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NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956
I. ROLL CALL
II.ORAL COMMUNICATIONS
Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable time
restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from discussing or
acting upon any topic initially presented during oral communication.
III.APPROVAL OF THE MINUTES
Approval of the Minutes of the Utilities Advisory Commission Meeting held on December 5, 2018
IV.AGENDA REVIEW AND REVISIONS
V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS
VI.GENERAL MANAGER OF UTILITIES REPORT
VII.COMMISSIONER COMMENTS
VIII.UNFINISHED BUSINESS - None
IX.NEW BUSINESS
1.Update on Activities to Facilitate Distributed Energy Resources Adoption and Discussion
Next Steps
2.Staff Request for Feedback on Recommendations Regarding the City’s Fiber-Optic,Discussion
Wireless and Advanced Meter Infrastructure Planning
3.Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action
NEXT SCHEDULED MEETING: February 6, 2019
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)).
12-Month Rolling Calendar Public Letter(s) to the UAC
UTILITIES ADVISORY COMMISSION
WEDNESDAY, JANUARY 9, 2019 – 7:00 P.M. – SPECIAL MEETING
COUNCIL CHAMBERS
Palo Alto City Hall – 250 Hamilton Avenue
Chairman: Michael Danaher Vice Chair: Judith Schwartz Commissioners: Arne Ballantine, Lisa Forssell, A. C. Johnston, Lauren Segal and Terry Trumbull Council Liaison: Eric Filseth
Utilities Advisory Commission Minutes Approved on: Page 1 of 8
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF DECEMBER 5, 2018 REGULAR MEETING
CALL TO ORDER
Commissioner Segal called the meeting of the Utilities Advisory Commission (UAC) to order at 7:00 p.m.
Present: Commissioners Forssell, Johnston, Segal, and Trumbull
Absent: Chair Danaher, Vice Chair Schwartz, Commissioner Ballantine
ORAL COMMUNICATIONS
None.
APPROVAL OF THE MINUTES
Commissioner Trumbull moved to approve the minutes from the October 3, 2018 meeting as presented.
Commissioner Forssell seconded the motion. The motion carried 4-0 with Commissioners Forssell, Johnston,
Segal, and Trumbull voting yes, and Chair Danaher, Vice Chair Schwartz, and Commissioner Ballantine absent.
AGENDA REVIEW AND REVISIONS
None.
REPORTS FROM COMMISSIONER MEETINGS/EVENTS
Commissioner Trumbull hoped Councilmember Filseth continued as Council liaison to the UAC in 2019.
UTILITIES GENERAL MANAGER REPORT
Ed Shikada, Utilities General Manager, delivered the General Manager’s Report.
Council Actions on AMI and Electric Supply Planning. On November 19, after a short discussion, the Council
approved the Finance Committee’s recommendation to accept the Utilities Smart Grid Assessment and
Utilities Technology Implementation Plan. This provides staff confidence in its tentative roadmap for an
Advanced Metering Infrastructure, or AMI, rollout. Staff will move forward in coordinating the timeline with
other major software projects currently in progress, such as the Utility’s customer information system
replacement. Also on December 3, Council approved the Electric Integrated Resource Plan as recommended
by the Finance Committee and Utilities Advisory Commission.
VMware and Palo Alto Explore Microgrid Partnership. VMware and Palo Alto made a joint announcement
on November 1 about potentially developing a microgrid at the VMware headquarters in the Stanford
Research Park. The campus-level microgrid could serve as a charging site for the City’s emergency command
vehicles during major emergencies and power outages. As the Commissioners are likely aware, a microgrid
is made up of generators, batteries and electric loads that can connect to the main power grid or power
critical electric loads when off-grid. This community microgrid could operate cooperatively with the City’s
own Utilities infrastructure to provide a level of backup and will serve as a testbed for the company and City
to explore the potential of microgrids to advance resiliency at the corporate and community level. Mayor
DRAFT
Utilities Advisory Commission Minutes Approved on: Page 2 of 8
Kniss joined VMware CEO Pat Gelsinger and Congresswoman Anna Eshoo at this special event announcing
the public-private partnership. Thanks also to Commissioners Schwartz, Segal, and Vice Mayor Filseth for
joining us there.
Upcoming Events:
• On Saturday, December 8, Utilities hosts a free landscape workshop focused on maintaining native plant
gardens and leak detection. Feel free to join us at the Mitchell Park Community Center for this event
from 9 am to noon. Details and registration are at www.cityofpaloalto.org/workshops.
COMMISSIONER COMMENTS
None.
NEW BUSINESS
ITEM 1: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that the City
Council Approve the Continuation of the 2018 Utilities Legislative Guidelines into 2019.
Heather Dauler, Senior Resource Planner, reported the Legislature has begun introducing bills for 2019. A bill
for regionalization, the joining of the California grid with the western states grid, failed in 2018. The 2018 bill
concerned the governance structure of a regional body and included heavy involvement of the California
Independent System Operator (CAISO). With respect to a 2019 regionalization bill, rumors suggest CAISO no
longer wishes to be involved in regionalization in any form. Staff anticipates quite a few bills concerning
wildfires will be introduced in 2019. Press reports indicate Senator Hill wants to break up investor-owned
utilities (IOU) and abolish the investor-owned model for utilities. At the current time, Senator Hill has not
introduced such a bill. Assemblyman Holden will introduce a bill that will allow rate recovery for IOUs. At the
end of the 2018 legislative session, Governor Brown supported inverse condemnation and strict liability,
which is the legal concept of a utility being responsible for a wildfire even though it was not negligent. The
issue could arise again in 2019.
In response to Commissioner Trumbull's inquiry regarding an alternative entity to an IOU, Dauler advised that
Senator Hill has some thoughts about contorting the IOU model into a publicly owned utility (POU) model.
Senator Hill has not proposed that the State take control of IOUs.
Dauler continued with the presentation, stating that 2019 will be the first year of the two-year legislative
cycle. Any bills that are not passed in 2019 can be continued into 2020. Bills were introduced in 2018 that
would have mandated source-specific procurement, i.e., the bills would have mandated all electric utilities
procure a specific number of megawatts of power from specific sources of renewable energy, but the bills
failed. Bills mandating source procurement could be introduced in 2019. A 2019 bill would require the
California Energy Commission (CEC) and the California Public Utilities Commission (CPUC) to report to the
Legislature in 2020 a joint assessment of options for establishing a central statewide entity to procure
electricity for all end-use retail customers in California. San Diego Gas & Electric (SDG&E) has stated that it
wants to stop participating in commodities. Senator Hueso with SDG&E's support has drafted legislation
calling for a state energy procurement task force and requesting the State's help in relieving SDG&E of its
contracts to buy and sell electricity. A 2018 bill would have required development of rebate programs for
energy storage, but it died. The issue could return in 2019. Two 2018 bills would have allowed large
hydroelectric power to count toward the Renewables Portfolio Standard (RPS), but the bills died early in the
session. The application of large hydroelectric power to the RPS could arise again in 2019. In addition,
buildings and transportation electrification and telecommunications small cell facilities could return in 2019.
Governor-elect Newsom's support for issues is unknown. He has publicly stated he will focus on healthcare
and preschool for all, cradle-to-college education, a new middle-class workforce strategy, ending childhood
poverty, and a plan for aging with dignity. The Electric Utility complies with SB 100's mandate to increase
renewable energy from 50 percent to 60 percent and to reach zero carbon energy by 2045. SB 901 mandates
utilities to have a wildfire mitigation plan and an annual assessment of the plan. Staff has been working with
the California Municipal Utilities Association (CMUA) to implement SB 901 and prepare a plan template. The
Utilities Advisory Commission Minutes Approved on: Page 3 of 8
question is whether the Legislature will change the requirements contained in SB 901 before reports are due
in 2020.
In answer to Commissioner Trumbull's question regarding individuals capable of assessing wildfire mitigation
plans, Dauler explained that CAL FIRE will develop a list of individuals whom IOUs may utilize to assess plans.
The Northern California Power Agency (NCPA) has contracted with a third-party entity that will assist member
POUs with preparing a list of independent evaluators. SB 901 states the evaluators must have experience in
fire safety and electrical utilities.
In reply to Commissioner Segal's query regarding the amount of funding needed to develop a wildfire
mitigation plan, Dauler indicated staff has not considered a budget at the current time. Debra Lloyd, Acting
Assistant Director of Utilities Engineering, added that staff has taken additional measures regarding wildfire
mitigation, but there could be some budget impact.
In response to Commissioner Forssell's inquiry regarding 2019 legislation that could adversely impact CPAU,
Dauler related that the few bills introduced thus far are not concerning, but the deadline to introduce
legislation is February 22, 2019. By the end of March, staff will have more information to share.
Dauler further reported the Utilities Legislative Policy Guidelines approved in 2018 have been effective in
allowing staff to work with outside entities, to advocate for utility lines, and to seek guidance in grant funding.
Staff asks the UAC to continue the 2018 Guidelines into 2019.
ACTION: Commissioner Forssell moved that the Utilities Advisory Commission recommend the City Council
approve the continuation of the 2018 Utilities Legislative Policy Guidelines into 2019. Commissioner Trumbull
seconded the motion. The motion carried 4-0 with Commissioners Forssell, Johnston, Segal, and Trumbull
voting yes, and Chair Danaher, Vice Chair Schwartz, and Commissioner Ballantine absent.
ITEM 2: DISCUSSION: Discussion of CPAU's Role in Community Resilience Including Workshop Summary and
Draft Vision and Goals.
Debra Lloyd, Acting Assistant Director of Utilities Engineering, reported the goal of the discussion is to review
the draft vision and goals that were developed during the August 28 workshop and next steps. The original
plan was to hold two workshops, one to learn the direction and priorities of the UAC and the community and
a second to develop actionable items. Common themes from the August workshop are development of a
roadmap to Smart grid/Smart utility; management of critical utility facilities; providing community support
and identifying key locations for community hubs following a disaster; development of a technical utility
volunteer group; and communication. The draft vision is to support community resilience by advancing CPAU
to become "Smart" utilities that are able to assist the City in preparing, responding, supporting, and
rebounding from manmade and natural disasters. The three major goals are to assist the City in ensuring that
residents can stay in place or return as soon as possible in the event of a disaster or emergency; to support
community resilience by prioritizing utility services and infrastructure support to critical facilities and retail
establishments; and to enhance the City's utilities to ensure their overall resilience. The second workshop
will refine the framework and guiding principles and be oriented toward solutions. Staff requests the UAC's
opinion as to whether the second workshop should be a standalone meeting or part of a UAC meeting.
Ed Shikada, Utilities General Manager, advised that Vice Chair Schwartz has ideas for the structure of a second
workshop. In particular, Vice Chair Schwartz suggested the workshop focus on investing in proactive
measures for reasonably foreseeable challenges. Staff can target that as a key takeaway of a second
workshop if the UAC wishes.
Commissioner Johnston concurred with Vice Chair Schwartz's comments regarding specific priorities and
projects that CPAU can begin to implement. The second workshop should develop a list of priority projects.
Utilities Advisory Commission Minutes Approved on: Page 4 of 8
Commissioner Forssell suggested solutions do not have to lie solely in infrastructure investments. The initial
resilience goals largely respond to comments made during the workshop. She did not hear workshop
participants talk about Smart grid/Smart utility, but that features prominently in the common themes and
draft vision. She heard participant comments about the ability to stay in place, to form community groups,
to obtain critical services, and to educate the community. Commissioner Forssell preferred a workshop
format, fewer consultant presentations, and more opportunities for the community to speak. The draft vision
and goals should be available online with the invitation or notice of the workshop so that the community can
prepare for the workshop. Utilities, Public Works, and Emergency Services staff should be present during the
second workshop to answer questions about current procedures and practices and could offer brief
presentations.
