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HomeMy WebLinkAbout2017-09-06 Utilities Advisory Commission Agenda Packet NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956 I. ROLL CALL II. ORAL COMMUNICATIONS Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable time restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from discussing or acting upon any topic initially presented during oral communication. III. APPROVAL OF THE MINUTES Approval of the Minutes of the Utilities Advisory Commission Meetings held on August 2, 2017 IV. AGENDA REVIEW AND REVISIONS V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS VI. DIRECTOR OF UTILITIES REPORT VII. COMMISSIONER COMMENTS VIII. UNFINISHED BUSINESS None IX. NEW BUSINESS 1. Utilities Strategic Plan Discussion 2. Discussion of Electric Integrated Resource Plan – Hydroelectric Resources and Carbon Discussion Neutral Portfolio Alternatives 3. Local Solar Programs and Community Solar Survey Discussion Discussion 4. Update on Smart Grid Pilot Projects and Development of the Utility Technology Discussion Implementation Roadmap 5. Staff Recommendation that the Utilities Advisory Commission Recommend Council Adopt Action a Hydroelectric Generation Variability Management Strategy 6. Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action NEXT SCHEDULED MEETING: October 4, 2017 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)). Public Letters to the UAC 12-Month Rolling Calendar UTILITIES ADVISORY COMMISSION WEDNESDAY, SEPTEMBER 6, 2017 – 7:00 P.M. COUNCIL CHAMBERS Palo Alto City Hall – 250 Hamilton Avenue Chairman: Michael Danaher  Vice Chair: Arne Ballantine  Commissioners: Lisa Forssell, A. C. Johnston, Judith Schwartz, Lauren Segal and Terry Trumbull  Council Liaison: Eric Filseth Utilities Advisory Commission Minutes Approved on: Page 1 of 10 UTILITIES ADVISORY COMMISSION MEETING MINUTES OF AUGUST 2, 2017 MEETING CALL TO ORDER Chair Danaher called the meeting to order at 7:00 p.m. Meeting of the Utilities Advisory Commission (UAC). Present: Chair Danaher, Commissioners Trumbull, Schwartz, Forssell, and Johnston, and Councilmember Filseth Absent: Vice Chair Ballantine, Commissioner Segal ORAL COMMUNICATIONS Bob Evans, founder of Fiber Internet Center, spoke about the Fiber Utility. He had founded Fiber Internet Center in 2001 and had been a City fiber use since before that. He was concerned about the City’s fiber pricing. In 2001 he had been offered a pricing structure that involved flat $150 pricing, but as his facility grew larger the pricing changed. He recommended that customers be involved in pricing decisions. Competitors’ costs were dropping every year, unlike Palo Alto’s prices, which went up. Fiber Internet Center in Palo Alto had more customers connected using AT&T fiber than City fiber. The City considered Fiber Internet Center a competitor. The City promoted Palo Alto Internet Exchange (PAIX) over Fiber Internet Center. At one point the City had promoted another provider, Hurricane, on their website, but when he requested a link for Fiber Internet Center, they denied him a presence on the website and removed Hurricane. He said it took a very long time to get a facility connected. He questioned the fees associated with service installation. There was not effective marketing of pricing changes and service commitment duration changes. He recommended requiring that new buildings be fiber-ready. He had moved his location to Mountain View. He recommended diversifying the City’s power pathways to provide higher reliability. He said the City’s Fiber Utility was not run competitively. APPROVAL OF THE MINUTES Commissioner Johnston moved to approve the minutes from the June 7, 2017 UAC meeting. Commissioner Trumbull seconded the motion. The motion carried (4-0-1) with Commissioners Danaher, Trumbull, Forssell, and Johnston voting yes, Commissioner Schwartz abstaining, and Vice Chair Ballantine and Commissioner Segal absent. Commissioner Schwartz corrected a grammatical error on the first page of the July 12, 2017 minutes under “REPORTS FROM COMMISSION MEETINGS/EVENTS” and said that section should state “the most innovative community solar projects” were located in Colorado, not “the most innovative utilities.” Commissioner Johnston moved to approve the minutes from the July 12, 2017 special meeting with Commissioner Schwartz’s edits. Commissioner Trumbull seconded the motion. The motion carried (5-0) with Commissioners Danaher, Trumbull, Forssell, Schwartz and Johnston voting yes and Vice Chair Ballantine and Commissioner Segal absent. DRAFT Utilities Advisory Commission Minutes Approved on: Page 2 of 10 AGENDA REVIEW AND REVISIONS None. REPORTS FROM COMMISSION MEETINGS/EVENTS Commissioner Schwartz was at the National Town Meeting in Washington DC, now renamed the Grid Evolution Summit. She encouraged the utility to send staff to the event. The integration of distributed energy resources (DERs) was a commonly discussed topic. There were ideas in that space that had previously been considered to be several years away and that were now becoming seen as commonplace. Examples include having AMI infrastructure, being able to use the data, deciding what to do with the data, using it to integrate renewables, and dealing with the topics of electrification and transportation. Having the infrastructure to take advantage of these potential capabilities was important. It sounded like a given that time-variant pricing would be available. It would make sense to have time variant pricing that took into account new pricing patterns in the market due to the duck curve. It may also make sense to create incentives for people to charge during specific times of day, such as when prices are negative. She had also been to a discussion with the 51st State group, a SEPA initiative. It would be useful for Palo Alto to be a part of those discussions. UTILITIES GENERAL MANAGER REPORT Utilities General Manager Ed Shikada delivered the General Manager’s Report. City is Paving the Way for More Electric Vehicles with Renewable Energy: On July 24, the City unveiled new solar panels installed on top of two public garages and electric vehicle (EV) charging stations that will be powered by the renewable energy generated on-site. A ceremony was held at the Bryant Street parking garage to celebrate the occasion. The 240 kilowatt (kW) solar canopy at this site is owned and operated by Komuna Energy, and the electricity produced is sold back to CPAU through the City's feed-in-tariff program, Palo Alto CLEAN. This is the first operational project in the CLEAN program. This moves the City toward its goal of adding a total of 1.3 megawatts (MW) of solar capacity to four City-owned parking structures downtown and near California Ave, as well as 18 new EV chargers and the capacity for 20 more. Electric Vehicle "Charge" for Charging: Part of the City’s effort to make it easy to drive electric in Palo Alto is by expanding EV charging infrastructure throughout the City and encouraging greater “turnover” at these charging stations. As of yesterday, August 1, the City is now implementing a “charge for charging” fee at public facilities. The new fee is 23 cents per kilowatt hour (kWh). With the average charging session lasting about two hours, or 8.5 kWh, the total cost to EV drivers will be about $2 to charge up. Chargepoint, the vendor managing the system, will send individuals a mobile notification once a charging session is complete. Drivers will have a 20 minute “grace” period to move their car, after which they will face a $2 per hour fee if their fully charged car continues to be plugged in. The fee is intended to support expansion and use of public EV charging facilities and serve as a cost recovery mechanism for ongoing maintenance. More information about the City’s EV initiatives, including an interactive map of charging station locations, can be found at cityofpaloalto.org/electricvehicle Recycled Water Project Grant and Loan Funding Applications: Utilities is applying for two funding opportunities to extend Palo Alto’s recycled water system to the Stanford Research Park. One is an application for approximately $9M in grant funding under a new federal program called Water Infrastructure Improvement for the Nation. The other is for a $36M loan from the California Clean Water State Revolving Fund, which provides below-market interest rate financing for projects like Palo Alto’s recycled water project. Either of these funding opportunities would improve the recycled water business case set to be released in September. The applications do not commit City resources or pre-suppose a policy decision by Council to proceed with the project. Cap and Trade Bill Signed: The Governor signed AB 398, the state’s cap and trade bill for greenhouse gas emissions, into law on July 25. This extends the cap and trade program to 2030, which was originally set to Utilities Advisory Commission Minutes Approved on: Page 3 of 10 expire in 2020. Among other features, the program continues the use of direct allowances to utilities. CPAU uses the revenue from sale of surplus allowances to promote programs such as energy efficiency and to purchase renewable energy. Some of the allowances allocated to the gas utility are used to meet compliance obligations. As required by the cap and trade regulations, the remaining allowances are sold, and staff intends to use the revenues to purchase offsets to supply the carbon neutral program and fund gas efficiency programs. Update on SB 649 – Wireless Telecommunications Facilities: SB 649 is a bill sponsored by wireless companies wanting to soon deploy 5G technology in the state. In order to do so, they need to place their equipment on various poles owned and maintained by cities throughout California. To ease the path for these companies, SB 649 seeks to streamline permitting, leasing, and financial policies as they apply to locally-owned poles. CPAU originally had concerns about how this bill might compromise worker safety and utility reliability, but we successfully worked with NCPA to lobby for amendments to address these issues. There are other concerns from the City’s perspective as to how this impacts our ability to enforce permitting and design approval processes for antenna and associated box-like equipment on streetlights, utility and other poles in the public right of way. As a result, the City as a whole will likely continue to take a position of opposition to the bill. SunShares Program Launches this Month: The City is participating for the 3rd year in Bay Area SunShares, a solar group-buy program administered by Building Council for Climate Change, or BC3. Residents and employees of companies in Palo Alto along with 40 other Bay Area communities are eligible to participate. The program provides group-buy discounts through three solar installers, and negotiations are in progress with vendors to also include discounts on EV charging equipment and zero-emission vehicles. SunShares runs for a limited time only. Registration is open from August 7 through November 10. Contracts for PV installations must be signed by December 31. Participation in a solar group-buy program is part of our Local Solar Plan. COMMISSIONER COMMENTS None. UNFINISHED BUSINESS None. NEW BUSINESS ITEM 1: ACTION: Study Session Between the Council and UAC Jeff Hoel, resident, recommended making sure joint UAC and Council study sessions happened annually. He recommended verbatim minutes for UAC meetings. He also asked whether there was a process for the UAC to agendize an action item to provide a recommendation to Council. Subcommittees had not been helpful so far in helping the UAC send specific UAC-initiated feedback to City Council. He recommended talking to the City Council about undergrounding before any discussion of taking the topic “off the table.” He recommended getting clarity from the Council on the UAC’s priorities with respect to a second transmission line. He made some suggestions on how to agendize items for the UAC. He recommended updates to the website. Chair Danaher noted that the UAC was able to agendize items by raising them during the section of the agenda devoted for that purpose. General Manager / Assistant City Manager Ed Shikada said the staff report for this item summarized the upcoming workload and some potential topics for discussion. Staff was prepared to modify and use the staff report as a way to introduce any topics the UAC wanted to discuss at the joint study session. Utilities Advisory Commission Minutes Approved on: Page 4 of 10 Commissioner Schwartz said it was problematic that the UAC had not been consulted on the scheduling of the community focus group for the Utilities Strategic Plan. To have a good focus group it was important to have a good outreach process that involved reaching out to leaders in the community, community groups like Acterra, the neighborhood groups, and business groups, and having community leaders reach out to their networks. Shikada said the role of the UAC in that workshop was open for discussion, and staff intended to push the community meeting to October, possibly replacing the October UAC meeting. Commissioner Schwartz noted an article about cohousing projects. She had been thinking about the fact that 30% to 50% of utilities employees were going to retire in the coming years. She wondered if there were ways to help attract people already tied to the Bay Area using creative ideas like cohousing projects or partnerships with local community colleges. It was important for utilities to communicate the heroic nature of the work of system maintenance and operation. She recommended discussing these issues as part of the joint study session. She also recommended discussing reliability comprehensively at that meeting. She asked whether the UAC would passively accept topics from the Council or whether the UAC could introduce topics for discussion at the study session. Councilmember Filseth said the UAC had latitude in the topics of discussion it asked the Council to discuss at the joint study session. Staffing was a reasonable topic to discuss. Chair Danaher said to make the meeting effective it was necessary to have a framework for the meeting. It was important to get the Council’s feedback on what their priority issues were, then bring up UAC-initiated topics to develop a good work plan for the coming year. Shikada referred the UAC to the attachment to the staff report. If this were a helpful framework for the study session discussion the UAC could use it or modify it as a basis for the study session. Commissioner Johnston found the attachment helpful. He felt resiliency was a broad topic and important to discuss. Moving forward on smart meter installations was also important. Commissioner Forssell felt the four items mentioned in the staff report as potential topics were what she wanted to talk about, but in the reverse order from the way they were listed in the report. She wanted to have a discussion of local solar in general, given the duck curve and the economics of rooftop solar, and not just limiting that discussion to community solar. It was worth discussing the integrated resource plan and the strategic planning process, and focusing minimally on looking back at 2017. It was also important to talk about long-term drought potential and the issue of long-term water supply and hydroelectric power as it related to climate change. Chair Danaher thought it was helpful to think about the agenda in terms of categories. The first discussion might be “Council priorities.” A second discussion might be “Policy Areas,” during which different Council members might express policy views. This section might be introduced by a short summary discussing the cost of local solar as compared to utility-scale solar, and could result in identifying some of the Councilmembers’ views on subsidies for solar. Other topics might include undergrounding and how to promote EV chargers. Commissioner Schwartz said cost was not the only issue to look at with respect to local solar. Having an energy source within Palo Alto could contribute to resiliency if buildings were set up to be able to operate independently of the grid during curtailments. The UAC was able to provide value by looking deeper into potential policies that sound good in principle, but are not as worthwhile when you try to implement them. Chair Danaher said Vice Chair Ballantine had explained that solar on its own did not provide resiliency. Utilities Advisory Commission Minutes Approved on: Page 5 of 10 Commissioner Schwartz agreed with this, but noted that if the solar system were designed with connected storage, it added to resiliency. Commissioner Forssell said it would be helpful to understand the Council’s objectives when they previously set the 4% local solar goal. Councilmember Filseth said there had been turnover in the Council and there may be different priorities now than at the time the Local Solar Plan was adopted. Chair Danaher recommended introducing the topic by listing out the different costs of local and utility-scale solar and what the City’s compliance requirements were. Jonathan Abendschein, Assistant Director of Resource Management said there were no remaining State mandates aside from net metering for local solar, and that the Local Solar Plan required no subsidies from non-participating ratepayers. For example, the Community Solar program involved having the subscribers rather than non-participating ratepayers pay the excess cost for the installed community solar. Chair Danaher said not all of the costs had been covered by the subscribers. Abendschein said staff could address this topic in more detail at the joint study session. Councilmember Filseth shared his back of the envelope analysis. Assuming local solar costs about 7 cents per kWh more than utility scale solar, the cost of getting 4% of the City’s energy from local solar could cost more than $2 million per year, and it was important to discuss what value the community got out of local solar and who paid the additional costs. Chair Danaher agreed it was important to provide the right information to inform the discussion. He went back to his outline of the agenda, which started with a first agenda item focused on Council direction on UAC priorities, then a second agenda item on policy discussions, including local solar, and then a third agenda item on information the UAC wanted to draw Council attention to, including the workforce issues