HomeMy WebLinkAbout2017-06-07 Utilities Advisory Commission Agenda Packet
NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956
I. ROLL CALL
II. ORAL COMMUNICATIONS
Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable
time restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from
discussing or acting upon any topic initially presented during oral communication.
III. APPROVAL OF THE MINUTES
Approval of the Minutes of the Utilities Advisory Commission Special Meeting held on May 3, 2017
IV. AGENDA REVIEW AND REVISIONS
V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS
VI. DIRECTOR OF UTILITIES REPORT
VII. COMMISSIONER COMMENTS
VIII. UNFINISHED BUSINESS
None
IX. NEW BUSINESS
1. Election of Officers Action
2. Staff Recommendation that the UAC Provide Feedback on the Development of the Discussion
City of Palo Alto Utilities Electric Integrated Resource Plan
3. Staff Recommendation that the Utilities Advisory Commission Recommend that the City Action
Council Approve Community Solar Preliminary Program Design Elements and Feedback
on Application of Design Elements for a Solar Photovoltaic Project at the Municipal Golf
Course Parking Lot
4. 2017 Utilities Strategic Plan Progress Report Discussion
5. Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action
NEXT SCHEDULED MEETING: July 12, 2017 - Special Meeting
ADDITIONAL INFORMATION
The materials below are provided for informational purposes, not for action or discussion during UAC Meetings (Govt.
Code Section 54954.2(a)(2)).
Informational Report
Public Letters to the UAC
12-Month Rolling Calendar
UTILITIES ADVISORY COMMISSION
WEDNESDAY, JUNE 7, 2017 – 7:00 P.M.
COUNCIL CHAMBERS
Palo Alto City Hall – 250 Hamilton Avenue
Chairman: Vice Chair: Michael Danaher Commissioners: Arne Ballantine, Lisa Forssell, A. C. Johnston, Judith Schwartz, Lauren Segal and Terry Trumbull Council Liaison: Eric Filseth
Utilities Advisory Commission Minutes Approved on: Page 1 of 13
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF MAY 3, 2017 SPECIAL MEETING
CALL TO ORDER
Chair Cook called the meeting to order at 12:15 p.m. Meeting of the Utilities Advisory Commission
(UAC).
Present: Chair Cook, Vice Chair Danaher, Commissioner Schwartz, and Councilmember Filseth
Absent: Commissioners Johnston, Ballantine, Forssell, and Trumbull
Commissioner Cook said there was no quorum, but they would proceed with the meeting without
the ability to take action. Commissioner Forssell was expected to arrive late.
Commissioner Forssell arrived at 12:43 p.m. and Chair Cook called the meeting to order (as noted
in the minutes below during Item 3).
Present: Chair Cook, Vice Chair Danaher, Commissioners Schwartz and Forssell, and
Councilmember Filseth
Absent: Commissioners Johnston, Ballantine, and Trumbull
ORAL COMMUNICATIONS
Utilities Inspector and City of Palo Alto Service Employees International Union Chapter Chair Lynn
Krug spoke regarding the number of grievances emanating from Utilities Operations, Engineering,
and Public Works Operations. She believed this could be improved by having a Human Resources
representative at Elwell Court and the Municipal Services Center. She thanked management for
stationing a Human Resources representative temporarily at Elwell Court, but recommended
making this permanent. She believed making the change would help with employee morale. She
also spoke regarding an ongoing vacancy in the Division Head of the Engineering Division. She said
it was important that position be filled quickly by somebody with engineering expertise to ensure
smooth operation of the Division.
Herb Borock spoke regarding the meeting procedures. He said it was inconsistent with the Brown
Act to proceed with the UAC meeting without a quorum of Commissioners.
REPORTS FROM COMMISSION MEETINGS/EVENTS
None.
DRAFT
Utilities Advisory Commission Minutes Approved on: Page 2 of 13
UTILITIES GENERAL MANAGER REPORT
General Manager and Assistant City Manager Ed Shikada delivered the General Manager’s Report.
First Place Award for Most Solar Watts Per Customer
CPAU ranked first place on the Smart Electric Power Alliance (SEPA) Top 10 utility list for solar
watts per customer connected to the grid in 2016. SEPA’s 10th annual survey includes figures from
412 utilities across the country. CPAU ranked number one with 2,753 watts per customer installed
in 2016. This is the fourth time Palo Alto has made SEPA’s Top 10 list of utilities. Awards were
announced last week at the Utility Solar Conference in Tucson, Arizona. Utilities Resource Planner
Lindsay Joye delivered a presentation to conference attendees about the history of Palo Alto’s
solar programs and accomplishments leading up to this first place award. Congratulations to the
entire team!
In addition to issuing awards for solar successes, SEPA provides research and technology resources
for member utilities, including evaluation and analysis of industry trends. One recent contribution
from SEPA is a white paper which Commissioner Schwartz shared with us about utilities’
relationships with electric vehicle vendors, owners, and use of technologies to “manage” charging
for effective electric load management. We shared a copy of this in a recent media update for the
UAC.
Local Solar Projects
A number of activities are underway as part of the City’s Local Solar Plan goal to generate 4%
community-wide electricity from local solar projects by 2023. In addition to CLEAN project
applications for solar PV on city garages, there is interest for installing solar arrays on parking lot
carports at a number of non-city facilities. When these projects are fully built, the systems could
generate 0.5% of the City’s annual energy needs. Staff expects the program to be fully subscribed
by the end of the year.
Staff is also evaluating the potential for a 500 kilowatt PV carport project at the municipal golf
course parking lot which could possibly serve 100 to 200 residents and small businesses. Staff
discussed the project feasibility with the Parks and Recreation Commission on April 25.
Commissioners were generally supportive, but highlighted a number of topics that will require
careful consideration to further develop the project idea. Some considerations include tree
shading, reflective glare at the adjoining airport, incorporating a physical design that blends with
the surroundings, potential impacts on attracting golf course patrons, and risk if the parking lot
needs to be reconfigured within the 20-year life of the solar project. We expect to bring this
discussion back to the UAC in June.
Earth Day Festival and Great Race for Saving Water
The City celebrated Earth Day on April 22 with the Great Race for Saving Water 5K fun run and
walk and festival. This is the fourth year the City has hosted this family-friendly event to celebrate
the environment, water resources, sustainability and climate action. This year saw the biggest
turnout and was perhaps most successful in terms of number and variety of activities. In addition
to partnering with the City of East Palo Alto, dozens of community and environmental groups, non-
profits, businesses and student organizations gathered together to share resources for a healthy
climate and healthy community. The City plans to host the event again on April 21 in 2018.
Utilities Advisory Commission Minutes Approved on: Page 3 of 13
Upcoming Events and Workshops - Details and registration at cityofpaloalto.org/workshops
• Heat Pump Workshop with Passive House California: Wednesday, May 24, 3-6 pm
• Green Building, Lighting and Air Quality Workshop: Saturday, June 3, 9:30-noon
The July 5 UAC meeting date may be changed to avoid conflicts with the Independence Day
holiday.
The Joint Study Session with the Council is scheduled for August 21.
Shikada also noted that this was Chair Cook’s last UAC meeting since he had not sought
reappointment. Chair Cook had been on the UAC since 2010. He thanked Chair Cook for his
service. He said he would arrange with the City Council for a commendation at an appropriate
time.
COMMISSIONER COMMENTS
None.
UNFINISHED BUSINESS
None.
AGENDA REVIEW AND REVISIONS
Chair Cook moved Agenda Item 3 to the beginning of the agenda, prior to Agenda Item 1.
NEW BUSINESS
ITEM 3: DISCUSSION: Discussion of Smart Grid Assessment and Development of Utility
Technology Road Map and Implementation Plan
At 12:43, Commissioner Forssell arrived.
Chair Cook called the meeting to order.
Jeff Hoel said he wished that staff had specified in the report who had bid on the smart grid
project and how they were selected. He said the Citizen's Advisory Commission he served on was a
good resource to use. He said smart grid systems often needed more bandwidth than expected.
Low latency was important, as well as reliability and security. Fiber was better than wireless in
those areas. Any consultant selected should be able to assess those issues. The City of
Chattanooga had done an excellent job with smart grid and the City should benchmark against
that City's implementation.
Herb Borock listed several reports and surveys previously done in 2011 related to smart grid. RKS
survey consultants had found the privacy and control were most important to consumers.
Technology was also important. He said a Fiber to the Premise (FTTP) system provided better
privacy and faster communication of data than wireless. People wanted to be informed about
spikes in usage quickly. Back office functionality was also a major concern and would need to be
upgraded to deliver the kinds of services customers would want from a smart grid system as
compared to a system in place solely for billing purposes.
Commissioner Schwartz said she would also like to see the list of people who submitted bids. She
asked where the UAC could see the results of the pilot projects.
Utilities Advisory Commission Minutes Approved on: Page 4 of 13
Commissioner Schwartz asked about the results of the pilot projects and if there was any customer
surveys done.
Senior Resource Planner Shiva Swaminathan said there were some internal assessments of the
pilot projects, but it was not ready for presentation yet. One consultant task was to review this
information and pull it together into a presentable format. The quarterly report was one place to
see these types of updates. Swaminathan also mentioned that staff had also done some
participants surveys interviews in the cents months and will be sharing that information.
Commissioner Schwartz asked whether the pilot had involved a customer portal.
Swaminathan said it did. There were three portals involved, provided by Utilismart. There was a
consumer portal, a utility portal, and a network health portal. Customers could see their usage on
an hourly basis.
Commissioner Schwartz said there were some people who said an hour was not a granular enough
time scale for people to fully understand their usage.
Swaminathan said it was possible for people to independently disaggregate their usage using tools
that connect to the zigbee radio in the meter, other than what the City provides in the portal, and
some residents had done that.
Commissioner Schwartz said she thought that Utilitworks's proposal did not reflect the unique
characteristics of the City of Palo Alto. She wondered if there was something she could review
related to the Utiliworks contract that would shed light on the unique factors that would be faced
by an implementation in Palo Alto.
General Manager Shikada said the Utiliworks contract was not under consideration by the UAC
that night.
Commissioner Schwartz said that what was presented is a standard process to do such consulting
work and wanted to understand what the consultant provided was different than those of
communities such as Lodi, Riverside or Alameda.
Swaminathan said that staff invited four finalist consultants to make presentations in person, in
Palo Alto, on how they would undertake the assignment for this community. The finalist was
selection by staff was based on past qualification of the firm and their ability to meet the needs of
this community as outlined by staff in the RFP and documents we had provided them.
Utilities Strategic Business Manager Dave Yuan said, as a member of the evaluation committee,
what impressed him the most was their thought depth of experience and their through process to
implement beta-version of the project over an 18 month period to test technology before mass
deployment.
Commissioner Schwartz said that she was a consultant and that consultants can give something
specific or generic, and what she was hearing was that this is the consultant process and we
accepted it.
Utilities Advisory Commission Minutes Approved on: Page 5 of 13
Assistant Director – Resource Management Jonathan Abendschein asked Commissioner Swartz if
she could share her ideas about unique Palo Alto features that staff should consider as the
evaluation gets underway with consultants.
