actual sales volume for Q1 of FY 2023 were about 5% lower than forecasted in the FY 2023 Financial Plan. But
actual sales revenue was about 35% higher than forecasted due to high gas market commodity prices. Much of
the revenue is pass-through in nature and offsets commensurately higher gas commodity purchase costs.
Figure 14: Gas Sales Volume (Therms), up to FY 2023-Q1
Figure 15: Gas Sales Revenue ($), up to FY 2023-Q1
2.5.2 Financial Position (Eric Keniston)
FY 2022 ending Operations Reserves were $11.1 million, and above the minimum reserve level of $7.8 million.
Through FY 2023Q1, therm sales were slightly lower than budget by about 5%, but sales revenues were almost
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FY 2023 Burlget Actual Variarice Variance% ------
4M Jul 1,312,955 1,262,859 -50,096 -3.8%
3M I
Aug 1,273,05 6 1,250 ,771 -22,285 -1.8%
Sep 1,372,999 1,239,006 -133,993 -9 .8%
Oct 1,577,927
"' E 2M w Nov 2 ,140,219
L De c 3,153 ,5 98 f-
Jan 3,830 ,945
lM I Fe b 3 ,575 ,685
M ar 2 ,770,018
OM Apr 2,56(),158
I Jul Aug Sep Oct Nov Dec Jan Fs:b Mar Apr May Jun Ma y 1,670,754
■ Gas , Actual Gas , Budget J un 1,162,461
P, 2023 Bud[.et Actual Variance Variance%
5M Jul 2 ,1 58 ,795 2,880,043 721,24tl 33.4%
Aug 2 ,142,170 2 ,7 87,1 92 645,022 30.1%
Sep 2 ,136,412 2,993,352 856,940 40.1%
~-4M Oct 2,420,904
"' Nov 3,371,129 .L
n,
0 Dec 5 ,123,807
0
2M I Jan 6,241,688
I Fe b 5,195,946
M ar 4,753 , 58
OM
Aug Ser Oct Nov Dec Jan F~b Mar A~r May Jun I Apr 4,296,964
I JJ May 2,984,368
■ Gas , Actual Gas ,Budg et Jun 2 ,644,552
17Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
35% higher than budget. Because the gas commodity charge is a pass-through of market costs, increased revenue
offsets the increased cost.
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18Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
3 Water Utility
The Water Utility serves water to virtually all Palo Alto residential and non-residential customers.All potable water
in the City is from the San Francisco Public Utilities Commission (SFPUC) Hetch Hetchy Water System. This system
delivers high quality water from the Sierra Nevada and uses no pumping to deliver water to Palo Alto. Palo Alto
uses a small amount of recycled water for irrigation of the Municipal Golf Course and a few other sites near the
Regional Water Quality Control Plant. The City also maintains a system of reservoirs and wells that enable Palo
Alto to serve water during an interruption of the Hetch Hetchy system. Costs for the Water Utility are split
approximately half for the operation, maintenance and periodic replacement of Palo Alto’s water system and half
for the costs of the water purchased.
3.1 Water Supply and Transmission (Lisa Bilir)
On November 10, 2022, Governor Newsom’s senior Water-Policy Officials, the San Francisco Public Utilities
Commission (SFPUC), and the Modesto and Turlock Irrigation Districts reached agreement on a Memorandum of
Understanding to provide greater water flows and increased habitat for the Tuolumne River. The Bay Area Water
Supply and Conservation Agency (BAWSCA) anticipates that this MOU will become a part of a larger voluntary
agreement for the Sacramento-San Joaquin Delta. The agreement includes investments of $64M for habitat
restoration. The next step is for the MOU signatories and others to work out the implementation details of a Bay-
Delta wide voluntary agreement for evaluation by the State Water Resources Control Board as an alternative to
the adopted Bay-Delta Plan.
In August, 2018, Palo Alto’s City Council voted to support the State Water Resources Control Board’s Bay-Delta
Plan to have 40 percent of natural water in the Central Valley to enter the Delta from February to June and
associated Southern Delta salinity objectives; and send a letter expressing this policy position to BAWSCA,
California State Water Resources Control Board, San Francisco Public Utilities Commission (SFPUC), and other
stakeholders.
Storage in the San Francisco Regional Water System is below normal while in better shape than many reservoirs
across California. As of October 31, 2022, the Regional Water System total storage operated by the San Francisco
Public Utilities Commission (SFPUC) was 64.8% full (normal system storage for this time of year is 79.7%). As of
October 31, 2022, Water Bank was 45% full while normal for this time of year would be nearly full.In the figure
below, the solid black line shows storage in the Regional Water System for the past 12 months (color bands show
contributions to total system storage) and the dashed black line shows total system storage for the previous 12
months. Regional Water System Storage remained fairly steady through September, 2022, but did not pick up in
October of 2022 as it did during October 2021 when there was significant precipitation.
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19Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 16: Regional Water System Storage
On August 20, 2021 the SFPUC received curtailment orders for Tuolumne River diversions. The curtailments
eliminate access to the Water Bank which, as shown in the figure above, provides much of the system storage.
From October 2021 through May 2022, the State Board suspended the curtailments and reinstated them on June
8, 2022.
The SFPUC declared a local water shortage emergency by Resolution No. 21-0177 on November 23, 2021 calling
for voluntary systemwide 10% water use reductions from FY 2019-2020 levels and increased the systemwide
water use reduction to a voluntary systemwide 11%from FY 2019-2020 levels on May 24, 2022 via adoption of
Resolution No. 22-0098. SFPUC’s increased the systemwide water use reduction in compliance with the State
Water Resource Control Board’s May 24, 2022 emergency regulation requiring urban water suppliers to
implement the demand reduction actions associated with water shortage level of 10% to 20% by June 10, 2022.
Each Wholesale Customer has its own requested cutback level; Palo Alto’s voluntary water purchase cutback level
is 8%.For January – November , 2022, Palo Alto’s cumulative monthly water budgets were 4,101,982 CCF while
actual total purchases were approximately 4,338,211 CCF or 6% above the budget. This is in part because of the
exceptionally dry conditions in January through March 2022. However, for the billing months July 2022 through
October 2022, compared with the same period from July 2019 to November 2022 , the Palo Alto community
reduced water usage by 10%%.
On May 24, 2022, SFPUC adopted Resolution No. 22-0098 adopting a systemwide voluntary water use reduction
of 11% compared to baseline water use during FY 2019-2020. Palo Alto’s voluntary water purchase cutback level
remains at approximately 8%. SFPUC’s cutbacks are currently voluntary, however they could become mandatory
in early 2023 if dry conditions continue. Under mandatory water cutbacks, SFPUC may impose excess use charges
for water purchases above Palo Alto’s water budget.
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-Total St orage Dec 1 2021 to Nov 1 2022
- -Total St orage Dec 1 2020 to Nov 1 2021
Loca l Reservoirs
Cherry Reservoir+ Lake Eleanor
Hetch Hetchy Reservoir
Water Bank o~=================~-------------.....1
Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
20Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
During drought that require up to 20% cutbacks, water is allocated between San Francisco and the Wholesale
Customers collectively based upon the Water Shortage Allocation Plan (or Tier One Plan)that is outlined in Palo
Alto’s water supply contract with San Francisco. The collective Wholesale Customer share from the Tier One Plan
is then allocated among Wholesale Customers based upon a formula in a negotiated and adopted “Tier Two Plan.”
Palo Alto’s current water budget is based upon the results of the current Tier One and Tier Two Plans. In 2022,
staff have been participating in a negotiation with the other Wholesale Customers to update the Tier Two Plan.
Staff expects to finalize the updated Tier Two Plan in 2023.
The figure below shows water usage for the South Bay/East Bay (including Palo Alto)compared to several
benchmarks including 2019. For the South Bay/East Bay region as well as systemwide, summertime peak demand
so far has been shaved off below demand levels for each of the past three years.
Figure 17: SFPUC Water Deliveries
Valley Water, the groundwater manager in Santa Clara county, declared a water shortage emergency and
adopted a 15% mandatory water use reduction for water retailers its agency serves. Valley Water called for the
County, water retailers and cities to restrict ornamental landscape and lawn irrigation with potable water within
their service or jurisdictional areas to no more than two days per week. Although Palo Alto purchases all of its
potable water from SFPUC, and does not purchase any water from Valley Water, Palo Alto partners with Valley
Water on wide variety of water conservation programs. On June 20, 2022, the Palo Alto City Council restricted
potable irrigation of ornamental landscapes and lawns to 2 days per week, except to ensure the health of trees
and other perennial non-turf plantings.The State Water Resources Control Board also prohibited the use of
potable water for the irrigation of “non-functional turf” at commercial, industrial, and institutional sites other
than to the extent necessary to ensure the health of trees and other perennial non-turf plantings.
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S F PUC Regian<311 Water Sys1ern -M€tec DelNe.ries
Sooth Ba)"East Bat Cu stomers
Source:: SFPUC Regional Wate r System County Me-'.ers
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21Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
The Palo Alto City Council also implemented the water use restrictions in Stage II of the Water Shortage
Contingency Plan which are 1) restaurants and other food service operations shall serve water to customers
only upon request and 2) operators of hotels and motels shall provide guests with the option of choosing not to
have towels and linens laundered daily. Palo Alto is working with Valley Water on messaging to customers in the
county to avoid confusion as much as possible. As such, the wise use of water rather than specific targets will
continue to be emphasized.Palo Alto staff is continuing to focus on education and outreach and providing
resources to eliminate water waste and achieve efficient water use and completed the process of hiring a Water
Waste Coordinator in October. The Water Waste Coordinator is logging and following-up on water waste
reports.Palo Alto is kicking off the WaterSmart Customer Portal and Residential Home Water Report Program
and also re-engaging with Waterfluence software to target water efficiency for large landscape customers. We
continue to promote rebate programs and resources through online outreach, bill inserts, and newsletters.
