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HomeMy WebLinkAbout2017-12-06 Utilities Advisory Commission Agenda PacketNOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956 I. ROLL CALL II.ORAL COMMUNICATIONS Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable time restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from discussing or acting upon any topic initially presented during oral communication. III.APPROVAL OF THE MINUTES Approval of the Minutes of the Utilities Advisory Commission Meeting held on November 1, 2017 IV.AGENDA REVIEW AND REVISIONS V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS VI.GENERAL MANAGER OF UTILITIES REPORT VII.COMMISSIONER COMMENTS VIII.UNFINISHED BUSINESS - None IX.NEW BUSINESS 1.Discussion of the Joint Council and UAC Study Session Discussion 2.Staff Recommendation that the Utilities Advisory Commission Recommend Council Action Adopt a Resolution Amending Utilities Rules and Regulation 11 “Billing, Adjustments and Payment of Bills” to Update the City’s Billing Adjustment Process 3.2018 Utilities Strategic Plan Discussion 4.Discussion of Sustainability and Climate Action Implementation Plan Discussion 5.Staff Recommendation that the Utilities Advisory Commission Recommend Council Action Adopt a Hydroelectric Generation Variability Management Strategy 6.Renewable and Carbon Neutral Portfolio Strategy Discussion Discussion 7.Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action NEXT SCHEDULED MEETING: January 2018 – Date (To Be Determined) ADDITIONAL INFORMATION - The materials below are provided for informational purposes, not for action or discussion during UAC Meetings (Govt. Code Section 54954.2(a)(2)). 12-Month Rolling Calendar Public Letter(s) to the UAC UTILITIES ADVISORY COMMISSION WEDNESDAY, DECEMBER 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 11 UTILITIES ADVISORY COMMISSION MEETING MINUTES OF NOVEMBER 1, 2017 MEETING CALL TO ORDER Chair Danaher called the meeting of the Utilities Advisory Commission (UAC) to order at 7:02 p.m. Present: Chair Danaher, Commissioners Forssell, Schwartz, Segal, Johnston, Trumbull (arrived at 7:12 p.m.) Absent: Vice Chair Ballantine ORAL COMMUNICATIONS Robert Hinden, Murray Way, inquired about the status of implementation of smart meters. The smart meter pilot project has closed. He added solar panels to his home and is getting an electric car, so he wanted to get an idea of his electric generation and consumption. Chair Danaher reported smart meters are in the plans for the City. The City has to implement software updates prior to beginning installation of automated meter infrastructure in two years. Ed Shikada, Utilities General Manager, suggested Mr. Hinden speak with Shiva Swaminathan, the Senior Resource Planner in charge of the project, who was in the audience. APPROVAL OF THE MINUTES Commissioner Johnston moved to approve the minutes from the September 6, 2017 meeting and October 4, 2017 special meeting. Commissioner Forssell seconded the motion. The motion carried 5-0 with Chair Danaher and Commissioners Forssell, Schwartz, Segal, and Johnston voting yes, Vice Chair Ballantine and Commissioner Trumbull absent. AGENDA REVIEW AND REVISIONS The agenda was reordered to the following sequence: agenda items 1, 5, 4, 3, 2. REPORTS FROM COMMISSION MEETINGS/EVENTS Commissioner Schwartz attended the California Independent System Operator (CAISO) stakeholder symposium and spoke on a panel for community solar. The symposium was followed immediately by the Germany-California bilateral conference. In both events, decarbonization was an important topic for the attendees. California cannot decarbonize the energy supply on its own, and Palo Alto has an even smaller role in the scheme of decarbonization. Goals set by the Legislature, the CPUC, and CAISO are so aggressive that it is already a stretch to meet statewide operational goals. Therefore, it makes no sense for Palo Alto to set aspirational goals more aggressive than existing statewide goals. Electric vehicles are the important factor to focus on. Residential heating and cooking is such a small part of the equation that Palo Alto should not focus on encouraging heat pumps. Germany has experienced problems with reliance on coal after eliminating nuclear energy. She encouraged staff to follow up with LADWP and with geothermal providers. If the Commission wishes to animate markets and help renewable generation, it should support DRAFT Utilities Advisory Commission Minutes Approved on: Page 2 of 11 resources like geothermal, which in the long term will be more valuable than relying on Renewable Energy Certificates (REC) to achieve carbon neutrality. She spoke about Community Choice Aggregators (CCA) and their impact on the electric system as a whole. After attending these