Shikada said some of the key issues for him included technology risk management to implement
systems across all three utilities, operational issues related to deployment and staffing.
Commissioner Schwartz mentioned that she was not looking for that, but will take the
conversation off-line.
Commissioner Schwartz asked how staff planned to select the right CIS system without knowing
for functional requirements for such systems.
Swaminathan pointed out that City is currently developing CIS specification in a separate process,
currently underway with Plante Moran as consultants.
Yuan mentioned that MDM/AMI deployment was contemplated when developing the CIS
specifications and that Utiliworks for a subcontractor helping under that assignment too.
Abendschein added the CIS specification also considered input from retail rates and operations,
and cited solar PV net energy meter successor program as an example of thinking through of
systems we need over the next decade.
Vice Chair Danaher suggested that some of the detailed questions about the specifications could
be taken offline. He recommended there be some interim discussions on the topic of the smart
grid before delivery of the final report.
Swaminathan agreed to the request of interim check-in with the Commission as the project
proceeded.
Chair Cook asked whether anything significant had changed in the technology or how the
technology was used since the last assessment was done.
Swaminathan said the devices had become more robust, but the functionality of the meters had
not changed significantly. However, the number of applications available for use of smart meter
data had grown significantly since the last assessment.
Chair Cook asked the same question Commissioners had asked in 2012, that is, whether there was
a real value in the devices. Palo Altans appreciated having advanced technology available, but was
the value there?
Swaminathan said there was clearly value in the capabilities a smart grid system could provide to
the utility, as distributed energy resources like PV, EVs proliferate in the distribution grid.
Commissioner Forssell asked whether the cost of carbon was included in its cost benefit
assessment of a smart grid system, and if so, what carbon price was used.
Utilities Advisory Commission Minutes Approved on: Page 6 of 13
Swaminathan said the cost of carbon was included, and staff used the market price of carbon.
Commissioner Schwartz recommended using the voluntary Data Guard protocols, the DOE
sponsored consumer energy data privacy program and vendor code of conduct, with the smart
grid system from the start. It was a way to provide reassurance to members of the community that
the utility was taking issues of privacy seriously.
Shikada appreciated the comment and said there was a directive from the City Council to develop
a standard like this.
Commissioner Schwartz said the City was not on the vanguard of smart grid technology. The
technology was well field-tested. If the City moved forward it would simply be moving into the
mainstream.
ACTION: No Action.
ITEM 1: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that
the City Council Adopt the Proposed Operating and Capital Budgets for the Utilities Department
for Fiscal year 2018
Utilities Strategic Business Manager Dave Yuan thanked Commissioners Forssell and Johnston for
their review as part of the UAC Budget Subcommittee. He reviewed the timeline for the annual
budget cycle. He discussed the proposed rate adjustments, including a 14% increase to electric
rates, a 4% increase to gas rates related to the carbon neutral as plan, a 3% decrease to water
rates resulting from the removal of drought surcharges, and a 3.5% CPI increase to EDF-1 fiber
rates. No increase was proposed to sewer rates. He noted residential Refuse rates were increasing
to balance residential and commercial rates with the cost of service, and Storm Drain rates were
increasing in line with a recent voter-approved plan. He reviewed the City's residential utility bills
for electric, gas, wastewater, and water services compared to other utilities. The total bill was 16%
below the average of neighboring cities. He gave a summary of discretionary as compared to non-
discretionary charges. These ranged from 29% to 37% for electric, gas, wastewater, and water
services, and were 82% for fiber services. He talked about strategies to control costs. For example,
staff had rebid capital projects that had come back with high costs. They had also investigated
streamlining operations around staff vacancies. One example was combining the water and gas
meter shops. Staff also worked to contain charges allocated to the City by external agencies. He
talked about factors that affected costs, including increasing commodity costs, costs for capital
replacement, and salaries and benefits costs, and decreasing customer usage. This had also
resulted in decreasing rates of capital replacement. There were difficulties in filling positions.
Vice Chair Danaher said the issue of vacancies was an important one, though not within the
purview of the UAC. It was part of the issue with capital replacement, and could degrade
performance and lead to cost-ineffective business practices if we’re unable to hire qualified staff.
He said it would be good to think about the long-term implications of continuing reduced rates of
capital replacement.
Yuan noted that the most recent gas main replacement project had come back with high costs and
staff would review the bid and submit a budget change to address this.
Commissioner Schwartz asked what the UAC could do about these issues.
Utilities Advisory Commission Minutes Approved on: Page 7 of 13
Shikada said there would have to be management review of issues at such as the increased gas
main replacement costs. We would need to evaluate the bids more specifically. Right now this
was primarily informational for the UAC. Salaries and benefits is an ongoing issue with Council.
Councilmember Filseth asked whether the information related to the gas main replacement
project would be included in the Finance Committee meeting on May 18.
Shikada said the May 18 meeting would address rates and financial forecasts at a higher level.
Some of these more detailed issues would be part of an ongoing management discussion.
Yuan listed some major initiatives planned for the year, including the Utilities Strategic Plan, the
Downtown University CIP projects, the Carbon Neutral Plan for the gas utility, the Smart Grid
Assessment, local solar generation projects coming online, and workforce development.
Chair Cook asked for public comment before beginning with reviews of the budgets for each
utility.
Citizen Herb Borock commented on the fiber optic initiatives specifically on expansion of dark fiber
opportunities and development of a work plan to support next generation broadband. At the April
UAC meeting, Chief Information Officer Jonathan Reichental said the future was headings towards
5G and wireless instead of fiber-to-the premises and wired. I hope Policy and Services Committee
and Council will have an opportunity to discuss and provide direction on the fiber initiatives.
Yuan reviewed the Electric Utility budget. He said the electric fund costs were increasing in part
due to new renewable projects coming online. There were several capital projects being moved
into FY 2018. He said a significant portion of the Calaveras debt service would be paid off by 2024,
and the remainder by 2032. He discussed the CIP plan for the next five years. Some of the costs
were backlogged from 2017. He noted a spike in FY 2020 related to smart grid projects. He
highlighted several projects, including facility relocation for Caltrain and a project at Colorado
Station. Major initiatives for the electric utility included replacing aging underground utility
infrastructure, upgrading substation facilities, increasing the renewable energy in the City's
portfolio, and continuing to implement cost-effective electrification projects.
Yuan reviewed the Fiber Utility budget. There are no significant changes to the fiber budget. The
fiber optic system rebuild CIP is expected to be completed in 2018 to increase capacity at
congestion points near Stanford Research Park and downtown areas.
Chair Cook asked staff what the impacts were of not keeping up with the capital improvement
plan.
Shikada noted there have been issues in filling vacancies in the Engineering Division. He also noted
there had been some delay in the Downtown water and gas projects to exercise due diligence to
ensure minimal impact to University Avenue.
Chief Operating Officer Dean Batchelor said construction costs had been increasing, and staff had
rebid projects, which resulted in delays. Staff would propose additional funding for the CIP
program to enable continuing investment in the system.
Utilities Advisory Commission Minutes Approved on: Page 8 of 13
Shikada said the pace of replacement had not decreased to the point of creating any kind of safety
concern.
Batchelor noted that most ABS gas lines had been removed in a previous gas main replacement
project. Staff was continuing on to begin replacing PVC gas mains.
Yuan reviewed the Gas Utility budget. He said the primary increase in the budgets were related to
commodity costs, including increases to Pacific Gas and Electric (PG&E) transportation rates and
costs related to implementation of the Carbon Neutral Gas Plan. The most notable CIP project was
gas main replacement project 22, which would address University Avenue downtown as well as
other locations. Another initiative for the gas utility was the cross-bore safety inspection program,
which would cost roughly $1 million per year for three years. This was due to a change in
construction techniques decades ago from trenching to boring of new gas lines. This sometimes
resulted in boring through sewer lines. This budget was to video inspect older and higher risk
laterals with potential cross-bores.
Chair Cook asked if this was a one-time cost or ongoing cost.
Batchelor said it was a one-time cost. Staff's current practice when boring new services was to
inspect any sewer lines for cross-bores at the time the install was done. This project was only to
assess older high risk boring installations.
Yuan reviewed the Wastewater Collection Utility budget. There are no significant changes in the
wastewater collection operating and capital budgets. Staff is not proposing any rate adjustment in
FY 2018.
Yuan reviewed the Water Utility budget. He noted commodity costs were going up due to seismic
rehabilitation of the Hetch Hetchy system. The five year CIP outlook included the University
Downtown water line replacement, seismic upgrades to the City's reservoir system, as well as a
study to assess the current configuration of the City's reservoirs to improve efficiencies and
emergency response.
Yuan discussed staffing trends. He noted proposed additions to staff, including a Chief Operating
Officer, replacing two hourly customer service representatives with a full-time Customer Service
representative, reclassifying an Equipment Operator with a Cement Finisher, and combining the
gas and water meter shops. He showed vacancy rates for the utilities, which was roughly 15%
vacancy for most utilities. No significant changes in the vacancy rate had been seen over the
previous several years.
Chair Cook thanked Commissioners Forssell and Johnston and Vice Chair Danaher for being a part
of the UAC Budget Subcommittee and asked if they wanted to comment.
Vice Chair Danaher noted there had increasing hydroelectric power and asked whether there
would be improvements to the budget outlook as a result.
Yuan confirmed there would be.
Utilities Advisory Commission Minutes Approved on: Page 9 of 13
Commissioner Forssell noted that staff vacancies were a significant concern. She hoped the City
did not find itself in the same position the following year, with the resulting operational issues
such as CIP projects not being completed or postponed. She thought it was important that there
may be rate impacts due to having to catch up on CIP projects in the future.
Yuan noted that not all projects are being postponed but some are continuing into the next budget
cycle. Some projects are planned as multi-year projects.
Chair Cook asked about the status of the second transmission line into Palo Alto. It seemed to be
taking a very long time to get the project done.
Shikada said that over the course of the previous year there had been several meetings with SLAC
and Stanford University. There had been the need to give Stanford University some time to
analyze possible ways to participate in the project. It was time to press the University soon about
whether it made financial sense for them to participate. If they did not want to, the City could
pursue an alternative project with PG&E.
Commissioner Schwartz said it was an important issue, and it was worth considering its priority
relative to other utility projects.
Chair Cook asked how the utilities were doing with respect to the reserve guidelines.
Yuan said most utilities reserves were within guidelines. The electric utility reserves were slightly
below guidelines, but good hydroelectric conditions were expected to improve the situation.
ACTION:
Commissioner Danaher moved to recommend that the City Council approve the Utilities
Department FY 2018 Operating Budget proposal. Commissioner Forssell seconded the motion. The
motion carried unanimously (4-0, with Chair Cook, Vice Chair Danaher and Commissioners Forssell
and Schwartz voting yes and Commissioners Johnston, Ballantine and Trumbull absent).