that Commissioner Schwartz had raised earlier. Commissioner Trumbull recommended having a focused discussion by talking about what has happened in the past, what is planned for the future, and one significant topic, which he believed should be the Utilities Strategic Plan. He did not think it was productive to talk about solar and try to get a policy decision from the Council, given the wide range of issues they had to cover at a policy level. Chair Danaher disagreed, saying much of the UAC had expressed that it was important to talk about solar. He thought it was important, even if it would not be possible to get a formal policy decision from the Council. The Council would know about the topic in advance, and he would be able to discuss it with the Mayor and Vice Mayor prior to the meeting. He agreed with Commissioner Trumbull’s other comments. Shikada said the structure recommended by Commissioner Trumbull would work as a way to organize the study session and that the study session could be used as a way to get feedback from Council on local solar, if not a decision. He would not be surprised if the Council were very open to recommendations from the UAC on this topic. Staff could organize upcoming agenda items and the strategic plan direction to reflect Council feedback. Chair Danaher appreciated the ideas raised in the staff report, and recommended staff set an agenda for the August 21 meeting and that Commissioners e-mail suggestions to Chair Danaher or Vice Chair Ballantine to share with staff in setting the agenda. He suggested an attachment with information, an overview of the strategic plan, and a separate agenda for the meeting. Utilities Advisory Commission Minutes Approved on: Page 6 of 10 Commissioner Forssell thought it would be good to have verbatim minutes, and was interested to hear Council’s thoughts on their priorities with respect to the fiber utility, including what level of subsidy they would be open to when considering a business plan. Chair Danaher said it would also be helpful to understand how Council wanted the issue of the fiber utility to be presented to them. Commissioner Schwartz said some progress had been made on the issue through work done by the UAC last year, and she hated to think the City was back at the beginning of the discussion. Chair Danaher said the interesting question Commissioner Forssell was asking was how much the Council was willing to subsidize the system. It was a different perspective that had not been discussed, he thought. Commissioner Johnston said it would be helpful to clarify the UAC’s role in the fiber utility as compared to the Citizen’s Advisory Commission on Fiber. ACTION: No action ITEM 2: DISCUSSION: Discussion of Developing a Flexible Distributed Energy Resource Plan and Forecasting Long Term Customer Electrical Loads in Palo Alto Senior Resource Planner Shiva Swaminathan noted several other staff members who are working on distributed energy resources (DERs) strategy and implementation, including Sonika Choudhary, Lena Perkins, Eric Wong and numerous other staff members from Utility Program Services group working on DER programs daily. He described what DERs were: they were typically installed at a customer’s premises, changed the character of the loads the City served, and could act as a replacement for services typically provided by central station energy generation. He gave some examples of DERs. He listed some existing City policies related to DERs, and noted that generally the City’s practice has been to facilitate customer adoption of DERs when there was a City policy or when it was cost-effective from a societal perspective. He gave an overview of historical utility programs applicable to a variety of DERs. He requested feedback on a set of proposed strategic principles for integrating distributed energy resources. Commissioner Johnston asked if it was possible to speed up smart grid investments. Swaminathan said prior Council direction had been to defer action because smart grid investments had not been cost effective. Implementation timeline is expected to be 2021, and is dependent upon the successful implementation of our Customer Information System (CIS), planned for in the coming years. Commissioner Schwartz endorsed the approach of enabling customers to invest their own money in technologies that were not yet cost effective. With respect to demand response, she talked about a service that allowed you to be a part of a voluntary demand response program even if you did not have a smart meter. She also recommended looking at participating in smart thermostats and peer to peer battery sharing solutions available in the marketplace to learn from them in the next 5 years. She also talked about Hawaii’s approach to targeted AMI deployment. Commissioner Forssell expressed support for the guiding principles. She appreciated the effort to ensure the distribution system could handle increased DER penetrations. She asked what stress tests were undertaken for the distribution system. Swaminathan outlined elements of the stress test – high and low load growth scenarios for the overall community, localized distribution transformer loading, and level of PV penetration. Chair Danaher seconded previous support for the strategic principles. He recommended more specifics on strategic principle 3, listing examples of the types of work staff would do to facilitate customer adoption Utilities Advisory Commission Minutes Approved on: Page 7 of 10 such as reducing barriers to permitting. He also encouraged staff to look investments that can be undertaken now, even if unneeded, that may create greater value later, and cited enabling vehicle-to-grid type technologies now as an example of such “future proofing.” Commissioner Forssell recommended using some low probability but high impact scenarios when developing stress tests for the distribution system, as well as the impacts to the distribution system. She cited an analogous example of a low probability, high impact scenario that had a financial impact, where customers sign up for a higher cost community solar projects and then do not follow-through with paying for it. Swaminathan acknowledge many type of stress tests could be looked at it, from both a DER perspective and from a broader utility-wide perspective such as load growth due to a large server farm moving into town or large customers leaving if there is direct access in the future. Commissioner Schwartz mentioned that load growth due to EV charging is a good problem to have from a utility perspective, when most other utilities worry about declining loads. She also outlined how utilities can show leadership by coming up with ways to assist with EV adoptions in the most effective way and underscored the role AMI would play in this regard. Chair Danaher also recommended prioritizing programs based on the cost of carbon reduction, such as those established by past studies. Abendschein mentioned that such analysis is being undertaken behind the scenes as staff evaluates and recommend customer programs for implementation, and promised to present such analysis in public in the future. ACTION: No Action ITEM 3: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that the City Council Approve Policy Objectives for the 2017 Wastewater Collection Utility Cost of Service Analysis Senior Resource Planner Eric Keniston presented three general objectives for the proposed Wastewater Collection Cost of Service (COSA) study, and asked if the commissioners had any additions, comments or concerns they wanted addressed in the study. Commissioner Johnston supported the staff recommendation. Commissioner Trumbull asked staff to clarify how sewer rates were charged. Keniston noted that residential customers were charged a flat rate, based on class averages, while non- residential customers were charged a rate based on water consumption. As not all residential units charged for wastewater are billed directly for water, such as in apartments, tying sewer bills to water usage has not been feasible in the past. This could be evaluated for the future. Chair Danaher asked staff to confirm that one goal of the study was to determine if here could be different class averages for different types of customers. Keniston affirmed this. Commissioner Schwartz asked if a larger house with more plumbing fixtures may have a different rate than a smaller home, and whether the difference between rates would be large or small. Keniston replied that low water usage months would be the proxy for outflow, and allocations would be evaluated based on that. Utilities Advisory Commission Minutes Approved on: Page 8 of 10 Commissioner Schwartz stated she was a proponent of having allocations to smaller homes be smaller than to larger homes. Councilmember Filseth asked whether landscaping and irrigation were included in wastewater calculations. Keniston mentioned that these were factored out when performing calculations. Abendschein stated that census figures show that multi-family residences have fewer people on average, and thus lower indoor consumption. ACTION: Commissioner Danaher made a motion to recommend that the Utilities Advisory Commission recommend that the Council approve the Policy Objectives for the 2017 Wastewater Collection Utility Cost of Service Analysis. Commissioner Trumbull seconded the Motion. The motion carried unanimously (5 - 0) with Vice Chair Ballantine and Commissioner Segal absent. ITEM 4. DISCUSSION: Discussion of Electric Integrated Resource Plan – California Wholesale Energy Market Overview and Electric Portfolio Cost Drivers Senior Resource Planner Monica Padilla acknowledged fellow Senior Resource Planners Jim Stack and Shiva Swaminathan and Assistant Director Jonathan Abendschein for their contributions towards the development of the UAC report and presentation along with staff from the Northern California Power Agency (NCPA), Dave Dockham and Tony Zimmer, for their contributions in developing the slides related to the California Wholesale Market. Padilla provided a two-part presentation with the first part focused on the California wholesale electricity market and Palo Alto’s role in the market. The second part focused on the Electric portfolio and key cost drivers and uncertainties. Padilla explained how Palo Alto’s interaction with the wholesale market is primarily through NCPA as NCPA is responsible for managing Palo Alto’s electric load and resources within-the-month of delivery all the way through real time, while City staff focuses on managing load and resource needs beyond the current month. NCPA is Palo Alto’s billing agent and provides settlements services after the fact and as the City’s scheduling coordinator is responsible for interactions with the California System Operator (CAISO) on behalf of the City. Padilla explained the role of the scheduling coordinator and the unique arrangement Palo Alto and other NCPA members share with the CAISO under a metered-subsystem agreement. This agreement enables NCPA’s participating members to operate a sub-control area with the CAISO and thus follow their own load and resources in real-time. Padilla reviewed some of the key issues facing California’s wholesale market including over-generation as a result of the State’s Renewable Portfolio Standard policies and how the CAISO, and Palo Alto through NCPA is responding to the challenge including the use of economic bidding to discourage generation in certain hours. Additionally, the CAISO is expanding market opportunities through the development of the Energy Imbalance Market (EIM) and support for an expansion of the CAISO beyond California. Padilla shared that staff supports all efforts to improve market efficiency, but is cautious about the expansion of the CAISO and the potential for additional transmission costs being imposed on California ratepayers. Commissioner Schwartz asked a question about California’s ability to achieve carbon reduction goals in light of Pacific Gas and Electric’s (PG&E’s) announcement to close the Diablo Canyon Nuclear Power Plant. Padilla explained that the plan to close the plant was due to the large expense to recommission the plant and the PG&E’s future load uncertainty due to the proliferation of community choice aggregators. She also Utilities Advisory Commission Minutes Approved on: Page 9 of 10 acknowledged that the State plans to achieve a high renewable portfolio standard and meet its carbon reduction goals without the use of nuclear energy, including Diablo Canyon. Commissioner Schwartz indicated that the marginal resource is fossil-fuel based and not carbon-free like nuclear energy. For the second part of the presentation, Padilla focused on key electric portfolio cost drivers including: • Western Base Resource • Renewable Portfolio Standard; and • CAISO and transmission costs Padilla explained how transmission costs are now a significant portion of the cost to deliver energy and that forecasts for transmission access charges continue to increase. She explained that Palo Alto works closely with other NCPA members, the California Municipal Utilities Association, the Transmission Agency of Northern California and the Bay Area Municipal Transmission group to advocate for fair and just transmission rates. For the cost uncertainty portion of the presentation, Padilla shared that staff generally tracks two types of risk, or cost uncertainty: recurring risks and large cost uncertainties. Recurring risks are those associated with supply variability, most notably hydroelectricity, changes in wholesale market prices, and congestion and delivery costs associated with the solar portion of the electric portfolio (which was a relatively new risk to the portfolio). She explained how staff is trying to understand this cost variability and establish better ways to manage it. As for large cost uncertainties, Padilla identified revenue requirements associated with the City’s Western Base Resource contract and transmission-related costs as creating the greatest level of cost uncertainty going forward. Padilla also mentioned that from a retail revenue stand point, the City faces uncertainty due to load degradation either from distributed generation and/or the possibility of direct access. Padilla closed her presentation with a summary of the work plan for developing Electric Integrated Resource Plan and the next steps which includes providing an overview of the City’s two large hydroelectric resources and a discussion of how to achieve carbon neutrality goals for the electric portfolio through the analysis of alternative portfolios. Several commissioners provided positive feedback to staff on the quality and depth of the presentation. There were no additional questions. ACTION: No action. ITEM 5. ACTION: Selection of Potential Topics(s) for Discussion at Future UAC Meeting Chair Danaher asked staff to confirm whether it would be possible to move the Strategic Plan community focus group. Shikada confirmed it was possible and staff would follow up. Chair Danaher recommended staff present information to help the discussion. Shikada thought by October staff would have some preliminary thoughts on the structure of the strategic plan, and would present that and seek community feedback. The focus group was intended to be informal, not a Brown Act meeting. Utilities Advisory Commission Minutes Approved on: Page 10 of 10 Shikada noted there would be a discussion of the crossbore audit at the City Council and that staff would return to the UAC for a discussion of this issue. Chair Danaher asked whether there would be a future discussion of the low income and other customer populations. Abendschein said staff was evaluating options and planning to return with information on this issue. Chair Danaher asked that the issue of resiliency be discussed in the future. Shikada said this would be an issue discussed in the Strategic Plan. Chair Danaher also asked about agendizing a discussion related to operation of the fiber utility, including the issues raised during Oral Communications. Shikada said he would like to discuss the topic with staff first. Commissioner Schwartz asked whether staff had looked at customer analytical tools that were becoming available. Abendschein said staff used some analytical tools, but was interested in hearing more about the tools Commissioner Schwartz was referring to. Commissioner Forssell said she would like to receive some basic education on the fiber utility and how it had been built and was operated. She had also enjoyed hearing about Customer Service at the previous meeting and would be interested in hearing more. ACTION: No action Meeting adjourned at 9:45 p.m. Respectfully Submitted, Marites Ward City of Palo Alto Utilities 1 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: September 6, 2017 SUBJECT: Utilities Strategic Plan ______________________________________________________________________________ RECOMMENDATION Staff recommends that Utilities Advisory Commission (UAC) receive a presentation by staff and the City’s consultant, NewGen Strategies and Solutions (“NewGen”), for discussion related to the development of the Utilities Department’s Strategic Plan (“Strategic Plan”). BACKGROUND AND DISCUSSION At the July 12, 2017 UAC meeting, staff and NewGen presented to the UAC an approach (Attachment A) for developing a new Strategic Plan and facilitated a discussion on key market and industry trends the Utilities Department must address in the next five to ten years. Since the July meeting, much progress has been made towards gathering input from a broad range of internal and external stakeholders representing Utilities employees, other City departments and the residential and business communities. Through these discussions, staff has developed a draft strategic direction for consideration, which is intended to align with the City and Utilities Department’s values and vision. Staff has also been engaged in stakeholder discussions regarding key issues the Utilities Department faces in the coming years. NewGen will facilitate a similar discussion with the UAC to identify key issues and long-term vision for the Utilities Department. Along with the strategic direction, the vision and key issues will inform the development of the Strategic Plan. NEXT STEPS A community workshop has been scheduled for the October 4, 2017 in lieu of the regularly scheduled UAC meeting. The workshop will allow for an open dialogue between staff, the UAC and the community-at-large