Palo Alto launched the One Water Plan with the goal of Council adoption of a One Water supply plan that is a
20-year adaptable roadmap for implementation of water supply and conservation portfolio alternatives. In June
the City Council approved a contract for this work with Carollo Engineers,Inc.In September, staff conducted
stakeholder engagement meetings with community members and city staff focusing on One Water community
needs and priorities.Additional stakeholder engagement meetings are planned with city staff, community
members, and regional partners in early December to discuss water supply and conservation options and review
draft evaluation criteria for the One Water Plan.
3.2 Capital Improvement Plan Status (Silvia Santos)
The following capital projects are currently in progress:
WS-14001 - WMR 28 (Water Main Replacement 28): The project is to replace approximately 18,763 linear
feet of water main and 256 water services in the Crescent Park, Barron Park, and Charleston Meadows
neighborhoods. Construction of this project started during April 2022 and the anticipated completion date is
in November 2023.
WS-07000 – California Avenue and Page Mill Road Turnouts: This project includes work to upgrade California
Avenue Turnout and to restrain the pressure reducing valve at Page Mill Road Turnout. The construction is
anticipated to start in March 2023 and be completed by June 2023 (before water demand increases during
the summer).
3.3 Rate and Bill Comparisons (Lisa Bilir)
The figure below shows the water bills for single-family residential customers compared to what they would be
under surrounding communities’ rate schedules as of October 2022. CPAU is among the highest monthly bills of
the group. Palo Alto’s water bills at 9 CCF per month are 17% higher than the comparison group average.
Figure 18: Residential Water Bill Comparison ($/month)
As of October 2022
Usage CCF/month Palo Alto Menlo Park
Redwood
City
Mountain
View Santa Clara Hayward
4 $50.74 62.83 $54.04 $43.47 $29.32 $41.03
(Winter median) 7 76.54 87.32 76.09 67.29 51.31 63.23
(Annual median) 9 98.46 103.65 90.79 83.17 65.97 78.03
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22Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
(Summer median) 14 153.26 148.02 138.94 122.87 102.62 123.48
25 273.82 257.41 267.39 257.81 183.25 223.47
3.4 Reliability (Melissa Smart)
The City of Palo Alto tracks all water service interruptions. A summary chart of these interruptions can be found
below. Water service interruptions are usually due to repairs of broken or damaged water services and mains.
Figure 19: Water Service Interruptions, FY 2023
Water Q1
Number of Breaks 10
Combined Minutes 1007
Customers Affected 46
3.5 Financial Health
Below is a summary of the financial position for the water utility.
3.5.1 Sales Forecasts vs. Actuals (Eric Wong)
Actual water sales volumes through Q1 of FY 2023 were about 10% lower than forecasted in the FY 2023 financial
plan. Actual water sales revenues were about 13% lower than forecasted during the same period. Despite the dry
weather conditions, substantial water conservations were made by the Palo Alto community during Q1 of FY 2023.
Staff will continue to promote drought-related and water savings communication through the rest of the FY 2023.
Figure 20: Water Sales Volume (CCF), up to FY 2023-Q1
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P 202~ Budget Actua-1 Variance Vanance %
Jul
500
525,621 449 ,495 -76,126 -14.5 %
Au g 490,256 449 ,6.99 -40,557 -8 .3%
Sep 479,29 454,552 -24,739 -5 zq
Oct 454,425
lL Nov 354.487 u u
Dec 275,706
Ja11 237,777
00 Feb 232.409
M ar 288,269
0 Apr 268,185
May 382,762
■ Wai.er, Aa:ual Wa:er, Budget Jun 424,508
23Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 21: Water Sales Revenue ($), up to FY 2023-Q1
3.5.2 Financial Position (Lisa Bilir)
The Water Operations Reserve was filled to the maximum guideline level at the end of FY 2022 as higher bid costs
and delays in project schedules resulted in deferred main replacement projects over the past few years. There are
additional funds in the Operations Reserve above the maximum guideline level that will continue to be used to
cover water utility operational and capital costs in FY 2023. At year end FY 2022 there was approximately $12.2
million in Water CIP Reappropriations and Commitments reserves. The FY 2023 Water Utility CIP includes a main
replacement (WMR 28) as well as one-time seismic reservoir upgrades (one upgrade is complete and a second
and third are planned in FY 2023 and FY 2026). At year end FY 2022, there was also $10.7 million in the CIP Reserve
and $9.07 million in the Rate Stabilization Reserve. Staff’s preliminary projection of expected revenues and
expenses together with transfers from the CIP Reserve,estimates the Operations Reserve will reach approximately
target levels by the end of FY 2023. Staff will continue to monitor drought conditions and respond to calls for
voluntary or mandatory conservation. Staff will evaluate and propose reserve transfers between the Rate
Stabilization Reserve, CIP Reserve, and Operations Reserve in the annual Financial Plans.
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F 2023
<
Burlget Actua l Variar<;c Variance ll-0 1
Jul 5 ,702.307 4 ,505,935 -1,196,372 -21.0%
Aug 5 ,318 ,642 4,707,270 -611,372 -11.5%
Sep 5 ,199,686 4,807 ,131 -332,555 -6.4%
-~ Oct 4,929,922
1/1 Nov 3,84 5 ,7 24 ...
m
D Dec 2 ,991,053
0
Ja n 2,579,572
Feb 2 ,521,336
M ar 3,127,345
Apr 2 ,909,460
M ay 4,152,472
■ W arnr, Actual Water, Budget Jun 4,605,362
24Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
4 Wastewater Utility
The Wastewater Utility includes the system of sewer pipes that collect and transport wastewater to the Regional
Water Quality Control Plant (RWQCP) operated by the City of Palo Alto under a partnership agreement with
several surrounding communities, as well as Palo Alto’s share of the cost of operating the RWQCP. The RWQCP
provides treatment and disposal of wastewater for Palo Alto. Costs for the Wastewater Utility are split
approximately half for the operation, maintenance and periodic replacement of Palo Alto’s sewer collection
system and half for the costs of wastewater treatment at the RWQCP.
4.1 Wastewater Treatment Updates and Capital Planning Status (Lisa Bilir)
The Regional Water Quality Control Plant is operated by Palo Alto’s Public Works Department and provides
wastewater treatment to Palo Alto, Mountain View, Stanford, Los Altos, East Palo Alto and Los Altos Hills. The Palo
Alto Wastewater Collection Utility pays its share (approximately 32% projected in FY 2024) of the costs for
wastewater treatment and disposal. Capital costs for wastewater treatment are a major driver for cost increases
for the Wastewater Treatment Utility and by extension for the Wastewater Collection Utility. These costs are
projected to increase at approximately 15% per year on average from FY 2023 through FY 2032. The RWQCP is
facing the need for major upgrades in coming years, due to aging equipment and changing environmental
regulations. Rehabilitation and replacement of plant equipment that has been in use for over 40 years is necessary
to ensure the city can continue to provide wastewater treatment operations safely and in compliance with
regulatory requirements for the discharge of treated wastewater 24 hours a day.
4.1.1 Treatment Cost Trends (Lisa Bilir)
RWQCP staff project treatment costs paid for by Palo Alto’s Wastewater utility to increase by approximately 5.8%
annually on average from FY 2023 through FY 2032. A key driver of the increases are capital projects, parts,
materials and debt. The treatment capital expenses,including debt service costs, are increasing at an average of
about 15% per year from FY 2023 through FY 2032 to keep up with ongoing replacement of aging equipment.
Larger increases to capital expenses are expected to begin in FY 2024 in the form of new debt service for major
projects to implement the Plant’s capital program. The figure below shows Palo Alto’s share of each component
of estimated treatment costs. Major upcoming capital projects and estimated years for debt service to begin are
reflected in the “Planned Debt Service” bar in the figure below and include:
Joint Interceptor Sewer Rehabilitation (FY 2024)
1900 Embarcadero Road Purchase; Primary Sedimentation Tank Rehabilitation (FY 2025)
Outfall Line Construction, Operation Center and Laboratory (FY 2027)
Secondary Treatment Upgrades, Headworks Facility (FY 2029)
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25Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 22: Palo Alto’s Share of Estimated Wastewater Treatment Expenses (Projection and Planned CIP)
The figure shows the ongoing annual CIP reinvestment (“Recurring/Minor CIP” and “Existing Debt Service”) as
well as treatment operations costs, which make up the majority of the treatment costs but are not growing as
quickly as the planned debt service. Factors that are contributing to cost increases for treatment operations are
rising salary and benefits costs, allocated charges for centralized city services needed to support wastewater
treatment fund operations, increased water and air permitting fees from the Regional Water Quality Control
Board and Bay Area Air Quality Management District, commodity rates to operate the facility, and chemical
expenses.
4.1.2 Regional Water Quality Control Plant Capital Planning Status (Lisa Bilir)
The Long-Range Facilities Plan, completed in 2012, guides the capital plans for the RWQCP. The RWQCP’s current
capital work in-progress includes an estimated $359 million in projects. The following table summarizes these
ongoing projects and provides their status and costs.
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$20,000,000
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$4,000,000
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$-
FY 2024 FY 2025
Palo Alto Estimated Expenses FY 2024-2033
Proje ction + Planned C/P
FY 2026 FY 2027 FY 2028 FY 2029 FY2030
-Treatment Operations -Reaming/MinorCIP
One Time CIP for Joint Intercepting Sewer -Existing Debt Service
FY 2031
Planned Debt Service ~ Treatment Operations & Planned CIPs
FY 2032 FY 2033
26Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 23: Current RWQCP Capital Work In-Progress (information from RWQCP June 2022 Partners Meeting)
Project Status Expense (million $)
Primary Sedimentation Tanks Rehabilitation and
Equipment Room Electrical Upgrade
Construction $19.4
New Outfall Pipeline 90% Redesign $17.4
Secondary Treatment Upgrades Awarding Construction $193
Advanced Water Purification System 90% Design $56
Technical Services Building/Lab Building, Ops
Building Remodel
Advanced Planning $41.4
Buy 1900 Embarcadero Road Planning $6.0
Headworks Facility Replacement Budgeted $48.6
Joint Interceptor Sewer Rehabilitation Design $5.6
Projects in Progress Various $10.6
Subtotal $398
The largest projects listed above include the Headworks Facility Replacement which involves replacement or
rehabilitation of the parts of the facility that pump raw sewage to the main treatment works (the headworks), and
rehabilitation of primary sedimentation tanks that separate out primary sludge. Additionally, the RWQCP
anticipates regulations to limit nutrient discharges (on total nitrogen) into the San Francisco Bay. The current
secondary treatment design cannot remove nitrogen and the Secondary Treatment Upgrades will address this
regulatory change as well as address aging mechanical and electrical equipment that must be replaced.