Commissioner Danaher moved to recommend that the City Council approve the Utilities
Department FY 2018 Capital Budget proposal. Commissioner Forssell seconded the motion. The
motion carried unanimously (4-0, with Chair Cook, Vice Chair Danaher and Commissioners Forssell
and Schwartz voting yes and Commissioners Johnston, Ballantine and Trumbull absent).
APPROVAL OF THE MINUTES
Commissioner Schwartz clarified that on page five of sixteen it said "she had seen a presentation
by Commissioner McAllister." She corrected it to say that "she had seen a slide at the Renewables
Rush conference.” It turned out that the slide had been presented by Jay Andrew Murphy, Sr. Vice
President of Strategic Planning at Edison International, rather than Commissioner McAllister, who
was a CPUC commissioner rather than a CEC commissioner as had been stated in the minutes. She
had obtained a similar slide and provided it to General Manager Shikada.
Commissioner Forssell asked whether she could vote to approve the minutes given that she had
not been at the meeting. She knew her vote was needed for a quorum.
Utilities Advisory Commission Minutes Approved on: Page 10 of 13
Senior Deputy City Attorney Jessica Mullan said it would be appropriate given Commissioner
Forssell’s access to materials from the meeting online.
Commissioner Schwartz moved to approve the minutes from the April 5, 2017 UAC meeting with
the corrections noted previously. Commissioner Danaher seconded the motion. The motion
carried unanimously (4-0, with Chair Cook, Vice Chair Danaher and Commissioners Forssell and
Schwartz voting yes and Commissioners Johnston, Ballantine and Trumbull absent).
ITEM 2: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that
the City Council Declined to Set an Energy Storage System Target Due to Lack of Cost-effective
Options
Senior Resource Planner Shiva Swaminathan said this was a reprise of a discussion related to
storage and microgrids with the UAC in October 2016. AB 2514 required that every three years
publicly owned utilities (POUs) are required to make a determination of whether it was cost-
effective to set storage goals. The City had made a determination three years ago that such a goal
was not cost-effective, and was recommending making the same determination at this time. Staff
had reviewed thirteen value propositions for storage in Palo Alto. Many of the potential uses for
storage had minimal value in Palo Alto, and the costs of storage still outweighed the benefits.
However, staff recommended considering a pilot storage project within the next three years. The
best projects would fulfill multiple roles, providing benefits to the customer, the distribution
system, and the transmission system.
Chair Cook noted this was an action item recommending that the City not set a goal for installation
of energy storage systems. He asked what the next steps were.
Swaminathan said that following the UAC recommendation staff would ask for Council's
recommendation, and would then file the decision with the California Energy Commission (CEC).
Chair Cook asked whether staff anticipated any pressure from the CEC to adopt a goal.
Swaminathan said he did not, thought legislative action was always possible to require POUs to set
a goal.
Shikada asked Swaminathan to discuss whether the City’s assessment was in line with other POUs’
assessments.
Swaminathan said most POUs had not set a goal. He said page four of the October 2016 report
listed a number of POUs that had set goals. He said the few POU who had set storage goals had
use cases that worked well for them specifically. For example, Redding Electric Utility had a hot
climate and air conditioning load.
Shikada noted that other POUs had unique circumstances. For example, Silicon Valley Power
(Santa Clara) had obtained grant funding that enabled installation of storage. Cost-effectiveness
was the standard for setting the goal.
Commissioner Schwartz noted that she had learned that week that PG&E had a program to offer
storage and renewable generation incentives to its customers. This would be happening in
neighboring cities, which could lead to Palo Altans not understanding why these programs were
Utilities Advisory Commission Minutes Approved on: Page 11 of 13
not available in Palo Alto. She said it was important to be able to explain the reasons and
communicate well with the public. She said it would be good to explore having other programs
that reduced barriers, such as an improved permitting process, as a substitute for these programs.
It was possible to facilitate storage in Palo Alto without paying customers. She asked staff to
articulate the reasons that storage was not ready in Palo Alto when PG&E found it ready.
Swaminathan said the PG&E programs, such as the Small Generation Incentive Program (SGIP),
were not intended to be cost-effective. They were intended to transform the market.
Abendschein said as a very large utility with a large rate base, PG&E could afford to engage in
market-transformational programs that would not be affordable or effective in a small utility like
Palo Alto. It was more compelling to engage in other programs to reduce barriers for people who
wanted to voluntarily install storage.
Commissioner Schwartz said the small rate base and difficulty of funding those programs sounded
reasonable, and it was important to communicate that effectively and let people know what
options they had to take voluntary action on their own and what the City was doing to facilitate
that.
Swaminathan said that some storage had been installed in Palo Alto voluntarily and there had
been some efforts to improve processes. A pilot program was planned to help the utility learn
more about how to integrate this sort of technology.
Commissioner Schwartz noted that any pilot should have a different flavor than other pilot
projects. It should not be something like a double-blind study, but rather a learning experience.
For example, the Fire Department might find they have specific issues to be aware of when
responding to a fire at a house with a storage system.
Swaminathan agreed. He also said it would be useful to learn about how storage projects could be
used to dispatch services into the California Independent System Operator (CAISO).
Commissioner Schwartz said that was an interesting possibility and thought it would be useful to
also include other controllable loads like water heaters in that type of a pilot.
Vice Chair Danaher asked whether technologies like storage and smart grid would be considered in
the strategic plan.
Shikada said smart grid would require organizational planning. He said storage was an example of
one technology in the wide range of new technologies that would need to be planned for in the
strategic plan.
Swaminathan said he also thought the strategic plan could also influence the City’s strategy by
determining what role the utility would play in this type of technology integration, which would
inform the projects the utility took on.
ACTION: Commissioner Schwartz made a motion to recommend that Council adopt the staff
recommendation to decline setting a target for energy storage, but to also encourage exploration
and facilitation of ways to encourage investment by members of the community.
Utilities Advisory Commission Minutes Approved on: Page 12 of 13
Vice Chair Danaher proposed a friendly amendment to the wording, modifying it to “encourage
exploration and facilitation of budget neutral ways to encourage investment.”
Commissioner Schwartz agreed.
Commissioner Forssell seconded the motion. The motion passed unanimously (4-0, with Chair
Cook, Vice Chair Danaher and Commissioners Forssell and Schwartz voting yes and Commissioners
Johnston, Ballantine, and Trumbull absent)
ITEM 4. DISCUSSION: 2017 Utilities Strategic Plan Progress Report
General Manager and Assistant City Manager Ed Shikada discussed the key drivers of the Utilities
Strategic Plan. Staff had compiled a list of statutory and regulatory State and Federal mandates the
utility was operating under, including the agencies that regulated our operation. He also showed a
list of Council-directed policies and plans. He noted he was aiming to consolidate these plans into
a more digestible format. All of this information had been provided as an addendum to the
Strategic Plan Request for Proposals (RFP). Consultant selection continued, with the goal to have a
contract approved by late June 2017.
Commissioner Schwartz asked if it was possible to see the list of consultants considered.
Shikada said he saw no problem with providing that list, though that was not typical City practice.
He said he would hesitate to provide actual pricing.
Vice Chair Danaher recommended sharing this information with Commissioner Schwartz
separately rather than sharing it with the full UAC publicly. He was concerned it would discourage
bidders.
Shikada said he would do that.
Vice Chair Danaher said it would be helpful to have a discussion of strategic planning in advance of
the joint UAC and Council meeting.
Shikada said he would work to accommodate that schedule as much as possible.
ACTION: No action.
ITEM 5. DISCUSSION: Joint Study Session between the Council and the Utilities Advisory
Commission
General Manager and Assistant City Manager Ed Shikada said there was a joint study session
scheduled for August 21. He noted there would be some turnover in Commissioners. He was
attempting to set up a meeting between the Chair and Vice Chair of the UAC and the Mayor and
Vice Mayor to discuss topics in advance of the meeting. He was sure that the UAC would want to
discuss the Utilities Strategic Plan as well as Fiber to the Premise.
Commissioner Schwartz expressed her disappointment that she would not be able to attend.
Utilities Advisory Commission Minutes Approved on: Page 13 of 13
Shikada said he would look for opportunities to get feedback from Commissioner Schwartz in
advance of the meeting.
Chair Cook recommended not changing the meeting date, given that it had been so long since the
UAC had a meeting with the City Council, unless there were a feasible way to reschedule and
accommodate Commissioner Schwartz.
ACTION: No action.
ITEM 6. ACTION: Selection of Potential Topics(s) for Discussion at Future UAC Meeting
General Manager and Assistant City Manager Ed Shikada said the rolling calendar was now online
and available to the public. He said staff had tried to reschedule the June UAC meeting but had
been unable to find a date that worked for everybody. Staff was working on rescheduling the July
meeting as well to accommodate Commissioner schedules. He was considering rescheduling the
Community Solar and Long-term Electric Acquisition Plan to July.
Commissioner Schwartz said a backup plan would be for her to provide a copy of her report on
Community Solar to share with the UAC at the June meeting.
ACTION: No action.
Meeting adjourned at 2:40 p.m.
Respectfully Submitted,
Marites Ward
City of Palo Alto Utilities
Page 1 of 6
2
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILTIES DEPARTMENT
DATE: June 7, 2017
SUBJECT: Staff Recommendation that the UAC Provide Feedback on the Development of
the City of Palo Alto Utilities Electric Integrated Resource Plan
______________________________________________________________________________
REQUEST
Staff seeks UAC feedback on a proposed work plan to update the Long-term Electric Acquisition
Plan to become the City’s Electric Integrated Resource Plan, which will be created in compliance
with Senate Bill 350. There is no recommended action.
EXECUTIVE SUMMARY
The Long-term Electric Acquisition Plan (LEAP) addresses the City’s strategy for procuring and
managing its energy supply. This involves multiple functions related to the pursuit and
management of the City’s electric resources consistent with State and Federal regulatory and
legislative requirements, the City’s climate sustainability goals, and the Utilities Department’s
strategic planning objectives. The 2012 Council-approved LEAP focused on various initiatives to
reduce the carbon intensity of the City’s electric supply portfolio through energy efficiency, an
aggressive renewable portfolio standard (RPS) and ultimately the consideration of a carbon
neutral portfolio. The LEAP is intended to be updated every three to five years to direct electric
procurement and portfolio management efforts over a ten-year planning horizon. An update of
LEAP is necessary to provide a basis for several key decisions and policies related to the electric
portfolio in the 2020 to 2030 planning horizon.
BACKGROUND
Integrated resource planning (IRP) traditionally is used to develop a plan for meeting forecasted
annual peak and energy demand through a combination of supply-side resources (e.g.
generators) and demand-side resources (e.g. installing energy efficient appliances) over a
specified future period. A comprehensive decision analysis modeling tool is used to evaluate
cost, benefits and uncertainties related to the various alternatives with the objective of
identifying the best-fit, least-cost solutions. Generally, IRPs take the following factors into
account in identifying solutions:
1.Loading Order. Pursue all cost effective energy efficiency and demand-side resources.
