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HomeMy WebLinkAboutStaff Report 2505-46875.Status Update on Studies Related to the Electric Utility’s Reliability and Resiliency Strategic Plan (RRSP) Strategies 4 and 5 and Request for Feedback on Draft Proposals for Implementation. CEQA Status: Not a Project. ACTION: 8:35 PM – 9:35 PM Item No. 5. Page 1 of 11 Utilities Advisory Commission Staff Report From: Alan Kurotori, Utilities Director Lead Department: Utilities Meeting Date: July 9, 2025 Report #: 2505-4687 TITLE Status Update on Studies Related to the Electric Utility’s Reliability and Resiliency Strategic Plan (RRSP) Strategies 4 and 5 and Request for Feedback on Draft Proposals for Implementation. CEQA Status: Not a Project. RECOMMENDATION Staff is seeking feedback on studies and draft proposals for implementing two of six strategies under the Electric Utility’s Reliability and Resiliency Strategic Plan: Strategy 4 (Evaluate the benefits of flexible and resiliency technologies and efficient electrification strategies to the utility and community) and Strategy 5 (Evaluate the resource needs to promote the adoption of various flexible demand reduction and resiliency solutions and efficient electrification strategies) . Staff requests the Utilities Advisory Commission (UAC) provide feedback by discussion on various policy approaches to be incorporated into a forthcoming report to Council with a cost benefits for various technologies (Strategy 4) and programs for consideration (Strategy 5). Staff recommends the following policy feedback as a starting point for the UAC’s discussion: 1. Promote ways community members can save money by reducing peak period load (helping the electric grid) under time of use (TOU) rates once those rates are launched. 2. Monitor demand response technologies for positive benefit-cost opportunities but continue existing City practice of not pursuing demand response (unless benefit to cost ratios change in the future). 3. Promote residential solar and battery adoption, standalone batteries and thermal storage, but continue the City’s current policies of not providing technical assistance programs or incentives due to the fact costs exceed benefits. 4. Promote electric vehicle to home/grid as it becomes more available, but continue the City’s current policies of not providing technical assistance or incentives (unless benefit- to-cost ratios change in the future). 5. Further explore the cost-effectiveness of local larger-scale commercial solar + battery programs and bring to the UAC and City Council for consideration as part of the report Item No. 5. Page 2 of 11 on Strategies 4 and 5 if cost-effective options can be identified, while continuing to pursue utility-scale solar and storage and other renewables in parallel. 6. Monitor opportunities for distribution investment deferral using flexible technologies and efficient electrification but do not pursue additional analysis or new policies or programs at this time. 7. Maintain City’s current policies on microgrids and backup power (long-term resiliency). 8. Explore electric utility / treatment plant partnership on airport microgrid. Staff welcomes recommended adjustments to this set of policy choices or other approaches, but seeks majority UAC support to include implementation strategies given the amount of staff time and consultant costs that could be expended in further analysis or development of potential program ideas. These policy approaches and alternatives are explained further in the Analysis section (Topic 6) below. EXECUTIVE SUMMARY The RRSP was adopted by Council in April 2024 and contains six strategies intended to ensure a reliable, well maintained electric system with enhanced reliability to support an electrified community, and options for electrified homes during outages. An overall status update on RRSP implementation is in Attachment F. RRSP Strategies 4 and 5 encompass a wide range of studies and research to evaluate the use of solar and storage, other flexible technologies, and efficient electrification to reduce utility supply costs, defer distribution investment, and enhance short- term and long-term resiliency, with the goal of identifying potential utility and customer programs for Council consideration. This report provides updates on five topics staff and its consultants have analyzed or researched: 1.Supply Costs and Short-term Resiliency: Preliminary results of a cost-benefit analysis of the use of solar and storage and other flexible technologies to reduce utility supply costs and enhance short-term resiliency (Attachment A). This analysis completes implementation of RRSP Strategy 4, Action 1 and partially implements Strategy 4, Actions 3 and 4 (the parts focused on short-term as opposed to long-term resiliency). 2.Deferral of Distribution Investment: Preliminary analysis of the cost-benefit of deferring distribution investment and the associated challenges with doing so (Attachment B). This analysis implements RRSP Strategy 4, Action 2. 3.Microgrid and Long-term Resiliency Policies: Overview of current City policies on solar and storage microgrids and emergency backup power for community needs in an emergency and potential alternatives and challenges (Attachment C). This assessment partially implements RRSP Strategy 4, Actions 3 and 4 (the parts focused on long-term resiliency). 4.Airport Microgrid Study: Preliminary findings from the airport microgrid study (Attachment D). This study implements RRSP Strategy 5, Actions 3 and 4. 5.Draft Criteria for Cross-Parcel Microgrids: Draft screening criteria based on lessons learned from the airport microgrid study on when cross-parcel microgrids might be appropriate (Attachment E). These criteria partially implement RRSP Strategy 5, Action 4. Item No. 5. Page 3 of 11 BACKGROUND The RRSP1 resulted from discussions with the UAC and the Council’s Sustainability and Climate Action (S/CAP) Committee and its Working Group leading up to and following the June 5, 2023, adoption of the S/CAP and the 2023-2025 S/CAP Work Plan2. Included in the S/CAP Work Plan was work items 1.B and 1.C to create and implement the Electric RRSP. At its December 6, 2023, meeting the UAC discussed the elements and scope of the RRSP and recommended Council approval3. The City Council approved the Reliability and Resiliency Strategic Plan (RRSP) on April 15, 20244. In September 2024 the UAC reviewed the scope for a consultant study to implement Strategies 4 and 5 of the RRSP.5 In February 2025 the UAC provided feedback on some preliminary insights and results from the study.6 This report provides more comprehensive and developed results (though not yet finalized) and requests additional feedback to enable completion of the final report. ANALYSIS This report requests Commission feedback on the five topics above to help staff complete a final report containing the cost-benefit analysis (Strategy 4) and programs for consideration (Strategy 5) related to flexible technologies and efficient electrification for utility supply cost savings, distribution investment deferral, and customer resiliency. The Commission’s feedback will enable staff to finish developing the proposed programs. Topic 1: Results of Benefit-to-Cost Study on Supply Costs and Short-Term Resiliency Attachment A shows the results of an analysis by the City’s consultant, Buro-Happold, on the net community benefit of running programs to help people install various technologies (e.g batteries, vehicle to grid, solar, etc.) in Palo Alto. They assessed the benefits of the utility supply 1 Reliability and Resiliency Strategic Plan, Approved by the City Council April 14, 2024: https://cityofpaloalto.prime gov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=f90b4733-eb24-4699-b4f1- 229af03f8fd5 2 Adopted 2023-2025 S/CAP Work Plan: https://www.cityofpaloalto.org/files/assets/public/v/1/sustainability/repo rts/2023-2025-scap-work-plan_final.pdf 3 UAC, Staff report 2311-2263, December 6, 2023, S/CAP Strategic Plan on the Reliability and Resiliency for the Electric Distribution Utility. https://www.cityofpaloalto.org/files/assets/public/v/3/agendas-minutes- reports/agendas-minutes/utilities-advisory-commission/archived-agenda-and-minutes/agendas-and-minutes- 2023/12-dec-2023/12-06-2023-packet-v2.pdf 4 City Council, Staff Report 2401-2496, April 15, 2024, Approve the Reliability and Resiliency Strategic Plan as Reco mmended by the Utilities Advisory Commission, https://cityofpaloalto.primegov.com/meetings/ItemWithTemplate Type?id=4485&meetingTemplateType=2&compiledMeetingDocumentId=9592 5 UAC, Staff Report 2405-2984, September 4, 2024, Discussion of Implementation of Reliability and Resiliency Strate gic