The RWQCP plans to fund these capital projects through a combination of mechanisms including State Revolving
Fund loans, and revenue bonds. In addition,Valley Water will be providing $16 million of funding for the Advanced
Water Purification System.Additionally, Palo Alto was awarded a $12.8 million grant from the Bureau of
Reclamation’s WaterSMART: Title XVI WIIN Act Water Reclamation and Reuse Project funding for the Advanced
Water Purification System.
4.2 Collection System Capital Improvement Plan Status (Silvia Santos)
The following capital projects are currently in progress:
WC-17001 - SSR 30 (Sanitary Sewer Replacement 30): This project is to replace approximately 10,120 linear
feet of wastewater main and 156 sewer laterals in the Ventura, Research Park, Fairmeadow, and Midtown
West neighborhoods. The construction started on 3/28/22 and the project is scheduled to be completed in
January 2023.
WC-19001 - SSR 31 (Sanitary Sewer Replacement 31): This project is to replace approximately 10,000 linear
feet of wastewater main, sewer laterals, and manholes on El Camino Real. The construction is anticipated to
start in June or July of 2023. A significant portion of the work will be performed during nighttime due to
Caltrans’ restriction to close 2 traffic lanes only between 11 PM and 6 AM.
4.3 Rate and Bill Comparisons (Lisa Bilir)
The figure below shows the wastewater monthly bill for residential customers in Palo Alto compared to what they
would be under surrounding communities’ rate schedules as of November2022. Palo Alto’s monthly sewer bill is
lower than four of the six neighboring communities. Menlo Park in this table refers to the West Bay Sanitary
District. Staff will report on future rate increases once they are adopted by the wastewater utilities.
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27Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Figure 24: Residential Wastewater Bill Comparison ($/month)
As of November,2022
Palo Alto Menlo Park Redwood City Mountain View Los Altos Santa Clara Hayward
$44.62 $106.67 $89.28 $50.10 $42.05 $46.82 $38.58
4.4 Financial Health
Below is a summary of the financial position for the wastewater utility.
4.4.1 Sales Forecasts vs. Actuals (Eric Wong)
Actual wastewater sales revenues through Q1 of FY 2023 were around expectation, at about 0.4% higher than
forecasted in the FY 2023 Financial Plan.
Figure 25: Wastewater Sales Revenue ($), up to FY 2023-Q1
4.4.2 Financial Position (Lisa Bilir)
The Wastewater Collection Operations Reserve was within the guideline range at year end FY 2022; the CIP
Reserve had a balance of approximately $3.2 million at year end FY 2022 and staff will seek Council approval in
the FY 2024 Wastewater Collection Financial Plan to access funds in the CIP Reserve if they are needed for CIP
projects. The Wastewater Collection Utility CIP Reappropriation and Commitment Reserves totaled $4.6 million
at the end of FY 2022. In addition to these funds, the adopted FY 2023 budget included approximately $3.5 million
in the CIP program primarily for the Sanitary Sewer Replacement Project 31.
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FY Z0 .22 B udget Aci::.u al Va n 3nce Var iance %
Jul' 1 ,739 ,132 1 ,685 ,8% -53 ,23.6 -3.1%
Aug 1,733 ,213 1 ,786,224 53 ,0ll 3.1%
1 5 00K Sep 1,743,637 1,763,529 19,892 1.1%
!ft Oct 1,734,767
f l OOOK Nov 728,399
rn
0 Dec 1 ,771,013
Q
Jan 1 ,770, 11
'oCOf< Feb J.,669.155
Mar 1,810,061
OK Apr 1,696,.732
J J I Aug 5 ,;,i:; Oct Nov DH Ja n Feb r•.ilar Apr M ay Jun May 1 ,665,374
■ Wastewarnr , Actual Wastewarnr, Budge-Jun ,684,910
28Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
5 Fiber Utility
The City offers a "Dark" fiber service providing a fiber connection from Palo Alto businesses to the downtown
Internet Exchange. At the exchange businesses select an internet service provider (ISP) for bandwidth and
connection speed.
5.1 Fiber Utility Strategic Planning (Dave Yuan & Josh Wallace)
On September 19, 2022 the Council and UAC held a joint session (Staff Report #13956, Packet Pg. 54)) to discuss
the City’s fiber backbone network plan and findings from research into providing citywide fiber-to-the-premises
(FTTP). During the joint session, the Council and UAC reviewed plans to build the fiber backbone and evaluated
the feasibility of expanding the City’s current licensing of dark fiber to end users by building out the network to
connect to homes and businesses with a citywide FTTP distribution network to offer broadband services.
The City launched the Palo Alto Fiber Market Research Survey and Fiber Deposit program. 3,254 surveys were
completed (14.8% response rate) and 703 deposits received as of August 3, 2022. High-level findings from survey
results in are provided below:
1. 28.4% of households are either very dissatisfied or somewhat dissatisfied with their current internet
services. An additional 14.4% are neither satisfied nor dissatisfied.
2. 53% of households subscribe to internet streaming only and do not subscribe to cable television which is
also known as “cutting the cord”. An additional 18% of customers would consider canceling cable television
and using only internet streaming.
3. Top three reasons to switch from current providers (in priority order) are lower price,faster speed, and
higher reliability.
Staff identified several significant competitive risk factors and potential risk mitigation strategies. Risks include
market demand for a municipal broadband offering, speed to market to buildout FTTP, and staffing and contract
management to build and operate a new City-owned ISP business. Some of the mitigation strategies to address
these risks include expansive FTTP customer acquisition and marketing campaign,streamlined permitting, and
strong service level agreements with vendors.
Magellan analyzed two financing options to deploy fiber to the entire City.Option 1 is a citywide FTTP buildout
funded by fiber reserves and bond financing within five years. Option 2 is an incremental FTTP buildout using
fiber reserves without bond financing which could span over 15 – 20 years.
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January 4, 2023
5.2 Capital Improvement Plan Status (Patrick Valath/Dave Yuan)
The Fiber Network Rebuild CIP project is temporarily on hold pending the results of the fiber backbone expansion
and FTTP project. As part of the City’s wildfire mitigation plan, CPAU will underground approximately 11 miles of
electric line in the Foothills area by 2025. CPAU have already completed 1.5 miles of substructure work and have
started working on the next 1.5 miles. CPAU is adding spare conduits for fiber as part of the undergrounding
project in the foothills.
5.3 Reliability (Dave Yuan)
There were no unplanned fiber outages or events to report in Q1 of FY 2023.
5.4 Financial Health
Below is a summary of the financial position for the fiber utility.
5.4.1 Fiber Sales (Dave Yuan)
Actual fiber revenues for FY 2022 were $3.3 million, which is $0.3 million or 8% below FY 2022 revenue forecast
of $3.6 million. Based on the number of new dark fiber applications, staff projects annual fiber revenues will
return to pre-pandemic level of $4.5 million by FY 2024. To expand the dark fiber business, CPAU is recruiting for
a dedicated Fiber Engineer and Fiber Market Analyst to reduce fulfillment time for new applications.
Actual fiber expenses for FY 2022 were $3.2 million which includes $1.0 million of fiber consulting expenses with
Magellan Broadband for engineering design of the fiber backbone and FTTP networks, community engagement,
FTTP business models, and grant funding analysis. Funding is shared between Fiber ($2.0M) and Electric ($0.4M).
As of Q4 2022, $1.2 million is still remaining under the Magellan contract.
5.4.2 Financial Position (Dave Yuan)
The projected ending FY 2022 Fiber Optic Utility Rate Stabilization Reserve is $34.0 million.
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30Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
6 Customer Programs (Efficiency and Sustainability)
The City’s Utilities Department maintains a number of programs to help customers save money, use energy and
water efficiently, and reduce carbon emissions. These programs are funded through a variety of funding sources,
some of which are summarized below.
6.1 Customer Programs Updates
Below is a summary of the City’s energy and water efficiency programs, as well as programs to encourage building
electrification and adoption of electric vehicles.
6.1.1 Energy and Water Efficiency (Scott, Leanna, Brian, Christine, Linda)
Energy & Water Efficiency Workshops (Scott Mellberg, Kevin Carley, Linda Grand)
The City in partnership with the Bay Area Water Supply and Conservation Agency (BAWSCA) held three landscape
efficiency workshops in fall 2022. The workshops covered topics on harvesting rainwater, steps to take to design
and convert lawns into drought-tolerant landscapes, and available rebates. Attendance was strong, with more
than 91 residents total participating in the workshops..
Schedule of CPAU Workshops September - November 2022
Event #Date Event
1 9/24/2022 Rain Barrel Workshop
2 10/18/2022 Landscape Design 101
3 11/1/2022 Lawn Conversion 101
Please visit the BAWSCA website for a complete list of available classes and events at:
https://bawsca.org/conserve/programs/classes. All past Landscape Class Videos are available online at:
https://bawsca.org/conserve/landscaping/videos/. For updates on future events and workshops, please visit
http://cityofpaloalto.org/workshops
With collaboration from the City Manager's Office, Planning and Development Services and the Utilities
Department, a Making Better Choices in Your Home Workshop was held on Saturday, October 15 from 10 a.m. –
1 p.m. at Mitchell Park Community Center.Over 200 attendees learned about different climate-friendly choices
they can make in their home, including displays of heat pump water heaters, and experts answering questions
about induction cooktops, electric vehicles, e-bikes, water saving and the advantages of going all electric.