on matters related to planning for the Utilities of the future and development of the Strategic Plan. At the November 2017 UAC meeting, staff will provide initial strategies and tactics for review and feedback, followed by a proposed Strategic Plan for UAC’s consideration at the December 2017 meeting. RESOURCE IMPACT There is no direct resource impact as a result of the acceptance of the presentation. POLICY IMPLICATIONS There is no direct policy impact associated with this report, but any changes made through the ultimate approval of a new Strategic Plan may affect Council-approved policies. ENVIRONMENTAL REVIEW Acceptance of the presentation at the UAC meeting does not meet the definition of a project under Public Resources Code 21065 and therefore California Environmental Quality Act (CEQA) review is not required . ATTACHMENT A. Strategic Planning Process PREPARED BY: MONICA PADILLA, Sen i or Resource Planner ·~( DAVE YUAN, Utilities Strategic Business Manager Management L?h -!. REV I EWED BY: APPROVED BY: EDSHIKADA General Manager of Utilities Employee Workshop #1 Employee Workshop #2 City of Palo Alto U Ongoing Coordination All Hands Emplo Meeting Small Group Meetings Kick Off Meeting es I Strategic Planning Process City Mgmt Stakeholder Meeting Core Planning CPT Team (CPT) M eeting #2 Meeting #1 Utility Stakeholder Gro up (USGI #1 Utility Advisory Commission Meeting #1 7/12 Initial Vends Draft Vision & issues BluoPoint Planning UAC/Co un cil Joint Session 8/21 UAC M ee ting #2 g/6 Vision & Issues Defined CPT Meeting #4 tl Community Workshop UAC Update 10/4 Initial Strategies & Tactics UAC Update 11/1 Draft Strategic Plan ATT AC HMENT A UAC Meeting #3 12/6 Review & Revised Strategic Plan Council Presentation Final Strat egic Plan July 0, 2017 Page 1 of 12 2 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: September 6, 2017 SUBJECT: Discussion of Electric Integrated Resource Plan – Hydroelectric Resources and Carbon Neutral Portfolio Alternatives ______________________________________________________________________________ REQUEST In furtherance of the development of an Electric Integrated Resource Plan (EIRP) for the 2019 to 2030 planning horizon, this report is intended to provide the Utilitie s Advisory Commission (UAC) an overview of the City of Palo Alto Utilities’ (CPAU) hydroelectric resources and its Carbon Neutral Plan, as well as to begin a discussion about various alternative approaches CPAU might take to achieve carbon neutrality. Staff requests UAC feedback on the proposed portfolio alternatives and corresponding analysis. EXECUTIVE SUMMARY The EIRP provides the necessary planning and policy framework to meet CPAU’s planning needs . The EIRP – which is to be developed over the next eighteen months – will address several important electric portfolio decisions and strategic actions needed over the next two to three years for the 2019 to 2030 planning horizon. Through the EIRP process, staff will explore several key policy issues related to acquiring and managing electricity resources to meet community objectives. Two of the key items staff will seek through the development of the EIRP are: direction on how much hydroelectric generation the City should pursue long-term, and direction on how to best achieve a carbon neutral electric portfolio consistent with the City’s environmental sustainability objectives and CPAU’s Strategic Planning objectives. The purpose of this report is to provide an in-depth overview of the City’s two existing hydroelectric resources, the Calaveras Project and Western Base Resource; describe some of the key decisions on the horizon with respect to the latter hydroelectric project; provide an overview of the Council- approved Carbon Neutral Plan; and present a proposed methodology for evaluating alternative portfolio mixes that would achieve carbon neutrality in the future. BACKGROUND At the June 7, 2017 UAC meeting, staff provided a report and presentation outlining the need for CPAU to develop a new EIRP along with a proposed work plan (Attachment A) to develop this EIRP. The intent of the proposed approach is to both meet CPAU’s planning needs and to comply with IRP requirements as provided for in California’s Senate Bill 350 and the Public Utilities Code. Page 2 of 12 In furtherance of this effort, at the August 2, 2017 UAC meeting, staff provided two reports for discussion (no action requested) and presentations related to:  Distributed Energy Resources (DER) Plan and Load Forecasting – overview and proposed guidelines;  California Wholesale Energy Market – overview and Palo Alto’s role; and  Electric Portfolio Key Cost Drivers and Uncertainties Further, staff noted that the EIRP Work Plan was modified slightly to include a discussion on alternative portfolio mixes and analysis to achieve carbon neutrality. DISCUSSION Large Hydroelectric Resources CPAU’s electric supply portfolio includes two large hydroelectric resources, the Calaveras Hydroelectric Project (Calaveras) and Western Base Resource (WBR or Western), which supply 14 percent and 40 percent of the City’s annual supply needs, respectively, under average hydroelectric conditions. While combined these two projects can provide more than 50 percent of the City’s electricity needs, the actual amount varies significantly from year to year, resulting in significant variations in the amount of energy procured on the market. Both hydroelectric resources are considered carbon-free; however, with the exception of a relatively small portion of the output, neither project meets the Renewable Portfolio Standard (RPS) eligibility criteria under the California Energy Commission’s (CEC) rules.1 Both resources consist of a combination of facilities at multiple locations, including large dams and generators, small dams and generators, diversion dams, and other facilities. The small hydroelectric facilities (those with a nameplate capacity of 30 megawatts (MW) or less) associated with each project account for one percent of the City’s total annual supply needs. The following is a discussion of the two hydroelectric resources and key issues/decisions in the 2019 to 2030 planning horizon. Calaveras Hydroelectric Resources Calaveras was bond-funded and built as a joint project between members2 of the Northern California Power Agency (NCPA) and the Calaveras County Water District (CCWD) in 1983 . CCWD holds the Federal Energy Regulatory Commission (FERC) license and NCPA is the project operator . The project resides on the North Fork of the Stanislaus River in Calaveras, Alpine and Tuolumne Counties. Calaveras was built primarily for hydroelectric generation purposes and as such water is 1 The California Energy Commission establishes RPS eligibility guidelines, which generally include the following types of generating resources: wind, solar, biomass, landfill gas, geothermal, and small hydroelectric. “Small hydroelectric” refers to facilities with a nameplate capacity of 30 MW or less. See: Renewables Portfolio Standard Eligibility Guidebook, Ninth Edition. California Energy Commission, Publication Number: CEC -300-2016-006-ED9-CMFREV. http://docketpublic.energy.ca.gov/PublicDocuments/16-RPS- 01/TN217317_20170427T142045_RPS_Eligibility_Guidebook_Ninth_Edition_Revised.pdf 2 NCPA members participating in the Calaveras Project via the Calaveras Third Phase Agreement with NCPA, include the cities of Alameda, Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Roseville, Santa Clara and Ukiah and the Plumas - Sierra Rural Electric Cooperative. Page 3 of 12 stored and managed to optimize generation value and to meet member owners’ energy needs. Palo Alto’s share in the project is 22.92 percent. Calaveras’ project capacity is about 253 MW and can generate 575 gigawatt-hours (GWh) of energy under average hydroelectric conditions. Palo Alto’s corresponding share of the output is 58 MW of capacity and 132 GWh of energy. The City’s outstanding debt on the project is approximately $103 million, of which a large portion will be maturing in 2024 and the remainder will mature in 2032. Annually through fiscal year 2024, the City’s debt is on average about $9 million. For the remaining years until 2032, the debt is about $5 million. Historically, debt and other costs associated with Calaveras have resulted in the overall value of the project being below market.3 For fiscal year 2018, Palo Alto’s share of the project cost, including debt, is $12.5 million and the value is expected to be $5.7 million , resulting in a net cost of $6.8 million. However, because Calaveras’ variable operating and maintenance costs are relatively low, the project is dispatched regularly for the purpose of generating energy. Additionally, Calaveras has the ability to meet several of the California Independent System Operator’s (CAISO) compliance and operating requirements, including: following variations in the City’s load in real-time (load following), ancillary services related to regulation energy and spinning reserves; and meeting some of the City’s Resource Adequacy requirements, including flexible capacity and system capacity. Calaveras also serves as an energy storage asset, since water is stored in the main reservoir, New Spicer Meadow, and released at optimal times to meet energy and capacity needs. Long-term it is expected that the value of Calaveras will increase assuming average or above average hydroelectric conditions and favorable regulatory requirements. While there are no imminent decisions associated with Calaveras, a few issues may be worth evaluating in the context of the EIRP, including: 1. Assessment of Calaveras value and operating strategies, given the City’s commitment to other large hydroelectric resources, RPS resources, and hydro risk management objectives. 2. How to best optimize Calaveras given its potential value to meet intermittent resource integration requirements. 3. The value of the City’s long-term stake in Calaveras, including the post-2032 period, when the current FERC license expires. Western Base Resource Since the 1960s, CPAU’s participation as a power customer of the Central Valley Project (CVP) has been an instrumental factor in its ability to deliver low-carbon electricity to Palo Altans at low rates. The U.S. Bureau of Reclamation (BOR) built the CVP in the 1930s and is charged with the operation, maintenance, and stewardship of the project. The CVP was constructed primarily for flood control of 3 In anticipation of Direct Access and the possibility for load to leave CPAU, in 1996 Council approved a competitive- transition-charge (CTC) to be added as a non-by-passable fee on all CPAU customers electricity bills. This was done to collect the above market cost (stranded cost) associated with Calaveras debt and the funds were held in the Calaveras Reserve, which had been established in 1983 to help defray cost associated with Calaveras. The Calaveras Reserve was repurposed in 2011 and is now the Electric Special Project Reserve [Staff Report 2160]. Page 4 of 12 the Sacramento Valley area; however, it is also used to provide water for irrigation and municipal use and for navigation and recreational purposes. Hydroelectric generation is a lower priority function of the CVP, relative to the aforementioned purposes. The BOR is legally required to first provide power to “Project Use” for operations and pumping water through the CVP project, and then to “First Preference Customers”, those customers whose livelihood and/or property/land was impacted by the construction of the CVP. The remaining hydroelectricity is then made available for marketing under long-term contracts with not-for-profit entities such as municipal utilities and special districts. The Western Area Power Administration (WAPA) is the federal Power Marketing Agency (PMA) charged with marketing and contracting with customers for the electric output associated with CVP, and collecting funds to meet allocated revenue requirements on behalf of the BOR. In 2000, the City executed a 20-year contract with WAPA for CVP power to start in 2005 under the 2005 WBR contract. Under this contract the City receives 12.3 percent of all the WBR product output and is obligated to pay 12.3 percent of all the CVP’s revenue requirements as allocated to power customers, regardless of the amount of energy received . Under normal precipitation and hydrological conditions, WBR meets approximately 40% of CPAU’s energy needs. However, since 2005 the amount has varied from a low of 22% to a high of 64%. The corresponding cost per MWh has ranged from $22 to $61/MWh. The current WBR contract is set to expire at the end of 2024 . Western’s proposed 2025 Power Marketing Plan, submitted to the United States Federal Register Notification (U.S. FRN No 27433), if approved by the Department of Energy, would allow existing WBR power customers to renew up to ninety-eight percent of their existing allocation for a thirty-year term (2025-2054) under similar contract terms and conditions to their existing contracts. The process for extending this contract is well underway and is expected to take five to seven years to complete (Western's 2025 Power Marketing Plan Tentative Schedule). CPAU staff has been actively involved in the process by providing informal and formal comments in response to the 2025 Western Power Marketing Plan and by working with WAPA staff and other WBR contract customers to develop a better model of long-term generation and cost projections. Pending approval of the 2025 Power Marketing Plan, Western will seek commitments through execution of the new WBR contract in 2020 – although participants may have an option to reduce participation and/or terminate their contract in 2024. A key topic for consideration in the EIRP is whether or not the City should renew its WBR contract – and if so, at what level. The analysis necessary to aid Council in its decision will need to consider the cost and the value of the resource going forward, which are both highly uncertain . This is due in large part to the nature of the CVP and supply availability, which is dependent on unpredictable precipitation conditions, the long-term effects of climate change, and the potential for new environmental policies and/or projects which threaten to erode generation value. The costs associated with participating in the WBR are also highly uncertain. First, the BOR has yet to update the cost allocation study necessary to establish rates for CVP power under the existing Page 5 of 12 contract, and it is unclear when such rates will be published for the post -2024 period. Additionally, funding requirements under the Central Valley Project Improvement Act (CVPIA)4 and the appropriateness of the allocation of Restoration Fund collections between water and power customers is of serious concern to CPAU and other power customers. As such, through the Northern California Power Agency (NCPA),5 members have filed suit with respect to the collection and use of Restoration Funds under the CVPIA.6 Lastly, the potential for changes to local and state RPS requirements – such as portfolio mandates or carve-outs for baseload renewables and/or not providing consideration for supply variability associated with large hydroelectric resources – as well as the potential for loss of load due to distributed energy resources and/or load defection, increase the risk of a renewed WBR contract becoming a stranded resource, unless clear and reasonable termination provisions are included in the future WBR contract. NCPA staff and CPAU staff are in the process of assessing the impact magnitude and likelihood of several issues which threaten to dilute the future value of WBR, as well as NCPA’s and CPAU’s ability to influence these issues. These issues are in addition to highly variable hydrological and/or precipitation conditions which create year-to-year variations in value. Staff and NCPA will work towards refining the analysis of these risk factors, to aid in the decision of how much WBR to renew for the post-2024. Carbon Neutral Plan In 2012, Council approved a carbon neutral definition (Staff Report No. 2937) which defined carbon neutrality for CPAU’s electric supply portfolio as a supply portfolio that demonstrates annual net zero greenhouse gas (GHG) emissions, measured at Citygate, in accordance with The Climate Registry’s Electric Power Sector protocol for GHG emissions measure ment and reporting. In 2013 Council approved the Carbon Neutral Plan which set a goal to achieve carbon neutrality by end of 2013 (Attachment B) consistent with the Council-approved definition of carbon neutrality. In doing so, the Carbon Neutral Plan established a transparent and verifiable protocol to measure and neutralize the carbon content associated with the City’s electric supply portfolio. The Carbon Neutral Plan further directs staff to pursue carbon neutrality on an annual basis with a rate impact of no more than 0.15 cents per kilowatt-hour (kWh) through the use of preferred resources (e.g., energy efficiency and solar distributed generation), existing large hydroelectric resources (i.e., Calaveras and Western) and long-term RPS-eligible resources. The Plan also allows 4 The Central Valley Project Improvement Act was passed by the U.S. Congress in 1992 to establish the Restoration Fund, funding requirements and goals to restore the habitat of the area impacted by the CVP. Water and power customers are obligated to pay into the Restoration Fund. https://www.usbr.gov/mp/cvpia/docs/public-law-102- 575.pdf 5 In 2005, Council approved the Western Base Resource Administrative Assignment Agreement (AAA) between the City and NCPA. This agreement assigns Palo Alto’s full share of its WBR allocation to NCPA for administrative and pooling optimization purposes. Palo Alto’s WBR contract with WAPA is still in effect; however, Palo Alto’s allocation is zero percent. As such, all contract administration, billing, and representation happens through NCPA. The AAA may be terminated at any time by Palo Alto. 6 Northern California Power Agency, City of Redding, City of Roseville, and City of Santa Clara v. the United States, Court of Federal Claims no. 14-817C Page 6 of 12 for the use of short-term renewable products, other carbon-free resources (excluding nuclear energy), and/or renewable energy certificates (RECs) to neutralize the electric portfolio’s carbon content prior to the City’s contracted long-term renewable resources coming online or during below average hydroelectric years. The