events, she felt the Commission should think about the big picture in advising the City Council. [Commissioner Trumbull joined the meeting.] UTILITIES GENERAL MANAGER REPORT Ed Shikada, Utilities General Manager, delivered the General Manager’s Report. Community Workshop for the Utilities Strategic Plan - I'd like to thank all of the Utilities Advisory Commissioners for joining us at our October 4 community workshop for the Utilities Strategic Plan update. The meeting created a unique opportunity to share our Department's progress-to-date and gather feedback from the public. We got some great input! Our leadership team has made significant headway on drafting the key priorities, strategies and actions that will guide our strategic efforts over the next 3 to 5 years. If you have additional feedback to share, please do not hesitate to reach out to me or email our team at UtilitiesStrategicPlan@cityofpaloalto.org Registration Period Extended for Bay Area SunShares – Registration for the Bay Area SunShares program has been extended to November 30. Staff is engaging in a final outreach push to inform the community about this limited time offer to sign contracts for discounts on solar PV installations and zero -emissions vehicles. Palo Alto is currently ranked second among Bay Area cities for total number of registrations, following closely behind Berkeley. Please help us spread the word about this offer. People can easily register at cityofpaloalto.org/sunshares. It's Easy & Economical to Drive Electric in Palo Alto - Driving and charging an electric vehicle in Palo Alto especially makes sense due to the City's carbon-neutral electric utility and low electric retail rates. The City is one of the top cities in the nation to embrace this clean technology. The International Council on Clean Transportation (ICCT) recently released a report revealing that in 2016 more than 22% of all new vehicles purchased in Palo Alto were electric, which is the highest percentage of any California community! The City tries to make it easy and economical to drive electric by sharing information about financial incentives and FAQs through workshops, bill inserts, advertisements, and the City website at cityofpaloalto.org/electricvehicle Public Power & Public Natural Gas Week – During October 1-7, the City celebrated both Public Power and Public Natural Gas Week. These annual campaigns recognize the value of local, not-for-profit power and gas utilities. This year marks 120 years of CPAU delivering electricity and is the 100th anniversary of our natural gas utility. With a municipally-owned utility, Palo Alto residents and businesses are direct stakeholders in energy resources and infrastructure. This means that the utility’s operations and funds are tailored to meet the specific needs of our customers. From low rates and reliable service, to renewable resources and programs that invest in our community, CPAU has a long track record of empowering Palo Alto. Thank YOU for being part owner of our municipal utility! Upcoming Events  Saturday, November 4 – Workshop on Designing Native Gardens & Rainwater Harvesting. Details and registration are available at cityofpaloalto.org/workshops. COMMISSIONER COMMENTS None. UNFINISHED BUSINESS None. Utilities Advisory Commission Minutes Approved on: Page 3 of 11 NEW BUSINESS ITEM 1: DISCUSSION: 2017 Utilities Planning Update Ed Shikada, Utilities General Manager, reported that staff continues to develop the final Strategic Plan draft for the December 6 UAC meeting. He thanked Commissioners for their participation in the October community workshop. ACTION: No action. ITEM 5. DISCUSSION: Discussion of Proposed Distributed Energy Resources Plan Shiva Swaminathan, Senior Resource Planner, presented the staff report regarding distributed energy resources (DERs). DERs have the potential to impact timing, location, and size of the electric load in the distribution system. DERs are important because approximately 2,500 electric vehicles are registered in Palo Alto and about the same number are commuting into Palo Alto daily. Currently, approximately 0.5% of the City's energy load serves electric vehicles. DERs are a central part of the State's objective to reduce carbon emissions and increase resiliency. Ongoing programs and initiatives include the Local Solar Plan, the Electrification Work Plan, the Energy Storage Assessment, and Energy Efficiency Goals. Future programs include an Electric Integrated Resource Plan, a Distribution System Assessment, and AMI/Smartgrid implementation. In response to Mr. Hinden's question during Public Comment, Mr. Swaminathan advised that Advanced Metering Infrastructure (AMI) implementation is expected to be completed in 2022 and will be available to customers within a year of AMI implementation. Commissioner