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31Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Residential Energy and Water Programs (Scott Mellberg)
The Home Efficiency Genie program continues to provide residents with professional advice and information to
improve their home’s efficiency and comfort, lower their energy and water usage and get guidance on home
electrification options. Even with the Genie returning to in-home comprehensive and diagnostic assessments in
the fall of 2021, the virtual option developed during COVID continues to be a service that residents are interested
in. The Home Electrification Readiness Assessment (HERA) was also amended to include a virtual version during
COVID. Both the in-home and virtual versions continue to help residents assess home electrification upgrades that
their home can accommodate and provide actionable next steps. Between July and October of 2022, the Genie
performed 20 comprehensive in-home assessments, 19 HERAs and 3 virtual assessments.
CPAU’s Residential Energy Assistance Program (REAP) for income-qualified customers continues to reach our most
vulnerable population offering energy and water efficiency improvements at no cost to the customer. Residents
who are newly qualified for CPAU’s Rate Assistance Program (RAP) are notified each month of their eligibility for
these free upgrades installed by CPAU’s vendor, Synergy. Between July and October of 2022, 5 new REAP
customers have taken advantage of the free efficiency upgrades, with projects including building envelope
improvements, furnace replacements with high efficiency models, and lighting upgrades to LEDs.
For our multifamily (MF) property owners, CPAU continues to offer the Multi Family Plus (MF+) program which
offers free energy efficiency upgrades installed by our vendor, Synergy. These upgrades include lighting upgrades
to LEDs and whole building envelope upgrades.
Water Conservation Program (Linda Grand)
CPAU partners with Valley Water to offer a robust portfolio of water conservation programs and rebates for
residents and businesses.On July 1, 2022, the City entered into a new cost-sharing agreement with Valley Water
which increases rebate amounts for converting turf into drought-tolerant landscapes and includes a new Lawn to
Mulch rebate program for commercial customers. As drought conditions continue, CPAU is focusing outreach on
reducing outdoor water use and continues to encourage participation in rebates and resources.
On October 6, 2022 the City launched WaterSmart, an online water management tool to help residents and
businesses better understand their water usage and enable them to conserve water and save money. The
WaterSmart Portal is open to all City of Palo Alto Utilities customers and provides access to water use charts,
personalized recommendations for water efficiency, information on available rebates, and more. The WaterSmart
system integrates with MyCPAU, the Utilities online account management tool, for a streamlined sign-on
experience.
Bay Area SunShares Program (Leanna Huynh)
The 202For the seventh year in a row, the City of Palo Alto is an outreach partner for Bay Area SunShares, a solar
and battery storage group-buy program administered by Building Council for Climate Change (BC3). More than 35
Bay Area communities and companies are participating as outreach partners. Palo Alto’s participation as an
outreach partner helps CPAU customers receive information and discounted prices from vetted contractors. Three
solar installers (Solar Technologies, SkyTech Solar, and Infinity Energy) have been vetted and selected through an
RFP process.CPAU hosted a free educational workshop in partnership with BC3 on October 12, 2022 with 83
attendees.Palo Alto had the highest number of SunShares sign ups with 161 registered residents by the November
15, 2022 registration deadline. Contracts for installations must be signed by December 15, 2022.
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32Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Business Advantage Program (Brian Ward)
As of November 22, 2022, 2022, 2022, the Business Advantage Program (BAP) has installed 75 customers with
an additional 21 customer waiting on installs for the GridPoint Energy Management program (GEM). Of the 75
customers, only two have decided to withdraw and return equipment. One customer preferred their old
thermostat (NEST) and the other was frustrated using the system and had multiple overrides and could not control
employees like old thermostat behavior. The two returned units will be redeployed. The majority of program sign
ups continue to come from direct customer sales through face-to-face engagement.GridPoint currently has had
personal changes had an issue with its installer and had to replace them with another company. However, the
new installer was also let go because of poor customer services and substandard installation work. GridPoint
reacquired the old installer but rates for service were much higher. Point and Palo Alto continue to offer free 30-
minute customer training sessions on a monthly basis. The primary point is to educate current users on how to
properly program and operate the GEM system. Lastly, a second contract amendment was completed, and Wildan
Energy Services is the official contract holder.
Commercial & Industrial Energy Efficiency Program (Brian Ward and Christine Tam)
As of October 31, 2022, Enovity has completed 3 projects with 259,000 kWh savings. They have three additional
projects in the pipeline and anticipate finishing these projects before the end of the fiscal year with an additional
2,000,000 kWh savings in FY 2023. Key Account Managers have been actively reaching out to engage customers
with direct email contacts as well as through the Questline Key Account Newsletter. Lighting continues to be the
most popular energy conservation measure. Some companies, however, are reluctant to allocate resources to
efficiency upgrades until staffing levels at their sites return to pre-pandemic levels.
Business Customer Rebates, formerly Commercial Advantage Program (Brian and Christine Tam)
The Business Customer Rebate (BCR) program was launched in May this year, with the expansion of business
rebates for commercial electrification projects and also increased rebates for electric efficiency savings. This
program was rebranded from the Commercial Advantage Program to promote energy efficiency and
electrification projects among business customers. Both standard rebates and custom rebates are offered through
this program. This program is currently being publicized through business e-newsletters, bill insert, and cross
promotion from other CPAU business programs.
Business Energy Advisor (Christine Tam and Shelby Sinkler)
Since the Business Energy Advisor program launched in June 2022, 21 program participation agreements have
been sent to customers, 7 agreements have been signed, and 3 site assessments have been completed. There
are 4 additional assessments in the pipeline that are anticipated to be complete by the end of this year.
CLEAResult has launched a call center campaign to engage more customers, and both CPAU and CLEAResult
have continued in-person outreach to small and medium business in Palo Alto. Additional outreach plans
include a direct mailer campaign in early 2023, advertisement in the bi-monthly CPAU newsletter to small and
medium businesses, and presentations to business organizations in Palo Alto.
6.1.2 Building Electrification (Christine Tam, Lisa Benatar, Shelby Sinkler)
With sustainability continuing to be a Council priority, staff recognizes the need to promote the importance and
benefits of building electrification (BE) while removing barriers to voluntary electrification efforts in existing
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33Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
buildings. Current work covers three areas of activities: public outreach, customer program development and
implementation, and strategy and policy development.
For public outreach, staff continues to participate in meetings with Working Group teams developed through the
Council’s Ad Hoc Committee. These working groups hold periodic updates with the public, including one on June
14, 2022.
For residential customer programs, staff issued a comprehensive RFP in June 2021 for residential building
electrification, energy and water efficiency programs which includes single family and multifamily homes as well
as income and medically qualified residents. As part of the community engagement process, an Ad Hoc committee
of Council members was formed in April 2021, and staff was asked to pause activities related to contract
negotiations for the residential programs RFP until the Council Ad Hoc committee and related working groups had
the opportunity to provide input on program design and direction. Staff was also asked to wait to proceed with
contract negotiations while concerns raised by the Utility’s Engineering and Operations Division about potential
additional electric load resulting from building and transportation electrification were addressed. These
community and staff collaborative efforts resulted in the ongoing development of a turnkey heat pump water
heater installation program. Other programs planned include building electrification phone advisory and technical
assistance services for both single family and multifamily property owners, and self-service online tools to help
residents assess the economics of electrifying their homes. Staff has resumed contract negotiations with the
selected vendors since June 2022 and plans to bring the contracts to City Council for approval in the fall of 2022.
For strategy and policy development, Utilities staff is collaborating with Planning & Development Services to
propose building electrification requirements for the upcoming building code cycle (2023-2025). The proposed
requirements include the following elements:
All-electric design for new construction projects; this applies to low-rise residential buildings,
detached ADUs, multifamily buildings, and nonresidential buildings.
Addition/alteration projects that meet the “Substantial Remodel” definition will trigger the all-electric
requirements. For the purposes of electrification, substantial remodel shall mean the alteration of any
structure, including cumulative projects or additions to the existing structure within any three (3) year
period, that affects the removal or replacement of 50% of the linear length of the exterior weight-
bearing walls of the building, 50% of the wall plate height is raised, and/or 50% of the roof structural
framing.
Prohibit the extension of gas infrastructure in existing buildings to outdoor amenities such as pools,
spas, fireplaces and grills in order to minimize the carbon footprint of these equipment.
Require heat pump water heater when the existing water heater is replaced, or new water heater is
added as part of a residential addition or alteration project.
Collectively these proposed requirements will avoid over 3,420 MT CO2-e per year, about 1% to 1.5% of the
remaining emissions reductions needed to achieve the 80x30 goal (about 1.5% to 2% when upstream emissions
from fuel use are included).3 Other proposed Green Building requirements cover EV infrastructure, water
efficiency, and embodied carbon limits in the use of concrete for new construction projects. Additional details can
3 Using 20-year global warming potentials.
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be found in the 2022 Reach Codes webpage. Staff will be bringing the proposed Green Building regulations to City
Council for the first reading this coming October.
Business Electrification Technical Assistance Program (BE TAP)
The BE TAP program officially launched in August 2022, offering no-cost assessments to help nonresidential
customers identify electrification opportunities and free technical assistance to support them with their building
electrification journey. Since the program launched, our partner, CLEAResult, has completed 2 site assessments,
assisting large commercial customers with potential HVAC and heat pump water heater projects. The feasibility
study completed for the large HVAC project found an estimated 77,640 kWh and 54,263 therms savings, with a
potential incentive of $100,000 for the customer. The next steps for this program include completing additional
project feasibility studies and other electrification assessments in the pipeline. We plan to continue outreach
efforts through the call campaign, e-newsletters, and in-person communication.
6.1.3 Electric Vehicles (Hiromi Kelty, Shiva Swaminathan and Connie Chu)
Palo Alto continues to facilitate the installation of EV charging infrastructure throughout the City to support mass
EV adoption, with equitable access for multifamily and income-qualified residents, as well as workplaces, public
parking lots and retail areas. Correspondingly, cross-departmental work is progressing on proposals for fleet
electrification and permit streamlining.