City’s aggressive RPS—which set a goal to supply at least 33 percent of the City’s electric retail sales from renewable resources by 2015 and incur a rate impact of up to 0.50 cents per kWh in doing so—has allowed the City to achieve an expected RPS level of 60 percent starting in 2017. This, coupled with large hydroelectric resources meeting approximately 50 percent of energy needs, assuming average precipitation conditions, will enable the City to achieve carbon neutrality going forward without the use of RECs or short-term renewable products (under normal weather conditions). Figure 1 shows the electric portfolio’s actual and projected carbon intensity since 2005. Figure 1: City of Palo Alto Utilities Electric Supply Emissions Possible modifications to the City’s Carbon Neutral Plan may be warranted based on the decision the City makes with respect to its commitment to long-term hydroelectric resources, changes to its RPS (both mandated and voluntary), and/or other modifications deemed consistent with City’s GHG emission reduction and financial sustainability goals. For example, the UAC has expressed a desire to Page 7 of 12 explore the carbon neutrality definition and the implications of the City’s renewable resources not being aligned with its load in real-time, given the fact that for Palo Alto carbon neutrality is calculated on an annual basis. This counting convention allows for CPAU, at certain times of the year or even hours of the day, to operate with surplus carbon-free resources, which can then be used to offset periods when CPAU has a deficiency of carbon-free resources and must rely on the market for generic energy (which would most likely be fossil-fuel based). Since CPAU’s carbon neutral portfolio consists of mostly intermittent renewables, a portfolio with a greater dependence on baseload renewables, such as geothermal or biomass, would reduce the magnitude of CPAU’s reliance on the market for balancing its portfolio positions. However, even with a portfolio consisting primarily of baseload renewables, matching CPAU’s electric supplies and load in real-time would likely require a major investment in energy storage resources. Alternative Portfolio Mixes The EIRP and corresponding implementation plan will include discussion and evaluation of the right amount of large hydroelectric resources (specifically related to the renewal of the WBR contract) to be included in the City’s carbon neutral electric portfolio. It will also include discussion and analysis of what alternative resources could be used to continue to achieve carbon neutrality in the event that the Council opts for a reduced WBR allocation – such as an even more aggressive RPS, increased deployment of distributed energy resources, and/or acquisition of non-RPS eligible, in-state or out- of-state, carbon-free resources. The purpose of the discussion in the present report is simply to provide a qualitative overview of CPAU’s current portfolio of supply resources and some potential alternative resources, and to describe staff’s plans for the aforementioned analysis of alternative portfolio options. CPAU’s current electric supply portfolio comprises the following five major types of resources:  Federal hydro (WBR);  Owned hydro (Calaveras);  Long-term, in-state, RPS-eligible power purchase agreements (PPAs), which include solar, wind, and landfill-gas resources;  Distributed energy resources (DERs), including energy efficiency and rooftop solar; and  Market power purchases, matched with RECs, for portfolio balancing. For calendar year 2020, the projected contribution of each of these five resource types to CPAU’s overall supply portfolio is represented in Figure 2 below. Page 8 of 12 Figure 2: Projected CPAU Electric Supply Mix in 2020 by Resource Type On a monthly timescale, however, the portfolio looks significantly different. Figure 3 below shows a monthly load and resource balance for the City’s supply portfolio in an average hydro year. This graph includes only the City’s hydro and long-term PPA resources; not shown are DERs (which reduce the City’s load) and market purchases (which make up the differences, positive or negative, between the City’s total purchases and its load). Page 9 of 12 Figure 3: Monthly Load and Hydro/PPA Supplies in an Average Year On an even finer timescale, the portfolio looks even more variable still. Shown below are two daily load and resource balance graphs, for a typical day in January (Figure 4), when hydro and solar output are both minimal, and for a typical day in July (Figure 5), when hydro and solar are both in abundance. Note that as hydro is a dispatchable resource, it is currently dispatched to optimize the financial value of the resource, rather than to balance the City’s load and supply resources. This explains the odd shape of the July supply profile: market prices tend to peak in the evening hours, so the bulk of the hydro generation is concentrated in this period. Page 10 of 12 Figure 4: Daily Load and Hydro/PPA Supplies for a Typical January Day in an Average Year Figure 5: Daily Load and Hydro/PPA Supplies for a Typical July Day in an Average Year Page 11 of 12 Given the upcoming momentous decision that the City faces regarding how much (if any) of its current share of WBR output to retain in its portfolio post-2024, the EIRP will include a discussion and exploration of alternative portfolio mixes to achieve carbon neutrality during the EIRP planning horizon. In this analysis, WBR as well as all of the potential alternative resource supplies that the City could potentially replace it with will be evaluated against several key metrics, including:  the ability to meet community-wide GHG emission reduction targets;  cost and rate impacts;  cost variability and long-term uncertainty;  portfolio resource type, location, and supplier diversity;  impact on local resiliency;  level of reliance on fossil fuel resources for balancing load and supply;  stranded asset risk; and  ease of management under various conditions. Staff requests UAC input on the above portfolio analysis metrics – whether these are appropriate metrics to evaluate supply resources against, what the relative weighting of these metrics should be, and whether any other metrics should be considered. For the purposes of this alternative portfolio analysis, it will be assumed that achieving carbon neutrality is a requirement; thus only carbon neutral resources will be considered. Still, there are an unlimited number of different portfolio mixes that could be considered. Rather than attempt to itemize all possible permutations of resources capable of meeting the City’s supply needs, Attachment C presents a listing of the types of resources that make up the City’s current por tfolio, an indication of the flexibility the City has to increase or decrease each resource’s contribution to the current overall supply mix, and a qualitative assessment of the pros and cons of each resource type. Also presented are a number of major potential alternative resource types, along with pros and cons for including them in the City’s supply portfolio. Finally, Attachment D provides a graphical overview of the City’s current supply portfolio along with – for illustrative purposes only – a sampling of several potential alternative portfolios the City could pursue. Staff requests UAC feedback on which of these types of resources and/or portfolio mixes to focus on in the upcoming in-depth analysis of portfolio alternatives. NEXT STEPS Based on UAC feedback, staff will structure and evaluate several portfolio alternatives to achieve carbon neutrality objectives. The results of this analysis along with UAC and Council direction will form the basis for recommending strategic objectives and/or initiatives as part of the EIRP. The attached EIRP Work Plan summarizes discussion and action items planned for the UAC, Finance Committee and Council. The work plan is structured in four phases followed by implementation as follows: Phase 1 – Information and discussion on various electric portfolio planning elements, including:  Distributed energy resources; • Mark~t overview and cost drivers; • Large hydroelectric resources; • Carbon Neutral Plan and portfolio alternatives portfolio mixes to achieve carbon neutrality; • Renewable portfolio standard; • Portfolio and transmission cost management; Phase 2 -Analysis of electric portfolio alternatives; Phase 3 -Update of EIRP Objectives, Strategies and Implementation Plan; and Phase 4-Council approval of the EIRP and submittal to the CEC. At a future UAC meeting, staff plans to discuss the City's RPS, necessary changes to meet new RPS requirements provided for in SB 350 and consideration of other changes. RESOURCE IMPACT There is no direct resource impact as a result of this informational report and proposed analysis. Work will be performed with existing staff and consultant support which has been budgeted for under the Electric Utility's fiscal year 2018 operating budget. POLICY IMPLICATIONS There is no direct policy impact associated with this report, but any changes made through the EIRP may affect Council-approved policies related to electric portfolio management. Staff will also update the EIRP to ensure consistency with CPAU's sustainability goals as established in its Sustainability and Climate Action Plan. ENVIRONMENTAL REVIEW This informational report on the EIRP and corresponding work plan does not meet the definition of a project under Public Resources Code 21065 and therefore California Environmental Quality Act (CEQA) review is not required. ATIACHMENTS A. Electric Integrated Resource Plan -Proposed Work Plan B. Carbon Neutral Plan C. Current and Alternative Resource Supplies Table D. Potential Alternative Portfolio Mixes PREPARED BY: MONICA PADILLA, Sen ior Resource Planner JIM STACK, Senior Resource Planner REVIEWED BY: f-JONATHAN ABENDSCHEIN, Assistant Director, Resource Management r:::7~ APPROVED BY: ED SHIKADA General Manager of Utilities Page 12of12 ATTACHMENT A Item Purpose & Objectives UAC Council EIRP Overview and Work Plan Provide a high level framework for what will be discussed, time line; guiding principles; and key drivers. June 2017 (discussion) DONE September 2017 INFO ONLY Market Overview and Portfolio Cost Drivers Overview of the California energy market, the City’s participation, Northern California Power Agency; Portfolio cost drivers and uncertainties. August 2017 (discussion) DONE Load Forecast - Needs Assessment Overview of electric load forecast and– energy, demand and impacts from EE, EV and PV August 2017 (discussion) DONE Distributive Energy Resources Strategy and Planning for Growth Distributive Energy Resources Plan - energy efficiency, Local Solar Plan, distributed generation, electrification, electric vehicles, storage and distribution system planning August 2017 DONE November 2017, January 2018 (action) February 2018 (action) Hydroelectric Resources Overview of Palo Alto’s hydroelectric resources; hydro risk management; Western Area Power Administration’s 2025 Power Marketing Plan; Calaveras Project; key decisions; and direction. September 2017 (discussion) Portfolio Alternatives Overview of alternative resource portfolios and metrics to be evaluated to achieve carbon neutrality objectives. September 2017 (discussion) Renewable Portfolio Standard Overview of RPS; update to meet SB 350 requirements; renewable over-generation and curtailments; and other RPS modifications. December 2017 (action) January/ February 2018 Finance Committee/ Council (action) Carbon Neutral Plan Overview and updates – dependent on RPS and large hydro direction; assessment of alternative portfolios and scenarios February 2018 (discussion) March/April Finance Committee/ Council (discussion) Transmission Transmission planning in California; California Oregon Transmission Project; Second Transmission line update February/March 2018 (discussion) Proposed EIRP Objectives, Key Strategies and Implementation Plan Draft EIRP objectives, key strategies and implementation plan; June 2018 (possible action) Aug/Sep 2018 Finance Committee/Council (possible action) Final EIRP Approval of EIRP objectives; strategies and implementation plan; and SB 350 IRP submittal to CEC October 2018 (action) Nov/Dec 2018 Finance Committee/Council (action) ATTACHMENT B 1 Exhibit A to Resolution No 9322 Adopted by City Council on March 4, 2013 City of Palo Alto Utilities Electric Supply Portfolio Carbon Neutral Plan 1. Carbon Neutral Definition A carbon neutral electric supply portfolio will demonstrate annual net zero greenhouse gas (GHG) emissions, measured at the Citygate1, in accordance with The Climate Registry’s Electric Power Sector protocol for GHG emissions measurement and reporting. 2. Carbon Neutral Plan Objective Reduce the City of Palo Alto’s overall community GHG emissions by achieving carbon neutrality for the Electric Supply Portfolio starting in calendar year 2013 within an annual rate impact not to exceed 0.15 cents per kilowatt-hour (₵/kWh) primarily through the: 1) engagement of customers to increase energy efficiency; 2) expansion of long-term renewable resource commitments; 3) promotion of local renewable resources; 4) continued reliance on existing hydroelectric resources; and 5) meeting short-term balancing requirements and/or neutralizing residual carbon through the use of short-term purchases of renewable resources and/or renewable energy certificates (RECs). 3. Resource Strategies a. Energy Efficiency i. Continue to pursue energy efficiency strategies as identified in the Council- approved ten-year Energy Efficiency Plan. b. Long-term Renewable Resources i. Continue to pursue the City’s Renewable Portfolio Standard (RPS) goal to purchase renewable energy to supply at least 33% of retail sales by 2015 while ensuring that the retail rate impact of these purchases does not exceed 0.5 ₵/kWh. ii. Continue to pursue local renewable resources through the Palo Alto CLEAN and PV Partners programs. iii. Pursue additional RPS-eligible, long-term renewable resources (beyond the RPS goals) to achieve a target of 100% carbon-free resources based on average year hydroelectric generation. 1 Citygate is the location of the City’s main meter where the City interconnects to the Pacific Gas and Electric transmission system. Emissions associated with of the output of the locally sited fossil gas fired combustions units (COBUG), while not measured at Citygate, will be neutralized. ATTACHMENT B 2 c. Short-term Renewable Resources and Renewable Energy Certificates i. For calendar years 2013 through 2016, procure short-term renewables, if the price is comparable to that of an un-bundled REC; ii. For calendar years 2013 through 2016, procure RPS-eligible, un-bundled RECs as needed to achieve carbon neutrality based on actual load and resources; iii. Neutralize anthropogenic GHG emissions associated with renewable resources with unbundled-RECs, which may or may not be RPS-eligible. d. Banking and Truing Up i. In the event that there are surplus renewables beyond the load in a particular year, bank as many RECs as allowable under the TCR EPS protocol from qualifying renewables from that year to minimize the need for purchasing RECs in subsequent years. ii. Neutralize emissions associated with market purchases resulting from deviations between expected and actual load and renewable and hydroelectric generation resources with unbundled-RECs, which may or may not be RPS-eligible. 4. Hydroelectric Resources a. Continue to preserve and advocate for existing carbon-neutral hydroelectric generation resources that provide approximately 50% of average year resource needs. b. Plan for and acquire carbon neutral resources assuming average hydroelectric conditions going forward. c. Under adverse hydroelectric conditions, procure unbundled-RECs, which may or may not be RPS-eligible, to achieve carbon neutrality up to the 0.15 ₵/kWh rate impact limit and seek Council direction if carbon neutrality cannot be achieved within the rate impact limit. d. Under favorable hydroelectric conditions, where carbon neutral resources are expected to be surplus to needs, even after allowable banking, then pursue selling short-term renewable energy, or the renewable attributes, associated with one or more carbon- neutral resources in the portfolio. 5. Financial and Rate Payer Impacts a. In addition to the RPS annual rate impact limit of 0.5 ₵/kWh, the cost of achieving carbon neutrality shall not exceed 0.15 ₵/kWh based on an average hydro year. b. Revenues collected from surplus energy sales related to hydroelectric resources under favorable conditions (e.g. wet years), will be maintained within reserves to adjust for the cost of achieving carbon neutrality under adverse hydroelectric years. c. To the extent available and allowable, revenues from the auction of cap-and-trade allowances may be used to fund resources acquired to meet the carbon neutrality goals. 6. Reporting and Communication a. Develop a communication plan for stakeholders to inform them of the City’s efforts towards achieving a carbon neutral electric supply. ATTACHMENT B 3 b. Submit an annual, verified report of the carbon content of the electric supply portfolio to The Climate Registry. c. Provide customers a report of the electric supply portfolio’s carbon content to supplement the mandated Power Content Label. d. Inform large commercial and/or corporate customers of the City’s carbon neutral portfolio and its relevance to their individual corporate sustainability goals. 