Commissioner Segal concurred with Commissioner Forssell's preference for a workshop format and less
outside input. Based on comments from the first workshop, the community understands and is willing to
participate and provide support in the event of an emergency, but there was no discussion of ways for the
community to act. If CPAU wants community support, then it should understand what the community is
willing to do and to learn and obtain feedback from the broad community. As part of the workshop, perhaps
the participants can comment regarding the ways they inform themselves and recommendations for
informing the broad community.
Esther Nigenda remarked that Community Emergency Response Team (CERT) volunteers could participate in
the technical utility volunteer group because of their training. She expressed concern regarding the
statements that well water can be pumped indefinitely and that the City can provide 9 million gallons of
water per day. According to the draft groundwater use assessment report, Palo Alto's sustainable
groundwater yield is approximately 2,500 acre feet per year, which is approximately 2.2 million gallons of
water per day or 20 percent of Palo Alto's daily water usage. She requested the UAC consider a plan to provide
power during and after a disaster to people who depend on electricity for medical equipment.
ACTION: No action
UNFINISHED BUSINESS
ITEM 3. DISCUSSION: Staff Update on the Green Acres Rebuild and Request for Feedback on Preparation of
a Utilities Rule and Regulation Governing Community Requests for Fully Undergrounded Systems, Including
a Procedure for Assessment Funding.
Debra Lloyd, Acting Assistant Director of Utilities Engineering, reported the residents of Green Acres
petitioned the City for underground utilities and agreed to contribute 25 percent of the cost for the original
project. Currently, residents would have to contribute 50 percent of the cost for undergrounding utilities.
The original equipment remains in use today. In 2018, staff proposed updating the equipment with switch
boxes and pad-mounted transformers, but the community generally opposed the proposal. In August 2018,
the UAC tasked staff with finding a compromise. Staff now proposes six pad-mounted transformers be placed
in discrete locations. In a meeting with three Green Acres Homeowners Association (HOA) board members,
staff offered to place sample cabinets in the community so that residents could understand their visual
impact and to attend a community meeting. Over the previous month, staff received community feedback
that only a complete subsurface rebuild would suffice. Pad-mounted equipment is the industry standard
because of safety, reliability, purchase and maintenance costs, and capacity and system flexibility. Systems
are designed to operate below their capacity, and in a subsurface environment systems would operate at an
even lower capacity. Rule and Regulation 3 requires all new equipment in underground areas be pad-
mounted. However, the Utilities Director, General Manager, or his designated representative can determine
that subsurface equipment can be installed in locations where pad-mounted equipment would be impractical
or infeasible. Generally, subsurface equipment is installed in locations where the City does not have a right-
of-way or where the right-of-way would disrupt traffic or pedestrian flow. Rule and Regulation 20 specifies
that the additional costs of special facilities will be allocated to the customer requesting the special facilities.
Rule and Regulation 20 applies to a customer request that exceeds CPAU standards. CPAU does not have
Utilities Advisory Commission Minutes Approved on: Page 5 of 8
rules and regulations that address a community request that exceeds CPAU standards. Questions for UAC
consideration are whether to allow a group of property owners located in an existing underground district to
request that the existing design be maintained in a rebuild; if such a request is allowed, whether the Utility,
ratepayers, or requesting parties should pay the additional costs; how the additional costs should be
calculated; and how additional costs should be collected. CPAU has an obligation to provide safe and reliable
service, and CPAU's goal is to replace equipment before it fails. An additional concern is developing a process
and timeline for the community to reach agreement on the project and to collect funds to pay for the project.
To avoid burdening ratepayers or diverting funds from other projects, CPAU could require the requesting
property owners to pay the additional costs of the project. The levy to be charged the requesting property
owners could be based on the Special Facilities fee. The community's cost could be based on costs for
equipment, installation, maintenance, losses, and a property owner election if needed. Staff does not
recommend the community's cost include the cost of replacement. Staff proposes the levy be imposed
through a real property assessment; a requirement for 75 percent of homeowners formally petition for a
property owner election; and a time limit for submitting a petition and holding an election be imposed. Staff
requests direction on whether the additional costs should be collected as a lump-sum payment or as annual
payments. Based on an engineering estimate, the cost difference between a pad-mounted and a subsurface
project is $413,101.
Gregory McKernan, Senior Engineer, explained that loop-feed transformers require less equipment and, thus,
cost less than a load-breaker transformer.
Commissioner Trumbull related that he had provided the project information to his energy policy students,
and they all opposed subsurface installation. In reply to his inquiry regarding staff's willingness to accept
subsurface transformers, Lloyd advised that operations crews opposed undergrounding transformers. OSHA
requirements do not prohibit subsurface installations, but OSHA does require confined-space training and
operations. In answer to Commissioner Trumbull's query regarding additional incremental costs for handling
problems in an underground system, Lloyd explained that the calculation of the additional cost is based on
the Special Facilities fee. The additional cost estimate is not specific to subsurface transformers. The
maintenance cost for a subsurface transformer is probably higher than estimated. Commissioner Trumbull
commented that many residents likely will not be interested in the project once they learn the actual cost.
He questioned the wisdom of holding an election without knowing the cost to residents. Lloyd stated that,
depending on the application of a Special Facilities fee, the cost could range between $3,500 and $5,000. Ed
Shikada, Utilities General Manager, added that the cost would be finalized prior to an election. An engineer's
report will determine the actual cost per property.
In reply to Commissioner Johnston's query regarding the number of undergrounding districts, Lloyd reported
two districts have been converted from all subsurface to pad-mounted transformers. With the exception of
the Green Acres district, other undergrounding districts will convert to pad-mounted transformers as the
districts come up for rebuild projects. Approximately 1,200 residential properties are located in districts
scheduled for rebuild projects. The current five-year infrastructure plan contains rebuild projects for five
districts. In response to Commissioner Johnston's inquiry about different figures for the cost differential
between the report and Attachment A, Lloyd explained that the cost differential contained in Attachment A
includes a replacement cost, which staff decided to remove when preparing the report.
Nina Bell questioned the installation of subsurface infrastructure along Arastradero-Charleston when staff
stated subsurface infrastructure is not safe. There appears to be a conflict with the definition of underground
because CPAU uses underground to mean underground wiring and pad-mounted transformers. The Green
Acres district is unique in that the infrastructure is entirely underground. Residents are concerned about their
safety should an explosion occur.
Jenning Chee characterized the residents' request as the maintenance and replacement of the existing
underground infrastructure. Over the years, budgets should have included projects for the maintenance of
underground facilities and replacement in-kind. The City should pay for replacement of the infrastructure.
Utilities Advisory Commission Minutes Approved on: Page 6 of 8
Alice Sklar, Green Acres HOA President, related that the HOA Board attempted to survey the neighborhood
twice but did not receive sufficient responses to provide significant results. From both surveys, two responses
indicated the property owner was willing to accept the second design. The vast majority of respondents
indicated a wish for additional discussions with staff rather than a preference for underground or pad-
mounted transformers. Once staff provides verifiable costs, the HOA Board can survey neighbors again. Given
the overwhelming interest in fully underground utilities, developing alternatives is a waste of time. She hoped
the UAC would direct staff to amend rules and regulations so that Green Acres could have fully underground
infrastructure.
Nancy Steinbach noted CPAU's rules and regulations regarding underground facilities changed after utilities
were fully undergrounded in Green Acres. She did not understand why pad-mounted transformers are being
pushed onto Green Acres residents when transformers are being placed underground along Arastradero.
Residents should not have to pay for undergrounding facilities. CPAU budget surpluses should be sufficient
to pay for upgrades.
Debbie Tasso [phonetic] did not understand how the few subsurface transformers in Green Acres would
appreciably affect employee safety when many more transformers would be placed underground in
commercial areas. Employee exposure to risks from underground transformers is considerably less than the
constant exposure of Green Acres residents. She wanted to see the invoices for transformers and bills for
labor in order to determine the cost to residents. The City has spent much more than $20,000 in responding
to residents' concerns.
Weidong Chen remarked regarding the safety of his family with a pad-mount transformer located on his
property. He hoped the infrastructure would remain fully underground.
Eugene Lee commented on the long life and low maintenance of the existing infrastructure. Residents have
been paying $11-$12 per month towards the replacement of the equipment, and those funds should be
applied to an underground solution.
Ada Banks felt all equipment should be located underground. Reliable and safe service can be achieved much
better through underground equipment.
Michael Maurier suggested three possible solutions: Green Acres residents could pay for a fully underground
system; residents and staff could explore the feasibility of underground systems; or staff could leave the
existing infrastructure as-is and make repairs as needed.
In answer to Commissioner Forssell's question about the number of responses to the survey by the Green
Acres HOA Board, Ms. Sklar reported receiving 19 responses to one survey and 15 to the other survey. In
response to Commissioner Johnston's query of whether a survey asked residents if they were willing to pay
the differential cost, Ms. Sklar responded yes. Residents had many questions regarding the differential cost
provided by CPAU.
At Commissioners' requests for staff to respond to questions from the public, Lloyd advised that five districts
with all subsurface equipment are scheduled for conversion to pad-mounted equipment in the next five
years. Staff learned that property owners in an underground district other than the Green Acres district
petitioned and paid 25 percent of the cost for the undergrounding of utilities. Other districts were originally
undergrounded with all subsurface equipment. In a small district along Arastradero, a right-of-way issue
resulted in one new piece of equipment being installed underground. McKernan added that the Arastradero
Corridor is an underground district, but the design of the rebuild is not complete. Infrastructure changes are
occurring along Arastradero, but electric is not part of the work. Lloyd indicated District 46 was scheduled to
have two pieces of pad-mounted equipment, but one was not feasible and the other was connected to
existing infrastructure. McKernan related that District 6 was rebuilt with pad-mounted transformers in the
Utilities Advisory Commission Minutes Approved on: Page 7 of 8
late 1990s. In earlier maps for District 6, transformers appeared to be subsurface. Transformers will be
located on the City's right-of-way, not on private property.
In reply to Commissioner Forssell's question regarding calculation of the cost estimate and providing
residents with invoices and contracts, McKernan clarified that he utilized the most recent purchase price of
equipment and obtained quotes from the City's contractor for substructure work in order to calculate the
cost. That information can be provided to the public. In answer to Commissioner Forssell's question as to
whether CPAU could defer a rebuild project for the Green Acres district, McKernan stated deferring a project
is not in the best interests of residents or CPAU. In the long run, replacing equipment prior to its failure is less
expensive. Lloyd advised that outages could negatively affect residents who rely on electricity to power
medical equipment. CPAU could wait until failure begins, but that is not CPAU policy.
Commissioner Trumbull did not believe the UAC has information that would prevent it from recommending
the staff proposal from August 2018 with the reduction in the number of pads. However, recommending the
staff proposal would be grossly irresponsible in that the UAC would be passing the decision to the Council.
Subsurface transformers are a serious OSHA problem, and that could be an enormous financial liability for
the City. Residents raised legitimate questions about the City installing subsurface transformers elsewhere.
He preferred staff hold a community meeting to discuss technical issues with Green Acres residents and
residents from the five districts scheduled for rebuild projects.
Commissioner Forssell did not wish to repeat a process that has not reached a resolution. Some of the
residents' written correspondence indicated they did not want to attend a community meeting about pad-
mounted designs because that would indicate they were willing to accept a pad-mounted design. The key
issues appear to be whether CPAU will consider designs that are less safe than pad-mounted designs; who
will pay for subsurface installation; and whether the property owners purchased the equipment used in the
original project or the right in perpetuity for subsurface utilities. CPAU does not have funds to purchase
additional equipment without it impacting all electric customers in Palo Alto. Perhaps the UAC should
recommend to the Council the framework of a policy in the form of a procedure by which a neighborhood
can petition for an exception to rules and regulations if the City is willing to accept the safety risk.