Plan – Review of Consulting Scope of Work to Scope Projects to Enhance Resiliency, Staff report: https://cityofpa loalto.primegov.com/api/compilemeetingattachmenthistory/historyattachment/?historyId=71a87cda-639b-441d- 9069-91ee5b89e717 Attachments: https://cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=541 6&meetingTemplateType=2&compiledMeetingDocumentId=11628 6 UAC, Staff Report 2501-4058, February 5, 2025, Reliability and Resiliency Strategic Plan: Update on Studies, https://cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=7116&meetingTemplateType=2&comp iledMeetingDocumentId=13041 Item No. 5. Page 4 of 11 cost savings and the value of the short-term resiliency benefits during utility outages. The analysis showed that almost no programs based on these technologies showed a positive benefit to cost ratio just based on these two factors, meaning they would need more value from other sources (such as deferral of distribution investment or long-term resiliency). More specifically: •TOU rates were not evaluated for cost-effectiveness since the overhead is minimal. Instead, the consultant estimated the potential savings associated with the rates. •Demand response showed low benefits relative to the costs. The costs were primarily the program costs of operating a demand response program. These programs require much larger economies of scale than are easily achievable in a small service territory like Palo Alto to be cost-effective. This is consistent with past City electric utility experience with these programs. •Standalone battery programs (including fixed battery storage systems, vehicle to grid, and thermal batteries in both residential and commercial contexts) also showed low benefit to cost ratios, primarily due to technology costs, but also program costs. Commercial standalone fixed battery storage programs showed the most promise, achieving a 0.9 benefit to cost ratio. A significant portion of the benefit came from the short-term resiliency gains for commercial property owners, which were estimated to be considerable based on the applied resilience valuation model. •Solar plus battery programs showed the most promise. Residential programs had a 0.9 benefit-cost ratio, with long-term resiliency benefits potentially pushing the benefits higher than costs for those who value them highly enough. Commercial programs achieved a 1.07 ratio, driven by significant short-term resiliency gains, suggesting owners may be willing to invest. However, long payback periods to realize benefits are a challenge, as businesses often require 2–4 year returns. To succeed, commercial programs may need on-bill financing or utility ownership models that treat systems as off-book expenses rather than capital investments. Topic 2: Preliminary Results - Distribution Investment Deferral Study Attachment B summarizes a preliminary analysis on deferring distribution upgrades to assess whether a deeper $150,000–$200,000 study was justified. Only 360 of 1,700+ transformers in Palo Alto were good deferral candidates, offering about $1 million per year in avoided debt service—or a 0.55% rate impact. However, achieving this would require over 2,400 batteries costing at least $1.3 million per year, and that does not include the additional costs for battery controllers, staffing of battery system control, operations and maintenance, and program management costs to get the batteries installed. Risks include insufficient participation that incurs program costs without realizing benefits, reduced efficiency of the grid modernization program by excluding some transformers in upgraded neighborhoods, construction costs rising faster than inflation and increasing the real cost of future replacements, and the fact that the approach is novel and cutting edge — posing execution risks for a small utility like Palo Alto. Item No. 5. Page 5 of 11 Topic 3: Policies on Microgrids and Long-term Resiliency Attachment C outlines the City’s current policies on microgrids and long-term resiliency (i.e. planning for backup power in a major emergency). A microgrid is essentially the combination of a local on-site solar and storage system that serves two functions by replacing imported non- local utility power while also providing backup power (supplementing or replacing diesel generators).7 Under current policies the City takes any utility supply cost savings created by on- site solar and battery and passes it through to the utility customer who installed the system through either the net energy metering rate or the PaloAltoCLEAN feed-in tariff. Typically, that value is insufficient to pay for the solar/battery system, so people who install systems in Palo Alto typically value short-term and long-term resiliency highly enough that the extra cost is worth it. Alternatives to solar and storage for backup power include both diesel and dual fuel (diesel or natural gas) backup generators. Fossil fuel backup generators are more scalable than solar and storage (they are not limited by available roof space) so can power larger electric loads. But they require fuel, where a solar and storage system sized properly can run electric loads indefinitely. Fuel availability is particularly a challenge for diesel generators in a longer-term emergency, but this issue can be mitigated by installation of a dual fuel generator that can use natural gas so long as the emergency did not result in a break in the natural gas infrastructure to the site. Current policies leave decisions about backup generation to the utility customers themselves. The City runs some programs to facilitate solar installations and removes barriers to adoption, but does not provide technical assistance or incentives. The Office of Emergency Services (OES) and City facility managers assess backup power needs for City facilities, but do not do the same for private facilities. If the City were to change those polices there would be a few decisions to make: •The purpose of the program. Some options might be: o Expanding community resiliency – focused incentives for facilities that would help. the community in an emergency if powered (e.g. groceries, community centers) o Assisting income-qualified households access resiliency. o Promoting local solar plus storage for all to enhance community resiliency, even if it increases electric bills for all. •Whether to provide technical assistance, financing, or incentives •How to fund the program •If implementing a community resiliency program, how to determine which facilities to prioritize. This would likely require additional resources for OES to develop recommendations 7 More broadly a microgrid can be any combination of generators, not just solar and batteries, but solar and battery microgrids are the most common system cited when the topic of microgrids is discussed. Item No. 5. Page 6 of 11 Staff is seeking feedback on whether to change policies, and if so, what the purpose of a microgrid / long-term resiliency program would be. Topic 4: Airport Microgrid Study Preliminary Results The airport has provided a good test case for microgrid analysis. The City’s consultant, Burns- McDonnell, has done some high-level analysis to determine the maximum potential for solar at the airport and some ways it could be used (Attachment D). First, there is a lot of solar potential – about 7 MW, which generates energy equal to about 1% of the community’s annual electric load. Staff and its consultant identified three potential purposes for all that energy: •A power purchase agreement (PPA) with the utility. •Backup power for the Regional Water Quality Control Plant (RWQCP). •Creating an EV charging depot that would be a fast charger for drivers just off the highway under normal operating conditions and enable vehicle charging during a major emergency, which would enable residents to power their homes using vehicle to home technology. The findings were mixed. The proposed power purchase agreement was costlier than importing non-local power. The system could reduce diesel use at the RWQCP, extending operations by 1– 5 days in January (when solar generation is lowest) and 45+ days in September (when it is highest). With only 1–3 days of diesel on site, this is appealing—but integrating with the existing backup system would be complex. Simpler options, like a dual-fuel generator, may offer better reliability. A 10-charger, 100 kW EV depot could provide major outage support for community EV charging but would need high non-outage use to justify the investment. It could be possible to combine these purposes, using the system for a utility PPA under normal operating conditions and to power the RWQCP under emergency conditions. If the RWQCP partners were