7. Implementation Plan The tasks that need to be completed in the next two years pending Council approval of the Carbon Neutral Plan in February 2013 are listed in the table below. Item Timeframe 1. Modify electric supply portfolio models and Energy Risk Management Policies, Guidelines and Procedures to account for Carbon Neutral objectives, balancing, banking of renewable attributes, reporting and financial impacts. By April 2013 2. Modify the Long-term Electric Acquisition Plan (LEAP) to include the carbon neutral objective By June 2013 3. Develop communication plan to inform customers and stakeholders of Carbon Neutral Plan and efforts. February to April 2013 4. Based on response to the Fall 2012 request for proposals, seek approval of new renewable power purchase agreements to meet the City’s RPS up to approximately 100% of the long-term resource needs in average hydro years. December 2012 to June 2013 5. Determine resource needs for CY 2013 through CY 2016 and develop plan to acquire short-term renewable resources. By June 2013 6. Determine long-term renewable purchase volumes for beyond CY 2016 and develop plan to acquire long-term renewable resources. By September 2013 7. Procure RECs as needed to neutralize carbon emissions based on actual load and resources for CY 2013. By May 2014 8. Along with annual Power Content Label, produce and report to customers the carbon intensity of the electric supply portfolio. May/June 2014 and annually thereafter 9. Produce and submit Electric Power Sector (EPS) and Local Governments Operation Protocol (LGOP) reports to The Climate Registry (TCR) for CY 2013. July and October 2014 and annually thereafter 10. Get independent verification of TCR reports and submit audited reports to TCR. By December 2014 and annually thereafter 11. Redesign the PaloAltoGreen program according to Council direction. By December 2013 Attachment C: High-Level Overview of Current Supply Resources and Potential Alternatives Current CPAU Supply Resources Resource Type Flexibility to Adjust Current Portfolio Share Pros Cons Federal Hydro (Western) Low cost/high volume; Provides ancillary services (AS); Dispatchable output Fixed cost/variable output; Very drought-sensitive; Regulatory risk Owned Hydro (Calaveras) Provides AS, capacity, load following; Dispatchable output Higher cost; Fixed cost/variable output; Very drought-sensitive Long-term PPAs (Wind/Solar) Moderate cost; Only pay for delivered energy Intermittent, highly variable; Creates flex capacity requirement; Curtailment risk Long-term PPAs (Baseload) Output matches City load well; Only pay for delivered energy; Would satisfy potential baseload carve-out requirement Higher cost than solar/wind; Geothermal resources produce GHG emissions Market + RECs Lowest cost resource; Easily match supplies with load Relies heavily on ISO grid (fossil fuel resources) Existing DERs (EE, Rooftop Solar) Avoids transmission costs/losses associated with remote resources Highest cost resources; Not dispatchable; Difficult to forecast Potential Alternative Supply Resources Resource Type Pros Cons Out-of-State RPS Potentially lower cost than in-state resources; Potential use of City-owned transmission Would require procurement of transmission; Very high transmission costs Out-of-State Hydro Likely very low cost; Deliveries may be shapeable to match supplies with load; Potential use of City-owned transmission Would require procurement of transmission; Very high transmission costs; Not RPS-eligible; Would increase hydro variability risk In-State Renewables (Solar/Wind) Very low cost resource Would exacerbate intermittency and seasonal variability problems Baseload Renewables Output matches City load well Higher cost than solar/wind; Geothermal resources produce GHG emissions New DERs (Storage, Dispatchable Load) Avoids transmission costs and losses associated with remote resources; Helps match supplies with load; Would probably provide capacity and AS Extremely high cost resources (at present) Daily Put/Call Option on Renewables Would be great for matching supplies with load, reducing reliance on ISO grid (fossil fuel) resources There are likely few (if any) suppliers willing to provide this service; Option premium likely to be very high Attachment D: Potential Alternative Portfolio Mixes Portfolio 1: Current Supply Mix (in 2020) Key Features: - Large hydro variability risk - PPAs are all in-state resources, primarily variable (wind/solar) resources - > 90% remote resources (high transmission costs) - Heavy reliance on ISO grid for supply/load balancing Portfolio 2: Local Renewables & DERs Key Features: - Heavy reliance on expensive local renewables and new DERs (e.g., storage, dispatchable load) - High concentration of non-dispatchable solar PV - Lower hydro variability risk - Reduced transmission costs Portfolio 3: In-State Solar Key Features: - High concentration of non-dispatchable (but relatively low-cost) solar PV - Low hydro variability risk - High transmission costs - Potentially high integration costs (e.g., flexible capacity, ancillary services) - Heavy reliance on ISO grid for supply/load balancing Portfolio 4: Out-of-State Renewables Key Features: - Low hydro variability risk - Would require procuring transmission rights and/or using City’s share of COTP after layoff ends - Very high transmission costs - > 90% remote resources - Out-of-state renewables may be shapeable Portfolio 5: Out-of-State Hydro Key Features: - Very high hydro variability risk - Would require procuring transmission rights and/or using City’s share of COTP after layoff ends - Very high transmission costs - > 90% remote resources - Out-of-state hydro may be shapeable and/or dispatchable Portfolio 6: Short-Term Market Option Key Features: - Heavy reliance on ISO grid (and RECs) for supply/load balancing - Likely the least cost option, but high market price risk - > 90% remote resources (high transmission costs) Portfolio 7: Baseload Renewables Key Features: - Lower hydro variability risk - Lower seasonal variability - Better match between supply resources and load - Would protect against potential baseload RPS carve-out requirements - > 90% remote resources (high transmission costs) Portfolio 8: Real-time Balancing with Storage Key Features: - Extremely high-cost portfolio - Avoids transmission costs/losses associated with remote renewables - DERs would likely provide capacity and ancillary services - DERs and dispatchable hydro would balance supply resources and load well - Minimal reliance on ISO grid (fossil fuel resources) for balancing Portfolio 9: Real-time Balancing with Daily Option on Renewable Supplies Key Features: - Likely a very high-cost portfolio due to the daily option premium - Likely very few (if any) suppliers willing to offer this daily option service - Daily put/call option on renewables and dispatchable hydro would balance supply resources and load well - Minimal reliance on ISO grid (fossil fuel resources) for balancing MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM : UTILTIES DEPARTMENT 3 DATE: September 6, 2017 SUBJECT : Local Solar Programs and Community Solar Survey Discussion REQUEST This report is provided to the Utilities Advisory Commission (UAC) for information and discussion. No action is needed at this time. EXECUTIVE SUMMARY The City of Palo Alto (City) has been a leader in facilitating local solar PV system development. Over the past two decades, approximately 1,000 local solar systems have been installed (10,000 kW capacity), currently providing about 1.2% of the Palo Alto community's electrical energy needs . Attachment A provides an overview of the past solar programs and how they are evolving under the Local Solar Plan implementation. Community solar is one of the new programs proposed under the Local Solar Plan. Staff presented preliminary design elements to develop a community solar program to the UAC in June 2017 (Staff Report). The UAC recommended to delay consideration of this program until after the Council- UAC joint study session. There was also discussion of whether there has been any market research done related to customers' interest in such program and their willingness to pay. Subsequent to the June UAC discussion, staff conducted a survey to understand Palo Alto residents' interest in local solar given CPAU's carbon neutral portfolio. Attachment B summarizes findings from this survey. Attachment C lists the survey questionnaire. NEXT STEPS This is an informational update to the UAC and no action is requested. RESOURCE IMPACT There are no new proposals presented as part of this item, and therefore no additional cost impacts. ENVIRONMENTAL REVIEW UAC's discussion of local solar programs and community solar survey results does not meet definition of a project under Public Resources Code 21065 and therefore California Environmental Quality Act (CEQA) review is not required. ATTACHMENTS • Attachment A: Local Solar Programs Discussion • Attachment B: Community Solar Survey Findings • Attachment C: Community Solar Survey Questionnaire PREPARED BY: ~· SONIKA CHOUDHARY, Resource Planner REVIEWED BY: c!ft-JONATHAN ABENDSCHEIN, Assistant Director, Resource Management a~. APPROVED BY: ED SHIKADA, General Manager of Utilities Local Solar Programs Discussion Utilities Advisory Commission September 6, 2017 ATTACHMENT A Palo Alto has a long history of supporting customer-side solar 1998 -PV rebates program –city lead o First PV Demonstration grant @ $6/watt 1997 –present Net Energy Metering (NEM) –state mandated o A billing mechanism to compensate onsite renewables at the retail rates o NEM cap: 10.8 MW (up to 5% of the utility's aggregate customer peak demand) 2006 –SB1 (CA Million Solar Roofs bill) –state mandated o CPAU SB1 budget: $13 million o Total installed capacity 7.9 MW by 2016 2012 –present CLEAN (Feed-in Tariff) –city lead o Tariff rate started at 12.5 ¢/kWh and increased to 16.5 ¢/kWh in 2013 (3 MW cap) o 5 applications (including 4 public garages) for a total of 1.5 MW approved in 2016 2014 Local Solar Plan –city lead o Local solar to provide 4 percent of the City’s total electricity needs by 2023 Palo Alto Solar Programs –History 2 Palo Alto Solar Programs -Today 3 Transitioning beyond state mandates to innovative local solar programs and establishing CPAU as trusted advisor 5 10 14 16.5 3 0.5 0 2 4 6 8 10 12 14 16 18 Avoided cost local solar Community solar Net Energy Metering CLEAN projects ce n t s / k W h ±2 ¢/kWh Energy + Capacity T&D losses Tx/ AS Prices Across Solar Programs Illustrative: Fixed 20 –25 years prices 4 ±4 ¢/kWh APPENDIX Local Solar Installations 6 - 500 1,000 1,500 2,000 2,500 - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 An n u a l k W Cu m u l a t i v e k W Palo Alto PV Installations 1999-2016 NonRes kW Res kW Cumulative kW •Since 1998, 975 residential systems and 78 commercial systems have been installed at an estimated nominal investment of $55 million •Total capacity of 10 MW, meeting ~1.2% the community’s overall energy needs and contribute 5% towards City’s system peak capacity 7 Local Solar Plan: Strategies 3. Assess Technical and Market Potential 7. Educate through Innovation and Demonstration 1. Reduce Internal barriers to decrease “soft” costs Achieve 4% Penetration by 2023 6. Promote solar on City Facilities 2. Develop proper policies, incentives & rates 4. Develop programs for customers with good solar access5. Develop programs for customers without good solar access Approved by Council in April 2014 City of Palo Alto Utilities Community Solar Survey Summary September 6, 2017 ATTACHMENT B •The City of Palo Alto Utilities has 26,000 residential customers –15,000 single family and 11,000 multi-family (apartments, townhomes, condos) •Research question: Is there enough interest in a community solar program given City of Palo Alto’s carbon neutral portfolio? •Online survey structure: 4 sections consisting of demographics followed by interest in utility programs, local solar, and community solar •Survey response rate of 5.8%, with average customer requiring 5-6 minutes to complete 2 Survey Background •Sent one time e-blast to 13,000 self-selected and 1,700 randomly selected participants on July 26th, 2017 o 778 responses from an email list of 13,000 customers who self-selected to receive more information about City of Palo Alto Utilities programs or were past program participants – 6.0% response rate o 80 responses from an email list of 1,700 customers who were randomly selected from the multi-family list from the billing system –4.7% response rate •Total: 858 responses from outreach to 14,700 customers –5.8% response rate 3 Summary of Survey Participants 4 Survey Participants –Property Owners vs. Renters 686 99 60 0 100 200 300 400 500 600 700 800 House Apartment Townhome/Condo Owners vs Renters by Household Type Own Rent Total 5 Survey Participants by Neighborhood and Household Type 27 60 13 27 31 19 54 43 64 2 24 16 2 13 1 31 29 149 11 1 1 44 5 6 35 26 1 31 18 1 2 5 33 28 0 20 40 60 80 100 120 140 160 Nu m b e r o f R e s p o n d i n g H o u s e h o l d s House Apartment Townhome/Condo Other Total 6 Majority of Participants Believe They Are Already Energy Efficient and Reduce Waste, Majority Also Interested in Solar PV and Electric Vehicles Home Owners Apartment Renters Townhome/Condo Owners Please tell us a bit about your interest or activities as it relates to energy and utility services. 577 193 36 0 500 1000 Already Do Interested In Not Interested Improve Energy & Water Efficiency in My Home 656 96 54 0 500 1000 Already Do Interested In Not Interested Reduce Waste 140 418 248 0 500 1000 Already Do Interested In Not Interested Install Rooftop Solar PV at Home 168 377 261 0 500 1000 Already Do Interested In Not Interested Purchase/Lease Electric Vehicle 436 161 209 0 500 1000 Already Do Interested In Not Interested Participate in Other Mobility Options 378 259 169 0 500 1000 Already Do Interested In Not Interested Participate in Voluntary Clean Energy Programs 7 90% Respondents Across All Neighborhoods and Home Types Are Interested In Solar Generation Palo Alto provides 100% carbon neutral electricity sourced from renewable and hydroelectric resources in California, includin g 30% electricity from utility-scale solar. Moving forward our community’s sustainability goals include building up local solar capacity within Palo Alto’s city boundaries. What describes your attitude towards supporting increased generation of solar electricity within Palo Alto? 502 219 55 29 0 100 200 300 400 500 600 Very Interested Somewhat Interested Neutral Not Interested Attitude Towards Supporting Increased Solar Generation House Apartment Townhome/Condo Total 8 40% of Respondents are Most Interested in Installing Solar At Home or Participating in Community Solar. Only 5% Are Most Interested in Donating to Install Solar in Schools or Local Non-Profits Please rank your interest in the following ways of supporting local solar energy generation. (1 being most interested) 312 131 58 219 0 50 100 150 200 250 300 350 1 2 3 N/A Install Solar at my Home I have or am considering installing solar PV at my home 276 228 46 170 0 50 100 150 200 250 300 350 1 2 3 N/A Community Ownership I would be interested in participating in a community solar PV installation via a payment on my electricity bill 37 175 232 276 0 50 100 150 200 250 300 350 1 2 3 N/A Donations I would be interested in donating to help install solar PV at local schools and non- profits Home Owners Apartment Renters Townhome/Condo Owners 9 75% of Respondents Express Interest in Community Solar –Consistent Across All Household Types and Neighborhoods The City of Palo Alto Utilities is considering developing a community solar program to enable residents and businesses to exp erience local solar, even if they are unable to install solar on their own premises. Community Solar projects would be installed a local site or sites, preferably on municipal land that is open to the public. The solar installations could provide enough electricity to power between 100 to 1,000 homes in Palo Also. Community solar participants would have the opportunity to meet up to 100% of their electricity needs with locally gen erated solar electricity. How interested would you be in participating in a community solar project? 224 317 96 77 0 50 100 150 200 250 300 350 Very interested Somewhat interested Not interested I need more information House Apartment Townhome/Condo Total 10 Customers Who Need More Information About Community Solar Are Primarily Concerned About Cost 11 When Asked Why They Are Interested in Community Solar, 68% of Respondents Cannot or Do Not Want to Put Solar On Their Homes 174 194 78 94 0 50 100 150 200 250 I want to put solar panels on my roof but I an unable to do so, so community solar sounds like a great alternative. I want to support solar energy but there are aspects of putting solar panels on my roof that I don’t like, so I’m interested in community solar. I already have a solar PV system and I want to keep supporting solar, so I would support community solar. Other Why Interested in Community Solar? House Apartment Townhome/Condo Total 12 No Clear Trends for ”Other” Responses – Wide Variety of Responses Randomized List of 1,700 Opt-In List of 13,000 13 Resilient Power Supply, Rate Predictability,, Education, and Public Knowledge Are Features That Increase Interest in Community Solar Home Owners Apartment Renters Townhome/Condo Owners 94% of Respondents Who Are Interested in Resiliency are also interested in Rate Predictability 213 240 242 0 100 200 300 400 500 More Interested Somewhat Interested No Effect Public Knowledge 249 271 175 0 100 200 300 400 500 More Interested Somewhat Interested No Effect Education 87 164 444 0 100 200 300 400 500 More Interested Somewhat Interested No Effect Patron 414 221 60 0 100 200 300 400 500 More Interested Somewhat Interested No Effect Resilience 369 245 81 0 100 200 300 400 500 More Interested Somewhat Interested No Effect Rate Predictiability 14 73% of Respondents Are Willing to Pay a Premium to Participate in Community Solar 196 174 64 76 184 0 50 100 150 200 250 5% or $3 10% or $6 15% or $9 20% or $12 No premium Premium for Community Solar House Apartment Townhome/Condo Total 15 Key Takeaways and Next Steps Key Takeaways •There seems to be a noteworthy interest from Palo Alto residents to support local solar and community solar •200+ respondents have shared their email ids to be further informed about local solar and potential development of a community solar program Next Steps •Use these findings to guide and design CPAU customer programs 90% Respondents Across All Neighborhoods and Home Types Are Interested In Solar Generation 17 Palo Alto provides 100% carbon neutral electricity sourced from renewable and hydroelectric resources in California, including 30% electricity from utility-scale solar. Moving forward our community’s sustainability goals include building up local solar capacity within Palo Alto’s city boundaries. What describes your attitude towards supporting increased generation of solar electricity within Palo Alto? 36 24 4 6 0 5 10 15 20 25 30 35 40 Very Interested Somewhat Interested Neutral Not Interested 1,700 List (86% Interested) House Apartment Townhome/Condo Total 466 195 51 23 0 50 100 150 200 250 300 350 400 450 500 Very Interested Somewhat Interested Neutral Not Interested 13,000 List (90% Interested) House Apartment Townhome/Condo Total When Asked Why They Are Interested in Community Solar, 67% of Respondents Cannot or Do Not Want to Put Solar On Their Homes 18 152 186 78 87 0 20 40 60 80 100 120 140 160 180 200 I want to put solar panels on my roof but I an unable to do so, so community solar sounds like a great alternative. I want to support solar energy but there are aspects of putting solar panels on my roof that I don’t like, so I’m interested in community solar. I already have a solar PV system and I want to keep supporting solar, so I would support community solar. Other Why Interested in Community Solar? 