2.Regulatory Compliance. Comply with regulatory requirements (e.g. Renewable Portfolio
Standards, rooftop solar) and other standards as appropriate (e.g. CAISO capacity
requirements).
Page 2 of 6
3. Climate Goals and Carbon Neutral Plan objectives. Reduce carbon intensity of the
electric portfolio by utilizing 1) maximum procurement of long-term CEC eligible
renewables; 2) existing large hydroelectric resources; and 3) Renewable Energy Credits
(REC) when long-term resources are not sufficient.
4. Customer Preferences. Facilitate customer preference for other resources (e.g. a desire
for local solar as embodied in the Local Solar Plan or PaloAltoGreen) and facilitate the
deployment in a cost effective manner.
5. Cost. Identify the least-cost approach that addresses Council-adopted objectives,
including rate impact limits such as 0.5 cents/kWh for RPS compliance and 0.15/kWh
cents for Carbon Neutrality. Manage existing resources to maximize value.
6. Risk Management. Structure the portfolio or add mitigations to manage known risks
(e.g. market price risk or hydroelectric variability) and build flexibility into the portfolio
to address other less quantifiable risks (e.g. regulatory uncertainty) through
diversification of suppliers, contract terms, and resources, and through the use of
creditworthy counterparties when appropriate.
The last time the City conducted an IRP was in 1992. The City was facing a decision on whether
to sign a new Western Base Resource (WBR) contract for hydroelectric power from the Western
Area Power Administration for 2005-2025 which would be significantly different than the
contract at the time. The existing contract met almost 100% of the City’s electric needs and had
very little variation in cost. The new WBR contract was expected to meet about 38% of the
City’s expected supply needs.1 The goal of the 1992 IRP analysis was to evaluate several
resources, including demand-side measures, with the objective of identifying the best-fit, least-
cost energy solutions to meet the new deficit position resulting from the new WBR contract.
Ultimately, the City signed the 2005-2025 WBR contract and pursued several other resources.
In November 2001 (CMR: 425:01) Council adopted the first LEAP, which provided policy
direction to guide staff in the acquisition and management of electric supply resources through
objectives and key strategies. The LEAP was different than a traditional IRP, in that its primary
focus was on how to manage the electric portfolio consistent with RPS and other mandates
rather than an exclusive focus on portfolio optimization. The LEAP was later updated in October
2002 (CMR: 398:02) and in March 2007 (CMR: 158:07) to reflect regulatory and legislative
changes in the industry and to align with evolving community values related to energy
efficiency, renewable supplies and climate protection. Within the LEAP Objectives and
Guidelines framework, Council also adopted implementation plans which provided specific
initiatives to evaluate and bring back to Council for consideration.
The last LEAP update took place in 2012 after a multi-year process of reviewing electric portfolio
planning objectives, key strategies, and implementation initiatives (Attachment A and Staff
Report #1317). The LEAP included initiatives to evaluate the feasibility of several policies and
programs, many of which were adopted, including:
1 The was because the new WBR was proposed as a run-of-the-river contract, whereby the City would receive an
allocation of generation based on hydrological conditions along with a corresponding share of costs.
Page 3 of 6
• Development of an avoided cost model which is used to evaluate all demand and supply-
side resources on an equal basis;
• Incorporation of 10-year Energy Efficiency Plan updates to take place every four years
(2012 and 2016);
• Demand Response Pilot Programs;
• An Energy Storage Potential assessment;
• An assessment of gas-fired generation in Palo Alto;
• Evaluating a Clean Local Energy Accessible Now (CLEAN) – feed-in tariff for clean
distributed generation;
• Termination of the PLUG-In Program for cogeneration;
• Update of the Renewable Portfolio Standard;
• A redesign of the PaloAltoGreen program;
• Evaluation of adopting a Local Solar Plan;
• A California Oregon Transmission Project long-term layoff amendment; and
• Evaluation of adopting a Carbon Neutral Plan
DISCUSSION
The need to conduct a traditional IRP has been minimized significantly through California’s and
the City’s adoption of several legislative initiatives and policies which mandate how resources
will be procured through loading order mandates, targets for roof-top solar photovoltaics,
renewable portfolio standards and/or capacity planning reserves. However, on October 7, 2015,
Governor Edmund G. Brown, Jr. signed Senate Bill 350 (SB 350) into law, which among other
things requires that publicly owned utilities (POU) serving loads greater than 700,000 megawatt
hours per year, such as Palo Alto, submit an integrated resource plan (IRP) to the California
Energy Commission (CEC) every five years with the first one due by January 31, 2019. One of
the main objectives of SB 350 is to ensure that POUs are on track to meet the State’s
greenhouse gas reduction goals by 2030.
An update of the current LEAP is necessary and will provide a basis for several key decisions and
policies related to the electric portfolio in the 2020 to 2030 planning horizon. This update will
serve as the basis for meeting the requirements set forth in SB 350 and going forward, staff will
refer to the next LEAP as the Electric Integrated Resource Plan (EIRP).
A key factor for consideration in the EIRP includes the City’s contract with the Western Area
Power Administration (WAPA) for hydroelectric resources from the Central Valley Project (CVP)
which expires at the end of 2024. The process for extending this contract is well underway and
is expected to take five to seven years to complete. The EIRP and corresponding
implementation plan will include discussion and evaluation of the right amount of large
hydroelectric resources to be included in the City’s electric portfolio. The EIRP will also need to
address necessary modifications to the City’s RPS; how to integrate the impacts of distributed
energy resources and electrification; and how to best deliver a carbon neutral portfolio which
meets greenhouse gas reduction goals set forth in the City’s Sustainability and Climate Action
Plan and maintains the financial health of the City’s Utilities.
Page 4 of 6
SB 350 also requires the doubling of energy efficiency savings targets by 2030 and established a
new RPS for all load serving entities from 33% in 2030 to 50% by 2030. The 10-Year Energy
Efficiency Potential Plan approved by Council in March 2017 addresses the new energy
efficiency savings requirements and while the City expects to achieve an RPS of 57% in 2017,
formal adoption by Council of the new RPS and compliance requirements is necessary.
Several state legislative initiatives are underway which may impact the electric portfolio
planning for the City including:
• establishing a 100% clean energy standard, which may impact the viability of large
hydroelectric resources;
• major modifications to California’s cap and trade program; and
• renewed interest in providing full retail competition through expansion of Direct Access.
The new EIRP will need to address the aforementioned initiatives and mandates along with
internal policy drivers and the need to provide customers with low-cost, safe, reliable and
environmentally sustainable electricity.
The schedule and structure of the EIRP process is being guided in large part by requirements
imposed by SB 350 and CEC guidelines to implement it. Passage of SB 350 requires the
development and submission of an IRP to the CEC no later than January 31, 2019. The IRP must
be consistent with CEC guidelines that are still in development. At a minimum, Sections 9621
and 454.52 of the State Public Utilities Code require that the City’s IRP will need to:
1. Meet GHG emissions targets that reflect the electricity sector’s contribution to achieving the
economy-wide greenhouse gas emissions reductions of 40 percent from 1990 levels by 2030
2. Ensure procurement of at least 50 percent eligible renewable energy resources by 2030
3. Meet the following goals
a. Fulfill obligation to serve customers at just and reasonable rates
b. Minimize impacts on ratepayers’ bills.
c. Ensure system and local reliability.
d. Strengthen the diversity, sustainability, and resilience of the bulk transmission and
distribution systems, and local communities.
e. Enhance distribution systems and demand-side energy management.
f. Minimize localized air pollutants and other greenhouse gas emissions, with early
priority on disadvantaged communities
4. Address the following procurement topics
a. Energy efficiency and demand response resources
b. Energy storage
c. Transportation electrification.
d. A diversified procurement portfolio consisting of both short-term and long-term
electricity, electricity-related, and demand response products.
e. Resource adequacy requirements
To address the City’s electric portfolio planning needs in a comprehensive EIRP update and to
meet SB 350’s requirements, staff proposes a series of discussions on specific portfolio elements
over the next 12 to 18 months. These discussions will enable the UAC and Council to have a
Page 5 of 6
better understanding of the issues and decisions facing the Electric Utility and to provide input
and direction early on in the process.
Staff is seeking feedback from the UAC and Council on how to best address the many internal
and external issues, initiatives, directives and requirements in the new EIRP and an evaluation
of the appropriateness of current LEAP objectives and strategies. Table 1 provides potential
discussion topics along with a tentative schedule for UAC and Council consideration.
Attachment B includes an illustration of the proposed work plan.
Table 1: 2017-18 EIRP Tentative Work Plan
Discussion Item Meeting Objectives/Goals UAC Council
1. EIRP Overview
and Work Plan
Provide a high level framework for what will
be discussed, time line; guiding principles;
and key drivers.
June 2017 August 2017
2. Load Forecast,
Needs
Assessment; and
Market Overview
Overview of electric load forecast and
expected supply resources; long-term
energy and capacity needs and California
market overview (tentative)
July 2017 September
2017
3. Distributive
Energy Resources
Strategy and
Planning for
Growth
Distributive Energy Resources Plan - energy
efficiency, Local Solar Plan, distributed
generation, electrification, electric vehicles,
storage and distribution system planning
August 2017,
October 2017,
January 2018
(action)
March 2018
(action)
4. Hydroelectric
Resources
Overview of Palo Alto’s hydroelectric
resources; hydro risk management;
Western Area Power Administration’s 2025
Power Marketing Plan; Calaveras Project;
key decisions; and direction.
September
2017
October 2017
5. Renewable
Portfolio
Standard
Overview of RPS; update to meet SB 350
requirements; renewable over-generation
and curtailments; and other RPS
modifications.
November
2017 (action)
January 2018
(action)
6. Carbon Neutral
Plan
Overview and updates – dependent on RPS
and large hydro direction
February 2018 April 2018
7. Portfolio
Management
and Transmission
Portfolio risk management; delivery costs;
transmission planning; and California
Oregon Transmission Project
February/
March 2018
April/May
2018
8. Proposed EIRP
Objectives, Key
Strategies and
Implementation
Plan
Draft EIRP objectives, key strategies and
implementation plan;
June 2018
(possible
action)
July/August
2018 (possible
action)
9. Final EIRP Approval of EIRP objectives; strategies and
implementation plan; and SB 350 IRP
submittal to CEC
October 2018
(action)
December
2018 (action)
Page 6 of 6
NEXT STEPS
Staff will incorporate the UAC’s input on the proposed EIRP work plan and share with the
Council for their input as well.
RESOURCE IMPACT
There is no direct resource impact as a result of the proposed EIRP work plan. Work will be
performed with existing staff.
POLICY IMPLICATIONS
There is no direct policy impact associated with the proposed work plan, but any changes made
through EIRP will affect policy related to electric portfolio management. Staff will also update
the EIRP to ensure consistency with the City’s sustainability goals as established in its
Sustainability and Climate Action Plan.
ENVIRONMENTAL REVIEW
The Utilities Advisory Commission’s discussion of the EIRP work plan does not meet the
definition of a project under Public Resources Code 21065 and is therefore California
Environmental Quality Act (CEQA) review is not required.