willing to pay enough for this additional resiliency, it might make the project viable. Determining the feasibility would require additional analysis. If none of these alternatives worked, a small solar and storage microgrid at the airport without utility partnership could still be viable. Topic 5: Draft Criteria for Consideration of Cross-Parcel Microgrids The airport microgrid analysis provided some insights into when a cross-parcel microgrid might or might not be useful. This concept is a solar and storage installation that is connected across multiple sites that normally would have completely separate utility connections. Staff created draft criteria for future consideration of this concept in Attachment E. It envisions a cross-parcel microgrid potentially being useful only for a site that: 1. First, has such a high priority electric power need that it requires a backup power solution more resilient than a diesel or dual fuel natural gas / diesel engine. Diesel fuel availability in a major emergency would need to be a concern, as would breaks in the natural gas system feeding the site. Item No. 5. Page 7 of 11 2. Second, the electric power need would have to require more power than an on-site solar + storage microgrid can provide 3. Third, there would need to be a nearby parcel or parcels that has enough spare solar capacity to help power the high priority electric load. Staff is seeking UAC feedback on these criteria before incorporating them into the final proposed report on Strategies 4 and 5. Topic 6: UAC Feedback on Next Steps for Further Analysis and Program Idea Development Staff is seeking UAC feedback on how to proceed with further analysis and program development. Below are explanations for the proposal staff provided in the Recommendation section and potential alternatives to each component for UAC discussion. 1. Promote ways community members can save money by reducing peak period load (helping the electric grid) under time of use (TOU) rates once those rates are launched. As the City launches TOU rates, staff recommends promoting technologies and behaviors that will help community members save money under time of use rate designs but not pursuing technical assistance programs or technology incentives. An alternative policy approach could be to evaluate appliances with scheduling capabilities and provide incentives for those capabilities based on the expected grid savings in addition to providing information to potential buyers. 2. Monitor demand response technologies for positive benefit-cost opportunities but continue existing City practice of not pursuing demand response (unless benefit to cost ratios change in the future). Given the low cost-benefit found for demand response in the Buro Happold study (see Topic 1 and Attachment A), staff does not recommend pursuing demand response at this time. The City could track demand response technologies and, if opportunities for demand response programs with a positive benefit to cost ratio arise, pursue them. An alternative approach could involve a comprehensive analysis to identify the scale and type of demand response technology with the highest benefit-cost ratio, helping the City uncover potential niche opportunities worth pursuing.3. Promote residential solar and battery adoption, standalone batteries and thermal storage, but continue the City’s current policies of not providing technical assistance programs or incentives due to the fact costs exceed benefits. Staff does not recommend providing incentives or technical assistance programs for technologies with a low benefit to cost ratio in the Buro Happold study (see Topic 1, Attachment A). These technologies can help the electric grid if installed voluntarily, but do not provide enough value to merit providing incentives or technical assistance programs. This includes residential solar and commercial batteries. These both had higher benefit to cost ratios than most other technologies analyzed, but overall benefits are lower than costs. Both of these technologies would be affordable under existing rates and policies to a utility customer who values resiliency and reliability highly enough. An alternative to this approach could be to Item No. 5. Page 8 of 11 provide programs or incentives for residential solar and battery adoption to income-qualified customers. 4. Promote electric vehicle to home/grid as it becomes more available, but without continue the City’s current policies of not providing technical assistance or incentives (unless benefit-to-cost ratios change in the future) Vehicle to home and vehicle to grid technologies, based on current early estimates of technology costs and availability, have costs that exceed benefits. However, these technologies are still being commercialized. Staff recommends monitoring these technologies, reducing barriers as they become more widely available, and reassessing this analysis in a few years to see if they would be cost-effective. An alternative could be to actively run a pilot program of these technologies, which would require staff time and other resources that could be defined in the final report if such an option were requested by the UAC. 5. Further explore the cost-effectiveness of local larger-scale commercial solar + battery programs and bring to the UAC and City Council for consideration as part of the report on Strategies 4 and 5 if cost-effective options can be identified, while continuing to pursue utility- scale solar and storage and other renewables in parallel. Commercial-scale solar and battery programs showed a positive benefit to cost ratio based on the combined reduced utility supply costs and customer short-term resiliency benefit. Staff recommends further exploration of this project type. A program involving a commercial customer monthly on-bill financing payment or third party ownership with a utility PPA may avoid some of the challenges that come with the short payback periods commercial customers generally need and the lack of availability of capital for nonprofits and public agencies. An alternative could be to do no more exploration of this project type. 6. Monitor opportunities for distribution investment deferral using flexible technologies and efficient electrification but do not pursue additional analysis or new policies or programs at this time The results of staff’s preliminary analysis of deferring distribution investment was not promising (see Topic 2, Attachment B). Staff recommends continuing to promote efficient electrification (e.g. circuit sharing, circuit pausing, and low wattage equipment, avoiding panel upgrades), and continue to seek even more cost-efficient approaches to the grid modernization project through efficient capital planning and project management. Staff does not recommend pursuing further analysis or program proposals on deferring distribution investment using flexible technologies like batteries. An alternative to this approach could be to do a more detailed analysis for $150,000 to $200,000 or wait until AMI data is available from more all- electric homes and rerun the analysis with a broader data set to see if it surfaces potential opportunities. 7. Maintain City’s current policies on microgrids and backup power (long-term resiliency) Item No. 5. Page 9 of 11 As described in Topic 3 and Attachment C, there are several current policies facilitating microgrids for those who value long-term resiliency sufficiently. As noted in the Buro Happold analysis (Topic 1, Attachment A) the benefit to cost ratio for solar plus batteries is close to one based on just supply cost savings and short-term resiliency, and a utility customer who values long-term resiliency enough will do an installation. Staff recommends continuing these policies. An alternative could be providing incentives for long-term resiliency, which requires determining the goal of the incentives as discussed in Topic 3 and Attachment C (e.g. to promote long-term resiliency at community-serving businesses like grocery stores that might be beneficial to have operating in an emergency, to help residents on an income-qualified basis, or to create long-term resiliency programs accessible to all). 