Financial Overview
FY 2022 EV expenses to date is $0.54M, of which $0.465M was for the first installment of the CALeVIP program.
No direct customer rebates have been paid to date. Revenues for the year is $1.59M, lower than anticipated a
year ago due to declining market prices for LCFS credits.Total LCFS revenues received to date is $10.1 million.
Summary of All EV Programs for Multi-family (MF) Properties and Workplaces
Mission:The EV team’s mission is to facilitate the installation of EV chargers to support increased EV adoption
with a priority on MF properties. To reach 80 by 30 S/CAP goals, it is imperative that there is enough charging
infrastructure for residents, commuters and visitors. For residents, the priority is to close the MF EV access
gap, as only 13% of EVs in Palo Alto are registered at MF buildings, while MF makes up 42% of households.
Goal of EV Programs:Expand EV charging accessibility to 10% of MF households (about 1,100 homes) by 2025.
Why:This is an equity issue. Most middle-income and low to moderate-income residents in Palo Alto live in
MF housing. EVs provide significant lifetime household savings, and yet those who most need those savings
have the hardest time gaining EV charging access due to the challenges associated with installing chargers at
MF properties. Private industry is not adequately serving this market, whereas the City is well positioned to
support this hard to reach, slower to move, customer segment, making meaningful use of available City
funding sources for EV promotion.
Target Customer Segment:MF property owners, HOA’s,nonprofits, owners of small medium businesses and
buildings,as well large C&I customers.
What CPAU can provide:
o Trusted, neutral advisory services (rather than vendor sales services) with a direct connection to
internal City staff to facilitate problems.
o Technical assistance (site evaluation, including electrical capacity, business case development,
project design, obtaining bids, preparing permit packages)
o Incentives (both for charging equipment and distribution upgrades)
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35Utilities Quarterly Update: First Quarter of Fiscal Year 2023
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Strategy:Facilitate development of shared Level 2 chargers in multi-family buildings as well as, as many Level
1 chargers as can be installed. Size electrical infrastructure to enable the building owner to add more EV
charging ports in the future.
Aggregated Results to-Date for All EV Programs Targeting Multi-family (MF) Properties and Workplaces
Program Commencement:December 2017 (multi-family rebates), October 2019 (multi-family/nonprofit
technical assistance), December 2019 (workplace charging rebates)
Leads:Over 130 sites have enrolled in the programs, of which 86 are multi-family properties representing
over 3400 units
Results:When the active projects are completed, the City will have:
o Facilitated access to EV charging for over 1500 multi-family housing units. Without accessible
charging facilities these residents are unlikely to consider an EV.
o Access to EV charging for employees of several non-profits and workplaces.
Marketing Strategy: Of Palo Alto’s 803 multi-family (MF)buildings, focus on the largest 5%(44 sites) which
represent 32% of total MF units (about 3800 households).Also,partner with affordable housing providers
which represent over 1600 low-income households at 35 sites of which 5 properties have 100 units or more.
Outreach consists of direct outreach to property owners via call campaigns, with marketing done by the 3rd
party program provider, CLEAResult.
Updates by EV Program
EV Technical Assistance Program (EVTAP)
Goal: Facilitate the installation of 180-360 ports @ 60-90 sites (By 2024)
Offer technical assistance for the installation of EV chargers at Non-Profit and MF properties, involving a series
of site visits, technical evaluations and engineering reviews, that culminate in the landlord receiving contractor
bids and then assistance submitting a building permit, applying for incentives and project management of the
installation. Projects expected to take up to 2 years or more to reach completion.
As of the end of September 2022:
o 0 installations complete
o 16 Permit Applications Submitted
o 88 sites enrolled and working through the program
o Potential for over 300 Level 2 ports and 60 Level 1 ports
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Figure 26: EV Technical Assistance Program (EVTAP), Cumulative Progress Report (November 2019 - September 2022)
EV Charger Rebate Program
Goal: Incentivize the installation of EV chargers at Non-Profits and Multifamily properties. CPAU currently
offers up to $8,000 per port for up to 10 ports.
As of the end of November 2022:
o FY22 - 32 ports installed
o Since the launch of this program in 2017, CPAU has facilitated the installations of 94 new EV charging
ports/connectors at 14 sites. The breakdown of the installation sites: 6 MF and 8 non-profits (including
3 schools). Avg. cost of each port: $10k and projects have averaged 12 months to complete.
California Electric Vehicle Infrastructure Project (CALeVIP)
Goal: Facilitate and Incentivize the installation of EV chargers at commercial sites.
As of November 2022, a total of $1.9M (out of $2M)has been reserved by 11 site owners through CALeVIP, a
commercial EV charging, matching grant program sponsored by the California Energy Commission (CEC).The
proposed installations could lead to the installation of 115 Level 2 ports and 14 DC Fast Chargers.
o 0 installations completed
o 11 sites enrolled and working through the program (1 hotel, 7 office sites, 2 retailers and 1 multi-unit
dwelling)
o 8 Permit Applications Submitted
o 5 Permits Issued
o Potential for 179 Level 2 ports and 12 DC Fast Chargers
California Clean Fuel Rewards (CCFR)
Goal: Incentivize the purchase of new EVs
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37Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Since the launch of the CCFR program in November 2020, Palo Alto residents have earned 1,906 rebates
valued at $2M. This translates to over 7%% of Palo Alto households purchasing an EV taking advantage of this
program. To date, Palo Alto has contributed $1.3M towards this state program. The most popular EV continues
to be the Tesla Model Y and Model 3 and the most popular plug-in hybrid continues to be the Toyota Prius
Prime.
Due to higher-than-expected participation levels statewide and lower than expected Low Carbon Fuel
Standard (LCFS) credits prices, the California Air Resources Board paused the program at the end of August
2022.
November 2020 – November 2022:
o 1,906 Rebates paid to Palo Alto residents for EV Purchases
EV Awareness and Outreach
Goal: Raise awareness, answer questions and encourage residents to consider transitioning to electrified
modes of transportation, including electric cars, e-Bikes and other modes of clean transportation. CPAU is
offering a wide array of EV classes and events, partnering with multiple vendors and organizations. Through
the end of November 2022, CPAU has been involved in 18 EV education and outreach events and expects to
offer over 2 dozen workshops and events during calendar year 2022. There is a high level on interest and
many of the online webinars regularly attract over 100 highly engaged participants. CPAU is in the process of
putting together a full schedule of events and workshop for CY2023.
January – November 2022:
o 32 EV education and outreach events completed
Figure 27: Schedule of CPAU Workshops and Events,July - September 2022
Event #Date Event
1 7/19/2022 EV 102 Workshop
2 8/8/2022 EV 101 Workshop
3 8/17/2022 EV 101 Workshop
4 9/1/2022 EV 101 Workshop
5 9/11/2022 Neighborhood EV Expo @ Palo Alto Adult School
6 9/18/2022 Neighborhood EV Expo @ Universal Unitarian Church
7 9/21/2022 Bilingual Financial Incentives Workshop
8 9/24/2022 Neighborhood EV Expo @ Green House Tour
Visit http://www.cityofpaloalto.org/workshops for information on upcoming classes.
City-Owned EV Chargers
Goal: Install EV Charging Infrastructure for the public as well as City-fleet.
As of the End of November 2022:
o 124 - City-Owned Ports
o 120 - Publicly accessible EV Charging ports
o Newest chargers: 6 ports at renovated Junior Museum on 1451 Middlefield Rd.
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Transformer Upgrade Rebate Program
Goal: Provide discounts to defray the cost of utility distribution system upgrades triggered by EV
applications, costs that would otherwise be borne by the customers. With this program we are offering up
to $100K for MF & non-profits and up to $10K for Single Family Homes
As the End of November 2022:
Through EVTAP we are learning that many older properties in Palo Alto, especially multifamily buildings, have
limited electric capacity to accommodate EV chargers and building electrification. The EV team is working
closely with Engineering and is conducting a pre-screening of transformer loading for all commercial EV
projects enrolled in EVTAP.
For residential customer programs, staff issued a comprehensive RFP in June 2021 for residential building
electrification, energy and water efficiency programs which includes single family and multifamily homes as well
as income and medically qualified residents. As part of the community engagement process, an Ad Hoc committee
of Council members was formed in April 2021, and staff was asked to pause activities related to contract
negotiations for the residential programs RFP until the Council Ad Hoc committee and related working groups had
the opportunity to provide input on program design and direction. Staff was also asked to wait to proceed with
contract negotiations while concerns raised by the Utility’s Engineering and Operations Division about potential
additional electric load resulting from building and transportation electrification were addressed. These
community and staff collaborative efforts resulted in the ongoing development of a turnkey heat pump water
heater installation program. Other programs planned include building electrification phone advisory and technical
assistance services for both single family and multifamily property owners, and self-service online tools to help
residents assess the economics of electrifying their homes. Staff has resumed contract negotiations with the
selected vendors since June 2022 and plans to bring the contracts to City Council for approval in the fall of 2022.
For strategy and policy development, Utilities staff is collaborating with Planning & Development Services to
propose building electrification requirements for the upcoming building code cycle (2023-2025). The proposed
requirements include the following elements:
All-electric design for new construction projects; this applies to low-rise residential buildings,
detached ADUs, multifamily buildings, and nonresidential buildings.
Addition/alteration projects that meet the “Substantial Remodel” definition will trigger the all-electric
requirements. For the purposes of electrification, substantial remodel shall mean the alteration of any
structure, including cumulative projects or additions to the existing structure within any three (3) year
period, that affects the removal or replacement of 50% of the linear length of the exterior weight-
bearing walls of the building, 50% of the wall plate height is raised, and/or 50% of the roof structural
framing.
Prohibit the extension of gas infrastructure in existing buildings to outdoor amenities such as pools,
spas, fireplaces and grills in order to minimize the carbon footprint of these equipment.
Require heat pump water heater when the existing water heater is replaced, or new water heater is
added as part of a residential addition or alteration project.