13,000 List (Opt-In) 22 8 0 7 0 5 10 15 20 25 I want to put solar panels on my roof but I an unable to do so, so community solar sounds like a great alternative. I want to support solar energy but there are aspects of putting solar panels on my roof that I don’t like, so I’m interested in community solar. I already have a solar PV system and I want to keep supporting solar, so I would support community solar. Other Why Interested in Community Solar? 1,700 List (Randomized) Home Owners Apartment Renters Townhome/Condo Owners 60% of Randomized Respondents Are Willing to Pay a Premium to Participate in Community Solar Compared to 75% of Opt-In Respondents 8/28/2017 19 13 10 6 3 22 0 5 10 15 20 25 5% or $3 10% or $6 15% or $9 20% or $12 No premium 1,700 List (Randomized) House Apartment Townhome/Condo Total 183 164 58 73 162 0 20 40 60 80 100 120 140 160 180 200 5% or $3 10% or $6 15% or $9 20% or $12 No premium 13,000 List (Opt-In) House Apartment Townhome/Condo Total ATTACHMENT C Seeking F ckon Pote Questions marked with an asterisk (*) are optional 1. Are you a Palo Alto resident? Yes No 2. What neighborhood do you live in?` Other (please spectfv) ..................................... Click here for map of Palo Alto neighborhoods 3. Please select the option that best describes your home: House Apartment Condo Townhome Other (please specify) 4. Do you rent or own a home in Palo Alto? Rent Own Other (please specify=) Prey o Pal A0 C Sulu Pr Palo Alto provides 100% carbon neutral electricity sourced from renewable and hydroelectric resources in California, including 30% electricity from large solar projects located in the central valley. Moving forward our community's sustainability goals include building up local solar capacity within Palo Alto's city boundaries and increasing community resiliency in the long run. City support for local solar can take several forms: helping residents, businesses and non -profits install rooftop solar; developing City -owned local solar installations; and developing opt -in, community -owned local solar installations. 6. What best describes your attitude towards supporting increased generation of solar electricity within Palo Alto? Very Interested Somewhat Interested Neutral Not Interested Prey T 7. Please choose the option that best describes your personal opinions regarding local solar energy generation. Strongly Agree I Ike the idea of producing energy independently Solar may provide the opportunity for me to stabilize my electricity rates i want to support the growth of renewables and sustatnability in my community Locally sited solar may help reduce adverse environmental and wildlife impacts of utility -scale installations More solar projects in my community will help reduce stress on the electricity grid My friends and neighbors have installed solar and it has piqued my interest Other opinions on local solar generation in Palo Alto: Agree Neutral Disagree Strongly Disagree 8. Please rank your interest in the following ways of supporting local solar energy generation. Please rank from 1-3, with 1 being most interested. Options may be dragged to rank position as well. Mark N/A if you are not interested. 4, INSTALL SOLAR AT MY HOME: I have or am considering installing solar PV at my home, COMMUNITY OWNERSHIP: I would be interested in participating in a community solar PV installation via a payment on my electricity bill, ! DONATIONS: I would be interested in donating to help install solar PV at local schools, non -profits, etc, in Palo Alto, Prey N/A N/A N/A Page 1 of 6 4 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILTIES DEPARTMENT DATE: September 6, 2017 SUBJECT: Update on Smart Grid Pilot Projects and Development of the Utility Technology Implementation Roadmap ____________________________________________________________________________________ REQUEST This report is provided to the Utilities Advisory Commission (UAC) for information and discussion. No action is needed at this time. EXECUTIVE SUMMARY In 2012, City of Palo Alto Utilities (CPAU) completed an assessment of smart grid applications based on Advanced Metering Infrastructure (AMI) for Palo Alto. The study estimated the capital cost associated with AMI implementation for electric, natural gas and water utility services at $15 to $20 million, and the cost-benefit assessments found the costs outweighed benefits over a 15- to 20-year life of such an investment. Based on these findings, the study recommended, and City Council approved, deferring major investments in smart grid for several years until technologies mature and implementation costs decline, along with implementation of a number of smaller pilot scale smart grid projects (Staff Report 3330, 12/10/2012). This report outlines the pilot projects undertaken over the past 5 years and discusses the experiences gained and lessons learned. The report also discusses the process currently underway to evaluate the pilots and experience gained, and to develop an actionable technology implementation roadmap over the next 5-10 years. This effort is being coordinated with the update of the Utilities Strategic Plan. A draft technology implementation roadmap with associated resource needs will be brought to the UAC for discussion early next year, and for final Council approval in the spring of 2018. DISCUSSION Based on the 2012 evaluation and associated recommendations, staff implemented a number of pilots of smart grid applications and evaluated a number potential integration issues over the past 5-years as outlined below: 1. Implemented Residential CustomerConnect advanced meter pilot program whereby 300 single family residents1 were provided advanced electric, natural gas and water meters and given access to their hourly utility consumption information with the expectation of enabling residents to better understand their energy and water consumption patterns and improve their utilization or to undertake conservation efforts . The $450,000, 5-year pilot helped increase participant awareness of their utility consumption pattern, but no noticeable change in consumption was observed. The water leakage detection 1 Of the 300 residents, 200 were selected and volunteered to participate on a first-come first-served basis. An additional 100 were recruited by soliciting a group of 400 residents selected based on a stratified sampling technique. In addition to the 300 residents who received advanced meters for all three utility services, 106 additional residents were recruited at strategic locations in town to receive advanced electric meters only, in order to strengthen the meter communication mesh network throughout Palo Alto. Page 2 of 6 notification feature helped detect and fix a large number of water leakages occurred at participants’ homes and was well received by the participants. Useful customer energy consumption hourly profiles were obtained to further aid customer program development and distribution system planning. The program also facilitated a number of other pilots as outlined below. 2. Implemented Residential Time-of-Use (TOU) electricity retail rates to provide different pricing depending on the hour when electricity was consumed. The TOU rate is designed to encourage the use of electricity during off-peak hours. About 117 customers who participated in the CustomerConnect program were introduced to this rate plan. Only a small shift in consumption towards off-peak hours was observed among households with EVs, mostly because EV owners already tended to charge at night, even before they started on the TOU rate. Customers with EVs under this rate on average saved $1 per month. Customers without an EV or high electricity users did not benefit from the TOU rate. EV owners’ electricity consumption on average was about 35% or 180 kWh higher per month than an average household in Palo Alto. EV charging profiles obtained through the AMI meters will help better plan distribution system transformer sizing in the future. 3. Enabled the monitoring of electricity consumption through In-Home-Displays (IHD), devices that connect to the AMI electric meter, via a Zigbee radio in the meter, to display consumption in real time to the homeowner. The IHD’s ability to send this information through a customer’s wifi network to an online platform was utilized in a novel research project through a partnership with the Palo Alto Medical Foundation (PAMF). The research projects was designed to explore if near real time utility consumption information could be utilized by care-givers to monitor seniors’ activity at home in a unobtrusive manner to provide timely homecare as needed. Twenty such seniors were identified by PAMF and were enrolled in the pilot by providing AMI electric meter and IHD. PAMF and Robert Wood Johnson foundation funded this research project and the results will be published by the end of this year. 4. Implemented large commercial customer summer peak demand response (DR) program to lower Palo Alto’s overall annual summer peak load and associated electricity capacity purchase cost, and to reduce the need for the state to turn on inefficient fossil fuel peaker plants. Customers who signed up for the program were required to lower consumption by a minimum of 50kW when called upon and were compensated for energy consumption reduction during those periods at a rate of 50 cents/kWh, Palo Alto’s avoided energy/capacity cost for such peak load periods in the summer. The program was open to only large commercial customers who were eligible to receive communicating interval meters under an existing Meterlinks program. The program has attracted six to eight large commercial customers (including City facilities) and customers collectively reduced loads by 400 to 800 kW (in a 4-hour period between noon to 6pm) on such demand response days in the summer. The benefit of this program is about $10,000 per year, and is equal to the cost of program administration and customer compensation. 5. Assessed Conservation Voltage Reduction (CVR) potential, by utilizing voltage sensors in the AMI meter and transformer load tap changers, to more optimally manage voltage levels along the electric distribution system. A lowering of system voltage along distribution feeder lines, while maintaining the voltage within the industry standard range of 114 to 126 volts for all customers, tends to lower the energy consumption by customers. This strategy was successfully tested on a single distribution feeder. Citywide AMI meters need to be installed to harness this benefit on all 68 distribution feeders in Palo Alto. An assessment for Palo Alto was undertaken with a grant from American Public Power Association (APPA). The assessment found an energy conservation potential of 0.5% to 1% across all distribution feeders that could lower overall energy supply cost by $0.4 to $0.8 million per year. Page 3 of 6 6. Evaluated ways to lower overall AMI system integration cost with the Customer Information and Billing systems (CIS). The 2012 cost-benefit assessment estimated the cost of the AMI meter data management (MDM) system and its integration with Palo Alto’s SAP CIS system at $5 million. In 2016 CPAU decided to explore migrating to a utility best-of-breed CIS system, and expects to decide on this system in 2018. In developing the system specification for the new CIS system, the need to integrate with MDM/AMI system was considered. This coordinated CIS/MDM system procurement and implementation plan is expected to result in more successful integration at lower cost. If found merited, the MDM/AMI system implementation is currently planned for the 2020-21 timeline, after the CIS system implementation currently planned for 2018-19. 7. Evaluated ways to integrate AMI into the distribution system outage management system (OMS) currently in place. The vendor of the OMS system, NISC, has a proven record of successfully integrating the ‘outage last gasp signal’ from many AMI meter systems into their OMS. This signal notifies the OMS system that an AMI meter has lost power, indicating that an outage may have occurred. An AMI/OMS system integration will enable speedier response by CPAU crews in the event of electrical outages. Such integration, after full AMI implementation, is now thought to be a valuable operational tool and relatively straightforward to implement. 8. Evaluating ways to optimally integrate Distributed Energy Resources (DERs) installed by customers and to leverage these system for the benefit of the entire Palo Alto Community. DERs such as solar photovoltaics (PV), electric vehicles (EVs), Energy Efficiency (EE), Demand Response (DR), Energy storage (ES), and heat pump based water and space heaters (HP units) are expected to proliferate in the coming decades. The ability to communicate and control these DER systems to optimally utilize them will become more important in the coming years. Examples include the ability to: 1) inject capacitive energy from PVs using smart inverters, 2) use storage systems at customer premises to provide service to lower the customer utility bill and create savings for the utility in the process, and 3) explore the capability for DERs to provide transmission-related services. These efforts to optimally utilize customer DER system will require customer AMI metering to measure/impute the output of these systems and compensate customers for the services provided when warranted. The City’s plan for integrating and optimizing DERs will be developed through the DER Plan development process commencing in August 2017 and will be a topic discussed as part of the Utilities Strategic Plan. In addition, a number of implementation and logistical lessons were learned through these pilot projects and assessments as outlined below: a) A few participants in the CustomerConnect pilot expressed concerns regarding the potential adverse impacts of Radiofrequency (RF) radiation from AMI meters. Staff provided scientific industry information to allay their concerns, but two customers chose to opt-out of the AMI pilot due to such concerns. At the time of full deployment, a communication plan to address customer’s concerns of having an AMI radio at their homes and a policy to exempt concerned customers from receiving AMI meters would have to be developed. b) The implementation of AMI will touch CPAU’s customer segments in different ways (e.g. CustomerConnect pilot for single family homes and DR program for large commercial customers).2 In addition, since the AMI pilot and DR program have a limited and self-selected 2 Single family homes account for 15,000 customers, while multi-family homes account for 10,000 customers in Palo Alto. CPAU has 4,500 commercial customers, out of a total of 29,000 customers, and this segment of customers consume 85% of Palo Alto community’s total electricity use and approximately 50% of natural gas and water consumption. Page 4 of 6 group of participants, additional issues and opportunities will be discovered as these programs are expanded. Further analysis will be undertaken to evaluate ways to harness value from AMI for additional customer segments.3 c) Adoption of aggressive greenhouse gas reduction goals by the community in 2016 will likely increase the rate of DER systems adoption, increasing the need of AMI system deployment to facilitate customer adoption of such systems. d) Staff spent more time than anticipated providing QA/QC related to smart meter data displayed in the customer portal. At the time of full deployment, vendor and Palo Alto staff responsibility for QA/QC will be more clarified, and additional performance benchmarks with non- performance penalties may be included. e) Meter installation for the CustomerConnect pilot for the 300 homes was undertaken by staff, and this was a good learning experience for CPAU. However, it is apparent that third party installers would be needed at the time of full deployment due to the large workload this would entail. f) Greater understanding of the cost and value drivers related to AMI deployment was achieved.4 g) A number of risks related to full deployment of AMI pilot systems and post-implementation operations were identified.5 After learning from lessons and experiences gained by implementing pilots and evaluations over the past 4-5 years, CPAU is now gearing up to re-evaluate the merits of full-scale smart grid investments. In May 2017, CPAU retained Utiliworks Corporation (UWC) as consultants to assist with the evaluation and develop an overarching technology roadmap and implementation plan. Over the next 9 to 12 months, UWC has been tasked to: 1. Assess the smart grid pilot projects, the evaluations undertaken, and the lessons learned 2. Evaluate the progress of other ongoing technology projects and planned new projects 3. Update the cost-benefit assessment for AMI based smart grid investments 4. Develop a utility technology roadmap and actionable implementation plans with associated organizational resourcing needs for the next 5-10 years Upon completion of this work (Phase I), a recommendation on whether to move forward with the AMI investment would be made to Council. If the recommendation is to move forward, the recommendation would be accompanied by a draft implementation plan that will include a customer communication plan, resource needs, and timelines. If the Council makes a decision to proceed with the investment, Phase II work will commence to develop AMI system specification, solicit vendor proposals, and develop 3 CPAU’s Customer Programs are designed to serve every segment of the customer base. For example, residential customer segments include, single and multi-family homes, extent of energy/water consumption, customer income levels, adoption of DER systems such as PV/EVs, etc. 4 The cost of installing a communication network for AMI meter communication is now projected to be lower by more than 50% from the initial estimates made by the cost-benefit assessment conducted in 2012. The energy conservation potential via implementing CVR scheme in the distribution system was assumed to be zero in the 2012 assessment, but it is now expected to be in the 0.5% to 1% range, increasing the value of AMI deployment. 