Commissioner Johnston understood staff has not found any studies regarding the safety issue, which is the
missing piece. Pad-mounted equipment makes complete sense, but residents have raised some safety issues
about pad-mounted equipment. There must be a reason for pad-mounted equipment being the industry
standard. CPAU is installing subsurface equipment in areas where pad-mounted is not feasible, which implies
that safety concerns do not preclude subsurface equipment. If subsurface equipment is possible, if pad-
mounted equipment is feasible in a residential neighborhood, and if the neighborhood wants subsurface
equipment, CPAU should ask the neighborhood to pay the incremental cost of subsurface equipment. CPAU
should have a policy so that each neighborhood is treated equally and fairly.
Commissioner Segal concurred with the need for CPAU to have a policy. Having clear safety guidelines would
make the decision easier. Commissioner Segal wanted to know if the original allocation to property owners
of the cost for subsurface equipment was based on the lifespan or cost of the equipment so that the UAC
would have some insight into property owners' expectations.
Commissioner Trumbull commented that Commissioners seemed to agree that staff should draft a procedure
for property owners to request subsurface equipment and to pay for the additional cost.
Ed Shikada, Utilities General Manager, reported staff could prepare a procedure including costs, timeframes,
the level of community support needed, and election requirements. A draft procedure could be shared with
other neighborhoods in a situation similar to Green Acres' situation in order to obtain feedback. Once a
procedure is finalized, staff will expect the Green Acres neighborhood to comply with the procedure.
Utilities Advisory Commission Minutes Approved on: Page 8 of 8
Lloyd reiterated staff's proposal of the components that would comprise the cost to property owners and
requested direction from the UAC.
Commissioner Forssell suggested the City commit to a dollar amount for the homeowners' cost prior to an
election being held. If the actual cost exceeds the estimate, the residents' incremental cost should not
increase. If the actual cost is less than the estimate, the residents should pay a lower amount. The difference
in equipment and installation costs and the cost of ownership should be components of the residents' cost.
The cost of administering an election should not be included in the residents' cost.
Commissioner Johnston agreed with Commissioner Forssell's comments. In reply to Commissioner Johnston's
question regarding a shorter lifespan for underground equipment, Lloyd clarified that the expected lifespan
of underground equipment is shorter than pad-mounted equipment. The annual cost of ownership is based
on the current Special Facilities fee, which utilizes a factor of 6.7 percent. The annual cost of ownership
includes the cost of an increased asset base, the average cost of maintenance, and additional losses
calculated for underground equipment. Commissioner Johnston stated replacement costs should not be a
component of the residents' cost.
Shikada noted Green Acres residents are happy with the status quo. The urgency of the item is driven by
CPAU's responsibility to ensure safe and reliable service. Staff will return to the UAC as quickly as possible.
Commissioner Trumbull urged staff to meet soon with residents of underground districts. Commissioner
Segal concurred especially as policies and procedures will be adopted. Election costs should not be allocated
to neighborhoods.
Councilmember Filseth felt knowing the number of subsurface transformers across the City could be useful.
ACTION: No action.
ITEM 4. ACTION: Selection of Potential Topic(s) for Discussion at Future UAC Meeting.
Commissioner Segal requested an update regarding succession planning, vacant positions, and recruitment.
Ed Shikada, Utilities General Manager, advised that the Council will consider the Utilities Management and
Professional Association of Palo Alto's (UMPAPA) first negotiated Memorandum of Agreement on
December 10. Staff is anticipating some retirements in the next year and preparing follow-up actions to
ensure operations continue. Negotiations with the Service Employees International Union (SEIU) are
underway and expected to extend for several months.
ACTION: No action
NEXT SCHEDULED MEETING: January 9, 2019
Meeting adjourned at 9:22 p.m.
Respectfully submitted,
Rachel Chiu
City of Palo Alto Utilities
Page 1 of 6
1
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILTIES DEPARTMENT
DATE: January 9, 2019
SUBJECT: Update on Activities to Facilitate Distributed Energy Resources Adoption
and Next Steps
RECOMMENDATION
This is an informational report. Utility Advisory Commission feedback is sought on DER related
actions planned for the next three years.
EXECUTIVE SUMMARY
A draft Distribution Energy Resource (DER) Plan was discussed at the Utility Advisory
Commission (UAC) meeting in November 2017. This report summarizes the major planning and
operational activities undertaken in 2018 in the areas described in that plan. These topics
include electricity supply planning, distribution planning, customer retail rate design, and
customer programs to facilitate customer adoption of DERs. The report also outlines business
strategic planning efforts related to DERs and the actions planned in these areas in the next
three years. Given that work items related to DERs are listed in various other City plans
(Appendix A),1 staff has decided against creating a separate, permanent DER plan, but will
instead provide an annual progress update on the five DER-related work items in the various
plans, take UAC feedback, and adjust the DER-related work items based on that feedback.
BACKGROUND
DERs are electrical energy resources connected to the City of Palo Alto Utilities (CPAU ) electric
distribution grid that can significantly change the location, timing, and magnitude of the CPAU ’s
electric loads 2. These resources are primarily sited at customer premises, behind the utility
electric meter.
The goal of the draft DER work plan discussed at the UAC meeting in November 2017
(Attachment C) was to facilitate customer adoption of DERs and to enhance the value of
customer sited DERs to all members of the Palo Alto community by using DERs to lower overall
cost, lower greenhouse gas emissions, and increase the resiliency of the community while
avoiding or mitigating any potential negative impacts from DER growth. Since then staff has
1 These include the Electric Integrated Resources Plan, Distribution System Assessment, and a new Customer
Programs Work Plan currently in progress. See Appendix A for a full list of plans with DER-related work items.
2 The California Public Utilities Code 769 defines “distributed resources” as distributed renewable generation
resources such as solar photovoltaics (PV), energy efficiency (EE), energy storage (ES), electric vehicles (EV), and
demand response (DR) technologies.
Page 2 of 6
presented to the UAC an Assessment of Distribution System to Integrate DERs (April 2018) and
an Electric Integrated Resource Plan (EIRP) (October 2018). These plans include various policies
related to DERs. An additional plan related to Customer Programs is anticipated to be shared
with the UAC in the spring of 2019. See Appendix A for a full list of plans with DER-related work
items.
DISCUSSION
In order to effectively manage DER growth, CPAU’s planning and operational activities related
electricity supply, distribution system, and customer programs are closely coordinated. In
addition, retail rates have to be designed to remain cost-based while sending economically
efficient price signals to customers who are considering DER investment, and to collect
sufficient revenues to maintain a reliable utility system. Overall utility business strategies will
also have to be aligned to effectively integrate DERs. The report discusses the progress made on
each of these five areas of activities and activities planned for the next three years.
CPAU ’s efforts in DER planning are occurring in several areas listed below. Progress on DER-
related work items3
will be reported back to the UAC and Council under these five broad areas
of activities.4
DER Planning Focus Areas:
A. Business Strategic and Operational Planning
B. Electric Supply Planning and Operations
C. Distribution Planning and Operations
D. Customer Retail Rate Design
E. Customer Program Design
A. Business Strategic and Operational Planning
To effectively take advantage of the opportunities created by DER adoption, and to avoid
potential negative impacts, CPAU needs to put certain fundamental technologies in place, most
importantly the Advanced Metering Infrastructure (AMI). There are also potential opportunities
and impacts related to the way DERs could affect utility loads and utility finances. CPAU needs
to evaluate these opportunities and impacts to effectively take advantage of them or mitigate
them, as applicable.
3 The 2018 Utilities Strategic Plan (Priority#4, Strategy#4, and Action#2) set a goal of establishing and
implementing a DER Plan by December 2018.
4 The draft DER plan in November 2017 included nine work plan areas, which have now been collapsed into the
four areas as outlined to facilitate ease of communicating on progress. To avoid duplicative reporting, staff will
likely be reporting on the progress in each of the four work area independently, along with other relevant non-DER
related activities under that work area. For example, DER related customer programs would be reported along
with the full portfolio of customer programs. Activities related to DERs impact on supplies will be reported under
the EIRP work plan; distribution system and retail rates work areas would also be reported in conjunction with
non-DER related activities in those work areas.
Page 3 of 6
Actions in the next three years:
a. Begin planning to implement an AMI system as described in the Utilities Smart Grid
Assessment and Utilities Technology Implementation Plan.
b. Undertake a competitive assessment of the impact of DERs on the electric utility’s
finances and competitiveness. (Utilities Strategic Plan Priority 4, Strategy 4, Action 2)
B. Electricity Supply Planning and Operations
The Electric Integrated Resource Plan (EIRP) approved by the UAC in October 2018 and Council
in December 2018 considers electric supply provided by customer sited DERs and supply from
central resources located outside the Palo Alto. The highlights of the load forecast findings
were:
• Solar Photovoltaic (PV) systems in Palo Alto are projected to meet approximately 5% of
the community’s electricity needs by 2030, up from 2% in 2018.
• Electric Vehicles could add approximately 6% to the electric load by 2030, up from 1% in
2018.
• Overall, electrical energy supply needs from resources outside Palo Alto is projected to
decline by 4% to 8% by 2030.
In addition, the EIRP (in Strategies #2 and #6)5 contemplates the continued use of the ‘avoided
cost’ methodology to compare the economic merits of electric supply options from DER
resources within Palo Alto and from resources outside Palo Alto on an equal basis.6 The current
estimated avoided cost of CPAU ’s energy supply in FY 2019 is 10.1 cents/kWh, and is 10.3
cents/kWh for a 20-year PV system based energy supply.
Large commercial scale DERs (PV, Energy storage and demand response) will also impact day-to-
day operations to optimally meet the community’s hourly loads within a day. Any large variation
on DER operations at customer site7 will have to be coordinated by CPAU . Except for the
planned VMWare microgrid project, staff is not aware of any other large project that will have
such impacts in the next three years.
Actions in the next three years:
a. Continue to update electric load forecast based on anticipated growth of DERs and
incorporate it into the supply resource plans. (EIRP Strategy 1.d.)
5 The EIRP contemplates pursuing an optimal mix of supply and demand resource (Strategy#2) and procuring
flexible central resource supplies to effectively meet changes in customer loads due to DER adoption(Strategy #6)
6 The avoided cost methodology computes the cost of meeting customer loads from outside energy resources
(supply resources), and then uses this cost benchmark to evaluate the economics of DER resources (demand
resources) –with DER resources preferred when the cost of DER resources are at or below the avoided cost
benchmark. This methodology to compare supply and demand resources ensures energy is economically sourced
for all CPAU customers.
7 For an 180MW load like Palo Alto, DER resources such as Demand Response or Energy Storage systems in the
order of 3MW+ would be considered a large variation and will require operational coordination with Northern
California Power Agency (NCPA), CPAU’s scheduling coordinator with the CAISO.
Page 4 of 6
b. Continue to evaluate local resources like energy efficiency, distributed generation,
energy storage, and demand response as an alternative to resources from outside Palo
Alto, where feasible. (EIRP Strategy 1.d.)8
C. Electric Distribution Planning and Operations
The Electric Distribution System Assessment (DSA) report discussed with the UAC in April 2018
found the following:
• Electric substations and feeders have sufficient capacity to accommodate PV and EV growth
in the residential sector in the next 10 years
• Staff should closely monitor distribution transformer loadings in residential neighborhoods
which have a very high penetration of EVs.
• Sufficient capacity exists in the commercial sector to accommodate EV load growth.
• Development of large PV systems (>500 kW) may have system impacts related to ‘reverse
flow’ on lightly loaded distribution feeders. As such, each of the larger projects has to be
evaluated on a case-by-case basis.9
In addition to evaluating DER options as alternatives to electric supply purchases, to the extent
DERs at a particular location in town could permit CPAU to avoid additional distribution system
investment, the corresponding avoided costs are also included in evaluating the economics of
DER options. Currently there are no such opportunities to reduce distribution investments via
DER investments.