Collectively these proposed requirements will avoid over 3,420 MT CO2-e per year, about 1% to 1.5% of the
remaining emissions reductions needed to achieve the 80x30 goal (about 1.5% to 2% when upstream emissions
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from fuel use are included).5 Other proposed Green Building requirements cover EV infrastructure, water
efficiency, and embodied carbon limits in the use of concrete for new construction projects. Additional details can
be found in the . Staff will be bringing the proposed Green Building regulations to City Council for the first reading
this coming October.
6.2 Funding Sources for Emissions Reductions
Energy efficiency and water efficiency programs have traditionally been funded by electric, gas, and water rate
revenues. To fund emissions reduction programs, the City has developed multiple alternative funding sources
6.2.1 Low Carbon Fuel Standard (LCFS) Program (Shiva Swaminathan)
LCFS base credits are allocated by the California Air Resources Board (CARB) to CPAU, based on the number EVs
registered in Palo Alto, the estimated miles travelled and the difference in carbon intensity of transportation fuels
and electricity. Credits are also allocated based on CNG dispensed and electricity dispensed at city owned EV
chargers. The sales proceeds of these credits are the source of funds for CPAU’s customer programs related to
EVs. In CY2022, Palo Alto received ~15,000 credits and is expected to result in a revenue of about $0.9M. LCFS
credit prices have declined substantially in in 2022 compared to 2021, down from ~$130/credit to $60/credit.
6.2.2 Cap and Trade Program, Revenue from Allocated Allowances (Eric Keniston)
The Global Warming Solutions Act of 2006, also known as Assembly Bill (AB) 32, authorized CARB to develop
regulations to lower the state’s greenhouse gas (GHG) emissions to 1990 levels by 2020. CARB developed a cap-
and-trade program as one of the strategies to achieve the 2020 goal. Under the cap-and-trade program, an overall
limit on GHG emissions from capped sectors is established and facilities subject to the cap are able to trade permits
(allowances) to emit GHGs. Senate Bill 32 (2016) expanded upon AB 32 by requiring a 40% reduction in GHG
emissions below the 1990 levels by 2030.
In 2012, CARB’s cap-and-trade program commenced and certain covered entities, such as electricity generators
and other stationary sources of GHGs, had a compliance obligation under the new program. The City of Palo Alto
Utilities’ (CPAU’s) electric utility does not own or operate fossil fuel-based electricity generation covered by the
cap-and-trade regulations. CPAU also received free allowances from CARB to mitigate the costs of reducing its
GHG emissions. Since CPAU’s electric utility is carbon neutral and typically has no need to use the allowances for
compliance, it must sell them into the cap-and-trade auction.
Allowance revenues, estimated to come in at around $3 million in 2022 and onward, can be used for several
approved purposes, including: a) purchases or investment in renewable resources (outside Palo Alto or locally) for
the electric portfolio; b) investment in energy efficiency programs for the electric portfolio and retail customers;
c)investment in other carbon reduction activities, including those required to achieve a carbon-neutral electric
portfolio; and d) rebates to electric retail ratepayers.
As of 2021 reporting, some allowances have been utilized to purchase renewable resources while others have
been earmarked for future electrification programs (about $1.2 million). Staff is investigating using more of these
funds for investments in emissions reduction programs.
6.2.3 Electric Public Benefit Funds (Eric Keniston)
Locally owned municipal utilities like CPAU must collect Public Benefit funds from their electric utility customers
as required by section 385 of the Public Utilities Code, to be used on cost-effective energy efficiency and
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conservation, low-income programs, investments in renewable energy resources and technologies, and research
and development. CPAU currently has an Electric Public Benefit surcharge of 2.85% of the electric utility bill for all
customers. A portion of this fund can be used for building electrification pilot programs and projects.
6.3 Innovation and Pilot Programs (Lena Perkins)
CPAU’s Program for Emerging Technologies, or PET, (www.cityofpaloalto.org/UTLInnovation) provides the
opportunity for local businesses and organizations to submit proposals for innovative and impactful products to
CPAU for review as a prospective partner. The goal is to find and nurture creative products and services that will
improve customer value, save natural resources, or reduce carbon emissions. From the program’s inception in
June 2012 through today, the program has received a total of 104 applications. The figure below summarizes the
status of all applications through FY 2022.
So far this year, only a single academic collaboration has reached the threshold of value, quality, and relevance to
be considered a good fit for a pilot project. CPAU is currently in discussions with some applicants about revising
their projects and is also evaluating potential regional collaborations with promising early-stage companies. In
order to provide more clarity for applicants and better focus the applications on CPAU’s priorities, staff is also
revised the program’s guidelines to highlight what makes a compelling project pitch for CPAU. These updated
program priorities and guidelines were released this year and presented to the UAC. Pending other priorities and
sufficient resources, staff will work with local universities and accelerators to solicit high-quality applications
closely aligned with CPAU’s highest priorities in calendar year 2022.
6.3.1 Academic Collaborations (Lena Perkins)
CPAU staff is working with Keola Iskandar, a Stanford Fellow, for the summer to assess energy resiliency options
for residential units in collaboration with Office of Emergency Services. The study builds on techno-economic
models to compare the cost of different backup energy systems and the level of electric reliability these
technologies may provide during an outage. The final report will be presented at the November 2022 UAC meeting
6.3.2 Completed Projects (Lena Perkins)
In FY 2022 CPAU has received eight applications, declined three and is reviewing five others. Staff is also in
discussions with a few start-ups and will consider asking them to apply for collaborations.
Figure 28: Status to date of all applications to the Program for Emerging Technologies
Deadline Total Received Under Review Declined/Closed Active Completed
FY 2013 13 0 11 0 2
FY 2014 15 0 11 0 4
FY 2015 15 0 11 0 4
FY 2016 14 0 9 0 5
FY 2017 10 0 7 0 3
FY 2018 10 0 9 0 1
FY 2019 9 0 5 0 4
FY 2020 8 0 3 0 5
FY 2021 2 0 1 0 1
FY 2022 8 5 3 0 0
TOTAL 104 5 70 0 29
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7 Communications (Catherine Elvert)
This section summarizes communications highlights, updates on major campaigns and noteworthy events. Copies
of ads and bill inserts are available online at http://cityofpaloalto.org/UTLbillinsert.
Water Supply and Drought: Staff have been proactive about communicating the current situation of water supply
conditions and ever-changing water shortage emergency declarations. As a result of the continued dry conditions,
CPAU continues a robust outreach campaign about water supply conditions, water use restrictions, and resources
for water use efficiency. Staff are working with the Bay Area Water Supply and Conservation Agency (BAWSCA)
and Valley Water to coordinate public education events. Updates are available at cityofpaloalto.org/water
Business and Key Account Customer Surveys:CPAU regularly conducts customer satisfaction surveys
and this fall is currently conducting a survey of our commercial, other non-residential, and Key Account
customers. This survey aims to measure customer satisfaction levels and opinions, as well as identify
opportunities to improve the services and programs we provide to all of our customers.
Gas Safety Outreach:Throughout the year, CPAU delivers a variety of outreach materials to the
community about utility safety. An important element of our public awareness program is the annual
distribution of our gas safety awareness brochure. Per Federal Department of Transportation
regulations, we directly mail this information to all customers, non-customers living near a gas pipeline,
public officials, emergency responders, excavators, contractors, and locators working in Palo Alto. Gas
safety brochures were delivered in November. If interested in additional details about gas safety or this
outreach, please visit cityofpaloalto.org/safeutility
Gas Safety Awareness Surveys: It is important to assess the effectiveness of our outreach for gas safety
to guide our actions, and it is also required for public awareness per the Federal Department of
Transportation. A primary way most utilities, including CPAU, do this is by contacting stakeholders
through a randomized phone or email survey to ask questions about gas safety. Questions address items
such calling USA 811 before digging, who to call and what to do in case of a gas leak, among others.
During the month of November, we will engage with a contractor to conduct these stakeholder
awareness surveys.
Mayors Climate Protection Award:The City was recognized earlier this year with an honorable mention
for the 2020 Mayors Climate Protection Awards. The award highlighted our Multifamily Gas Furnace to
Heat Pump Retrofit Pilot Program, which will reduce the City’s greenhouse gas emissions and serves as
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42Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
a case study for future electrification projects in multifamily buildings. The Conference of Mayors made
the announcement at their Annual Meeting in Reno, Nevada on June 3. Mayor Pat Burt and City staff
received the award plaque in a special order of the day ceremony at the September 27 Council meeting.
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43Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
8 Legislative and Regulatory Activity
8.1 State legislation (Heather Dauler)
At the time of this writing, the legislature is not in session. In January, at the same meeting where the UAC receives
this quarterly update, staff will present information about 2022 bills that passed and what is expected in 2023.
Also,in January, we will know if Governor Newsom did in fact call a special legislative session in December to delve
into gas prices and oil company profits, and whether any proceedings also included discussions related to electric
vehicles or energy prices.
Fiscally, the state is not entering the new year in the surplus position expected and in fact,may end up with a
$25 billion deficit or more depending on a possible recession. While the state has many billions in reserves to
weather a downturn, the loss of surplus may mean less money for some of the Governor’s clean energy
priorities. We will know more mid-January, when the Governor publishes his proposed budget.
8.2 State regulatory proceedings (Heather Dauler)
Below are issues currently before state regulatory bodies that CPAU is monitoring, primarily through our work
with CMUA and NCPA.
8.2.1 Energy Commission
The CEC implemented the voluntary Demand Side Grid Support Program and held a workshop related to offshore
wind.
8.2.2 State Water Resources Control Board
The Water Board held a second comment period for its Water Loss Control Standards rulemaking. Board staff is
working on guidance for new federal Lead & Copper Rule Standards.
8.2.3 Air Resources Board
CARB is poised to adopt an updated Scoping Plan, the State’s strategy for fighting climate change.
8.2.4 Natural Resources Agency
The Wildfire Safety Advisory Board released its advisory comments to all POU Wildfire Mitigation Plans received
in July 2022. The Board was complementary of CPAU’s Plan.Staff is currently working on our 2023 Plan.