ATTACHMENTS
A. Existing LEAP Objectives, Guidelines and Implementation Plan
B. Proposed Work Plan
PREPARED BY: MONICA PADILLA, Senior Resource Planner
REVIEWED BY: JONATHAN ABENDSCHEIN, Assistant Director, Resource Management
APPROVED BY: ___________________________
ED SHIKADA
General Manager of Utilities
Long‐term Electric Acquisition Plan (LEAP)
Approved March 7, 2011 (Staff Report 1317, Resolution 9152)
Modified by Council March 19, 2012 (Staff Report 2581, Resolution 9237)
Modified by Council April 16, 2012 (Staff Report 2710, Resolution 9241)
LEAP Objectives:
1.Meet customer electricity needs through the acquisition of least total cost energy and
demand resources including an assessment of the environmental costs and benefits
2.Manage supply portfolio cost uncertainty to meet rate and reserve objectives.
3.Enhance supply reliability to meet City and customer needs by pursuing opportunities
including transmission system upgrades and local generation.
LEAP Strategies:
1.Resource Acquisition – Pursue the least total cost resources including an assessment of
environmental costs and benefits to meet the City’s needs in the long term by:
a.Evaluating each potential resource on an equal basis by evaluating rate impacts and
establishing costs and values for location, time of day and year, carbon, value of
renewable supplies and any secondary benefits attributed to the resource; and
b.Including all resources – conventional energy, local and remote renewable energy
supplies, energy efficiency, cogeneration, and demand reduction – in the evaluation.
2.Electric Energy Efficiency and Demand Reduction – Fund programs that maximize the
deployment of cost‐effective, reliable and feasible energy efficiency and demand reduction
opportunities as the highest priority resources by:
a.Every three years, preparing a ten‐year energy efficiency plan that identifies all cost‐
effective energy efficiency opportunities;
b.Using the cost of long‐term renewable energy resources adjusted for time of day factors
and location as the avoided cost when evaluating cost effectiveness of energy efficiency
measures;
c.Designing and making energy efficiency programs available to all customers; and
d.Considering the impacts (costs, benefits and GHG emissions) of substituting electricity‐
using appliances for natural gas‐using appliances and vice versa in the ten‐year energy
efficiency plan.
3.Renewable Portfolio Standard (RPS) – Reduce the carbon intensity of the electric portfolio
by acquiring renewable energy supplies by:
a.Pursuing a minimum level of renewable purchases of at least 33% of retail sales by 2015
with the following attributes:
i.The contracts for investment in renewable resources shall not exceed 30 years in
term.
ii.Pursue only renewable resources deemed to be eligible by the California Energy
Commission (CEC).
iii.Evaluate use of Renewable Energy Certificates (RECs) to meet RPS.
b.Ensuring that the retail rate impact for renewable purchases does not exceed 0.5 ¢/kWh
on average; and
c.Performing an ongoing evaluation of the Palo Alto Clean Local Energy Accessible Now
(CLEAN) program.
ATTACHMENT A
Long‐term Electric Acquisition Plan (LEAP)
4. Local Generation – Promote and facilitate the deployment of cost‐effective local resources
by:
a. Using the renewable market price referent (MPR) adjusted for time of day factors and
location as the avoided cost when evaluating cost effectiveness of local resources;
b. Considering energy delivery cost uncertainty and strategic value options when
evaluating opportunities;
c. Evaluating a Feed‐in‐Tariff to promote locally sited renewable resources;
d. Evaluating cost‐effective energy storage resources; and
e. Evaluating the feasibility of developing a 25 to 50 MW generating facility connect to the
City’s distribution system.
5. Climate Protection – Reduce the electric portfolio’s carbon intensity by:
a. Supporting the City municipal government’s climate protection goals;
b. Promoting the use of technologies (e.g. incentives for cogeneration systems, promotion
of EVs, in‐home energy displays) and programs that will reduce the community’s carbon
footprint at a cost of up to the City’s value of carbon;
c. Continuing to offer a renewable resource‐based retail rate for all customers who want
to voluntarily select an increased content of non‐hydro renewable energy; and.
d. Evaluating quantitative goals for possible future implementation.
6. Hydro Resource Management – Actively monitor and manage cost uncertainty related to
variations in hydroelectric supply and maximize value of hydro resources by:
a. Planning for an average hydro year on a long‐term basis;
b. Utilizing cost effective hydro resource management products; and
c. Implementing opportunities to maximize benefits and reduce costs of the Western Base
Resource and Calaveras hydroelectric resources.
7. Market Price Exposure Management – Actively monitor and manage operational,
counterparty and wholesale energy price risk in the short‐term (up to three to five years) by:
a. Maintaining an adequate pool of creditworthy suppliers; and
b. Diversifying supply purchases across commitment date, start date, duration, suppliers
and pricing terms in alignment with rate stability objectives and reserve guideline.
8. Transmission and Reliability – Pursue the reliability of supply at fair and reasonable
transmission and delivery costs by:
a. Actively participating through collaborative efforts with other entities, in local, regional,
statewide and federal regulatory and legislative forums;
b. Participating in transmission and reliability market design forums to ensure that adopted
market designs result in adequate reliability, workably competitive markets and
equitable cost allocation;
c. Evaluating interconnection options to the City to increase service reliability and lower
delivery costs; and
d. Exploring transmission opportunities and strategies to meet long‐term renewable
portfolio objectives beyond 2020.
Load &
Resources Distributed Energy
Resources and
Strategies
Hydroelectri
c Resources
Renewable
Portfolio
Standard
Carbon
Neutral
Plan
Portfolio
Management &
Transmission
Electric IRP Overview,
Key Drivers & Work Plan
UAC: June 2017
Council: August 2017
No Action – UAC & Council
Feedback & Direction
Final Electric IRP Objectives,
Strategies &
Implementation Plan
UAC: October 2018
Council: December 2018
Action
Draft Objectives,
Strategies and
Implementation
Plan
Possible Action
Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2017 2018
Council
Action
b
Council
Action
Electric Integrated Resource Plan Proposed Work Plan Attachment B
3
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: JUNE 7, 2017
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend that
the City Council Approve Community Solar Preliminary Program Design Elements
and Feedback on Application of Design Elements for a Solar Photovoltaic Project
at the Municipal Golf Course Parking Lot
RECOMMENDATION
Staff recommends that the Utility Advisory Commission (UAC) recommend that the City Council
approve a set of preliminary Community Solar (“Co-Solar”) program design elements to guide staff
as it develops the City’s Co-Solar program (Attachment A).
EXECUTIVE SUMMARY
City of Palo Alto Utilities (CPAU) has promoted solar photovoltaic (PV) and other environmental
stewardship programs within the Palo Alto community for over two decades. As such, CPAU is well
positioned to take on a leadership role in developing a Community Solar (“Co-Solar”) Program for
the benefit of community members for which rooftop solar PV is not feasible. The last attempt to
start a Co-Solar program involved negotiation with a third party vendor, and staff terminated this
effort due to inability to reach agreement on issues of customer risk mitigation and program
transparency. Staff is now proposing that CPAU take on a central role in developing Co-Solar.
Staff is seeking approval of preliminary design elements of a Co-Solar program including site
selection, cost and value proposition to participating customers, funding sources, and ways to
minimize the risk to non-participating electric utility customers. These program elements would
provide a framework for more fully developing a specific program for future UAC consideration
and Council approval.
Staff anticipates issuing a Request for Proposal for a solar PV carport project development at golf
course parking lot in the summer of 2017, seeking participating customer (“co-solar customers”)
pre-commitment by spring of 2018 and returning to UAC and Council for approval in the summer
of 2018, with final implementation planned by spring of 2019. Upon successful completion of the
first Co-Solar project, successive sites will be developed based on demand for such projects from
potential participants.
BACKGROUND
Community Aspirations for Local Solar
The City of Palo Alto (City) has been a leader in facilitating local solar PV electric generation
systems development. Over the past two decades, approximately 1,000 rooftop solar systems
have been installed (8,000 kW capacity), providing about 1% of the Palo Alto community’s
electrical energy needs.
In April 2014, the Council adopted the Local Solar Plan, which set the overarching goal of meeting
4% of Palo Alto’s energy needs from local solar by 2023 (Staff Report 4608, Resolution 9402). This
is equivalent to developing 23,000 kW of local solar capacity by 2023. Community Solar is one the
new programs proposed under the Local Solar Plan.1 It has the potential to enable significantly
more residents and businesses to experience and derive the benefits from local solar deployment,
even if they are unable to install solar at their own premises. Palo Alto has a number of customers
who may find this attractive, including a large percentage of renters, a sizable fraction of residents
living in multi-family homes, and an extensive urban tree canopy that shades numerous residential
and commercial rooftops. A community solar program would give these customers an opportunity,
for the first time, to get their energy from local solar.
Figure 1 below represents a forecast of total installed local solar capacity in 2023 and the
programs expected to generate that installed capacity, including the Palo Alto CLEAN program
(feed-in tariff), the Net Energy Metering (NEM) current and successor tariff and other new policy
initiatives like Zero Net Energy (ZNE) buildings.2
Figure 1: Progress Toward Meeting Local Solar Plan Goal of 4% Energy (23,000 kW) by 2023
Lessons Learned from Prior Attempt at Developing Co-Solar based on a Third Party Turnkey Design
CPAU staff worked with a third-party vendor in 2014 and 2015 in an attempt to launch Co-Solar.
The program design called for a turnkey approach, where the private sector vendor would both
develop the solar project and contract with CPAU customers to receive PV project electricity
generation. However, transparency and customer risk mitigation challenges made the turnkey
approach infeasible in Palo Alto.3 The participant agreements between the third-party vendor and
the program participant did not meet CPAU’s requirements for maintaining transparency in the
1 Community solar is defined as “a solar-electric system that, through a voluntary program, provides power and/or financial benefit
to, or is owned by, multiple community members”. Refer - A Guide to Community Solar: Utility, Private, and Non-profit Project
Development, U.S. DOE and Solar America Communities Report.
2 See CPAU website for details on Palo Alto Solar Programs
3 Informational Report to Council: Community Solar Program Development Update and Redirection of Efforts, Aug 2015
Co-Solar First
Project:
550kW
Potential
Co-Solar
Projects:
2,500 kW
CLEAN
Program:
3,000 kW
@ 16.5 ¢/kWh
Gap to meet
2023 goal:
7,300kW
(rooftop PV
likely by NEM-
SP, ZNE)
NEM
remaining
capacity:
1,600 kW
Currently
Installed Local
Solar:
8,000 kW
(PV Rebates,
NEM, Group
Buy)
contractual arrangement. Other challenges identified at the time included finding a host site for
the solar system, challenges in communicating and marketing the program, and managing the
balance of risk between CPAU and the program participants.