Actions in the next three years:
a. Update the city’s mapping of customer meters to the distribution transformer serving
them to enable better assessment of distribution transformer loading.
b. Identify distribution transformers that have potential to overload due to the high
adoption of EVs, and upgrade them as needed.
c. Evaluate a standardized policy and connection fee for residential customers requesting
electrical panels larger than 200 Ampere panels and implement if feasible.
d. Explore the potential to integrate smart inverter capabilities into the City’s distribution
system.
e. Facilitate the implementation of customer –initiated and owned microgrid projects.
The actions listed encompass those recommended in the DSA Report in April 2018.
8 In the absence of an AMI system, this effort will largely focus on energy efficiency, distributed generation, and
limited commercial demand response efforts. More complex actions like aggregating small scale residential DER
systems to provide supply related ancillary services will require AMI.
9 For example, VMware is considering a large expansion of a PV and energy storage system to create a community
microgrid on VMWare’s campus in the research park. This may result in DER capacity addition of 4 to 8MW, and will
require close evaluation of the impact on the distribution system operations/reliability.
Page 5 of 6
D. Customer Retail Rate Design
The most important DER-related rate design task will be time-of-use (TOU) rate implementation
once AMI meters become available. TOU rates enable CPAU to send economically efficient price
signals to customers who are contemplating DER investments to optimally meet their electricity
needs. While CPAU has a pilot-scale residential TOU rate, due to the delay in smart meter roll-
out, an expansion of CPAU’s residential TOU rate is not contemplated until the 2023-24
timeline. Medium and large commercial customers currently do have the option to elect to be
on TOU rates.
Staff is working on some interim rate design studies to explore whether rate structures can be a
valid mechanism to encourage adoption of certain types of DERs, such as EVs and other
electrification technologies, while remaining cost-based and constitutionally compliant. It will
also be important to review any proposed changes to current rate designs to ensure DER
adoption avoids cost shifts from adopters to non-adopters.
Actions in the next three years:
a. Evaluate an all-electric homes retail rate.
b. Evaluate the feasibility of providing a fixed monthly utility bill discount for customers
with EVs registered at the utility service address.
c. Analyze, forecast, and monitor the impact of DER adoption on rate designs and utility
financial health.
E. Planning & Implementing Customer Programs & Communications
CPAU ’s customer programs are designed with the objective of fulfilling customer priorities,
meeting the community’s sustainability goals, and meeting regulatory mandates, such as
mandates related to energy efficiency. In order to determine the level of effort CPAU should
devote to promoting various DER technologies, a residential customer survey was undertaken in
July 2018. The objective of the survey was to seek customer input on their preference for
various DER technologies and to understand the drivers for their actions to enable CPAU to
develop customer programs to best meet their needs. Attachment B outlines staff’s key
takeaways from the survey and how staff plans to incorporate the findings in future customer
programs. Staff is in the process of developing a Customer Programs Work Plan that it will share
with the UAC in the spring.
Actions in the next three years
a. Revise portfolio of customer programs by spring of 2019 for implementation over the
next three years.
NEXT STEPS
Staff will continue to take a comprehensive approach to integrating customer-sited DERs to
lower overall cost, lower greenhouse gas emissions, and increase the resiliency of the
community. Staff expect to finalize a portfolio of customer programs for implementation in
next three years, and will be discussing them with the UAC in the spring.
RESOURCE IMPACT
Staff's main role related to programs on customer premises in the past has been related to
energy efficiency and solar PV. Expansion of staff's role in implementing customer programs
related to EVs, electrification of building systems, and energy storagehas resulted in internal
evaluation of priorities. This evaluation is currently underway and reallocation of staffing roles
is contemplated. No new staffing requests are planned.
POLICY IMPLICATIONS
The policies referenced here are part of various plans, including the Utilities Strategic Plan, the
Sustainability and Climate Action Plan (S/CAP), and the Electric Integrated Resource Plan (EIRP).
ENVIRONMENTAL REVIEW
The Utilities Advisory Commission's discussion of this informational report does not meet the
definition of a project under Public Resources Code 21065 and therefore California
Environmental Quality Act (CEQA) review is not required.
PREPARED BY:
LENA PERKINS, Resource Planner
BRUCE LESCH, Manager, Utility Program Services
SHIVA SWAMINATHAN, Senior Resource Planner
CHRISTINE TAM, Senior Resource Planner
REVIEWED BY: JONATHAN ABENDSCHEIN, Assistant Director, Resource Management
APPROVED BY:
DEAN BATCHELOR
Interim General Manager of Utilities
ATTACHMENTS'
A. DER Business Impacts and Relevant Planning Documents
B. Key Takeaways from the Residential Customer Survey
C. Discussion of Proposed DER Plan — November 2017
Electric Supply
Business
Utilities
Administration
Electric Distribution
Business
Citywide
Sustainability
Utility Technology and
Smart Grid Roadmap
New technology has
various impacts on the
distribution system,
requiring careful
planning, but with
planning the utility can
take advantage of
their flexibility and
reduce the impacts.
Distribution System
Assessment
Integrated
Resource Plan
Customer
Programs Marketing
Customer Surveys /
Outreach
Customer Programs
Work Plan
Marketing Plan (Internal)
•Changes in load due to new technologies will
create competitive pressures and ratepayer
impacts in both distribution and supply
businesses
•Rate designs influence new technology
adoption and use
Competitive Assessment
Financial Forecasts
Rate Studies / Redesigns
Budgeting / Cost Containment
DER Progress Updates
to the UAC
Some new technologies that
reduce carbon affect the utility’s
load, but can provide flexibility
and grid services
Utilities Technology Road map
upgrades CPAU technology
infrastructure to get the maximum
benefit from new technologies
•Flexible resources can
provide grid services at
the CAISO level
•Need to manage risk
of stranded generating
assets and supply
contracts due to load
changes
Plan complete, starting implementation
Plan in progress
Plan not started
Tech/Smart Grid
Roadmap
Sustainability and Climate
Action Plan
New Energy
Technologies (DERs)*
EV, Solar, Storage, Demand
Response, Heat Pump Water
Heaters, Heat Pump Space Heaters
Utility primary business line
Utility‐wide support function
City‐wide effort
Customers want support and
advice on new technology. Well‐
designed programs can provide
incentives for customers to use
new technology to benefit the
whole community and minimize
business impacts.
Resiliency
Planning
Some new
technologies can
contribute to
customer/utility
resiliency.
Cyclical planning effort
*Distributed Energy Resources
New Energy
Technologies and their
Effect on the Electric
Utility
Including Planning Documents
with Relevant Work Items
ATTACHMENT A
Key Takeaways from the Residential DER Survey
The key takeaways from the Residential DER Survey 1 and application of the findings for future
customer programs were as follows:
a. Electric Vehicles
Customer Interest: There is a high level of interest in Electric Vehicle adoption (15% have
vehicles and 37% of who do not have EVs are considering EVs in the next 2-3 years; 52%
are not considering EVs in the next 2-3 years). Given this level of interest and impact EVs
have in lowering GHGs, promoting EV adoption is a very high priority for CPAU and the
City as a whole. Customers in the survey indicated rebates (44%), more public and work
charging (32%) and special EV utility rates (32%) may persuade them to own a EV.
Challenges: Barriers to EV adoption among customer surveyed were (in the order of
importance): 1) not needing a new car, 2) limited driving range, 3) EV is too expensive, 4)
don’t have access to EV chargers at home.
Actions: The concern about the lack of access to EV chargers at home was expressed by
32% of respondents who were not planning to get an EV – this is an area in which CPAU
can make a difference by incentivizing EV charger installations. In addition to the current
EV supply equipment (EVSE) rebate program, CPAU is also examining a point-of-sale EV
rebate program in collaboration with the California Air Resources Board (CARB) and a bill
credit for homes with EVs using funds from the Low Carbon Fuel Standards (LCFS)
program.
b. Solar PV:
Customer Interest: High level of interest in community solar PV systems, with 53% of
residents responding that they are extremely or very interested, with 54% of those
customers willing to pay up to $20/month extra on their bills for such energy. This is in line
with our prior survey results on the topic. The interest for community solar primarily comes
from customers who do not have suitable roofs, such as those in apartments and condos.
Challenges: Since the electric supply portfolio is already carbon neutral, local solar will
have minimal impact on GHG emissions. The relatively high level of staff resources
needed to develop and administer the program as well as the relatively high cost of local
construction are also challenges.
Actions: No projects are currently planned regarding community solar. Staff will leverage
limited staff resources by continuing to partner with all nine bay area counties in the
annual Bay Area Sunshares Solar PV Group-Buy program.
1 For more detailed information of the survey conducted in July 2018, please see the October 3, 2018 UAC Report.
ATTACHMENT B
c. Energy Storage
Customer Interest: There is customer interest in energy storage systems (6% of
customers), but the interest level is lower than that of PV or EV programs.
Challenges: Currently energy storage systems offer only minimal GHG reduction
potential, and are relatively expensive. Customers with solar PV who value back-up
power likely value energy storage systems the most.
Actions: Staff will continue to work with customers who are interested to install such
systems in their homes and businesses, but staff does not plan to actively promote
energy storage systems. The value of storage systems will be re-evaluated in 2020 as
part of the mandatory energy storage assessment required in bill AB2514.
d. Heat-Pump Water Heaters
Customer Interest: About 26% of customers were either very or somewhat familiar with
heat pump water heaters (HPWH). Of those who were at least somewhat familiar 39%
indicated that they either had a HPWH or were interested in switching to one.
Challenges: Customers reported the relatively high cost of heat-pump water heaters and
having recently replaced their water heaters were major barriers. Unfamiliarity of
customers and contractors with heat-pump water heaters are also challenges since most
replacements are unplanned.
Actions: Staff expects to continue to implement programs in this area at a moderate
level of effort and continue to promote the HPWH Pilot rebate. The survey results also
validate that the rebate is addressing a customer concern but highlights that many
residents are not aware of this rebate. Staff is partnering with BayREN on a regional
market transformation program to provide contractor training, consumer messaging,
and a mid-stream HPWH incentive to distributors throughout the Bay Area (nine
counties). This BAAQMD grant funded regional program approach can catalyze market
transformation and address the many persistent barriers that cannot be addressed on a
local scale. Other key partners in this HPWH market transformation program include
local governments and CCAs and non-profit organizations. This program is expected to
launch in early 2019.
e. Smart Appliances
Customer Interest: There is a very high level of adoption and interest of smart appliances
such as smart thermostats, smart lighting and smart power strips.
Challenges: Lack of smart meters to leverage existing smart devices with time-of-use
rates.
Actions: Staff is planning to launch a Tier 2 smart power strip program as well as
evaluate including smart devices in an online marketplace. Staff will also investigate
using smart devices in a flexible demand response program which could help lower
supply costs, lower peak demand, and lower carbon emissions. Upon implementation of
smart meters, providing price signals to incentivize customers to use energy at the
lowest system cost period will help lower utility costs.
f. Customer Awareness of 100% Carbon Neutral Electricity Supply
Customer Interest: Survey respondents consistently cited sustainability as one of their
top priorities.
Challenges: Fewer than 11% of those surveyed responded that they believed that CPAU’s
electric portfolio was at least 80% carbon neutral.2 This shows a high proportion of CPAU
customers who do not know that CPAU has owned or contracted carbon neutral
electricity supply resources equivalent to its annual electricity load.
Actions: Staff will continue to educate customers about the very low carbon emissions of
using electricity in Palo Alto in order to reiterate that the greatest carbon reductions
potential is from transportation electrification, natural gas efficiency measures, and
electrification of natural gas appliances. Staff will also investigate if more nuanced
messaging may be warranted regarding the difference between real-time emissions and
having a carbon neutral electric supply balance on an annual basis.
2 Question wording: “From what you know, what percentage of the electricity supplied by City of Palo Alto Utilities
is carbon neutral, that is, produces zero net carbon emissions.