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44Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
Appendices
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45Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
9 Appendix A: Energy Risk Management Program
This appendix provides a quarterly update on the City’s Energy Risk Management Program.
9.1 Overview of Hedging Programs (Karla Dailey)
The City’s Utilities Department maintains a hedging program for its Electric and Gas Utilities. In the Gas Utility the
program protects against short-term (intra-month) price spikes caused by weather or major incidents on the
Western gas system. However, the City does not hedge its gas supply more than one month in advance, choosing
instead to protect the Gas Utility’s financial position by passing gas supply costs through to customers via a charge
that varies monthly based on gas market prices. As a result, the Gas Utility’s only market exposure is the amount
by which gas demand deviates from forecasts within the month. This exposure is relatively small and can be
managed using Gas Utility Operating Reserves. A risk assessment is performed each year as part of the Gas Utility
financial planning process to ensure adequate reserves to cover all risks. The most recent Gas Utility Financial Plan
was adopted June 21, 2021 (Staff Report #12240).
The City has entered into long-term contracts for its Electric Utility to ensure that the City has carbon free
electricity supplies equal to 100% of Palo Alto’s annual electric demand. However, the output from these
generating sources does not match Palo Alto’s electric load. In the summer, the City has a surplus of carbon free
energy and it has a deficit in the winter. This exposes the City to market risk, and staff maintains a hedging program
to protect against this risk. In addition, hydroelectric generators make up approximately half the City’s energy
supply. During dry years these resources do not generate as much energy, creating an additional market exposure
that must be hedged. Unlike the gas hedging program, which is operated by City staff, the electric hedging program
is operated by the Northern California Power Agency (NCPA), a joint powers agency the City formed in partnership
with several other California publicly owned electric utilities, with oversight by City staff.
9.2 Overview of Energy Risk Management Program (Karla Dailey)
The hedging programs described above are conducted in accordance with the City’s Energy Risk Management
Program,which includes a set of Program Policies adopted by the City Council, Guidelines adopted by the City’s
Utilities Risk Oversight Coordinating Committee (UROCC), and Procedures approved by the Utilities Director. In
addition, for the electric hedging program, NCPA maintains its own Risk Management Program. The City is able to
provide policy level oversight of this program through its seat on the NCPA Risk Oversight Committee, which is
held by the City’s Risk Manager.
Per the Energy Risk Management Policies, the City Council must receive quarterly reports on the City’s forward
contract purchases, market exposure, credit exposure, counterparty credit ratings, transaction compliance, and
other relevant data.
9.3 Forward Deals (Eric Wong)
Below is a table of forward Electric Resource Adequacy deals made in Q1 of FY 2023. Palo Alto did not transact
any Electric energy and Gas commodity deal in Q1 of FY 2023.
Figure 29: Electric Resource Adequacy Contracts
Delivery Month Deal Type Avg Capacity
(MW/Mo.)
Avg Price
($/kW/Mo.)
Amount ($)
Jan -Dec '22 Sale 9.45 7.25 823,000
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Attachment: Attachment A: Utilities Quarterly Report FY23-Q1 (14973 : Utilities Quarterly Report FY23-Q1)
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47Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
10 Appendix B: Staffing and Vacancies (Dave Yuan)
As of Q3 FY 2022, the Utilities Department has 45 vacant positions out of 248 authorized positions or a 18%
vacancy rate. Below is a breakdown of the vacancies by division. The Electric and Fiber Engineering and Operations
(E&O) division continues to have the highest number and hardest positions to fill. Electric Engineering and
Operations has a total of 30 vacancies or 33% vacancy percentage. As part of the FY 2022 midyear budget
adjustments, four new positions (Electric Project Engineer (3 FTEs) and Utilities Program Services Manager (1 FTE))
were added to accelerate S/CAP initiatives. These positions are required to increase capacity in project
management, build in-house resources, and design and implement infrastructure upgrades such as increasing
capacity in the electric distribution grid for electrification of single-family residences. Some of the critical and
difficult-to-fill positions include lineperson/cable splicer, compliance technician, engineer, and engineer
estimators. CPAU will continue to seek third party contracts for some of the difficult-to-fill positions until the
positions are filled and staff is trained.
Figure 31: Utilities Vacancies and Position Movements by Division, up to Q3 FY 2022
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Authorized Vacant Active
Division FTE HEs Recruitments Vacancy%
Ad mini .st rat i o n 1 8.5 2. 0 11%
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W GW Eng i nee rin g 25 3 2 1 2 %
W GW Opera ti o n s. 70 8 3 11%
Grand "fotal 248 45 25 18%
Movement by Carlenda.rYear CV2021 CV202.2
Hi res: 15 7
Pro m oti o n s 19 8
Re ir e m e nts 8 2
Se p arati o ns 11 10
48Utilities Quarterly Update: First Quarter of Fiscal Year 2023
January 4, 2023
11 Appendix C: Gas Utility Annual Infrastructure Maintenance and Replacement
Report (Silvia Santos)
In each Quarterly Update the Utilities Department will provide a detailed overview of a single utility’s investment
and maintenance activity. An update on the water utility was scheduled for this report, it is presented as
Attachment B.
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Updated: December 02, 2022 1 of 8
Gas Utility Asset Management
Overview
Executive Summary
·The City provides safe and reliable natural gas service to residents and
businesses;
·The City meets or exceeds federal regulatory requirements (examples:
Accelerated leak survey program & Cathodic Protection maintenance
requirements);
·Gas Main Replacement program continues to replace PVC and
corroded steel pipeline material to increase safety and minimize
greenhouse gas emissions;
·Completed the installation of 20,170 LF of gas main, 126 new gas
services, and 62 gas service reconnected on the Gas Main Replacement 23
project;
·Annually inspects and maintains gas distribution assets;
·Implement Advanced Metering Infrastructure (AMI) and Meter Data
Management (MDM) by September of 2022. Project awarded to Sensus.
Infrastructure Planning
Key infrastructure replacement efforts in the next five years include:
● Apply for federal grant funding opportunities for the replacement of PVC and corroded steel pipelines;
● Replace PVC and corroded steel pipelines, with polyethylene pipe, for gas mains and services;
● Maintain and inspect gas assets for regulatory compliance;
● Replace inoperable large-diameter emergency valves;
● Implement a calibrated hydraulic gas system model;
● Transition to an ESRI-based Geographical Information System (GIS);
● Upgrade utility fleet, equipment, and tools.
System Operations and Maintenance
Asset Management Goals
What are our goals?
-Create and utilize a calibrated hydraulic gas
system model to prioritize future pipeline
replacement projects.
-Minimize gas service interruption during
planned repairs, tie-ins, and installation by
following gas handling procedures.
-Continue with CIP replacements to reduce
maintenance costs and minimize greenhouse
gas emissions, while extending the gas
system life.
-Increase routine maintenance on aging
pipelines to maximize asset life and keep
replacement costs down.
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Figure 1: FTE (Full-time equivalent) Breakdown by Maintenance
Category
TOTAL FTE: 34.4
FTE 0 .13, 0 .4%
System Monitoring
Updated: December 02, 2022 2 of 8
·Staff assigned to New Construction:
Perform gas main and service upgrades at various locations.
Support Capital Improvement Projects (CIP) and install bollards for meter protection.
Replace new gas services, valves, and meters for Development Services projects.
·Staff assigned to System Monitoring:
Monitor and manage the system continuously to ensure it is operating safely and maintaining
adequate pressure throughout the city. A 24/7 On-call staff responds to emergency alerts sent by the
SCADA software.
·Staff assigned to System Inspections:
Valve Exercise: Regularly exercise valves to meet regulatory requirements and ensure proper
operation.
City Gate Stations: Annual inspection of the 4 gas receiving stations.
Cathodic Protection: Take monthly pipe-to-soil reads to monitor cathodic protection levels on steel
pipelines.
Mobile and Walk Leak Survey: Perform annual mobile leak survey of the entire gas system and
biennial walking leak surveys to detect underground gas leaks and check for atmospheric corrosion
on aboveground pipelines.
Patrolling: Perform quarterly inspections of gas pipeline bridge spans and railroad crossings.
·Staff assigned to Planned Maintenance:
Repair and replacement of gas distribution system pipeline, leaks, and valves.
Installation of bollards for meter protection.
Support on Gas Main Replacement projects.
·Staff assigned to Unplanned Maintenance:
Respond to emergencies.
Repair and replace infrastructure requiring immediate attention.
GAS MAINTENANCE ONGOING
Table 1: Status of Gas System Operation and Maintenance Programs
System Operation or
Maintenance Program
Status
Green = good
Yellow =
room for
improvement
Comments
Emergency Valve Inspection
and Exercise
Annual maintenance and exercise are performed on schedule as
part of compliance. Valves are exercised, greased, and cleaned to
ensure the valve nut is accessible and operable. Emergency valve
lids are coated in yellow and are brass tagged for identification.
Non-Emergency Valve
Inspection and Exercise
Inspected and exercised once every 5 years per City’s goal for
maintenance. Valves are exercised, greased, and cleaned to
ensure the valve nut is accessible and operable. Operations is
planning to have a program to locate and expose paved valve
cover lids.
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Updated: December 02, 2022 3 of 8
System Monitoring Continuous system monitoring and alerts via SCADA. Gas
Operations staff handles the monitoring of the gas system and are
adequately trained to operate the system. On-call staff responds
to emergency alerts after-hours. System updates are done
regularly.
City Gate Station Maintenance Annual maintenance is performed on the 4 City gate stations’
regulators along with visual inspection of aboveground piping and
fences. Every station has dual runs with two regulators per run for
redundancy, a working regulator, and a backup (monitoring)
regulator, which are alternated each year.
Gas Supply Monitoring Monthly gas meter revenue reports are generated for each
station from PG&E’s monitoring module. The City’s SCADA
technician monitors and reviews the reports. Whenever a
discrepancy is detected, the SCADA technician requests
maintenance and repair from PG&E. Staff propose installation of
City flow meters and gas quality monitoring equipment for each
station, which would allow City to validate PG&E’s billed gas
volumes and gas quality.