5 These risks include the need for proper planning of resources to implement and operate an AMI based smart grid system including plans related to organizational change management and stakeholder communication, maintenance and cybersecurity issues related to the new technology, public perception, reliability of metering technology and communication network, vendor selection and technology obsolescence, etc. These factors will be closely analyzed with industry experts with operational experience to successfully manage these risks. Page 5 of 6 a detailed implementation plan. Tasks in the implementation phase (Phase III) will encompass vendor contract execution, detailed implementation plan (including alpha and beta phase of scaling up), project implementation, and testing/acceptance. Phase II and III collectively could span 3-5 years, but it will be prudent to complete phase III in the shortest possible time to begin gaining value associated with the investments. Due to the imminent work to replace the CPAU’s current Customer Information and Billing System (CIS), AMI Implementation (Phase III) work is not expected to commence until 2019-2020. Full implementation of AMI is currently projected for 2021-22 period. Upon full implementation, the work to fully operationalize the investment and to build upon this enabling technology to provide improved customer service will be an ongoing process. Customer Segment Considerations & Meter Roll-out Sequence when Implementing an AMI System The pilot programs listed above focused on single-family homeowners and a few large commercial customers. It is worth noting that the AMI system is anticipated to impact CPAU’s 15,000 single family homes, 10,000 multi-family homes, and 4,500 commercial customers in different ways, and there will be additional lessons learned during implementation beyond those learned during the pilot program. An AMI system will assist all customer segments with more accurate billing, more granular usage information, and enable water leakage detection. However, some customers may see higher or lower value from AMI. For example, master-metered multi-family customers may not be able to use AMI to understand their water usage because of the lack of individual metering, which AMI will not solve. AMI will enable new customer programs to encourage efficiency and conservation to be rolled out to all customers (e.g. smart thermostats, demand response, TOU rates), but some customers will be able to use these more effectively than others. For example, higher usage customers or EV customers will have a greater potential to conserve or to shift usage from one time period to another to lower utility bills under time-of-use (TOU) retail rates. Commercial customers with flexible air conditioning loads or automated lighting controls could participate in an expanded demand response program. From a CPAU engineering and operations perspective, having visibility into hourly electricity consumption and customer voltage profiles will assist in detecting or replacing highly loaded distribution transformers and implementing a CVR program as discussed earlier. By knowing hourly customer consumption in different water pressure zones and natural gas distribution areas, better natural gas and water distribution system modeling is possible. An AMI system will also enable automated reading of hard-to-access customer meters and reduce injuries to meter readers. The industry norm for deploying AMI is to first deploy a few meters in the lab for testing meters, communication, and integration with the CIS system (alpha-phase). Upon successful completion of the alpha-phase, a few hundred to a thousand meters would then be deployed to customers who value AMI capabilities highly and/or a geographic spread of customers (for example, customers on a single meter reading route) to further test the system (beta-phase). The mass installation of meters with third party installers will be triggered only upon successful completion of the beta-phase testing. A sequenced approach, while more costly, may provide some value by rolling out AMI earlier to customers who will get the most benefit from it, or to customers whose use of AMI will enable CPAU to derive the most educational value from the project. During full implementation, for example, CPAU may want to first change out meters from multi-family family dwellings or locations were meters are hard to access. However, this must be balanced against the cost impacts of a less efficient deployment. Typically AMI deployments are done according to meter-reading routes to minimize logistical complexity, impact to normal operations, and to reduce costs. Though full implementation could be limited to certain customer segments who garner the highest value, staff is unlikely to recommend this for Palo Alto due the relative economics and operational issues related to doing so. Of the total investment in the AMI system, approximately 50% would be fixed costs related to IT systems and integration costs, hence savings related to a partial deployment would be relatively small. Also savings related to discontinuing manual meter reading cannot be achieved unless all three meters are automated in a meter reading route. In addition, carrying a wider variety of customer meters in stock results in higher inventory carrying cost and introduces operational risks related to meter replacements. Programs such as CVR and distribution system modeling also cannot be undertaken without AMI meters in vast majority of customer premises. NEXT STEPS This is an update to the UAC on pilot programs and assessments performed to-date to gain experience with smart grid and advanced metering technologies and their applications in Palo Alto. Staff has begun working with UWC on updates to the smart grid cost-benefit assessment, the business case for implementing such system for different customer segments, and technology implementation strategies.6 Staff anticipates providing an update on UWC's evaluations and findings at the November/December UAC meeting, and will coordinate the evaluation with the Utilities Strategic Plan development process. RESOURCE IMPACT There are no new proposals presented as part of thi s item, and therefore no additional cost impacts. The ongoing cost for the existing pilot programs is roughly 0.3FTE of effort annually and $20,000 in annual costs. In addition, approximately 0.5 FTE of effort will be expended to support the UWC assessment through the end of the year. POLICY I MPLI CATIONS The UWC findings and recommendations, along with the Utility Strategic Plan findings may have impact on policies under which CPAU currently operates. All policy-level findings and recommendations will be brought to the UAC and Council for review and action. ENVIRONMENTAL REVIEW The Utilities Advisory Commission's discussion of the Smart grid pilot projects and evaluations does not meet the definition of a project under Public Resources Code 21065 and is therefore California Environmental Quality Act (CEQA) review is not required. PREPARED BY: REVIEWED BY: APPROVED BY: TAHA FATTAH, Business Analyst SHIVA SWAMINATHAN, Senior Resource Planner ERIC WONG, Project Analyst ffiJoNATHAN ABENDSCHEIN, Assistant Director, Resource Management -.Jj/J DEAN BATCHELOR, Chief Operating Officer ,-Ot DAVE YUAN, Strategic Business Manager L/~v EDSHIKADA Gene ral Manager of Utilities 6 If Council decides to proceed with AMI investments, detailed implementation planning wou ld include staff/contractor resource needs, budgets, logistics of software and hardware procurement/installation, integration with existing systems, testing and operationalizing new systems, etc. Page 6of6 6054005 Page 1 of 12 5 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: September 6, 2017 SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend Council Adopt a Hydroelectric Generation Variability Management Strategy ______________________________________________________________________________ REQUEST Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council adopt a hydroelectric (hydro) rate adjustment (HRA) mechanism to help manage the fiscal impacts of hydroelectric generation variability on the electric utility. EXECUTIVE SUMMARY In an effort to manage the financial impacts of the annual variability in production of the City’s hydroelectric resources, and to allow for the City to maintain a lower target level for its hydro rate stabilization reserve, staff evaluated a number of different hydro variability management strategies, including: holding financial reserves, physical hedges, weather insurance, and hydro rate adjustment mechanisms. This report focuses on staff’s recommended strategy: the hydro rate adjuster. Hydro rate adjustment mechanisms are common tools utilized by utilities with significant exposure to highly variable (year-to-year) hydroelectric resources. The objective of a hydro rate adjuster is to automatically adjust a utility’s rates slightly upward or downward on an annual basis in response to hydroelectric conditions, in order to maintain a reasonably stable level of financial reserves. In other words, the hydro rate adjuster is intended to pass through to customers some portion of the variation in the utility’s costs resulting from changing hydro conditions. This ensures that the utility’s costs are fully recouped annually from ratepayer revenue, without resorting to larger, more permanent rate changes. In Palo Alto’s case, staff devised a hydro rate adjuster that is intended to maintain hydro rate stabilization reserve levels within a range ($3 million to $35 million) at least 80% of the time, based on historical hydro generation conditions. This objective balances the goal of managing hydro variability using a combination of reserves and a rate adjuster while minimizing swings in customer rates. BACKGROUND The City of Palo Alto is fortunate to have access to a large amount of relatively low-cost, carbon- free hydroelectric generation to meet its electric supply needs. Whereas for the state as a whole hydroelectric generation supplies about 10% of the overall electric supply, the City meets about 50% of its electric supply needs with hydro generation in an average year. 6054005 Page 2 of 12 The drawback to maintaining such a heavy reliance on hydroelectric generation, of course, is that the output of these resources is highly sensitive to weather conditions. Although the City receives about 50% of its electric supplies from its hydroelectric resources in a “normal” weather year, that amount can fall to as low as 20% in extremely dry years—such as in 2014 and 2015, the worst years of the recent extended drought. And unlike many of the City’s supply contracts, where the cost of the resource is proportional to the amount of generation delivered, the City essentially pays a fixed amount every year for the output of its two hydroelectric resources (Western Base Resource and the Calaveras project) regardless of the amount of electricity they produce. Meanwhile, the City must also purchase additional supply resources (generic market power and, to comply with the Carbon Neutral Plan, renewable energy certificates, or RECs) to make up for the reduced hydroelectric output in these dry years. Compounding the problem, market power prices are often higher in dry years, when the City has to purchase more, because the entire state is experiencing reduced supply conditions. Figure 1, below, illustrates this relationship between the City’s annual market purchase costs and the amount of hydroelectric generation it receives. Market purchase costs depend on other factors as well—namely, market power prices and the amount of renewable energy generation the City receives—but there is clearly a very strong inverse relationship between hydro generation and market purchase costs. Figure 1: Annual Hydro Generation vs. Market Purchase Costs (2012-2017) To date, the City’s strategy for managing the year-to-year variability of its hydroelectric output has been to hold financial reserves to absorb the resulting swings in its supply costs—to self- insure, in effect. The Council established the Rate Stabilization Reserves (RSRs) in May 1993 (CMR:263:93) for the Water, Electric, Gas and Wastewater Collection Funds, primarily to ensure 6054005 Page 3 of 12 that funds are available to cover short-term situations when expenditures exceed revenues. However, until 2005 the City did not face much exposure to hydro variability, due to the nature of its Western Base Resource contract at that time. In 2005, when a new We stern Base Resource contract allowed the City to begin to experience the full effects of hydro variability, it adopted the current policy of maintaining reserves, combined with a “laddering” approach to making forward market purchases, to manage this variability. At that time, a variety of risk management strategies (including those discussed below) were evaluated, but it was determined that utilizing a physical laddering strategy combined with financial reserves did the best job of maintaining low and stable rates (with “stable rates” being defined as needing to change rates no more than once every two years). The purpose of this report is to discuss some possible alternative hydro variability management strategies. DISCUSSION Staff feels that the best approach to managing the effects of hydro generation variability and satisfying the CPAU Strategic Plan objective of ensuring that customers pay reasonable, and reasonably stable, rates is to implement a Hydro Rate Adjustment mechanism. Hydro Rate Adjustment Mechanisms Hydro rate adjusters (HRAs) are mechanisms that automatically pass through to a utility’s ratepayers increases or decreases in its supply costs caused by hydrological conditions. At a utility that self-insures but does not utilize an HRA, they might hold rates steady for several years during a moderate drought, gradually drawing down their reserves, before resorting to a large, permanent rate increase in order to replenish those reserves. In addition, the rate increase might go into effect after the end of the drought, thereby causing problems for the utility in explaining the cause of the rate increase to its customers. On the other hand, at a utility that utilizes an HRA, they would be able to pass any additional drought-related costs to their customers through a small, ongoing rate increase—which would also be quickly removed at the end of the drought. In this way the utility would likely be able to manage its supply cost fluctuations with a smaller overall level of financial reserves. HRAs are used by a number of other California municipal utilities, including the Sacramento Municipal Utility District (SMUD) and the City of Roseville. Other utilities use similar types of rate adjustment mechanisms to adjust their customer rates based on other supply cost factors, such as the cost of fuel for electrical generation (particularly coal and natural gas), the cost of transporting that fuel, and transmission costs. In fact, in Palo Alto the gas utility’s customer rates include a volumetric “commodity charge” component that passes through to customers on a monthly basis cost changes related to the market price of natural gas. Similarly, in 2015 the water utility instituted a temporary “drought surcharge” on its customers’ bills. HRA Mechanism Details The proposed HRA mechanism maintains hydro rate stabilization reserve levels within a certain minimum-to-maximum range ($3 million to $35 million) at least 80% of the time. Under the proposed hydro variability management strategy, the utility will rely on reserves first to manage hydro variability, but when reserves are low, a rate adder will be activated when hydro 6054005 Page 4 of 12 production is also low to avoid exhausting reserves and to pass on a price signal to customers when low hydro production results in more expensive power. When reserves are high, on the other hand, a rebate will be given to customers when hydro production is high to avoid accumulating excessive reserves and to pass on the benefit of high hydro production to customers. As designed, the Hydro Rate Adjuster level would be determined in late April or early May each year (at the tail end of the rainy season) and applied to customers’ electric rates for the duration of the following fiscal year (July 1 through June 30). In the fall, when staff begins the budget process for the following fiscal year, staff’s budget submittals will incorporate its best estimates of hydro generation and supply costs. However, at this point, near the beginning of the rainy season, very little is known about what hydrological conditions will look like in the spring or summer. By the time budget hearings are held with the UAC and Finance Committee, staff will have a better view of the upcoming fiscal year’s hydro outlook, and will be able to provide a tentative assessment of whether the HRA mechanism will be applied or not. And finally, in April, once hydro conditions are fairly certain, if the HRA mechanism is to be activated for the next fiscal year, staff will agendize a consent action for Council at the same meeting that the budget is considered for adoption. If approved, the HRA would appear as an independent, transparent line item on customers’ bills for the following fiscal year. The determination of whether or not to apply the HRA, and at what level, would be based on the projected amount of hydroelectric generation for the upcoming fiscal year relative to the amount expected in a “normal” year, and the expected level of the Hydro Stabilization Reserve at the start of the upcoming fiscal year. For years in which reserve levels are relatively high and hydro generation levels are expected to be moderate or greater, customers would receive a slight discount to their regular electric rates; conversely, in years where reserve levels are relatively low and hydro generation levels are expected to be less than average, there will be a slight surcharge applied to customers’ regular electric rates. A graphical depiction of how the Hydro Rate Adjuster mechanism is applied based on varying levels of rate stabilization reserves and hydro conditions is displayed in the following chart: 6054005 Page 5 of 12 Figure 2: Graphical Depiction of Hydro Rate Adjuster Logic Simulated Impact of HRA on Reserves and Rates Using historical hydroelectric generation data, staff developed a model to simulate the effects of the HRA mechanism on Hydro Stabilization Reserve levels and customer rates. The figures below represent one particular 20-year simulation period, with a starting reserve level of $17 million. The upper pair of graphs illustrates the changes in reserve levels and system average rates with the HRA mechanism in effect, whereas the lower graph illustrates the changes in reserve levels for the same 20-year period, with the same hydro generation levels, but without the HRA mechanism being employed. +1 Std. Dev. Total Hydro Generation +1.30 +0.65 Min ($3M)+1.30 +0.65 -1 Std. Dev. Hydro Rate Adjuster Level (in cents/kWh) Hy d r o S t a b i l i z a t i o n R e s e r v e L e v e l ( $ M ) -0.65 -0.65 -1.80Max ($35M) -0.65 -1.30 75% ($27M) 25% ($11M) Normal Year Generation 6054005 Page 6 of 12 Figure 3: 20-Year Simulation of Hydro Rate Adjuster (Wet Scenario) Under this simulation run, hydro generation levels are significantly above average for several years during the 20-year period. As a result, the HRA mechanism calls for rebates to be applied during nine of the years in this period; however, these rebates are highly effective in maintaining reserve levels below the maximum level ($35 million). On the other hand, in the absence of the HRA mechanism, reserve levels quickly build up, reaching approximately $105 million by year 20. In reality, under these circumstances the utility would likely implement a significant “permanent” rate reduction around year 10 through the annual Council rate adoption process – a reduction that would likely have to be reversed at a later date (when hydro generation reverts to normal or below normal levels) through a similar process. On the other hand, during a period of extended drought, the HRA mechanism can help maintain adequate reserve levels which otherwise would fall well below the minimum target reserve level ($3 million). The figures below illustrate such a scenario occurring in another 20-year simulation run. Despite four consecutive years of severely below normal hydro output, the HRA mechanism is able to maintain reserve levels within the min-max band. Absent the HRA mechanism, reserve levels would fall to below -$20 million for an extended period. In this situation again, a Council-adopted “permanent” rate increase would have to be applied and then eventually rescinded once hydro conditions returned to normal. 