8. Explore electric utility / treatment plant partnership on airport microgrid Staff recommends additional discussion between the City’s Utilities and the Public Works Departments to determine whether a partnership to develop a microgrid at the airport for utility-scale power and backup power provision at the Regional Water Quality Control Plant (RWQCP) could be made cost-effective for both the RWQCP partners and the electric utility. This solution for extending the RWQCP’s backup power capabilities should be compared to a dual fuel diesel and natural gas combination backup solution. An alternative to this approach could be to stop work on this analysis or to prioritize further exploration of the EV charging depot concept in addition to or instead of the RWQCP backup power solution. FISCAL/RESOURCE IMPACT The studies and draft proposals for implementing RRSP Strategies 4 and 5 have been performed through existing budget and contracts, which are adequate for project completion. These include: •A $213, 250 contract with Buro Happold for evaluation of supply and short-term resiliency, research and recommendations on potential programs, and development of the final Reliability and Reliability and Resiliency Cost-Benefit Study and Program Inventory. Of this, $187,660 has already been spent and it will require the remaining $25,590 to complete the project. •A contract with Burns-McDonnell for evaluation of solar and storage at the airport for $208,000, of which $178,000 is for evaluation of microgrid options and use of the energy and $30,000 is estimated for site evaluations to enhance planned Federal Aviation Administration filings for the airport to enable this project in the future. To date $138,000 has been expended. •A contract with Energeia to complete the preliminary analysis of deferring distribution investment, already completed for just over $12,000. To date, $337,660 has been expended, and an additional $85,590 will be expended to complete the tasks currently underway. Item No. 5. Page 10 of 11 Pursuing additional analysis of the potential for deferring distribution investment would require an additional $150,000 to $200,000 in consultant costs and 0.25 FTE in staff time. This would come from existing Utilities’ consulting budgets. The City has received a $75,000 grant from the American Public Power Association (APPA) for this work, if the City were to proceed with the study. If the City did not proceed, staff could speak with APPA to explore reducing the grant and applying it to the preliminary study instead. Based on feedback from the Commission at this meeting, with the Climate and Sustainability Committee in August, and with stakeholders, staff will evaluate the fiscal impact of the programs listed in Attachment A for future Commission and Council consideration. STAKEHOLDER ENGAGEMENT The use of flexible technologies and efficient electrification, both before and after adoption of the RRSP, has been the subject of many public meetings and stakeholder discussions, including: •Various public and private meetings of the S/CAP Ad Hoc Committee and its Working Group from 2021 – 2023 •June 5, 2023 Council meeting adopting the Sustainability and Climate Action Plan and the 2023-2025 S/CAP Work Plan, including guidelines for development of the RRSP8 •The UAC and Council meetings listed in the Background section above related to the adoption and implementation of the RRSP, as well as a Council study session on the draft RRSP on February 12, 2024.9 Staff plans to bring this topic to the Climate Action and Sustainability Committee in the fall of 2025, and plans to discuss this with the Climate Action and Sustainability Working Group around that time as well. ENVIRONMENTAL REVIEW Potential environmental impacts of an RRSP were analyzed as part of the Sustainability and Climate Action Plan (S/CAP) Addendum to the Comprehensive Plan Environmental Impact Report. On June 5, 2023 (Staff Report #2303-1158), Council certified the Addendum, which found that the S/CAP programs would not result in any significant or substantially more severe effects beyond what was previously analyzed in the Comprehensive Plan EIR. Under CEQA Guidelines section 15183, projects consistent with an existing general or comprehensive plan do not require additional CEQA review. ATTACHMENTS 8 City Council, June 5, 2023, Adoption of a Resolution Approving an Addendum to the 2017 Comprehensive Plan En vironmental Impact Report and Adopting the Sustainability and Climate Action Plan (S/CAP); Approval of the 2023- 2025 S/CAP Workplan; and Review of the 2023 Earth Day Report, https://cityofpaloalto.primegov.com/meetings/It emWithTemplateType?id=2276&meetingTemplateType=2&compiledMeetingDocumentId=7200 9 City Council, Staff Report 2311-2211, February 12, 2024, Reliability and Resiliency Strategic Plan for the City’s Elec tric Utility, https://cityofpaloalto.primegov.com/meetings/ItemWithTemplateType?id=4071&meetingTemplateTyp e=2&compiledMeetingDocumentId=9079 Item No. 5. Page 11 of 11 Attachment A: Preliminary Benefit-Cost Results for Supply Costs and Short-term Resiliency Attachment B: Preliminary Distribution Cost-Benefit Analysis Attachment C: Current Microgrid and Long-term Resiliency Policies and Potential Alternatives Attachment D: Overview of Preliminary Airport Microgrid Study Results Attachment E: Draft Criteria for Consideration of Cross-Property Microgrids Attachment F: Status Update on RRSP Implementation Attachment G: Staff Presentation AUTHOR/TITLE: Alan Kurotori, Director of Utilities Staff: Jonathan Abendschein, Assistant Director for Climate Action Staff: Karla Dailey, Assistant Director of Utilities Resource Management Staff: Terry Crowley, Assistant Director of Utilities Electric Engineering and Operations Summary of Draft Reliability and Resiliency Cost-Benefit Results and Potential Programs Introduction •This cost-benefit analysis assesses customer programs for flexible energy technologies that enhance customer reliability and resilience in Palo Alto. •Customer programs were identified through an extended inventory of programs, pilots, and customer-scale projects throughout California that support resilience and electrification with technologies such as battery energy storage systems (BESS), solar, vehicle to grid (V2X), thermal energy storage, and demand response technologies. •The analysis considers the technological viability of each technology, avoided supply costs, value of resilience, as well as program feasibility, accessibility, and community impacts. •Table 1 and Figures 1-2 summarize the preliminary community cost-benefit results for baseline reliability conditions. •The results focus on the quantitative metrics associated with each technology and program, and they are subject to change as program parameters are adjusted and refined in the future. Additional qualitative parameters will also inform the final analysis and recommendations from this study. Cost-Benefit Analysis Results (Palo Alto Community Perspective) •The results indicate that most programs are a net loss to the Palo Alto community unless additional benefits are valued, or program characteristics are adjusted to improve performance. o Valuing long-term resilience (for the community and the utility) and fully capturing distribution benefits where applicable (not part of this study) are key to improving program outcomes. o Valuing long term resilience from a financial standpoint significantly improves the commercial benefits, but competition for capital and high interest rates is a challenge in practice. •Sensitivity analysis demonstrates that scaling the programs (increasing adoption), and reducing upfront administrative and operational costs can improve the cost benefits ratio •Preliminary findings include: o Solar and battery systems outperform battery only systems, and provide a positive net present value for commercial customers and a nearly positive net present value for residential customers ▪Solar and battery systems are also integral to realizing long-term resilience benefits for outages over 24 hours o Commercial battery systems outperform residential due to economies of scale, lower capital costs, and a higher value of resilience for commercial customers o Vehicle to grid programs differ from battery energy storage systems due to varying charging schedules that limit energy arbitrage, as well as other factors like reserve depths and program adoption rates. o Demand response programs require little up-front investment from customers but requires high level of customer participation for utility programs to be cost effective . o Thermal storage is not cost effective at the scale of system considered most applicable for a broad programs. Attachment A Table 1: Community Cost-Benefit Summary Program Benefits Costs Net Present Value Benefit-Cost Ratio (Baseline) 100 Residential Battery Installations $819,113 $1,887,713 -$1,068,600 0.43 100 Residential Solar + Battery $4,437,355 $4,861,920 -$424,565 0.91 35 Commercial Battery $6,899,110 $7,684,423 -$785,313 0.90 35 Commercial Solar + Battery $21,152,538 $19,684,930 $1,467,608 1.07 100 Residential VTX Installations $379,929 $848,215 -$468,286 0.45 35 Commercial VTX Installations $156,512 $464,283 -$307,771 0.34 250 Demand Response $534,927 $1,023,664 -$488,737 0.52 75 Commercial Demand Response $1,926,455 $2,255,989 -$329,533 0.85 35 Thermal Storage Installations $196,310 $2,652,299 -$2,455,989 0.07 Figure 1: Cost-Benefit Results - Residential Programs Figure 2: Cost-Benefit Results - Commercial Programs *Note: community benefits are customer savings net of distribution and commodity impacts. Time of Use Rates •Time of use (TOU) rates are a key enabling factor for flexible energy technologies and demand response programs, providing incentives to shift or shed end-use load. o In addition to enabling demand flexibility, grid reliability, and efficient use of electricity, price-based signals can provide cost savings for participating customers while creating a net benefit to utilities implementing them. •Demand response programs, enabled by price-based signals like TOU, are increasingly being considered for their technical potential to provide additional resource capacity for utilities through future load forecasting and integrated resource planning. o However, the current lack of data and experience with TOU programs limits their broader application in utility distribution system plans. o Currently, there is no widespread consensus of how assumptions of price-based DR load reductions from TOU should be incorporated into resource planning. •California’s 2018 TOU pilot (including PG&E, SCE, and SDG&E) averaged 4.6% in peak period load reductions •Of nearly 150 programs assessed by the Lawrence Berkeley National Laboratory, 20% reported outcomes on demand reductions, and 14% reported outcomes on program spending. o Utilities realized an estimated average demand reduction of 0.06 to 0.9 kW/participant/event. o Residential reductions for TOU programs ranged from 1-6% per participant o Commercial and Industrial TOU reductions ranged from 1.5-5% o Utilities spent approximately $40-100 per kW for first-year costs Program Design •Various program design typologies have been considered, with different designs being suited to different technologies. These considerations also inform program costs and implementation mechanics. •The current program designs under consideration include: o Battery energy technologies could utilize a 3rd party administered incentives/grant structure or a feed-in tariff, or be rolled into a demand response program o Demand response would be best suited to a third-party aggregator administered program o Vehicle to grid could be best administered by 3rd party incentives, or be rolled into a demand response program •For all program designs, the smaller scale of Palo Alto is a particular challenge as administrative costs risk being a significant portion of the overall costs and benefits. o Reducing program costs could be achieved by leveraging existing grants of state funding (more research is needed to determine availability and eligibility) or by integrating technologies into existing programs. •Scaling incentives for, or specifically targeting, low-income residents may also be necessary to address inherent equity issues associated with programs, given that those with means are more likely to adopt flexible energy technologies and utilize program incentives. •More generally, Palo Alto programs for strategic communication and outreach to increase adoption of flexible technologies may be worthwhile to improve community awareness and overall community resilience, especially to the extent that these efforts improve access to enabling technologies to low-income/vulnerable residents. • Alternate Cost-Benefit Summaries Figure 3: Cost-Benefit Summary - Residential Programs Figure 4: Cost-Benefit Summary - Commercial Programs Results of Preliminary Distribution Study Goal: Complete a preliminary analysis to determine the need for a full analysis of the potential for batteries, vehicle to grid, and efficient electrification to defer electric distribution system investment. Results: In an optimistic scenario, staff identified potential savings from deferral of infrastructure investment from 326 transformers. If these could be deferred without cost the savings would be equal to about $1 million per year in avoided debt service costs or about a 0.55% reduction in rates. Staff estimated that 2,400 energy storage systems at well over 1,000 homes would be required to achieve this deferral, however, at a debt service cost of about $1.3 million per year, exceeding the potential savings. When combined with the additional considerations below, especially those related to the novelty and complexity of such a program, the analysis points to there being minimal or negative value to pursuing deferral through utility-controlled flexible energy technologies. Additional Considerations: •This program depends on the use of transformer-level microgrid controllers that are not extensively used in the utility world at this time, leading to some operational risk due to use of an earlier-stage technology, and likely staff time and ongoing cost impacts that may not be accounted for in the estimates above •It would require very rapid launch of a major program effort to deploy utility- controlled batteries at homes •It also results in less efficient infrastructure investment and may involve higher operational costs from maintaining a diversity of equipment •And lastly, if construction inflation continues to exceed general inflation, deferring investments in infrastructure could mean the real cost is greater later on, meaning higher rates for future Palo Altans. Methodology: Staff did a simple calculation to estimate the number of 13.5 kWh, 3.375 kW four-hour batteries needed to manage any grouping of homes that exists on the City’s electric system. Staff used the grid modernization coincident peak load assumption of 6 kVA per home to evaluate the peak transformer loading, then calculated the number of batteries needed to reduce the total loading below the transformer limit. An underlying assumption of this method is that the energy capacity of the batteries is sufficient to discharge at all hours needed to keep the transformer loading below the load limits. A Monte Carlo simulation using actual AMI data found that this assumption did not hold in all scenarios, Attachment B meaning this methodology yields an optimistic outcome, and in reality, more batteries would likely be needed to achieve the program’s goals. Staff then identified candidate transformers for deferral: those less than 20 years old and that are not being replaced as part of a 4 kV -> 12 kV upgrade, 326 transformers. Staff ran the calculation for each transformer and found the following: Number of transformers with these characteristics (transformer size and number of homes) Number of connected homes 25 kVA 37.5 kVA 4 22 5 24 11 6 33 5 7 30 21 8 32 15 9 21 16 10 11 31 11 13 12 30 13 11 TOTAL 173 153 GRAND TOTAL: 326 In this preliminary analysis, the City is assumed to pay for these batteries because they are used exclusively for distribution management. Staff estimated the total up-front cost of the batteries needed, then calculated the cost of debt financing those costs over 20 years. Staff then compared that to the debt service cost of upgrading the transformers instead of doing the program. The results are shown below: Average cost per transformer upgrade $50,000 Avoided upgrades 326 Total avoided capital investment $16.3 million Debt service (30 years, 4.5% interest rate)$1.0 million per year savings Cost per battery $5,900 Batteries 2,400 Total required capital investment $14.3 million Debt service (20 years, 6.5% interest rate)$1.3 million per year cost The ongoing debt service for the batteries in this case exceeds the savings generated by deferring distribution investment. This back of the envelope analysis also does not include the cost of battery controllers to match battery charge and discharge to transformer loading, program costs to deploy the batteries, and staffing for ongoing maintenance of the battery controller system. The high-level analysis also does not account for degraded battery performance overtime, losses incurred during battery charging cycles, possible benefits from shifting consumption (thru battery charging/discharging) to periods of lower- cost and/or cleaner energy production, potential of higher customer peak demands due to electrification, and changes in construction pricing. In general, further sensitivity analysis is expected to result in a higher cost to pursue the battery storage alternative. Current Policies on Microgrids and Long-term Resiliency and Potential Alternatives This is an overview of current City rules, regulations, and activities that affect solar plus battery microgrids and community