Page 1 of 10
5
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILTIES DEPARTMENT
DATE: November 1, 2017
SUBJECT: Discussion of Proposed Distributed Energy Resources Plan
RECOMMENDATION
This is an informational report. UAC approval is not sought at this time. Staff is seeking input on
the proposed Distributed Energy Resources (DER) Plan provided in Attachment A.
EXECUTIVE SUMMARY
DERs are electrical energy resources connected to the City of Palo Alto Utilities (CPAU ) electric
distribution grid that can significantly change the location, timing, and magnitude of the CPAU’s
electric loads. The California Public Utilities Code 769 defines “distributed resources” as
distributed renewable generation resources such as solar photovoltaics (PV), energy efficiency
(EE), energy storage (ES), electric vehicles (EV), and demand response (DR) technologies. New
State guidelines from the California Energy Commission (CEC) require that DERs be incorporated
into the 2019 Electric Integrated Resource Plan (IRP) as they impact supply planning and could
even be used to offset some of the services traditionally provided by utility-scale electricity
generation resources.
As of 2017, the combined effect of DERs (primarily energy efficiency and PV) has been to reduce
CPAU’s net electricity demand by 6.9% relative to 2007, and staff expects the cumulative
reduction from DERs to reach 13.6% by 2030. The proliferation of DERs over the coming decade
means managing and leveraging DERs will be critical for Palo Alto’s utility system operations,
resource planning, and customer programs.
The proposed DER Plan in Attachment A organizes various DER-related initiatives currently
planned or underway into a single plan in order to capture various types of benefits and
coordinate effort wherever possible. It is consistent with current Council-approved policies and
programs related to EE, PV, EVs, ES, DR, and electrification. The DER Plan was developed in
coordination with the Utilities Strategic Plan (USP) initiative currently underway, and will also be
incorporated within the Electric Integration Resource Plan (IRP) being developed in order to
plan for the City’s long-term electricity needs and fulfill state regulations related to Senate Bill
350 (SB 350).
This report is structured as follows: 1) background on DER work to-date; 2) the objectives and
strategies in the proposed DER Plan; and 3) an overview of the timeline and resources required
to implement the Plan over the next five years.
ATTACHMENT C
Page 2 of 10
BACKGROUND
The Clean Energy and Pollution Reduction Act of 2015 (SB 350) and related regulations require
CPAU to develop a detailed IRP which should include both forecasts for DERs and their impacts
on electric loads.1 This new emphasis on DERs from the State level is because multiple state
agencies see DERs as key enabling technologies to both lower greenhouse gas emissions (GHG)
and to help electric grid reliability with increased penetration of intermittent renewable energy
supplies.2,3 Locally, CPAU considers energy efficiency and demand reduction as the highest
priority resource 4 and Palo Alto’s Sustainability and Climate Action Plan (S/CAP)5 also identified
several DERs as key technologies for achieving the community’s greenhouse gas (GHG) emission
reduction goals, particularly EVs , high-efficiency heat-pump water heaters (HPWH), and heat-
pump space heaters (HPSH) which displace fossil fuel combustion. Well-integrated DERs could
offer a number of benefits to the Palo Alto community by reducing supply costs, deferring
distribution system upgrades, and increasing system resiliency and flexibility. On the other
hand, unmanaged DERs could increase costs for CPAU by increasing uncertainty and forecast
errors in the electric load-supply balance or by causing adverse impacts on the distribution
system. The goal of this proposed DER Plan is to provide a framework for mitigating the
potential downsides of DERs while leveraging the benefits for all members of the Palo Alto
community.
The proposed DER Plan is consistent with and/or feeds into the following initiatives currently in
effect or underway as shown in Figure 1. This DER plan does not supersede existing plans,
instead it is a supplemental document which includes DER issues which were not specifically
addressed.
• Local Solar Plan (2014)
• Electrification Work Plan (2015)
• Energy Storage Assessment (2017)
• Updated Ten-Year Electric Efficiency Goals (2017)
• Electric Integrated Resource Plan (2018)
• Distribution system assessment to accommodate DER growth (2018)
• AMI installation and evaluation of advanced rate structures (in progress)
• Adopting industry best practices to facilitate DER adoption and integration (on-going)
1 For the full IRP guidelines related to SB 350 see California Energy Commission: Publicly Owned Utility Integrated
Resource Plan Submission and Review Guidelines, September 5, 2017
2 The California Independent System Operator (CAISO) is the transmission system operator for most of California,
and its presentation on how DERs can help the integration of high penetration of intermittent renewables can be
found here: Renewable Integration, CAISO Presentation May 12, 2017. In addition the California Public Utilities
Commission (which regulates Investor Owned Utilities) has been working on a DER Action Plan for California.
3 Local renewables and flexible loads will not lower annual CPAU GHG emissions since CPAU’s electric supply is
100% carbon neutral on an annual basis; however, these resources could lower CPAU’s hourly GHG emissions by
shaping electricity demands to match when intermittent renewable resources are available. DERs such as EVs,
HPWHs, and HPSHs, which displace combustion of gasoline and natural gas, have even greater potential to reduce
GHG emissions in Palo Alto due to CPAU’s carbon neutral electric portfolio.
4 Long-term Electric Acquisition Plan (LEAP) Objectives and Strategies Approved March 7, 2011 (Resolution No.
9152)
5 Palo Alto S/CAP Report to Council (#6754), April 18, 2016
Page 3 of 10
Figure 1: Proposed DER Plan is consistent with planned and existing DER initiatives
It is important to note that CPAU already expends considerable resources promoting DERs in
Palo Alto, with energy efficiency programs currently requiring the most resources. An estimate
of CPAU staff time and annual budget in implementing each of the current DER technology
programs is outlined below in Table 1.
Table 1: Estimate of current staff time and annual expenditure on each DER technology
DER Technology Staff Time (FTE) Current Annual Expenditure
PV 1.5 $100k
EV 1 $200k – $400k
EE 4 $3M – $4M
DR 0.05 $5k – $10k
ES 0.1 None
HPWHs & HPSHs 0.7 $100k
Total 7.35 $3.4M – $4.6M
The adoption of a DER Plan by itself will not significantly change the current resource allocation
among the existing DER programs, as many efforts in the Plan can be incorporated into future
work plans. Staff expects that the DER Plan policies, when implemented, will result in more
effective coordination among City departments on DERs, as well as enable better
communication with the Palo Alto community, UAC, City Council, and industry stakeholders
regarding future DER programs.
Page 4 of 10
DER Projections To -date
As of 2017, staff estimates that CPAU’s net electricity demand would be 6.9% higher than it is
today if currently installed PV, EV, and EE had not been installed. Initial estimates suggest that
DERs, primarily EE, PV, & EV, will lower net electricity demand by another 6.6% from 2017 to
2030, amounting to a cumulative reduction of about 13.6% since 2007. Forecasts predict
electricity sales would grow an average of approximately 0.4% per year were DERs not present.
Therefore the net effect of load growth and DERs is that overall CPAU electricity retail sales are
expected to remain nearly flat from 2017 through 2030, with an overall reduction of 0.6% by
2030.
Since DERs are expected to spread rapidly in Palo Alto over the next decade, Table 2 below
provides a brief summary of the current and projected number of DER systems, the DER impacts
on CPAU’s electricity sales, and a preliminary estimate of the financial impacts of DERs. The
details and assumptions embedded in these preliminary analyses are included in Attachment B.
These financial impacts are rough estimates of changes in the utility’s revenues and its
wholesale electricity supply costs. They do not incorporate possible revenue changes from
potential future changes to utility rate structures, nor do they include costs or savings on
distribution system operations, distribution system upgrades, staffing, or additional benefits or
revenue streams from interactive flexible DERs. More detailed analysis will be required to
better project the long-term financial impacts of DERs over the next decade. However, since
previous load and financial projections have included impacts from PV, EV, and EE adoption,
most of these impacts are already incorporated into the 2017 Electric Utility Financial Plan.
Table 2: Estimates of number of DERs and impact on electricity sales for 2017 and 2030 6
Approximate Number
of DER Systems
Impact on CPAU
Electricity Sales (%)
Financial Impact on
CPAU , $
DER Technology 2017 2030 2017 2030 2017 2030
PV 1,000 2,500 -1.6% -4.9% -$0.8 M -$3.2 M
EV 2,500 7 18,700 +0.8% 6.0% $0.4 M $4.3 M
EE 8 40,880 60,000 -6.0% -15.2 % -$2.9 M -$9.7 M
DR 8 75 - -0.02% - -
ES 11 580 - - - -
HPWH 10 2,700 - 0.3% - -
HPSH - 800 - 0.3% - -
Combined DER
Total 44,409 85,355 -6.9% -13.6% -$3.4 M -$8.6 M
6 These estimates are calculated based on technologies deployed since 2007, and reflect the total impact observed
by 2017, and the estimated impact by 2030.
7 It is estimated that about 2,500 EVs are registered in Palo Alto and another 2,800 commute vehicles drive into
Palo Alto daily.
8 These numbers reflect the number of EE measures implemented, for example the number of boilers replaced or
the number of buildings which added insulation.
Page 5 of 10
In order to understand the impact of DERs on total CPAU electricity sales going forward from
2017, Figure 2 shows the contribution of new DERs to projected electricity sales. This shows
that the combined effect of DERs added between 2018 and 2030 is to lower the electricity sales
by 6.6% by 2030 compared to what it would have been without those DERs. Without the DERs
electricity sales are projected to grow at 0.4% annually, but with the DERs, electricity sales are
expected to remain nearly flat through 2030.
Figure 2: Estimated contribution of different DERs to total energy sales from 2018 to 2030
Insights from Preliminary Projections
With Palo Alto community members projected to make substantial DER investments at their
homes and businesses in the next decade, the City, in coordination with community
stakeholders, will need to plan and implement strategies to maximize the value of these
investments to the community. The utility distribution system and utility rate structures will
also need to accommodate the growth of these customer investments. Some other key
takeaways from the analyses are:
1) While DERs are expected to account for approximately 13.6% of the electrical loads by
2030, they will be unevenly distributed among customer types as well as by location.
Planning for DERs will require more detailed visibility into the operation of the
distribution system and more detailed financial impact modeling.
2) Load growth from residential EVs is projected to increase demand on the residential
sections of the distribution grid by up to 30% by 2030, and therefore must be
proactively managed through strategic programs and incentives.
3) More detailed analytical methods can improve projections of the anticipated growth
and financial impacts of DERs to better mitigate negative impacts of DERs and enable
the City to realize additional benefits.
Page 6 of 10
DISCUSSION
The growth of DERs will have a variety of impacts to the electric utility, and therefore DERs must
be proactively integrated to ensure utility operational and financial resiliency for the future.
While there are already a number of initiatives underway to adapt to the emerging importance
of DERs, the goal of the proposed DER Plan is to formalize several of the best practices required
to ensure successful adaptation, and to ensure clear communication between work groups
especially regarding distribution system planning, supply planning, customer service,
operations, rate design, and customer program design.
While the analysis to-date has focused on the mitigation and planning required to
accommodate high growth of DERs, these technologies also have the potential to provide a
number of benefits to CPAU , the CAISO transmission area, and the Palo Alto community,
including:
• Enhancing CPAU’s system resiliency and reliability;
• Reducing peak demand to reduce the cost of transmission and distribution upgrades;
• Lowering supply costs by reducing curtailment of renewable projects throughout the
CAISO market, including CPAU renewable projects;
• Lowering CAISO and real-time CPAU GHG emissions by load shifting, demand response,
and flexible demand resources to better match electricity demand to when intermittent
renewable resources are available; and
• Enabling customers to directly bid their DER capabilities into the wholesale electricity
markets (e.g. through third-party aggregators or other mechanisms) to provide new
flexible low-cost and low-emission resources for energy and ancillary services, which can
help accommodate a higher penetration of intermittent renewable resources and
provide alternatives to new utility-scale generator construction.