6054005 Page 7 of 12 Figure 4: 20-Year Simulation of Hydro Rate Adjuster (Dry Scenario) Revenue Impact of HRA Mechanism As discussed in the City’s 2016 electric cost-of-service analysis (COSA), the cost of market energy (the purchase of which the HRA adder is designed to collect for) is allocated entirely based on the kWh consumption of each customer class. A volumetric (per-kWh) adder is therefore a reasonable and appropriate way to collect for the costs associated with below normal hydro output. Based on the utility’s current annual retail sales, a rate adjustment of +/- 0.65 ¢/kWh translates to a revenue adjustment of +/- $6.15 million. Similarly, a rate adjustment of +/- 1.3 ¢/kWh translates to a revenue adjustment of +/- $12.3 million and a rate adjustment of + 1.8 ¢/kWh translates to a revenue adjustment of + $17.0 million. Based on historical hydroelectric generation and market price data for northern California, staff estimates that relative to a normal hydro year, a typical dry or wet hydro year would result in a supply cost impact to the utility of about +/- $8.8 million. 6054005 Page 8 of 12 In addition to this recommended approach, staff also evaluated the following alternatives: holding financial reserves (the current approach), physical hedges, and weather insurance and derivative products. Financial Reserves Each year, beginning in late fall, staff develops an electric supply budget for the prompt fiscal year, based on the most current precipitation data and reservoir storage conditions. In general though, the precipitation season is not done until the end of April each year; however, at this point it is too late to adjust supply cost projections for the prompt budget cycle, as Council aims to adopt the budget by May. This creates a cash flow uncertainty issue (budgeted supply costs versus actual supply costs), which forces the City to either budget for dry year conditions (i.e., maintain artificially high rates), maintain high reserve levels, or regularly implement mid-year rate changes. Palo Alto has chosen to address this uncertainty through maintaining high reserve levels. (Although it should be noted that the recent drought has been so severe that the Hydroelectric Stabilization Reserve and Rate Stabilization Reserves have dwindled to unprecedented low levels, even as large rate increases are being implemented.) This strategy is not without its own costs, however. The carrying cost of holding large financial reserves can, depending on interest rates, be quite significant itself. Passing through supply costs changes to customers can permit the City to reduce its targeted reserve levels permanently, thus saving ratepayers money. The proposed HRA Mechanism operates in a similar manner to the City’s current budget review and rate-setting process, except that under the HRA Mechanism the rate change decision is made in May, using end-of-water-year hydro forecasts and reserve level estimates, rather at the beginning of the water year. By utilizing a clear formula and the most up-to-date information available, the HRA Mechanism is both more transparent and more accurate than the current rate-setting approach. From a financial and environmental sustainability perspective too, it can be valuable to have some variability in customer rates, in that it sends an appropriate price signal to customers – i.e., that they should use less electricity during periods of drought. Physical Hedges A physical hedging strategy – that is, one based on the trading of actual electrical generation – can take a variety of forms: seasonal exchanges, laying off a resource, or simple forward trades. The latter approach is already being implemented by CPAU: staff executes physical purchases and/or sales of electricity to try to balance forecasted supplies with load in advance of a given delivery month. This strategy would continue to be implemented even with the adoption of the proposed HRA Mechanism. The more complex physical hedging strategies essentially amount to transferring the output of the City’s hydro resources – along with the variability risk associated with that generation – to another party. This approach presents several challenges. A seasonal exchange (e.g., the City sending some of its surplus hydro generation to another party during the summer months, while receiving generation from that party in the winter months) would help the City to balance its supply portfolio with its load and would help it reduce the variability risk associated with its supply for the summer months; however, it would likely just shift this variability risk over to the 6054005 Page 9 of 12 winter months. In addition, given the nature of hydro generation, there would likely be very few counterparties with an appetite for this type of transaction – i.e., having surplus generation in the winter months and a deficit in the summer months.1 A long-term layoff of one of the City’s hydroelectric resources would certainly help to alleviate hydro variability risk. However, doing so would also cause the City to lose out on the many products and services that these resources provide—for example, resource adequacy capacity, ancillary services, and load following capability. In addition, over the long-term, the City’s hydroelectric resources have proven to be a low-cost source of large volumes of carbon neutral electricity. The City may ultimately find that laying off some or all of its hydroelectric generating capacity would be to its benefit. However, this decision should be made as part of a comprehensive and in-depth analysis of the City’s supply portfolio along with the alternative supply resources available to it. Weather Insurance Just like insurance that protects people against earthquakes, floods, fires, and automobile collisions, insurance sellers also offer insurance and derivative products to protect buyers against weather-related risk. These policies are highly customizable, and can be tailored to protect against a wide range of different conditions, such as temperature, precipitation, sun, or wind. Farmers, ski resorts, outdoor festivals, and golf courses are often buyers of such weather protection contracts. For an electric utility like the City with a large concentration of hydroelectric resources, a weather insurance contract would typically be structured to pay out based on the total precipitation measured at one or more weather stations over the course of a year. Although total precipitation is not a perfect proxy for hydroelectric output (particularly for a complex system like the Central Valley Project, which provides the City’s Western Base Resource output, and which also serves a number of other purposes, such as irrigation and recreation), there is typically a strong correlation between the two. Another challenge in structuring a weather insurance contract is in selecting a weather station or group of weather stations that most accurately reflect the hydrological conditions of the watershed(s) that feed into the utility’s hydroelectric generators. Palo Alto’s hydroelectric resources are spread across central and northern California, so a single weather station would likely do a poor job of representing hydrological conditions at all of these facilities, so an index comprising numerous weather stations would likely need to be created. The trade-off is that the more complex a weather station index becomes, the higher the annual premium (cost) the resulting weather protection contract will likely carry. There are many different ways to structure a precipitation-based weather insurance contract. The primary factors that must be considered are: (a) the precipitation level at which the 1 From 1993 to 2008, the City participated (along with other NCPA members) in a seasonal exchange with Seattle City Light (SCL). In this transaction, SCL delivered approximately 10 MW of power around-the-clock to Palo Alto in the summer (June through mid-October), while Palo Alto delivered 10 MW of power to SCL in the winter (mid- November through April). Thus the transaction was designed not so much to balance the City’s supply portfolio with its load, but to take advantage of a summer-versus-winter price arbitrage opportunity. Ultimately the City found the exchange to be of negative value, and laid off its share of it to another NCPA member in 2008. 6054005 Page 10 of 12 contract begins paying out, (b) the maximum payout, and (c) the incremental payout levels. The values chosen for these key factors will determine the annual premium of the contract. However, it is also possible to structure a contract such that the annual premium is reduced or even eliminated. This can be done by requiring that, in addition to the utility receiving a payment from the insurer when certain dry conditions exist, the utility pays the insurer in wetter years. (This type of structure is referred to as a “costless collar.”) Staff is aware of at least one public utility in California (SMUD) that procures weather insurance as part of a comprehensive hydro variability management strategy that also involves financial reserves, physical hedging, and a hydro rate adjuster. Starting around 2001, SMUD – which in a normal year receives about 15-20% of its electricity supply from hydro resources – began procuring costless collar insurance coverage to ensure rate stability. However, they soon found that this type of insurance contract limited their upside (wet year) benefits too severely. So they stopped doing costless collar contracts and focused more on self-insurance (by increasing their financial reserves and adopting a hydro rate adjuster). For the past several years, SMUD has procured multi-year simple (one-sided) insurance contracts to protect against extreme dry conditions – when precipitation levels are less than half of what they area in an average year. In SMUD’s experience, these extreme “tail” insurance contracts have never paid out to them. However, SMUD has also procured a smaller amount of insurance coverage to protect against moderately dry years (when precipitation levels are between 50 and 70% of average), and these contracts have in fact paid out to them in a couple of years. The main benefit of using weather insurance is that, if the insurance contract is designed well, it is very effective at mitigating the adverse financial impacts (and, if desired, the favorable financial impacts as well) of hydro generation variability. In addition, the triggering event in a weather insurance contract (precipitation levels at a weather station, in this example) is a very objective and transparent measure. The downside of weather insurance, of course, is its cost. Although an insurance policy will mitigate the adverse risk associated with hydro variability, it will also cost a considerable amount every single year (for a one-sided contract , where the utility never pays the insurer) or it will mitigate the favorable risk as well (for a two-sided, or costless collar, contract). Staff has evaluated weather insurance options numerous times in the past and always found them to be prohibitively expensive relative to the self-insurance (financial reserves) option; this time is no different. The table below provides indicative pricing for a variety of different types of insurance contracts. In each case, either the annual premium is very high or the likelihood of a payout to the City is very remote. 6054005 Page 11 of 12 Table 1: Indicative Pricing for Select Weather Insurance Contracts Structure Put Put Put Put Put Put Costless Collar Term (yrs) 1 5 1 5 1 5 1 Inception 1/1/18 1/1/18 1/1/18 1/1/18 1/1/18 1/1/18 1/1/18 Expiry 12/31/18 12/31/22 12/31/18 12/31/22 12/31/18 12/31/22 12/31/18 Put Strike (in.) 10 10 25 25 37 37 25 Call Strike (in.) -- -- -- -- -- -- 63 Tick ($/in.) 2,000,000 2,000,000 400,000 400,000 400,000 400,000 400,000 Annual Limit ($) 8,000,000 8,000,000 6,000,000 6,000,000 6,000,000 6,000,000 6,000,000 5yr Limit ($) -- 24,000,000 -- 15,000,000 -- 15,000,000 -- Annual Premium ($) 475,000 355,000 709,100 555,700 1,153,700 967,600 0 In Table 1 above, a “Put” structure is a simple one-sided insurance contract (protecting the City against downside risk), the “Put Strike” is the annual precipitation level below which the City would start receiving payment, the “Call Strike” is the annual precipitation level above which the City would have to pay the insurance seller (for the “Costless Collar” contract structure), the “Tick” is the dollar amount that the City would receive (or pay) for every inch the precipitation level falls below the Put Strike (or exceeds the Call Strike). The indicative pricing above was quoted by a well-known weather insurance seller for an index of northern and central California weather stations that represent the City’s hydro generation resources and watersheds quite well. For this index of weather stations, the long-term average annual precipitation level (since 1950) is 53.1 inches. Figure 5 below shows the long-term history of annual precipitation for this group of weather stations, along with lines denoting the various put/call strike levels listed in Table 1 above. The first two contracts listed in Table 1 are reasonably priced (premiums of about $400,000 per year), but they only protect the City against precipitation levels below 10 inches – an extreme drought condition that, as Figure 5 indicates, has not been experienced in the last 67 years. The next two contract structures, with a 25 inch strike, are a bit more expensive ($500,000-$700,000 per year) and would only have paid out to the City in two of the last 67 years (2013 and 1976). The next two contract structures, with a 37 inch strike, provide a moderate level of protection to the City – they would have paid out three times in the last ten years (2015, 2013, 2007) – but they cost approximately $1 million per year. And finally, the last column of Table 1 shows the terms of a costless collar (two-sided) contract structure. In exchange for protection against sub- 25 inch precipitation conditions (which, again, have occurred only twice in the last 67 years), the City would have to pay the insurance seller in any year in which precipitation levels exceed 63 inches. As shown in Figure 5 below, wet conditions like this have occurred in eight of the last 25 years and in 15 of the last 67 years. Thus this “free” option would provide little protection to the City and would actually come at a fairly high cost. Figure 5: Historical Index Precipitation levels and Selected Put/Call Strikes Historical Index Values 115 105 95 85 75 45 35 ©weather}( change 2s------------------------..-iJP-------------------------------------M--- 15 5 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ Years NEXT STEPS After receiving the UAC's recommendation, staff will take the HRA mechanism discussion to the Finance Committee, followed by consideration by the City Council. If adopted by the City Council, the HRA mechanism would go into effect on July 1, 2018. RESOURCE IMPACT The Hydro Rate Adjustment mechanism is designed to modify customer rates, either up or down, such that overall sales revenue is aligned with supply costs for the electric utility. POLICY IMPLICATIONS The adoption of a Hydro Rate Adjustment mechanism supports the Utilities Strategic Plan objective that customers should expect to pay reasonable, and reasonably stable, bills. ENVIRONMENTAL REVIEW Adoption of a Hydro Rate Adjustment mechanism does not meet the definition of a project, under Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(S), because it is an administrative governmental activity which will not cause a direct or indirect physical change in the environment, thus no environmental review is required. PREPARED BY: JIM STACK, Senior Resource Planner REVIEWED BY: }'t JONATHAN ABENDSCHEIN, Assistant Director, Resource Management c~ APPROVED BY: ED SHIKADA, General Manager of Utilities 6054005 Page 12of12