backup power planning to ensure longer-duration resiliency in major emergencies. Microgrids A microgrid is an on-site generator that can run both when the grid is up and running, replacing non-local power transmitted from outside Palo Alto, and when the grid is down, replacing a traditional diesel backup generator. The value of a microgrid can be compared to the cost of the avoided power purchased outside Palo Alto and transmitted to the community to serve electric load plus the avoided cost of a diesel backup generator. And advantage of a solar and battery microgrid is that solar generators do not run out of fuel. A disadvantage is that they are limited in the amount of generation by the amount of available roof space, the season, and the weather, so they require more complex planning. It is possible to have more complex microgrids that include a variety of generating sources (e.g. solar plus natural gas engines) but this overview focuses on solar-only microgrids. Utility On-Site Solar Generation Policies and Programs The City’s electric utility provides two programs for customers who install on-site solar and batteries: Net Energy Metering1 or the PaloAltoCLEAN feed-in tariff2. The Net Energy Metering program enables customers to avoid the full retail rate for energy used on site, while paying for energy exported to the electric distribution system and used to serve other electric utility customers based on the avoided cost of the imported energy and transmission services that would otherwise have been needed to serve those customers. Under the PaloAltoCLEAN feed-in tariff program the utility buys all the energy from a solar system under a power purchase agreement and uses it to serve electric utility customers in Palo Alto. The City’s electric utility pays a price based on the avoided cost of the imported energy and transmission services that the local solar generation replaces. Typically neither program provides enough value to repay the cost of the solar and battery system. This is because it generally costs more to build solar locally than to 11 https://www.paloalto.gov/Departments/Utilities/Electrification/Residential-Electrification/Consider- Solar/Net-Energy-Metering 22 https://www.paloalto.gov/Departments/Utilities/Electrification/Business-Electrification/CLEAN Attachment C import it from outside Palo Alto. However, a local solar and battery microgrid can provide additional value in the form of long-term and short-term resiliency. Those who value that resiliency highly enough are willing to pay the cost to install solar and batteries even if they do not recover the full value just from the City’s programs. The City’s electric utility does not currently provide additional subsidies for local solar and batteries for the purpose of creating additional local resiliency. Current Long-term Electric Resiliency Activities City’s Office of Emergency Services (OES) coordinates City response to a major emergency, coordinates with other emergency operations teams regionally, provides information to residents, and coordinates community preparation efforts, such as Emergency Services Volunteers. As part of its planning efforts OES will note gaps it identifies in the backup power plans made for critical City facilities, though responsibility for identifying backup power needs is shared across all City staff managing facilities. OES maintains a solar plus battery backup power trailer to flexibly provide backup power portably. Backup power decisions for private entities are typically made by those individual facility owners. The City does not currently involve itself in those decisions. OES provides information on disaster planning, but does have the resources to actively push private facility owners to ensure they have adequate backup power. Potential Additional Actions If the City wanted to extend its support for community emergency planning, the following additional actions could be considered, and would require additional resources: •Incentives or other subsidies for solar and battery generation. If these incentives were to be provided, the purpose of the program should be well-defined. Some possibilities include: o Make incentives for on-site solar and battery resiliency available to all (or to all residents). This option would likely require a very large funding source that would raise electric rates or require additional taxes. o Make incentives available to low-income residents. This would also require funding sources. Further analysis would be needed on the amount. o Provide incentives for facilities that serve community needs in an emergency. This would require both funding for incentives and resources for OES to develop criteria for identifying such facilities. •Instead of (or in addition to) providing incentives, additional resources could be provided to OES for identifying critical community facilities and facilitating development of backup power at those sites (both solar and battery and traditional backup power). •Alternatively, OES could use existing networks and resources to promote the electric utility’s existing NEM and PaloAltoCLEAN programs even if a new electric utility incentive program were not created. Overview of Preliminary Airport Microgrid Study Results The City’s consultant, Burns-McDonnell, has studied a potential microgrid at the airport in sufficient detail to assess a few potential options for City consideration. Alternative 1: Microgrid serving the airport alone A small microgrid serving the airport alone would not require significant site development. Under 1 MW of solar would be needed for the airport to withstand a multi- day outage in any season. Potential alternatives are being provided to the airport management team for consideration. No utility involvement is needed for this scenario beyond the usual interconnection review and solar rate designation provided by the electric utility for all utility customers putting solar on a site. Alternative 2: Maximum airport solar and storage buildout under a power purchase agreement (PPA) with the City’s electric utility Under this scenario the City would have 6.6 MW of solar capacity built at the airport along with sufficient battery capacity to optimize the value for the electric utility. The City could own the system or hire a developer to build and own it, most likely the latter. The estimated price for such a PPA is (very preliminarily) $235/MWh + $27/kW-mo, more than avoided cost of buying renewable energy remotely and transporting it to the City ($80-$90/MWh + $14-$18/kW-mo). To make this project a net value to the electric utility another revenue source would be needed to monetize the resiliency value, paying for a share of the project and lowering the PPA price to the electric utility. Alternative 3: Maximum airport solar and storage buildout with electric utility PPA and resiliency services To lower the PPA price to the electric utility staff identified three potential users of resiliency services for the project. The final PPA price to the electric utility would depend on how much one or more of those users would be willing to pay for those services. Alternative 3A: Airport Resiliency Services One potential user of resiliency services could be the airport. Resiliency service from a fully-built-out solar and storage system could replace the need for other backup power or a standalone smaller microgrid just serving the airport (as in Alternative 1). Alternative 3B: Regional Water Quality Control Plant (RWQCP) With its large electric load, the RWQCP would be another potential user. The RWQCP currently has 1-3 days of diesel backup in an emergency. The City’s consultant estimated that connecting the RWQCP to a maximized solar and storage microgrid at the airport could provide 1-5 additional days of power in January (when solar energy is at a minimum), on average, and at least 45 days of additional power in September Attachment D (when solar energy is at maximum). This solution for the RWQCP should be compared against dual fuel diesel and natural gas backup generation, which could provide even greater resiliency during the winter. Alternative 3C: EV Charging Depot Another option for raising revenue and providing resiliency is an EV charging depot. This would be a bank of high-speed chargers located at the airport intended to raise revenue from EV drivers day to day or, if feasible, provide charging for City fleet vehicles. Electric aviation may be another possible source of revenue. For this analysis the City’s consultant evaluated a bank of ten 100kW EV chargers that could be used in an emergency. A 6.6 MW solar and battery system at the airport could provide 400 40 kWh charging sessions per day (over