Industry Trends in Developing Community Solar & Value of Co-Solar in Palo Alto
Community solar offerings are increasing throughout the country, with smaller utilities and rural
electric cooperatives being at the forefront of this transformation.4 These programs also tend to
have the local electric utility playing a central role in project development and customer
recruitment for the program. Having promoted a variety of environmental stewardship initiatives
within the community, CPAU is well positioned to take a lead in developing Co-Solar. Providing
local solar access to all interested customers would also provide greater community benefits such
as the opportunity to showcase local solar generation, educational information for children, and
greater local resiliency. The Council has recognized the value of local renewable sources as
compared to energy purchases outside Palo Alto, including:
• reduction in CPAU’s costs and energy losses associated with energy transmission and
distribution,
• a reduction in CPAU’s capacity requirements,
• keeping a portion of CPAU’s electric expenditures within the community, and
• reducing the environmental impacts of the electric system and improving reliability in
transmission-constrained regions like the Greater Bay Area.5
Co-Solar provides a cost-competitive way to deploy local renewables while providing customers a
choice to “go solar”. The cost of developing and installing the community solar facilities could be
lower than developing and installing smaller systems on individual customer roofs.6 Moreover,
optimal community solar program design ensures fair and reasonable cost allocation between
participating and non-participating customers.
DISCUSSION
Staff is seeking UAC and Council approval of preliminary Co-Solar program design elements that
address site selection, cost and value proposition to program participants, and CPAU’s role in the
program development, implementation, and administration. The proposed five (5) elements will
provide a framework for staff to evaluate and develop local sites for Co-Solar projects and to
assess customer interest in participating in the program. Staff may seek exceptions or propose
modification to these design elements from the Council while fully developing and offering each
Co-Solar project.
In summary, Co-Solar projects are anticipated to be developed and owned by third parties on City
owned or privately owned land, with CPAU contracting for energy generated and in turn selling
this energy to customers who value locally generated solar power. If the site is City owned, the
land will be leased from the City to develop the project. The initially identified PV project at the
golf course has the potential to serve 100 to 200 customers and serve 0.1% of Palo Alto’s energy
4 GTM Research, U.S. Community Solar Outlook 2017
5 Refer : Resolution for Palo Alto CLEAN program
6 This trend is true for most regions in the country but could be challenging in Palo Alto due to limited land availability for
developing community solar projects.
needs. If the initial Co-Solar project proves successful, subsequent projects would target to meet
0.5% of the community’s energy needs and serve up to 1,000 customers by 2023.
Community Solar Program Preliminary Design Elements
Element 1: CPAU’s Role in Program Development and Management
Figure 1, below, illustrates the proposed CPAU role in developing and managing Co-Solar. Staff is
proposing a program design in which CPAU would procure local solar by signing a power purchase
agreement with a solar developer, marketing the program to potential customers, and
administering the program for the participants. Participants will receive energy from the Co-Solar
project, albeit no direct flow of electrons, in return for annual or monthly payments. This approach
is different from earlier turnkey based efforts.7 CPAU-led program management will ensure
contractual transparency and mitigate other program development risks that otherwise might
have been borne by participating customers.8 It also enables CPAU to deploy its existing and
trusted customer communication channels to enroll and administer customer participation.
Program Design Element #1
CPAU’s Role in
Program
Development and
Management
CPAU will take a lead role in the program design, procurement,
and management. Specifically:
a. CPAU will identify a site and solicit potential developer
counterparties for execution of power purchase and land
lease agreements.
b. CPAU will market and sell the generated electricity to
participating customers.
c. CPAU will manage changes among participants, balancing
convenience and flexibility for Co-Solar customers with
overall program costs and administrative sustainability.
d. CPAU will purchase the excess energy, the difference
between energy produced and purchased by Co-Solar
participants.
Figure 1: CPAU-led Community Solar Program
Program
Participants
CPAU electric
customers interested
in local solar
Solar
Developer
Finance, Construct,
Operate and Maintain.
Leasing agreement
with site owner.
Solar Energy Payment
(via PPA)
Solar Electricity Delivery
Annual or monthly
payments
RECs, On-bill credit (if
applicable)
PROGRAM
DESIGN
PROGRAM
ADMIN
PROCURE
LOCAL SOLAR
POWER
CPAU
Element 2: Selection of Community Solar Site(s)
Staff recommends that solar PV project sites for Co-Solar be readily accessible to members of the
public, and preferably on publicly owned municipal facilities. A solar system that is installed on a
7 Informational Report to Council: Community Solar Program Development Update and Redirection of Efforts, Aug 2015
8 Program development risks identified in the turnkey third party solution included challenges in finding a host site for the solar
system, challenges in communicating and marketing the program and balance of risk between the City and the program
participants.
municipal facility would offer greater opportunities for community visibility, education and
outreach. Moreover in the expensive and dynamic property market in Palo Alto, it can be a
challenge to gain site control at a non-municipal facility at reasonable leasing terms. Attachment B
is a list of City owned sites which have potential for local solar development in coming years.
To achieve project economies of scale, staff proposes that Co-Solar project site have a minimum
capacity to host 50 kW of solar project to meet average electricity demand of 10 - 25 residential
customers, though staff expects to target larger sites (250-750 kW) as much as possible.
CPAU will make best efforts that the solar project design enhances the site use and meets Palo
Alto design guidelines. Consistency with City master plans and architectural review processes is
important. However, given the expected costs for local solar projects, this will have to be done
cost-effectively to make sure the program remains attractive to co-solar customers. Spending too
much on design is likely to hurt program viability.
Program Design Element #2
Selection Criteria for
Community Solar Site
a. Co-Solar sites should be accessible to the public to promote
participation and community visibility, education, and outreach.
b. Municipal sites will take priority in the site selection process due to
the fact they are controlled by the City and provide the greatest
opportunities for visibility, education, and outreach for the duration
of a PPA, as well as sustained intrinsic value to participants.
c. To achieve economies of scale, pursue sites that can accommodate
significant solar capacity, ideally 250-750 kW. Sites smaller than 50
kW should not be pursued.
d. Choose sites where there is a reasonable expectation that the
project will be able to enhance the site use and meet Palo Alto
design objectives cost-effectively. Design objectives should not hurt
CPAU’s ability to price the program to attract participants.
Design Element 3: Cost and Value Proposition to Participating Customers
Providing “Solar of All”, or more specifically for customers with no or limited access to good solar
resources (e.g. renters and houses with tree canopy), is a primary driver of the program. To
achieve these goals, the benefits of joining the Co-Solar program should be clear and compelling.
Program participants will need to understand the cost and value proposition, the environmental
and sustainability benefits, the commitment terms and flexibility, and the risks associated with
participation (if any).
Local solar, within Palo Alto City limits, gives Co-Solar customers the opportunity to actually see
their energy source, providing a tangible connection to the City’s renewable energy and carbon
reduction efforts. Local solar provides environmental benefits, since it is located on already-
developed sites, unlike utility-scale solar, and does not require transmission lines, which can have
aesthetic and physical impacts on the environment. When paired with storage, local solar can also
provide emergency preparedness benefits. Staff will need good market research to identify which
messages are compelling enough to attract participants. Palo Alto customers have been willing to
pay a premium for environmental and community benefits in the past, as shown by the high
subscription rate for the PaloAltoGreen program.
Co-solar program will likely be a premium product.9 Staff is currently exploring possible pricing
options for this program. These options are discussed in Attachment C. These pricing options
under consideration give participants flexibility to make a short-term participation commitment,
likely one year or less.10 Staff recommends that the premium paid by program participants be
reasonable and low enough to generate interest. Staff will aim that the Co-Solar subscription rate
does not exceed 15% of their annual or monthly electric bill, which amounts to approximately
$7.50 per month or $90 per year for an average residential customer.11
Other program terms such as Co-Solar signage identifying the potential participants and sharing
real-time panel production information via web portal or smartphone app will be considered.
Providing such terms to customers will need to be balanced against the administrative burden
associated with moving customers in and out of the program.
Since customer interest and buy-in is a critical for the success of the community solar program,
staff plans to seek feedback from potential customers before finalizing this important aspect of the
program design.
Program Design Element #3
Cost and Value
Proposition to
Participating
Customers
a. Before launching, the program must be able to demonstrate a clear
and compelling value proposition that will attract participants.
b. The commitment term and ability to enter and leave the program
should be flexible enough that customers are comfortable signing
up for the program.
c. Program subscription fees to be reasonable and low enough to
generate interest.
Design Element 4: Power Purchase Agreement Terms and Project Capital
As discussed in Design Element 1, CPAU plans to have a third party developer build, own, and
operate the solar facility, while CPAU operates the program and sells the energy to participants.
This structure provides the developer with a single counterparty, CPAU, to buy the energy. It will
increase certainty for project developer and reduce project development costs and risks. A private
sector market place exists for solar project development in which tax-equity financing is used,
where the power from the project can be sold to a buyer like CPAU through a Power Purchase
Agreement (PPA). Design Element 4 discusses the terms and options CPAU would seek in such a
PPA.
9 Program participation price or fee will be based on CPAU’s ‘avoided cost of purchasing solar from a large remote
solar system’ or commodity portion of the retail rates. Local solar projects located within Palo Alto city limits is likely
to be more expensive than procuring energy from large utility-scale solar projects (even including transmission and
other costs associated with non-local projects).
10 SEPA’s What the Community Solar Customers Want report lists residential customers desire for a shorter term
commitment
11 PaloAltoGreen Program had premium subscription fees of about 1.5 cents/kWh in its early days and achieved
significant participation (~20% of residential customers, or 5000 customers). This amount is about a 10% - 15%
premium over average electric rates for residential customers.
CPAU will seek to execute a Purchase Power Agreement (PPA) for a term of up to 25 years with a
third-party solar developer. The term will correspond with to the duration of the lease for the
underlying site. Such a long-term output purchase commitment is expected to be necessary to
attract private equity for the construction of solar project.
Staff also recommends exploring leveraging the City’s low cost of capital by using the Electric
Special Projects (ESP) reserve. ESP funds could be used to partially pre-pay for the project at the
start of the project or to buy-back the project mid-way through the life of the project. When a
privately funded solar project is developed, a portion of the financing typically comes from tax
equity investors12 and a portion is debt-financed at private sector interest rates. In concept, by
pre-paying CPAU could enable the developer to eliminate some or all of the debt financing,
allowing the developer to save on interest payments. Under such a structure, CPAU would require
the developer to reduce the power purchase price charged to CPAU, enabling CPAU to lower the
price to Co-Solar customers. Although this transaction may enable a lower power purchase price, it
would require careful legal review to ensure all risks are properly addressed, since it is not a simple
transaction.
Staff is also exploring the option to buy back the project after approximately 7 years. This takes
advantage of the fact that tax-equity investors typically receive all tax benefits within the first
seven years of project operation. One way this might work is to include an option for CPAU to buy
the project from the developer at the seven year mark at a price to be negotiated. If the price
offered by the solar developer were attractive, it might provide additional savings to Co-solar
program subscribers, as CPAU would own the energy generated. It may also provide a benefit if
the solar project lifetime ends up being more than the PPA term (say, 30-35 years vs. a PPA term
of 25 years), allowing CPAU to take advantage of the extended project lifetime at little or no cost
without PPA energy purchase costs. Any capital provided by the ESP reserve would be repaid with
interest over the life of the project by the program participants. Just like the pre-pay alternative, a
buyback is not a simple transaction and would require careful legal review to ensure all risks are
properly addressed.