The proposed DER Plan seeks to position CPAU to be able to harness these benefits. In August
2017,9 the UAC provided feedback on staff’s intentions to develop the DER Plan guided by the
following principles:
1) Facilitate the operation of DERs in ways that enhance the value to the DER owner as well
as the rest of the Palo Alto community; and
2) Staff will act as a facilitator of DERs. This means that:
i. Where DERs are cost-effective as an alternative to traditional generation
resources or distribution system upgrades, CPAU will create incentives for
adoption of DERs;
ii. Where DERs are not yet cost-effective alternatives to traditional generation
resources or distribution system upgrades, CPAU will facilitate voluntary
customer adoption;
3) Ensure that both the electric distribution system and electric utility finances can
accommodate DER growth.
9 Developing a Distributed Energy Resource Plan and Load Forecasting Report to UAC - August 2017
Page 7 of 10
These guiding principles have been expanded into the proposed DER Plan in Attachment A,
which encapsulates the City policies and actions that staff is proposing to enable beneficial DER
integration into the community. The goal, objectives, and strategies of the proposed DER Plan
are included in the following section.
City of Palo Alto Utilities - Distributed Energy Resources (DER) Plan
Goal of the DER Plan:
Enhance the value of DERs to all members of the Palo Alto community by using DERs to lower
costs, increase sustainability, and increase the resiliency of CPAU while avoiding or mitigating
any potential negative impacts from DER growth.
Objectives of the DER Plan:
1. Remove internal obstacles to allow greater DER adoption and improve DER value to the
entire community.
2. Facilitate the installation and integration of DERs in Palo Alto in order to increase utility
resiliency, lower utility costs, and reduce the City’s GHG emissions.10
3. Understand the community’s DER adoption potential and diverse needs and develop
DER programs accordingly.
4. Ensure that the utility financial structure and the distribution system can accommodate
DER growth.
5. Be innovative in accelerating adoption of cost-effective DER technologies as well as
initiating pilots programs for strategic emerging DER technologies.
Strategies to Achieve DER Plan Objectives:
This section lists key strategies to implement the DER Plan. Details and tactical actions related
to each of these strategies are listed in Attachment A.
1. Lower Barriers to Adoption – Lower barriers and reduce soft costs that may impede the
adoption and installation of DERs by streamlining processes (such as permitting and
interconnection), training local installers, and evaluating and updating fee structures.
2. Resiliency – Coordinate DER integration efforts with efforts to improve community
resiliency and evaluate how DER technologies can enhance community resiliency in the
future.
3. DER Growth Forecasts and Valuations – Develop and communicate DER growth
forecasts and valuations to ensure that all departments have current forecasts, costs,
10 Although CPAU’s electricity supply portfolio is carbon neutral on an annual basis, DERs have the potential to
lower the real-time GHG emissions in a number of ways, including load shifting to better match electricity
demands to the availability of intermittent renewables.
Page 8 of 10
and benefits. Ensure that these projections are integrated into planning processes (such
as distribution and financial planning).
4. Customer Programs – Develop pilot programs and incentives to encourage DERs that
can provide quantifiable benefits to the electric utility (and therefore to all customers
and the entire community). Prioritize those that are the most cost-effective and provide
the greatest GHG savings.
5. Advanced Metering Infrastructure (AMI) and Advanced Rate Structures – Implement
automated customer metering infrastructure and advanced retail rate structures to
effectively manage the DER resources in the community. Examples include evaluating
and potentially implementing of Time-of-Use rates as well as rates for EV owners.
6. Distribution System Planning – Develop a distribution system plan to accommodate the
adoption of DER growth at the lowest cost while maintaining system reliability to all
customers. Examples include evaluating the cost-effectiveness of installing or
incentivizing DERs as an alternative to local distribution system upgrades. In this way
local DERs could provide benefits to the distribution system while lowering costs for all
community members.
7. Electric Supply Planning – Consider DERs as a preferred resource and plan for maximum
deployment of cost-effective and feasible DERs within Electric Integrated Resource Plans
(IRP). Examples include integrating the forecasts and DER scenarios into short and long-
term electric forecasts related to energy, capacity, and ancillary services.
8. Workforce Development and Industry Resources – Leverage existing industry resources
to grow in-house staff expertise by pursuing strategic partnerships and participating in
industry expert forums. Disseminate knowledge throughout the organization to staff
who will be involved with DERs.
9. Organizational Structures – Ensure effective organizational structures are in place to
accommodate DER growth by establishing multi-departmental teams to implement the
DER Plan and to ensure that the strategies in the DER Plan are integrated into the work
planning, staffing, and resource requirements of all the departments and divisions
affected.
NEXT STEPS
Upon receiving UAC input on this proposed DER Plan, staff will incorporate the feedback and
seek additional stakeholder input. Staff will then return to the UAC in early 2018 to seek UAC
recommendation of the DER Plan for Council approval. Upon Council approval of the DER Plan,
staff anticipates returning to the UAC and Council every two years to report on the progress
made.
The DER Plan will also be incorporated within the Utilities Strategic Plan (USP). It will also be
incorporated within the Electric IRP to meet SB 350-related state regulations.
Page 9 of 10
RESOURCE IMPACT
Approval of the DER Plan in itself will not require additional resources. Many of the strategies
and actions in the plan can be incorporated into existing efforts since they are tightly
intertwined with ongoing staff work in the areas of energy efficiency, electric vehicles, local
solar, and electrification, or integrate with existing financial planning, distribution system
planning, and electricity supply planning processes. However, increasing penetration of DERs
may introduce additional complexity into the electric utility’s operations, and it is not
implausible that additional resources might be needed. If additional staffing needs are
identified, approval will be sought as part of the annual budget development and approval
process. In addition, in order to realize many of the potential benefits of DERs, CPAU will need
to deploy automated metering infrastructure (AMI) and associated smart grid technologies,
currently estimated to be in place by 2022. Therefore, the implementation of this DER Plan will
be broken into two parts: before AMI deployment (Phase 1), and after AMI deployment (Phase
2) as shown in Figure 3.
Figure 3: Phases of DER Plan within the context of the DER adoption curve 11
The resources currently being expended by CPAU staff and contractors to promote DERs are
shown in Table 1, above. Table 3, below, provides a preliminary estimate of additional staff
time and resources required to implement each of the strategies in the next five years under
Phase 1. These estimates will be refined prior to DER Plan adoption, and will be included in the
FY 2019 budget if appropriate.
The resources required to implement and maintain AMI and related smart grid systems are
clearly the largest driver of additional resources and will be further discussed with the UAC and
Council within the context of Utility Technology Roadmap 12 in early 2018.
11 This graphic is adapted from a CAISO presentation and displays the walk-jog-run framework
12 Smart Grid Assessment and Development of Utility Technology Roadmap – May 3, 2017 UAC Report
Table 3: Est imate of additional effort and budget required to implement DER Plan
Additional
Strategy Additional Effort (FTE) 2018-2022
Budget($)
CY CY CY CY CY CY
2018 2019 2020 2021 2022 2018-2022
1. Lower Barriers for Adoption 0.1 0.1 0 .1 0 .1 0.1 $100-$250k
2. Resiliency 0 .1 0 .1 0 .1 0.1 $20-$60k
3. DER Growth Forecasts & Valuations 0 .1 0.1 $10-$30k
4 . Customer Programs 0 .2 0 .2 0 .3 0.3 0.3 $100-$200k
5. AMI & Advanced Rate Structures 0.5 1 2 2 3 $15-$20M
6. Distribution System Planning 0 .3 0 .3 0.3 0.3 0.3 $100-$200k
7. Electric Supply Planning
8. Workforce Dev elopment & Industry Resources $50-$100k
9. Organ izational Structures 0.1 $25 -$50k
Total without AMI Deployment 0.8 0.8 0.8 0.8 0.8 $380-$865k
Total including AMI Deployment 1.3 1.8 2.8 2.8 3.8 $15.4-
$20.9M
POLICY IMPLICATIONS
The policies to be adopted i n th is DER Plan have implications for business practices throughout
the Utilities Department and implications for the services provided to customers with respect
to DERs. They will be coordinated closely with the Utilities Strategic Plan . Thi s DER Plan is
consistent with the Sustainability and Climate Action Plan (S/CAP) and the Electric Integrated
Resource Plan {IRP) currently under development.
ENVIRONMENTAL REVIEW
The Utilities Advisory Commission's discussion of the proposed DER Plan does not meet the
definition of a project under Pub lic Resources Code 21065 and is therefore California
Environmental Qual ity Act (CEQA) r eview is not requ ired .
ATTACHMENTS
• Attachment A: Distributed Energy Resources (DER) Plan
• Attachment B: Technical Addendum for DER Projections
PREPARED BY:
REVIEWED BY:
APPROVED BY:
LENA PERKINS, Resource Planner dP
SONIKA CHOUDHARY, Resource Planner
SHIVA SWAMINATHAN, Senior Resource Planner ~
cr~IN, Assistant Director, Resource Management.fk
EDSHIKADA
Assistant City Manager/General Manager of Utilities
Page 10of10
Attachment A
Page 1 of 4
City of Palo Alto Utilities - Distributed Energy Resources (DER) Plan
(Draft for Discussion)
Definitions
For the purpose of this document Distributed Energy Resources (DERs) are defined as electrical
energy resources connected to the electric distribution system that can significantly change the
location, timing, and magnitude of the City of Palo Alto Utilities (CPAU) electric loads. This
includes but is not limited to: distributed renewable generation resources such as solar
photovoltaics (PV), energy efficiency (EE), energy storage (ES), electric vehicles (EV), and
demand response (DR) technologies, as well as interactive and flexible resources such as EV
smart chargers, smart thermostats, heat-pump water heaters (HPWH), and heat-pump space
heaters (HPSH).
Goal
Enhance the value of DERs to all members of the Palo Alto community by using DERs to lower
costs, increase sustainability, and increase the resiliency of CPAU while avoiding or mitigating
any potential negative impacts from DER growth.
Objectives
1. Remove internal obstacles to allow greater DER adoption and improve DER value to the
entire community.
2. Facilitate the installation and integration of DERs in Palo Alto in order to increase utility
resiliency, lower utility costs for all customers, and reduce the City’s GHG emissions.
3. Understand the community’s DER adoption potential and diverse needs and develop
DER programs accordingly.
4. Ensure that the utility financial structure and the distribution system can accommodate
DER growth.
5. Be innovative in accelerating adoption of cost-effective DER technologies as well as
initiating pilots programs for strategic emerging DER technologies.
Strategies
1. Lower Barriers to Adoption – Lower barriers and reduce soft costs that may impede the
adoption and installation of DERs by:
a. Streamlining permitting and interconnection processes for all DER technologies,
training customer service and operations staff on revised processes, and
communicating processes to community members and installers.
b. Engaging with industry and DER markets to lower hurdles to adoption through
programs such as:
i. Pursuing bulk-buy programs for PV, EV, EV chargers, ES, HPWH, HPSH, and smart
thermostats; if feasible, pursuing bulk buy programs for strategic emerging DERs;
ii. Training local contractors in DER technologies, interconnection processes, and
permitting processes;
iii. Evaluating and potentially implementing on-bill financing programs for DERs;
Attachment A
Page 2 of 4
c. Regularly updating all fee structures which impact DERs to include the full value of DERs
including the value associated with what time of day and year DERs operate, their
location on electrical distribution system, their carbon reduction potential, and any
secondary benefits attributed to the resource;
d. Researching and evaluating removal of CPAU policies which preclude beneficial uses of
DERs, such as aggregation for the purpose of bidding into electricity wholesale markets.