a 24-hour period) for up to three days in January and any number of days in September. Other configurations would be possible, and further analysis would be needed to determine the economically optimal configuration. Draft Criteria for When to Consider Cross-Parcel Microgrids Staff intends to use the following criteria when considering whether a cross-parcel (neighborhood) microgrid should be considered: •A site has a critical electricity use that requires long duration backup power capability •Lack of availability of diesel fuel in an extended emergency is a concern •The site may not be prioritized by emergency planners for limited diesel supplies (e.g. a high priority use like a hospital trauma center may have fewer concerns about diesel availability than a medium priority use) •The critical electricity use cannot be served adequately just using solar on the property •Site is near other parcels with roof and/or land space for solar panels in excess of that needed for any critical electric uses on those parcels •Site owner is able and willing to pay for additional solar + storage and the physical infrastructure to connect across parcels to supplement diesel backup Dual-fuel backup generation (natural gas + diesel) should be considered as an alternative to cross-property solar + storage microgrids when addressing diesel fuel concerns. Attachment E 1 Attachment B: Reliability & Resiliency Strategic Plan – Progress Update July 2025 Strategy/Action Status Cost Strategy 1: Replace and Modernize Infrastructure 1.1 Replace aging infrastructure 1.2 Upgrade capacity to accommodate new loads 1.3 Improved feeder switching capabilities Strategies 1.1 – 1.3, the grid modernization project, will replace aging infrastructure and install a modern network infrastructure to meet future home electrification needs. Changes to the equipment on the network will include replacing/installing transformers, installing new protective devices to improve reliability, and the installation of system controls to allow for the import and export of energy from homes on the network. A pilot project to replace and upgrade aging infrastructure serving approximately 1000 residents was completed in 2025. Staff is evaluating results from this pilot before moving to the rest of Phase 1 of the project. Electric Fund CIP EL-24000 (Grid Modernization): $300 million (of which staff very preliminarily estimates 40% - 50% is for existing infrastructure replacements that would occur regardless of electrification) 1.4 Second transmission connection Staff, with consultant help, continues to work with the California Independent System Operator (CAISO) and PG&E to build a second transmission corridor from the broader electricity grid to Palo Alto. In May 2025 CAISO approved construction of this second corridor in the form of a new 115 kV line from Ames to Palo Alto to be completed in 2034 as part of the CAISO transmission planning process. Staff and consultants are working with PG&E and CAISO to move the completion date to closer to 2030 as loads are increasing faster than expected. Electric Fund CIP EL-06001 (115 kV Electric Intertie): $250,000 for planning and design work for application to CAISO 1.5 Foothills undergrounding A key wildfire mitigation activity is undergrounding approximately 49,200 feet of electric overhead distribution lines and fiber optic cable in the Foothills area. This iterative project consists of multiple phases 1-5 and is expected to be complete in 2025. Phases 1,2, 3, and 5 were completed in May 2025, and 10,000 Feet remaining in the MidPen Phase 4 area are scheduled for completion by August 30, 2025. Electric Fund CIP EL-21001 (Foothills Rebuild): $8 million Attachment F 2 Strategy/Action Status Cost 1.6 Reliability Metrics Research and metric development to commence in Q4 of 2025. 0.05 FTE of staff time for research and metric development Strategy 2: Operational Strategies to Improve Reliability and Manage Outages Effectively 2.1 Strengthen the workforce Concerted efforts are currently underway to recruitment, train, and retain lineworkers, system operators, engineers, inspectors to maintain system and respond to outages effectively. Staff have also contracted with third-party contractors to supplement staff to undertake emergency response, maintenance, and capital improvement projects. In FY 2024, 45 vacancies were filled. Between January to May 2025, CPAU has 11 new hires and 12 promotions. As of May 2025, CPAU 38 vacant positions or 14% vacancy rate of the authorized 267 FTEs. 20 of the vacant positions are in-progress recruitments. Significant progress has been made in filling critical vacancies like director, assistant director, lineworker, and engineer. 1.0 FTE (spread among three people) for additional recruitment and retention work 2.2 Wildfire protection maintenance practices Staff regularly updates its Wildfire Mitigation Protection Plan to protect power lines in the Foothills, and is exploring innovative software to make vegetation management more efficient. Implementation requires $150,000 to $200,000 for vegetation clearance annually 2.3 Communicate effectively during outages The new OMS allows CPAU to more quickly detect and respond to power outages and provide customers with timely notifications and updates. In FY 2025, OMS sent approximately 103,500 text messages for planned and unplanned outages and restorations. Staff has incorporated OMS texting features to support outbound communications during potential and active PSPS events. Staff will explore other uses for OMS, such as customer non-payments. $73,000 was spent to develop the system. Ongoing maintenance involves 0.25 FTE and ongoing system costs of $108,000 per year. 3 Strategy/Action Status Cost Strategy 3: Effectively Integrate and Ease Adoption of New Technologies 3.1 Configure the distribution system to accommodate high penetrations of solar, batteries, and other technologies Staff has completed an evaluation of the distribution improvements needed to accommodate high penetrations of solar and storage and is currently evaluating whether these same improvements will also accommodate vehicle to grid technologies, smart panels, and flexible loads. $30,000 to 50,000 in consultant studies from electric utility operating budgets 3.2 Review, communicate, and streamline permitting and other regulatory rules for efficient and flexible electrification technologies Staff completed an inter-departmental internal review of various technologies to establish clear rules and guidelines for implementation: •Planning and Development Services updated Intake forms for electrical load calculations were updated. Status: Complete. •Utilities is updating transformer upgrade fees and evaluating the role of flexible technologies and strategies for single-family. Expected completion: Q4 2025 •Utilities transformer upgrade policies for multi-family and non-residential properties take into account efficient and flexible technologies and strategies. Status: Complete. 3.3 Communicate how to electrify efficiently 3.4 Communicate how to use technologies in a grid-friendly way •Time of use (TOU) rates and a transition plan for these rates are currently being developed in parallel with the City’s rollout of advanced metering infrastructure. The voluntary residential TOU rates are expected to be approved by Council in August 2025. Staff plans an update to the UAC on implementation details in October 2025. Initial Launch Planned: Q1 2026 •Utility staff has hired Redwood Energy to develop an electrification guide for single family homes and is working on how to roll it out. Expected completion: Q3 2025 •Utilities launched an electrification expert service which can provide guidance to residents on efficient electrification. Status: Complete 0.25 FTE in staff effort from existing staff resources 4 Strategy/Action Status Cost Strategy 4: Value the benefits of flexible technologies to the utility and community 4.1 Value the utility benefit of flexible technologies on electric supply costs Staff has hired a consultant to perform these analyses, as well as the analysis of Actions 4.3, 4.4, and the analyses in Strategy 5. Staff expects study completion by end of 2025. Staff is reviewing preliminary results with the UAC in July 2025 and Council Climate Action and Sustainability Committee (CASC) in August 2025. Consulting assistance at a cost of $213,250, and 0.25 FTE in staff effort. 