Program Design Element #4
Power Purchase
Agreement Terms
and Project Capital
a. CPAU will execute a Power Purchase Agreement with a third-party
solar developer to design, construct, own and operate community
solar projects for a term not to exceed 25 years.
b. If it provides a savings to participants, CPAU may utilize Electric
Special Projects (ESP) reserve to partially pre-pay to lower the
financing cost of the capital investment in local solar projects.
c. If it provides a savings to participants, CPAU may use the ESP
reserve to buy the project from the developer in later years.
d. Capital provided by the ESP reserve shall be repaid with imputed
interest over the project life, not to exceed 25 years.
12 Tax equity investors are generally large firms with substantial tax liabilities. They provide capital to the project
developer, and in return receive rights to the tax credits resulting from the Investment Tax Credit provided by the
Federal government to solar developers (who generally do not have substantial tax liabilities).
Design Element 5: Minimizing Risk to Non-participating Customers
There are several risks associated with the Co-Solar program that could impact non-participating
customers. These risks cannot be completely eliminated, but can be mitigated. Table 1, below,
shows the risks staff has already identified and the proposed mitigations. Additional risks may be
identified as the program is developed and staff will seek to mitigate these risks as they are
identified.
Table 1: Identified Risks to Non-Participants and Proposed Mitigations
Risks Mitigations
Risk that few customers will participate. • Seek customer pre-commitment for 50% of
project output before constructing the project,
and in no event should construction begin with
less than 30%.
• Begin with a single project rather than multiple
projects to assess community interest and fine
tune program elements.
• If the project is not fully subscribed, the
remaining project capacity will be used for the
CPAU Carbon Neutral Electric Portfolio.
• Use Public Benefit Research and Development
Funds rather than ratepayer funds for start-up
costs and to partially fund on-going operating
costs.
If engaging in pre-payment or buyback,
identify potential risks of project failure
before negotiating buyback/pre-pay
terms.
• Solar projects, with no moving parts, generally
have low risk of physical failure. Any potential
risks would be mitigated using property
insurance or other performance warranties type
of mechanisms to minimize risk to capital
invested in the pre-payment or buyback.
Ensure funds are available for project
retirement or repowering.
• CPAU will ensure the developer provides funding
for project retirement to ensure the City has no
responsibility for project demolition or
repowering once the project ceases operation.
Risk that the project could be deemed to
involve the offer or sale of a security
under federal and state securities law,
potentially requiring Securities and
Exchange Commission registration and
ongoing financial reporting and
disclosures.
• Absent regulatory clarity, this risk can be
mitigated, but not eliminated, by thoughtful
program design, such as the design elements (#1
to #4) proposed here.
Program Design Element # 5
Minimizing Risk to
Non-participating
Customers
a. Seek demonstrated interest or pre-commitment from program
participants at a 50% level, but in no event shall it be less than 30%
of the local solar project capacity before commencing project
construction.
b. Ensure a successful first project before developing subsequent
projects.
c. If the project is not fully subscribed, any unsubscribed project
output will be added to the CPAU Carbon Neutral Electric Portfolio
d. Public Benefit funds will be used to cover the initial program
development cost and to partially fund on-going operating costs as a
back-stop measure, recognizing the value such Co-Solar program
projects bring to the entire community.
e. Any operational risks must be mitigated using insurance or other
mechanisms, particularly if electric utility capital is at risk.
f. Provision must be made for retirement or repowering at end of
project life.
g. Ensure as much as possible that any other potential risks are
identified and mitigated before launching any Co-Solar project.
Application of Program Design Elements to the Co-Solar Project at the Golf Course Parking Lot
After surveying several potential sites, staff found the municipal golf course parking lot as the
most promising initial site to host the first community solar project.13 If the concept of a centrally
owned community solar project proves to be successful, and this project is over-subscribed, staff
will further evaluate other sites identified to meet the community demand. Outlined below is a
discussion of the application of the proposed Co-Solar program guidelines to the initial community
solar project.
a) Role of CPAU in Co-Solar program Development
CPAU staff with help of legal and tax advisors, consulting resources, and short-term staffing
assistance will be performing the following tasks for the project:
• Soliciting and negotiating a PPA with developer/operators
• Seeking potential participants input on the program elements and pricing structure
• Facilitating and coordinating project approval and construction
• Developing customer communication and subscription systems
• Modifying the utility customer billing system as needed; and
• Developing systems for on-going administration upon program launch, for the first and
subsequent Co-Solar projects
b) Selection of the Project Site
The golf course parking lot is readily accessible to all community members and could
accommodate a 550 kW solar system that would be capable of serving the electricity demand of
100-200 residential customers.14 Attachment D provides an outline of the preliminary carport
13 Attachment B provides a list of City facilities with potential to install local solar.
14 Assuming 350 to 700 kWh average monthly electricity consumption per residential customer
solar PV system design. Though the location is within an area dedicated as parkland, staff believes
the program will have minimal impacts due to its location on an existing parking lot, and will
provide benefits (such as shading) to golf course visitors. Staff will ensure applicable guidelines,
such as the Baylands Master Plan, are addressed as the project is designed.
Staff briefed the Parks and Recreation Commission (PRC) on potential use of this site for a
community solar project in April 2017.15 The PRC comments were mostly accepting or supportive
of the project and advised staff on following aspects:
o Making sure that the project does not interfere with the golf course business and
considering that carport PV design be in harmony with the surroundings
o Consideration of what if parking lot configuration needs to be changed in intermediate
term (10 -15 years)
o Consideration about vegetation around the parking lot and if it will interfere with the
project
o Potential of glare impact at the airport
Staff will incorporate the PRC feedback as the further details of project implementation are
developed in coming months. Apart from contributing towards the local solar goals, the
community will receive additional benefits from the proposed project:
• The location will provide an opportunity to showcase local solar generation for the
community, including educational information designed for children. With proximity to the
Baylands Natural Preserve, this educational opportunity will be complementary to other
programs in the Baylands such as Water Quality Control Plant tours, EcoCenter and
Baylands Nature Interpretative Centre.
• There is a potential to develop the site to be a microgrid to provide emergency power, if
additional funding became available to pair carport solar PV project with energy storage.
c) Cost and Value Proposition of the Project
The value proposition of the community solar program is one of the critical elements to make the
program successful. As discussed above, Attachment C outlines pricing options staff is currently
considering, which will likely involve a premium to bills in early years and may provide a discount
in the long term. Staff plans to seek feedback from potential customers and develop a clear value
proposition and marketing plan before finalizing this aspect of program design.
d) Capital funding for the Project
As discussed above, CPAU will seek a Purchase Power Agreement (PPA) with a third-party solar
developer through a competitive solicitation process (RFP) in the Summer/Fall of 2017. CPAU will
explore PPA terms such as pre-payment of a portion of the initial capital cost and an option to buy
back the project after approximately 7-years.
e) Risk to non-program participants
• Demonstrated Customer Interest and Pre-Commitment: Staff plans to seek demonstrated
15 See the April 25, 2017 staff report to the Parks and Recreation Commission
(http://www.cityofpaloalto.org/civicax/filebank/documents/57241) and the meeting minutes
(http://www.cityofpaloalto.org/civicax/filebank/documents/57851)
customer interest and pre-commitment for a minimum of 30% of project capacity before
committing to actual construction of the project, but will aim for at least 50%
pre-commitment.
• Underwriting project development cost for the unsubscribed portion: The annual payment
under the project PPA is estimated to be $100,000 - $125,000. The incremental cost of
producing solar electricity locally compared to remotely is estimated at $15,000 to $35,000
per year over the 20- 25 year term of the PPA. This means that Council needs to make a
determination that $15,000 to $35,000 per year is additional cost to all electric customers in
beneficial to the community. . As a comparison, CPAU’s total electric supply portfolio costs
are $60-$80 million/year.16
• Start-up costs and ongoing administration costs considerations: These costs are estimated
at $300,000 plus 1.0 FTE of staff effort over the next 24 months. This cost will be funded
from the Electric Utility’s Public Benefit (PB) Funds collected under Public Utilities Code
Section 385. The cost of starting the program will be recovered over the long term not just
from the first Co-Solar project, but from future projects as well if the first Co-Solar project is
successful.17 Subsequent costs incurred by CPAU and the on-going program administrative
cost will be borne by program participants. The on-going cost of administering the program
is estimated at less than $50,000 per year.
DRAFT TIMELINE
Project Milestone Timeline
1. Parks and Recreation Commission discussion April 2017 (completed)
2. Utility Advisory Commission (UAC) review of Co-Solar program Design
Guidelines
June 2017
3. Proposal to Council for adoption – Co-Solar program Design Guidelines August 2017
4. Issue RFP to Select a Solar Developer August 2017
5. Select a Solar Developer through RFP Process (preliminary
determination)
Dec 2017/ Jan 2018
6. Customer Outreach and Pre-commitment March 2018
7. UAC approval of detailed Co-Solar program elements April/May 2018
8. Final Council Approvals
o Park Improvement Ordinance
o PPA agreement, including pre-payment and buy-back provisions, if
any (final)
o Land lease agreement with solar developer
June 2018
16 Refer: CPAU Fiscal Year 2018 Electric Financial Plan
17 Though the initial solar site at the golf course parking lot will generate only 0.1% community’s electricity needs, staff
anticipates subsequent Co-Solar program projects (~2,500 kW) would add up to 0.4% of community’s electricity needs
by 2023. In comparison, the Council approved CLEAN solar programs are expected to provide 0.5% of the community’s
electricity needs at an incremental cost of $385,000 per year over a 20 year life of projects.
o Detailed Co-Solar program rules related to customer commitment
terms & program administration
9.Required Permits and Approval for Project Construction July - Dec 2018
10.Construction of carport PV project (slow season for golfing)Dec – Feb 2019
11.Electricity flows from PV system, Co-Solar program launched April 2019
NEXT STEPS
Staff plans to bring a proposal for adoption to Council for community solar design guidelines in
August 2017. Staff will then launch the RFP process for solar developer selection and initiate
customer outreach efforts for the project. Staff will keep the UAC informed on important project
milestones and expects to return with the final program approval in April or May of 2018.
RESOURCE IMPACTS
The costs to undertake preliminary site assessment, feasibility studies, and initial program
development is estimated at $300,000 plus 1.0 FTE of staff effort over the next 24 months, and is
expected to be funded from the public benefit funds from the Electric Utility’s Distribution Fund,
specifically Public Benefit Funds collected as required by Public Utilities Code Section 385. These
are funds specifically collected for to fund energy efficiency and renewable energy projects.
The initial capital outlay is estimated at approximately $1.8 to $2 million18 and is likely to be
funded by tax equity financing from the private sector and may include pre-payment from the
utility ESP reserves. Project development and operational costs would be repaid by the community
solar program participants over the life of the program. No additional funds are requested at this
time.