2. Increase Community Resiliency – use DERs to increase community resiliency by:
a. Evaluating the capabilities of current and emerging technologies to provide the type of
resiliency of highest value to the utility and the community;
b. Investigating the potential to increase flexibility and technical capabilities of all future
and existing DERs on City property, and provide resources for increasing resiliency if
deemed feasible;
c. Investigating the potential for new large DERs to supply emergency back-up services at
City facilities and pursuing projects deemed feasible; and
d. Investigating the potential to modify existing customer incentive programs which could
provide resiliency as well as investigating the potential to supply additional resources to
all customer incentive programs which currently also provide resiliency services.
3. DER Growth Forecasts and Valuations – develop and communicate DER growth forecasts
and valuations by:
a. Regularly monitoring local growth of DER technologies as well as developing and
updating models for growth forecasts based on the technical, economic, and market
potential of DERs;
b. Establishing and updating costs and values associated with location on the distribution
system, time of day and year the DER operates, potential for carbon reduction, value as
a renewable supply of energy, and any secondary benefits attributable to the resource;
and
c. Ensuring consistent projections and valuations are used throughout the organization by
communicating DER growth projections to all relevant divisions and departments
regularly.
4. Customer Programs – maximize value of DER customer programs by:
a. In calculations evaluating cost-effectiveness, developing new incentives and programs,
and prioritizing programs include location on the distribution system, time of day and
year the DER operates, potential for carbon reduction, value as a renewable supply of
energy, and any secondary benefits attributable to the resource;
b. Evaluating strategic pilot programs that can serve local distribution system needs,
enable customers to achieve additional value by serving CAISO market needs, or lower
overall community electric supply and transmission costs, including:
i. Control and communication technologies for DERs (e.g. smart inverters to inject
capacitive energy from PV into the distribution system);
ii. An energy storage pilot program;
iii. A DER aggregation pilot to enable customer participation in wholesale electricity
markets; and
Attachment A
Page 3 of 4
iv. A program for automatic or centrally controlled demand response for commercial
and residential customers.
5. Advanced Metering Infrastructure (AMI) and Advanced Rate Structures – Implement
automated customer metering infrastructure and advanced retail rate structures to
effectively manage the DER resources in the community by:
a. Assessing the impact of current electrical rate structures on DER operations and
exploring cost-justified rate structures that reflect the cost to serve DER-enabled
facilities, while seeking ways to structure these rates such that they allow for cost-
effective operations, maximize benefits to both the utility and the customer, and do
not impede adoption (e.g. Time-of-Use rates, all-electric home rate);
b. Ensuring AMI implementation plan includes an evaluation of the costs and benefits of
system features necessary for effective integration of DERs (such as the ability to
remotely program meters for time-of-use periods); and
c. Forecasting the impacts of DERs on the utility’s long-term financial position.
6. Distribution System Planning – Develop a distribution system plan to accommodate the
adoption of DER growth at the lowest cost while maintaining system reliability to all
customers by:
a. Integrating the impact of DERs into long-term distribution system planning and
considering the cost-effectiveness of DERs to strengthen distribution infrastructure;
b. Performing a Distribution System Assessment at regular intervals that assesses the
available capacity for additional DERs throughout the distribution system within the
context of planned upgrades and projected DER growth;
c. Evaluating the response of the distribution systems for various stresses in the system
(e.g. concentrated locational DER growth, sudden loss of local PV generation due to
cloud cover, operation of protective relays and fault currents, etc.);
d. Evaluating and implementing DER programs that can enhance distribution system
reliability after the implementation of AMI;
e. Re-evaluate the interconnection fee structure and its impact on sizing electric services
to accommodate EVs and all-electric homes;
f. Creating an implementation plan for a Conservation Voltage Reduction (CVR) program
upon implementation of the AMI system when upgrading the substation transformer
controllers; and
g. Developing tools and processes to estimate interconnection fees of large DERs as part
of the initial permitting process.
7. Electric Supply Planning – Consider DERs as a preferred resource and plan for maximum
deployment of cost-effective and feasible DERs within Electric Integrated Resource Plans
(IRP) by:
a. Integrating the DER growth forecasts and scenarios into short and long-term electric
forecasts related to wholesale electricity costs for energy, capacity, and ancillary
services.
b. Considering the risk of stranding assets due to increased penetration of DERs when
evaluating commitments to long-term electric supply resources (i.e., Western contract
renewal and/or new renewable power purchase agreements);
Attachment A
Page 4 of 4
c. Updating as necessary the calculated value of DERs to ensure proper treatment of DERs
in avoiding transmission, distribution and ancillary service costs and/or obligations
using consistent models of time of day DERs operate, location on distribution system,
and potential for carbon reductions; and
d. Analyzing potential DER impacts on sub-annual CPAU carbon emissions and mitigation
strategies.
8. Workforce Development and Industry Resources – Leverage existing industry resources to
enhance in-house staff expertise by:
a. Partnering with industry experts when seeking financing and grant opportunities to
implement DER programs and pilots;
b. Encouraging staff to participate in different industry and expert forums to grow in-
house expertise; and
c. Developing staff training as needed when implementing programs or processes related
to DERs.
9. Organizational Structures – Ensure effective organizational structures are in place to
accommodate DER growth by:
a. Establishing collaborative multi-departmental teams to implement the DER Plan and to
engage with the community and stakeholders effectively (e.g. multi-department
sustainability board, utilities DER Plan implementation team, and technology work
group); and
b. Ensuring that the strategies in the DER Plan are integrated into the work planning,
staffing, and resource requirements of all the departments and divisions affected.
Attachment B
Page 1 of 6
Technical Addendum for Distributed Energy Resource (DER) Projections
Initial projections for DER technologies were developed to inform both the proposed DER Plan
as well as ongoing work regarding DERs. These projections will be updated as more detailed
market assessments are performed.
The distributed energy resources considered for the purposes of these analyses were:
- Energy Efficiency (EE)
- Solar Photovolatics (PV)
- Electric Vehicles (EV)
- Demand Response (DR)
- Energy Storage (ES)
- Heat-pump Water Heaters (HPWH)
- Heat-pump Space Heaters (HPSH)
As shown in Figure 1, projections were developed to address three main areas:
1. DER Adoption Projections: Adoption forecasts for each DER technology.
2. DER Load Impact Projections: Energy used or delivered to the system on an hourly and
seasonal basis to determine the impact of DERs on electric sales and load shape.
3. DER Financial Impact Projections: Financial impact to the utility of DER adoption based
on the adoption and load impact projections. This analysis considered only the impact to
wholesale electric supply costs, and did not include the impact of changes to current
rate structures.
The detailed assumptions and limitations of each of these projections are discussed in their
following respective sections.
Figure 1: DER projections and analyses undertaken to-date
Attachment B
Page 2 of 6
1. DER Adoption Projections
Preliminary forecasts of the number of DER systems through year 2030 are shown below in
Table 1. The 2030 estimates are highly variable, as they depend on market conditions,
technological innovations, and changing regulations, and therefore these estimates could
increase or decrease by up to 50%.
Table 1: Estimated number of DER systems through 20301
Estimated Number of Systems
DER Technology 2017 (current) 2020 2030
PV 1,000 1,300 2,500
EV 2 2,500 5,900 18,700
EE 40,880 45,000 60,000
DR 8 25 75
ES 11 85 580
HPWH 10 200 2,700
HPSH 0 25 800
Assumptions & Limitations:
These projections were developed for long-term load forecasting and budgeting purposes.
They reflect current realistic estimates of technology adoption rates. The current forecasts do
not achieve S/CAP goals by 2030, but staff will be coordinating with the sustainability team to
accelerate adoption wherever cost-effective. These forecasts will be updated regularly and
staff will continue to collaborate with other departments to support City sustainability goals.
- EE: Adoption rates for EE are based on the 10-year Energy Efficiency Goals for 2018-2027
which were updated in 2017.3 For the years 2028 through 2030 the assumed savings are
the average of the savings in 2026 and 2027 which is the methodology suggested by the
CEC for estimating savings beyond the 10-year goals.4 More details on the EE
methodology for market potential can be found in Staff Report 7718 from March 6,
2017.
- PV: These projections are based on a technical and economic potential, with adoption
growing steadily, with the growth rate itself plateauing as is typically seen in a maturing
market. These projections include behind the meter installations in residential and
commercial sectors, but do not include a Community Solar installation. These
projections also do not include the feed-in tariff installations from the CLEAN program as
1 These estimates represent current base case scenarios. Staff will explore appropriate high and low scenarios in
further modeling.
2 This is the total residential EVs currently registered in Palo Alto. There are also EVs which commute into Palo
Alto, some of which charge while in Palo Alto and add to CPAU electricity sales. In addition to the residential EVs
shown here, there are estimated to be approximately 3,100, 5,900 and 20,000 commuter EVs in 2017, 2020 and
2030 respectively.
3 Although CPAU established our EE goals based on net savings, the energy efficiency savings shown here are on a
gross basis (which includes EE savings due to free-ridership).
4 The extension of savings through 2030 is based on the methodology put forth in the CEC presentation September
7, 2017 which can be found here: CEC presentation on Energy Efficiency Savings from Utility Programs.
Attachment B
Page 3 of 6
these are counted as supply resources and count towards the electric utility’s Renewable
Portfolio Standard.
- EV: To -date Palo Alto has observed residential EV adoption rates approximately three
times greater than the California statewide average, and this rate for residential
adoption relative to statewide average projections is assumed to continue to 2030. To
estimate the EV adoption rates of commuters into Palo Alto the observed adoption rate
from 2017 census data for the entire Bay Area was extended to 2030.
- DR: This forecast is based on modest growth of the current voluntary large commercial
demand response program. Somewhat more robust growth is expected after AMI
implementation in 2023.
- ES: This forecast is based on statewide projections for batteries and CPAU electricity rate
structures.
- HPWH: This forecast is based on historical of PV penetration, market readiness, and
CPAU customer program management experience. Based on this forecast, staff projects
a natural gas load reduction of up to approximately 1% from HPWH by 2030.
- HPSH: This forecast based on historical of PV penetration, market barriers, and CPAU
customer program management experience. Based on this forecast, staff projects a
natural gas load reduction of up to approximately 1% from HPSH by 2030
2. DER Load Impact Projections
Table 2 shows the impact of DERs on CPAU’s energy sales based on the number of systems
projected in Table 1. These estimates are also highly variable, as each underlying component
could change by as much as 50% by 2030. Moving forward, the combined impact of all these
DERs is expected to lower energy sales by 2.2% by 2020 and 6.6% by 2030.5 The net effect of
projected DERs coming online after 2017 is to offset other anticipated electricity load growth
throughout CPAU territory,6 leading to essentially flat total CPAU system loads from 2017
through 2030. However, a scenario with higher load growth, lower adoption of EE or PV, or
higher adoption of EVs could result in an overall growth of electricity sales.
Table 2: Estimate of the impact of DERs on CPAU retail energy sales
DER Technology 2017 (current) 2020 2030
Contribution to Energy Sales MWh % MWh % MWh %
PV -15,000 -1.6% -18,800 -2.0% -45,200 -4.9%
EV 7,100 0.8% 14,300 1.6% 54,800 6.0%
EE -55,300 -6.0% -78,800 -8.6% -139,200 -15.2%
DR 7 - 23 - 200 0.02%
ES7 - - - - - -
5 All percentages are relative to Fiscal Year 2017 electricity retail sales.
6 For budgeting purposes the Northern California Power Agency has developed an econometric regression to
forecast electric sales from 2018 to 2030 with the current level of DERs (in other words assuming no additional
DERs). The CPAU overall system load growth from 2017 is the combination of this econometric forecast and the
individual DER forecasts.