4.2 Value the utility benefit of flexible technologies on electric distribution costs and capacity Staff was unable to complete a contract with an academic partner for this study and is working on a preliminary analysis to determine whether a more expensive private consultant study is warranted. Staff is reviewing the results of the preliminary study with the UAC July 2025 and the CASC in August 2025. Estimated $15,000 to $200,000 in consulting assistance, 0.1 FTE in staff effort 4.3: Explore estimating the value of resiliency for the community 4.4: Estimate the cost of various community resiliency approaches See status update for 4.1, above. See status update for 4.1, above. Strategy 5: Evaluate the resource needs for various demand reduction and resiliency programs 5.1: Evaluate utility-driven programs to enhance resiliency and lower the demand on the grid 5.2 Evaluate equity-based and need-based versions of the programs Staff has hired a consultant to develop a list of potential programs, as well as the analysis of Actions 4.1, 4.3, and 4.4, above. The study is expected to be completed by the end of 2025. Staff is reviewing a preliminary program list with the UAC in July 2025 and Council Climate Action and Sustainability Committee (CASC) in August 2025. See status update for 4.1, above 5 Strategy/Action Status Cost 5.3: Evaluate community-based versions of the programs 5.4: Evaluate other resiliency approaches like neighborhood- level microgrids Strategy 6: Implement any demand reduction or resiliency programs chosen by the community No actions planned until Strategies 4 and 5 are completed and policy direction is received from Council July 9, 2025 www.paloalto.gov Reliability and Resiliency Strategic Plan Status Update and Feedback Request Utilities Advisory Commission 2 Overview •Review Flexible Technologies Analyzed •Preliminary Results of Supply and Short-term Resiliency Cost and Benefit Analysis •Preliminary Results – Distribution Investment Deferral Cost- Benefit Analysis •Microgrids, Long-term Resiliency – overview of current policies, possible alternatives •Airport Microgrid Analysis – Preliminary Results •Summarize feedback requested Flexible Technologies & Strategies and their Value 3 Can Reduce Utility Supply Cost Provides Short-term Resiliency Could Defer Distribution Investment Provides Long-term Resiliency Time of Use Rates X Demand Response X Battery-only (e.g. ESS, V2G)X X X Battery + Solar X X X X Efficient Electrification X Time of Use Insights 4 •Consultant reviewed literature on impacts of time of use rates •Residential TOU impacts – 1% - 6% reduction in peak demand in programs studied •Commercial TOU impacts – 1.5% - 5% reduction •California IOU TOU studies: 4.6% peak period load reduction •Based on past CPA pilot, peak demand reduction will likely be on the lower end (less air conditioning load) Preliminary Results: Supply and Short-term Resiliency 5 Programs analyzed for cost-benefit analysis: Demand Response 1.250 Residential Projects 2.75 Commercial Projects Standalone Battery Projects 3.100 residential battery-only projects 4.100 residential V2G projects 6.35 commercial V2G projects 7.35 commercial thermal storage projects 8.35 commercial battery projects Solar + Battery Projects 9.100 residential solar + battery projects 10. 35 commercial solar + battery projects Preliminary Results: Supply and Short-term Resiliency 6 0 0.2 0.4 0.6 0.8 1 1.2 Comm. Thermal Comm. V2G Res. Batteries Res. V2G Res. Demand Response Comm. Demand Response Comm. Battery Res. Solar + Battery Comm. Solar + Batt. Ra t i o o f b e n e f i t s t o c o s t s Community-level Cost-Benefit Ratio: Supply Savings + Short-term Resiliency Benefit vs. Cost >1: Benefits exceed costs <1: Costs exceed benefits 1 2 3 Additional value needed from sources like distribution investment deferral or long-term resiliency to make positive benefit-cost ratio Staff Investigated Further: 1.Res. batteries to defer distribution investment 2.Residential solar + batteries for long-term resiliency and/or for distribution investment deferral 3.Comm. solar + batteries for public-private partnerships Preliminary Distribution Deferral Results 7 •Did preliminary analysis to evaluate whether a more expensive in-depth analysis is warranted •Assessed the most promising transformers for deferral: •Not in a 4 kV -> 12 kV upgrade area •Less than 20 years old •Identified 362 transformers (of about 1,750) for consideration •Most transformers had between 4 and 13 homes connected •Only about 30% had six or fewer homes – the higher the number of connected homes, the more measures needed to defer investment Preliminary Distribution Deferral Results •Max savings (all 362 transformer replacements deferred at no additional cost): $1M/year (0.55% avoided rate increase) •More in-depth analysis may find more savings (e.g. feeders, substations) •Over 2,400 batteries needed to avoid all 362 replacements •Cost of these batteries (about $1.3M/year) exceeds the savings •Using efficient electrification might lower costs – needs more analysis •Other considerations •This approach is cutting edge – challenging for small utility •Deferring transformer replacements reduces grid mod efficiency •Program expenses not included •Rapid program implementation would be required •Simulations using real world AMI data showed more batteries needed 8 Solar + Storage Microgrids 9 Microgrid = day to day power generation + backup power – all in one package Microgrid cost can be benchmarked against cost of non-local power + backup generator + is like Non-local power Backup GeneratorSolar + Battery Microgrid Policies: Microgrids and Long-term Resiliency •Current policies: •Value of replacing grid power with local solar + battery is passed on in net energy metering rate, PaloAltoCLEAN feed-in tariff program •Cost of solar + battery exceeds direct energy benefit in most cases •Community members who value resiliency highly enough will spend the extra money for the backup power •City does not facilitate community-wide backup power planning •Potential alternatives: •Subsidize, pay extra, or otherwise facilitate local solar + battery projects to promote local resiliency - but who may participate? •Options: 1) everybody (raises electric rates), 2) critical community facilities in an emergency (e.g. grocery stores), 3) first come first served, limited funding (creates equity issue), 4) income-qualified, or 5) those willing to pay extra (reflects current practice) 10 Airport Microgrid Study – Preliminary Results 11 •Maximum potential: ~7 MW of solar (~12,000 MWh of annual generation, about 1% of community load) + an amount of batteries needed to match each purpose below •Three potential purposes for large scale microgrid: •Power Purchase Agreement - $235/MWh + $27/kW-mo – costs more than avoided remote renewables + transmission ($80-$90/MWh + $14-$18/kW-mo) •RWQCP backup power – 4-8 days of operation in Jan (lowest solar generation), at least 45 extra days in summer (highest) •Currently the RWQCP has only 1-3 days of diesel •EV charging depot (10 100-kW chargers) – 200 80-kWh vehicle charges per day for three days in January (lowest solar generation), unlimited September use •Alternatively could just build small microgrid to power airport •Analysis provided insights on cross-parcel microgrids Staff Request 12 Staff requests UAC provide majority (or consensus) feedback on next steps. Staff’s straw proposal for UAC feedback: 1.Promote ways community members can save money by reducing peak period load (helping the electric grid) under time of use (TOU) rates once those rates are launched. 2.Monitor demand response technologies for positive benefit-cost opportunities but continue existing City practice of not pursuing demand response (unless benefit to cost ratios change in the future). 3.Promote residential solar and battery adoption, standalone batteries and thermal storage, but continue the City’s current policies of not providing technical assistance programs or incentives due to the fact costs exceed benefits. 4.Promote electric vehicle to home/grid as it becomes more available, but continue the City’s current policies of not providing technical assistance or incentives (unless benefit- to-cost ratios change in the future). (continues) Staff Request (Continued) 13 5.Further explore the cost-effectiveness of local larger-scale commercial solar + battery programs and bring to the UAC and City Council for consideration as part of the report on Strategies 4 and 5 if cost-effective options can be identified, while continuing to pursue utility-scale solar and storage and other renewables in parallel. 6.Monitor opportunities for distribution investment deferral using flexible technologies and efficient electrification but do not pursue additional analysis or new policies or programs at this time. 7.Maintain City’s current policies on microgrids and backup power (long-term resiliency). 8.Explore electric utility / treatment plant partnership on airport microgrid.