POLICY IMPLICATIONS
Community solar program conforms to the City of Palo Alto Utilities Strategic Plan objective to
provide environmentally sustainable customer solutions. The proposed pilot 550 kW carport PV
project will contribute towards the Local Solar Plan and the community goal of meeting 4% of
electricity needs with local renewable resources.
Organizationally, it should also be noted that Co-Solar would provide an additional resource for
CPAU staff that consult with consumers, and will involve customer support representatives as well
as program, marketing, and management staff. This represents a positive step in CPAU providing
unique value to Palo Alto customers.
ENVIRONMENTAL REVIEW
The Commission’s discussion of the community solar design guidelines to facilitate deployment of
the Co-Solar project is exempt from California Environmental Quality Act (CEQA) review as such
discussion does not meet the definition of a project under Public Resources Code 21065.
18 Assuming all-in installed cost of about $3 - $4 per watt for 550 kW solar carport project
ATTACHMENTS
Attachment A: Community Solar Program Design Elements
Attachment B: Estimated Solar Potential on City-Owned Sites
Attachment C: Pricing Options for Community Solar Program
Attachment D: First Co-Solar Project at the Golf Course Parking Lot
PREPARED BY: SONIKA CHOUDHARY, Resource Planner
SHIVA SWAMINATHAN, Senior Resource Planner
REVIEWED BY: JONATHAN ABENDSCHEIN, Assistant Director, Resource Management
APPROVED BY: ___________________________
ED SHIKADA
General Manager of Utilities
1
Attachment A
Palo Alto Community Solar Program (“Co-Solar”) Design Elements
The Community Solar Program is a central part of the 2014 Council approved Local Solar Plan
with the goal of producing 4% of community wide energy within the community by 2023. In
setting this goal Council found that local solar photovoltaic (PV) systems within Palo Alto to be
more valuable compared to PV systems sited outside the Palo Alto. Co-Solar program is being
developed to meet part of this goal, and to provide an opportunity to community members
without access to solar electric energy on their own roofs be part of a centrally located
community solar project.
The goals of developing Co-Solar in Palo Alto are as follows:
Providing local solar PV electricity access to all residents and businesses who seek such
energy, but are unable to do so (for example, do not have suitable roof space to site solar
PV panels)
Siting renewable projects on a local, already-developed site rather than a remote
undeveloped site
Avoiding siting renewable energy in a remote, prompting the construction of new
transmission lines
Keeping a portion of the economic benefits of renewable energy purchases in-town, where
possible
Building projects that, if paired with storage, could act as a community emergency power
supply
Providing Community benefits such as the opportunity to showcase local solar generation
and educational information for children
Community Solar Program Design Elements
1. CPAU’s Role in
Program
Development and
Management
CPAU will take a lead role in the program design, procurement,
and management. Specifically:
a. CPAU will identify a site and solicit potential developer
counterparties for execution of power purchase and land
lease agreements.
b. CPAU will market and sell the generated electricity to
participating customers.
c. CPAU will manage changes among participants, balancing
convenience and flexibility for Co-Solar customers with
overall program costs and administrative sustainability.
d. CPAU will purchase the excess energy, the difference
between energy produced and purchased by Co-Solar
participants.
2
2. Selection Criteria
for Community
Solar Site
a. Co-Solar sites should be accessible to the public to promote
participation and community visibility, education, and
outreach.
b. Municipal sites will take priority in the site selection
process due to the fact they are controlled by the City and
provide the greatest opportunities for visibility, education,
and outreach for the duration of a PPA, as well as sustained
intrinsic value to participants.
c. To achieve economies of scale, pursue sites that can
accommodate significant solar capacity, ideally 250-750
kW. Sites smaller than 50 kW should not be pursued.
d. Choose sites where there is a reasonable expectation that
the project will be able to enhance the site use and meet
Palo Alto design objectives cost-effectively. Design
objectives should not hurt CPAU’s ability to price the
program to attract participants.
3. Cost and Value
Proposition to
Participating
Customers
a. Before launching, the program must be able to
demonstrate a clear and compelling value proposition that
will attract participants.
b. The commitment term and ability to enter and leave the
program should be flexible enough that customers are
comfortable signing up for the program.
c. Program subscription fees to be reasonable and low
enough to generate interest.
4. Power Purchase
Agreement Terms
and Project
Capital
a. CPAU will execute a Power Purchase Agreement with a
third-party solar developer to design, construct, own and
operate community solar projects for a term not to exceed
25 years.
b. If it provides a savings to participants, CPAU may utilize
Electric Special Projects (ESP) reserve to partially pre-pay to
lower the financing cost of the capital investment in local
solar projects.
c. If it provides a savings to participants, CPAU may use the
ESP reserve to buy the project from the developer in later
years.
3
d. Capital provided by the ESP reserve shall be repaid with
imputed interest over the project life, not to exceed 25
years.
5. Minimizing Risk to
Non-Program
Participants
a. Seek demonstrated interest or pre-commitment from
program participants at a 50% level, but in no event shall it
be less than 30% of the local solar project capacity before
commencing project construction.
b. Ensure a successful first project before developing
subsequent projects.
c. If the project is not fully subscribed, any unsubscribed
project output will be added to the CPAU Carbon Neutral
Electric Portfolio
d. Public Benefit funds will be used to cover the initial
program development cost and to partially fund on-going
operating costs as a back-stop measure, recognizing the
value such Co-Solar program projects bring to the entire
community.
e. Any operational risks must be mitigated using insurance or
other mechanisms, particularly if electric utility capital is at
risk.
f. Provision must be made for retirement or repowering at
end of project life.
g. Ensure as much as possible that any other potential risks
are identified and mitigated before launching any Co-Solar
project.
ATTACHMENT B
Preliminary Assessment of Solar Development on City-Owned Sites**
Ready for Solar Deployment Now
1. Golf Course parking lot
2. Downtown Library
3. Utilities Control Center
4. WQCP warehouse
5. Fire Station #1 (Univ. Park)
Ready for Solar Deployment between now and 2020 (in pipeline)
1. Airport
2. Fire Stations #3 and #4 (rebuild)
3. Fire Station #2 (reroof)
4. Public Safety Building
5. Golf Course
6. Jr. Museum & Zoo
7. New downtown parking structure
8. New California Avenue area parking structure
Ready for Solar Deployment After 2020
1. Cubberley Community Center
2. Municipal Service Center
3. WQCP Admin/Ops Buildings (prospective rebuild)
4. Civic Center, Police-occupied area (prospective seismic retrofit after Public Safety building
established)
5. Ventura Center (consider during reroof)
* Data Source: 2015-2016 City Staff Assessment of the Local Solar Potential on City Owned Sites
** Note: One or more sites may need to be removed from the list upon further evaluation
1
ATTACHMENT C
Pricing Options for Community Solar Program Participants
Staff’s initial assessment and recommended approach to pricing community solar to
participating customers is outlined here. Staff plans to reach out to potential program
participants and seek their feedback on two alternate pricing options (monthly rate
subscription vs. block purchase with monthly credit) before finalizing this aspect of the program
design. Capacity of the utility billing system to handle such pricing options and cost of
administering such pricing options will also be considered before selecting a pricing option for
the program. Upfront purchase of or lease of panels will not be considered.
Community solar pricing options broadly fall into two categories:
• Upfront PV Panel Purchase (or Lease) by Participating Customers: The option requires
upfront payment and a long-term commitment (~20 years) by participants. This could
be a large hurdle for many interested customers (e.g. renters), pose significant
administrative burden on the City, and encumbrances to project sites that could cause
problems, for example on dedicated parkland. Therefore, upfront panel purchase (or
lease) option by participating customers is not included for further consideration.
• Customer Subscription with no Up-Front Commitment: This requires CPAU to be the
counterparty to the solar developer and then re-sell the output of the project to
participants as discussed in the Co-Solar Design Element # 1. Since individual customers
prefer to have the option to not make a long-term commitment and the City has the
ability to sell the output to larger pool of interested customers, CPAU is well positioned
to make such an offering. In addition, the CPAU can utilize its low cost of capital
available through ESP reserve and access the low cost private sector tax equity capital
(through public-private sector partnership) to finance the project and pass on the
savings to the program subscribers (Design Element #4).
Two subscription models will be considered, the monthly subscription option (Option A) and
annual subscription option (Option B).
i. Option A – “Monthly Rate Subscription”: This option would be similar to the
PaloAltoGreen program where customers will purchase local solar electricity
proportional to their monthly electric load. Participants are likely to pay a 10% -
15% annual premium in their utility bills for initial years (for example $5 to
$8/month for an average customer). In the long term, due to the price certainty
of a local project, participants may see a discount or credit on their electric bill.
Project may become unviable if monthly premium payments turn out to be
greater than 15% of monthly bills. Customers may subscribe and unsubscribe
2
from the program at any time; but to cover administrative cost, a small fee may
be charged for customers who do not stay in the program for a year
ii. Option B – “Block Purchase with Monthly Credits”: Customers can subscribe to
annual blocks of electricity. For example, 1 block = 500 units or output of one
300-watt panel.1 Customer will pay annual or monthly fixed fee for the blocks of
energy subscribed. Output from the local solar project will be credited to the
participants based on the seasonal variability of the solar generation (i.e. more
generation credited in spring and summer months and less in winter months).
Participants will need stay with the program at least for a year. Otherwise they
will forfeit the remaining credits for the year.
The exact subscription prices will be determined once solar project development terms are
confirmed through competitive solicitation process from private sector developers.
Environmental Attributes of the Program and Treatment of Renewable Energy Credits (RECs)
Staff recommends that CPAU retires Renewable Energy Credits (RECs) from the community
solar project on behalf of the program participants. In this way, program participants can claim
full environmental benefits of the program. Currently CPAU is well on the way to meet
Renewable Portfolio Standards (RPS) requirements.2 Incremental RECs from the community
solar program may not be needed for meeting 2015 Senate Bill 350 RPS compliance
requirements. Staff will consider the benefits of community solar project and RECs treatment
in the avoided cost calculations and finalizing the subscription rate for program participants.
1 Customers can purchase multiple blocks of community solar (say 500 units each) up to 100% of their annual energy usage.
For example, customers with annual usage of 4200 units (350 kWh/ month) can subscribe for 8 blocks of community solar
2 CPAU Quarterly Update for Second Quarter of FY 2017, Figure 1: Electric Supply Resource Actual and Projection, 2016 to 2018
ATTACHMENT D
Community Solar Project at the Golf Course Parking Lot
The golf course parking lot is located at the 1875 Embarcadero Rd, Palo Alto (see Illustration 1). The
proposed carport solar PV structures would cover and provide shade over the parking lot lanes (see
Illustration 2).
Illustration 1: Potential location for Carport Solar PV Installation
Illustration 2 - Preliminary Conceptual Design for the Carport Solar PV (550 kW)
Golf Course Parking Lot –
potential site for proposed
carport solar PV