7 Batteries and other ES devices may result in either net increased energy retail sales (due to battery losses where
commercial customers use batteries to avoid CPAU demand charges) or net decreased energy retail sales (due to
increased onsite consumption of behind the meter solar). For the purpose of these analyses these two effects are
assumed to be roughly the same magnitude and therefore ES systems are not considered to have any net effect on
Attachment B
Page 4 of 6
HPWH 9 - 190 0.02% 2,500 0.3%
HPSH - - 90 0.01% 2,800 0.3%
Combined DER Impact: from
2007 -63,200 -6.9% -83,000 -9.1% -124,000 -13.6%
Combined DER Impact: from
2017 - - -19,700 -2.2% -60,900 -6.6%
CPAU Overall System Load
Growth from 20178 - - -3,200 -0.3% -6,900 -0.8%
Figure 2: Projected impact of DERs on annual electricity sales from 2018 through 2030
Another important aspect of DERs is their ability to potentially flatten overall peak demand,
especially due to PV and DR. The impact of the projected DERs on a peak summer day in 2030 is
illustrated in Figure 3, showing that the combined effect is to flatten the overall load shape and
lower the peak demand. This overall flattening of peak demand is anticipated to increase the
overall system annual load factor from 62% in 2016 to 70% in 2030.9 A higher load factor and
flatter loads tend to lower overall CPAU costs.
energy sales.
8 Going forward from 2017 the total CPAU load is forecasted to grow at roughly 0.4% per year if no more DERs
were added to the system. With the addition of new DERs, the total CPAU load is projected to decrease by roughly
0.8% from 2017 electricity sales by the year 2030.
9 Annual Load Factor is a measure of transmission and distribution system utilization and is defined as the ratio of
average annual energy load to the peak annual energy load. A high load factor means that system capacity is
highly utilized, with average annual usage that is not much lower than the annual peak. A low load factor indicates
that electric use has a high annual peak relative to annual average usage, meaning that substantial additional
Attachment B
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Figure 3: Potential change in hourly electric loads on a peak summer day (2017 vs. 2030)10
3. DER Financial Impact Projections
As of 2017 CPAU’s retail electricity sales are approximately 6.9% lower due to EE, PV and EV
adoption to date (as illustrated in Table 2), which equates to a reduction of about $7.8 million in
revenues. The corresponding savings related to lower electricity supply purchases is estimated
to be about $4.4 million, which has resulted in a net revenue impact of $3.4 million reduction in
revenues for the utility compared to if those resources were not present in 2017 (considering
only savings in utility electricity supply costs).11 The potential financial impact figures are shown
here in order to facilitate understanding of the potential scale of impact from different DERs in
the future. The impact of successful EE and PV programs on CPAU is an integral part of utility
financial planning and projections.12
DERs projected to come online from 2018 through 2030 are estimated to reduce utility net
revenues by $5.4 million, relative to if those DERs did not come online (based on utility supply
costs and total revenues alone).13 The detailed contribution by resource is shown below in
system capacity is needed to serve that high annual peak, generally resulting in higher costs due to low utilization.
10 HPSH are included on a peak summer day since there is an expectation that heat-pump space heaters will be
used as air conditioners on the hottest days.
11 It should be noted that both EE and PV systems lower participants’ electricity bills, and can provide other
benefits not captured in this cost estimate.
12 Reduction in revenues can put upward pressure on customer retail rates. However, reduced use of utility energy
services due to EE and PV programs as well as other benefits not captured here will tend to lower overall customer
utility bills.
13 These estimates are highly uncertain and depend on the relative growth of different DER technologies, market
supply costs, and also do not include other potential costs and benefits to the utility. Given the levels of
Attachment B
Page 6 of 6
Table 3. However, total CPAU net revenues are expected to be nearly flat since these load
reductions are expected to be offset by other electricity load growth.
Table 3: Estimated impact of DERs on electricity supply costs & revenues from 2017 14 (∆ 𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹)−(∆ 𝑺𝑺𝑹𝑹𝑺𝑺𝑺𝑺𝑺𝑺𝑺𝑺 𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪)=(∆ 𝑵𝑵𝑹𝑹𝑪𝑪 𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹)
2020 Estimate 2030 Estimate
DER
Technology
Revenue
Impact
Supply Cost
Impact
Net Revenue
Impact
Revenue
Impact
Supply Cost
Impact
Net Revenue
Impact
PV -$0.6 M -$0.3 M -$0.3 M -$5.2 M -$2.8 M -$2.4 M
EV $1.1 M $0.5 M $0.6 M $8.3 M $4.4 M $3.9 M
EE -$3.5 M -$1.7 M -$1.8 M -$14.5 M -$7.7 M -$6.8 M
Combined DER
Impact -$3.0 M -$1.5 M -$1.5 M -$11.5 M -$6.1 M -$5.4 M
Well -integrated DERs have the potential to lower electricity supply cost even further, as well as
provide other benefits and value streams.15 Staff will be investigating ways of maximizing the
value of DERs in order to continue to keep customer retail rates low.
uncertainty and potential for technology and market changes, it is entirely possible that the impact on supply costs
and utility revenues could vary by more than 50% from the estimates provided here.
14 The impact on supply costs are estimated based on avoided supply costs of 7.4 cents per kWh in 2020 and 9.3
cents per kWh in 2030. The impact on revenues is based on projections of system-wide average retail rates of 15
cents per kWh in 2020 and 17 cents per kWh in 2030. Due to the high-level of uncertainty, only the largest DERs
are included in this preliminary estimate on utility financial impacts.
15 Additional value streams that could be garnered from DERs that could lower the reduction of net revenues
include: flattening of electricity demand profiles, shaping of electricity demand to better match renewable
resource availability, and enabling customer-owned DERs to bid into electricity wholesale markets.
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2
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: January 9, 2019
SUBJECT: Staff Request for Feedback on Recommendations Regarding the City’s Fiber-Optic,
Wireless and Advanced Meter Infrastructure Planning
______________________________________________________________________________
Request
Request for feedback from the Utilities Advisory Commission regarding the following two staff
recommendations regarding fiber-optic, wireless and Advanced Metering Infrastructure (AMI)
planning:
1. Staff is considering reissuing the Fiber-to-the-Node (FTTN) Request for Proposal to expedite
network planning, design and construction and to better align the FTTN network business case
with the AMI implementation plan. Additional tasks will include a detailed design and
construction cost estimate to build the network.
2. Have the Utilities Advisory Commission (UAC) assume the advisory role to provide guidance and
alignment for the AMI implementation plan with fiber and wireless expansion initiatives, and
sunset the Fiber and Wireless Citizen Advisory Committee (CAC), effective January 17, 2019.
Background
On August 21, 2017, Council directed staff to: (1) Pursue a Fiber-to-the Node (FTTN) network for fiber
and broadband expansion; and (2) Expand Wi-Fi to unserved City facilities and discontinue
consideration of City-provided Wi-Fi in commercial areas - Staff Report ID #7616:
https://www.cityofpaloalto.org/civicax/filebank/documents/61084).
The Council Motion directed staff to:
A. Develop a business case for a municipal-provided Fiber-to-the-Node (FTTN) network for fiber
and broadband expansion (“Option 2”); engage a management consultant to develop the
business case, funding plans, identify potential partners and/or service providers, and high level
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network design; and engage an engineering firm to design a FTTN network including an
expansion option to build a citywide Fiber-to- the-Premises (FTTP) network; and
B. Expand Wi-Fi to unserved City facilities and discontinue consideration of City provided Wi-Fi in
commercial areas; and
C. Expediently return to Council with Ordinances that will lower the City’s FTTN construction costs
such as a Dig Once, String Once Ordinance; a Multi-unit housing Ordinance; and a
Microtrenching Ordinance.
On November 19, 2018, the Council approved the City of Palo Alto Utilities Smart Grid Assessment and
Technology Implementation plan, including advanced metering infrastructure-based smart grid
systems to serve electricity, water and natural gas utility customers - Staff Report ID #9780:
https://www.cityofpaloalto.org/civicax/filebank/documents/67639)
AMI is a foundational technology that is becoming a standard in the utilities industry and will improve
customer experience while enabling City of Palo Alto Utilities to operate more efficiently. The Council
encouraged staff to align the FTTN business case and leverage the dark fiber network with the AMI
deployment.
Discussion
In response to the Council’s August 21, 2017 motion, staff completed the following actions:
1. A Request for Proposal (RFP) was issued on June 28, 2018, to retain a management consultant for
professional services to develop a business case to build a FTTN network to multiple neighborhood
nodes, assess local market conditions, identify potential public-private partnerships, and develop
City ordinances that could lower fiber construction costs and incentivize fiber development. The
RFP noted that depending on the outcome of the above-mentioned tasks, the City may issue
another RFP to engage an engineering firm to prepare a detailed design and cost estimate for a
FTTN network, including an expansion option to deploy a citywide FTTP network. The RFP scope of
work included all the above-noted items in parts A and C of the Council Motion.
2. The City’s OverAir Wi-Fi hotspots were expanded to the following unserved City facilities: Lucie
Stern Children’s outdoor theater, Lucie Stern courtyard, Baylands Golf Course Café and Pro Shop,
and within all rooms across the Cubberley Community Center campus.
Considering the Council’s acceptance of the smart grid and technology plan, it is recommended that
the fiber-optic network expansion planning employ a fundamental design principle of fully leveraging
and expanding this network to support a communications platform for AMI, Smart City initiatives and
wireless technologies to support City services. As a result, and in response to Council’s November 19,
2018 motion, staff is assessing whether to revise some of the tasks requested in the original FTTN RFP
to better align the business case with the AMI network, including potentially adding the detailed design
and cost estimate for a Citywide FTTN network to the project scope and reissuing the original RFP, with
the tasks shown below:
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• Task 1 – Develop a business case and identify potential applications for FTTN, including a
financial model for each alternative network and a high-level scalable design to support
essential City services, including AMI.
• Task 2 – Identify potential private-public partnership models to attract partners to deploy next
generation broadband services for the community.
• Task 3 – Draft City ordinances for Council consideration to lower fiber construction costs to
incentivize third parties to build and operate a new network. Example ordinances include Dig
Once, Microtrenching, String Once (a.k.a. One Touch Make Ready), and Multi-unit housing
access.
• Additional Task 4 – Dependent on the outcome of the business case, prepare a detailed design
and construction cost estimate for a FTTN network.
Staff has worked constructively with the Citizen Advisory Committee (CAC) since its appointment by
the City Manager in 2014. Notable accomplishments of the CAC include working with staff and a
consultant to prepare the 2015 Fiber-to-the-Premises Master Plan and Wireless Network Plan,
preparing a Request for Information (RFI) in 2016 for a public-private partnership to build a citywide
FTTP network, providing input for the 2018 FTTN RFP, in addition to providing assistance related to
Google Fiber. The Committee’s valuable guidance has been much appreciated. At this time, given
Council’s direction to prepare a FTTN network business case and approval of the AMI implementation
plan, staff recommends the UAC assume the primary role in aligning AMI with the fiber and wireless
expansion initiatives, and to provide recommendations to the Council. The UAC is well suited to
assume this role, which is in line with its purpose and duty to advise Council on major programs and
projects related to the City’s utilities, including the fiber optics utility. The UAC can also provide a broad
forum for wider community participation, outreach and oversight for fiber, wireless and AMI planning.
The UAC will effectively facilitate recommendations to the Council and create the best opportunity to
efficiently leverage the City’s fiber network with the AMI implementation to expedite network
planning, design and construction.
Resource Impact
Depending on feedback from the UAC, staff will recommend to Council an award of a professional
services contract to retain a consultant to perform the tasks above, and will return to Council for
approval.
Policy Implications
The fiber and wireless activities are consistent with the Telecommunications Policy adopted by the
Council in 1997, to facilitate advanced telecommunications services in Palo Alto in an environmentally
sound manner (Reference CMR: 369:97- Proposed Telecommunications Policy Statements).
PREPARED BY: Jim Fleming, Senior Management Analyst
REVIEWED BY:
Dave Yuan, Strategic Business Manager
DEPARTMENT HEAD:
Dean Batchelor, Interim Utilities General Manager