Pressure Monitoring There are currently 10 pressure monitoring points around the City
of Palo Alto, one at each of the 4 City gate stations and 6 in the
outer ends of the City. The pressure monitoring points in the City
are being well maintained by Operations. Additional pressure
transducers for pressure monitoring stations throughout the
system would improve system monitoring and expedite responses
in emergencies.
Large Commercial Gas Meter
Maintenance (Includes VA
Hospital)
Large commercial gas meters include rotary, ultrasonic, and
turbine meter types. These meters are maintained biennial and
replaced once every 10 years. In 2021, only visual inspections
were done for the meters. Maintenance that includes calibration
and checking of oil levels fell behind in 2021 due to a shortage of
staff. Staff is aiming to catch up on maintenance in 2021.
Gas Curb Meter Maintenance The 3-year inspection and maintenance cycle is on schedule. The
City’s curb meters are replaced once every 10 years.
Curb meters that cannot be retrofitted will be replaced as part of
the new AMI project with Sensus.
Residential and Commercial
Gas Meter Maintenance
Meters are inspected and maintained every two years.
Maintenance includes repainting as needed, leak survey, and
aboveground visual assessment of the gas meter set.
Gas Inspection Along Bridges The City has 28 gas main bridge crossings that require
maintenance. Visual inspection (pipeline markers, pipeline
support condition, wrap condition, etc.) and leak surveys are
performed quarterly each year. Recoating of Ross Road gas main
was completed in 2021. One crossing (Foothill Expressway) was
abandoned in 2021 and future projects will abandon more.
Unplanned Maintenance No backlogs of leaks or assets in need of repair. The City maintains
an emergency on-call program to respond to and control gas leaks
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Updated: December 02, 2022
4 of 8
Table 2: Condition of Gas System Assets
or other system emergencies after hours. In order to remain in
compliance, the staff is pulled to respond to emergency
situations, resulting in delays in planned work. Currently
experiencing long lead times for material.
Cathodic Protection
Maintenance and Monitoring 24-hour rectifier monitoring and alerts via Elecsys. Elecsys
provides our Cathodic operators with the troubleshooting and
software support for their system. Rectifiers and galvanic anodes
are regularly inspected and are in good condition. Anodes are
replaced as needed and require more frequent replacement
during the ongoing drought.
Operations is currently using Paradigm software to generate
annual DOT reports. Paradigm will need a software update from
the manufacturer (Fera) for compatibility with the current
operating system.
An apprenticeship program for the cathodic protection crew is
suggested to ensure a sufficient supply of trained staff.
Asset Class Quantity Maintenance Asset Condition
Gas Receiving
Stations (City
Gate Station)
4 Annual
maintenance
1 station
undergoes
maintenance
each quarter.
Standard maintenance is performed by the City’s meter
technicians.
· Visual inspection and regulator alternating is performed
annually
· Paint is inspected quarterly and replaced as needed
· Equipment and parts are maintained quarterly and are in
good condition.
· Station enclosure and safety headers are adequate and in
good condition.
· Station regulators are rebuilt once every three years.
Pressure
Monitoring
Stations
6 system
testing
points and
4 Gate
Stations
Annual
calibration
and
maintenance
· The pressure monitoring points in the City are maintained
regularly by Operations.
· The pressure monitoring systems in all 4 City gate gas
stations were updated in 2016 when the stations were
rebuilt.
· 5 of the 6 pressure monitoring points at the outer ends of
the City are over 20 years old. They should be upgraded
from conduit to fiber optic and additional pressure
monitoring stations should be added.
Cathodic
Protection
577 test
stations
Annual
maintenance
· 158 test stations, on average, are read monthly throughout
the year to meet and exceed the yearly maintenance
regulation.
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Rectifier and
Galvanic
42
Rectifiers
& 10
Galvanic
systems
Monthly
maintenance
·Rectifier systems are in good condition and are being
monitored through Elecsys for power interruptions or low
readings.
·Anode-based systems are suggested for an upgrade to
rectifiers due to poor performance during the ongoing
drought.
Meter
Regulators
Gas Meter
Audit
Project
Once every two
years for the
entire system
·Operations replaces regulators every 20 years as needed as
part of the gas meter replacement maintenance.
·The City is planning to establish a program to replace large
orifice regulators with properly sized regulators.
Gas Meters ~24600 ·Maintenance of curb meters and residential meters is in
good standing.
·Maintenance for large commercial gas meters is aiming to
catch up in 2021 with recent full staffing.
·The City is implementing Advanced Metering Infrastructure
(AMI) with Sensus to transition to smart meters. Currently
in alpha stage 2021.
Risers ~17395 Atmospheric
Survey
Maintenance
The survey is
performed
every two
years.
Risers are in good condition. They are inspected during the
biennial leak survey.
EFV (Excess
Flow Valve)
~8370 No routine maintenance is required for the EFVs in the system.
The City is planning to perform an EFV trip-test when replacing
gas meters.
Gas Valves 110
Emergency
Valves
~3500
regular
valves
Annual
emergency
valve
maintenance
Regular valve
maintenance is
performed once
every 5 years
Maintenance of emergency gas valves and regular valves is in
good standing. Maintenance activities include exercising valves,
greasing valves, cleaning the valve boxes, and ensuring valve
nut is accessible.
Gas Main and
Services
~210 miles
of main
~17,395
services
Mobile and
Walking Leak
Survey
·Ongoing Gas Main Replacement program continues as
planned, prioritizing leak-prone seismically susceptible PVC
and corrosion-prone steel pipelines.
·The single Gas Service Replacement project replaced the
majority of ABS and tenite gas services in the City. The only
remaining ABS and tenite services are on streets with active
street-cutting moratoriums. These remaining services will
be replaced by City crews as their moratoriums expire.
·Once ready, the calibrated hydraulic gas system model will
be used to prioritize future pipeline replacement projects.
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SCADA
Software
NA Quarterly
updates for the
system and
everyday
troubleshooting
for the 4 City
gate stations
The City’s SCADA system is structured for Electrical Utilities but
also handles all needed functions for the gas system. Quarterly
patches and updates ensure the system is in proper working
order. Several gas operations staff are trained to monitor the
SCADA system but are not trained to perform repairs, which are
handled by the City’s SCADA tech or third-party contractors.
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7 of 8
FIGURE 2: 2021 Gas Maintenance and Inspection Charts
0 0 0 0 0
0 0 0
349
0 0 0 58
698 698 698
349 349
0
200
400
600
800
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
Non-Emergency Valve Operation
Valves
Exercised
Monthly
Goal
Remaining
Valve
Inspections
0 0 0
110
0 0 0 0 0 0 0 0
0
110 110
00
20
40
60
80
100
120
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
Emergency Valve Operation
Valves
Maintained
Monthly
Goal
Remaining
Valve
Inspections
1 1 1 1
4
3
2
1
0
1
0
1
2
3
4
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
4 City Gate Maintenance
Station
Maintained
Remaining
Stations
1 Station Per
Quarter Goal
247
160
265
299
367
335
291
160
227
157
225
157
2880
147
0
500
1000
1500
2000
2500
3000
0
200
400
600
800
1000
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
Ba
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Test Stations Pipe-to-Soil Reads
Pipe-to-Soil
Reads
Remaining
Test
Stations
20
21 20 21 20 21 20
21 20 21 20 21
41
0
41
0
41
0
41
0
41
0
41
00
10
20
30
40
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
Rectifier Tests
Pipe-to-Soil
Reads
Bimonthly
Tests
Requirement
28 28 28 28
2828282828
0
5
10
15
20
25
30
35
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
2020 Pipeline Patrol Maintenance
Maintained Pipe
Mains along
Bridges and
Crossings
Quarterly
Maintenance
Goal
Quartely
Maintenance
Requirement
Cathodic Protection Gas Valves
City Gate Maintenance Pipeline Patrol Maintenance
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19
16 0 0 0 0 0 0
0
118 42 26 5 3 3 2
0%
50%
100%
5c 8c 3000 5000 23m 3" Ultra 4" Ultra 35 Tur
2 Year Large Volume Meter Maintenance Program
Completed Pending Total
3
2
4
1 1
4 4
1
3
0
1
3
0
1
2
3
4
5
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
Emergency Leaks (Grade 1) Repaired
Emergency
Leaks
Repaired
Emergency
leaks found
1 1 1 1 1 222 2 4 3 3 2 10 0
2
5 5
6
7
3
5
7
8
7
0
5
10
0
5
10
15
20
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
Gr
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Gr
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Grade 2 Leaks
Grade 2 Leaks Repaired Added Leaks Found in 2021 Grade 2 Leaks
5 2 3 2
20
1
10
4 2 1 2
127 126
102 110 110 111 111 111 110 112 112 112
0
20
40
60
80
100
120
140
0
10
20
30
40
50
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
Al
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Grade 3 Leaks
Grade 3 Leaks Repaired Resurveyed, No Leak Found
G3 Leaks Found Grade 3 Leaks
Gas Meters
Planned Maintenance (Monitored Leaks with planned repairs)
Unplanned Maintenance
Emergency leaks are repaired immediately
Note: Additional staffing and
the AMI & GMR projects
increased the overall number
of meters replaced in 2021.
Staff will re-evaluate the
overall monthly goal.
Note: Additional staffing and
the AMI & GMR projects
increased the overall number
of meters replaced in 2021.
Staff will re-evaluate the
overall monthly goal.
1 1 1
3
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200
150
100
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600
500
400
300
200
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J.39
108
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214
15 H,7 1/}. 175 16<)
101
fil l
-Replaced
Me ters
-----Monthly Goal
JA N FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
Gas Meter Test i ng Program
27
-TeMed Meters
345 3 l J5,r.
l-Sl -- - - -Monthly Goal
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221
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JA N FEB MAR APR MAY JU N JUL AUG SEP OCT NO V DEC
I I I I I I I
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