Schwartz encouraged staff to include highly interested residents in the pilot program. Swaminathan continued with the impact of DERs on electricity sales. With electric vehicles only, loads would increase approximately 5% by 2030. Factoring in energy efficiency savings and photovoltaic (PV) penetration, the total load due to DER would be approximately 6.6% lower than it would be without DERs. Staff anticipates the overall load will decrease approximately 1% between 2017 and 2030, with DER offsetting load growth. Most of the 5% energy load for electric vehicles will come from the residential sector. Projections indicate approximately 40% of homes will have EVs by 2030, which will result in faster growth of residential energy consumption. He presented peak summer load scenario of year 2030. Electric vehicles increase sales while energy efficiency and PV reduce sales. Staff is looking for opportunities to aggregate DERs and harness greater value. In response to Commissioner Forssell's question about commercial demand response increasing net revenues, Swaminathan explained that the utility pays a high capacity fee, which is offset through demand response, and some of that savings is passed on to the demand response participant as an incentive. To the extent the savings is higher than the amount paid to commercial customers, it's an addition to net revenue. In reply to Commissioner Schwartz's query about the impact on carbon emissions, Swaminathan indicated analysis of carbon impacts of DERs is included in the work plan. Staff will experiment with dispatching DERs into the California Independent System Operator (ISO). Swaminathan reviewed the goal, five objectives, and strategies of the DER Plan. DERs could lower reliance on the transmission grid. In the future with greater PV usage and lower storage costs, staff could consider feeder level resiliency measures like microgrids. Commissioner Schwartz shared the importance of proper pricing to ensure customers who have installed solar and may have reduced the energy they take from the grid pay their fair share of the cost of assets because at some point they will use electricity from the utility when their solar system is not operating. Utilities Advisory Commission Minutes Approved on: Page 4 of 11 Swaminathan reported seven to eight staff members are analyzing DERs related to energy efficiency, electric vehicles, electrification, and demand response. Phase I of DER penetration relates to DER adoption and pilot programs. Phase II will be integration and dispatching into the ISO, but this requires AMI. Next steps are to engage the community regarding programs. Staff plans to return to the Commission and Council in the spring for approval of the DER Plan. The DER Plan will become part of the Integrated Resource Plan, which has to be submitted to the State by the end of 2018. Staff requests Commission feedback regarding the proposed DER Plan and community engagement. Commissioner Schwartz felt the Strategic Plan community workshop could have been designed to reach more members of the community. It is important to increase community participation and understanding so that the general community can provide input. She expressed disappointment that Commissioners did not receive a workshop description that they could share with their community contacts. Shikada indicated staff provided multiple notifications of the workshop and conducted quite a bit of outreach, even though specific details of the workshop content were not provided. Commissioner Schwartz stated the information was inadequate. People need more information than was provided in order to generate interest and discussion among their cohorts. Shikada clarified that the intent of outreach is not to market programs. It is an opportunity for the community to share their thoughts with staff. Chair Danaher suggested Commissioner Schwartz share outreach techniques with staff at a later time. Commissioner Schwartz said she would be open to meeting with staff to share resources. Shikada indicated the next phase provides an opportunity for staff to obtain a more random and representative indication of consumer interest. Commissioner Johnston had three unrelated questions. These questions and Swaminathan’s response were as follows. 1) As presented in the report, how do four staff members devoted to energy efficiency program spend their time? About 30% of their time is spent promoting energy efficiency programs to residential customers by providing information and rebate services, bulk-buy programs such as the current Sunshares program for PV and EV purchases. On the commercial side, staff manages contractors who work with businesses to implement efficiency programs. Contractor effort costs $3-4 million, and is not accounted for within the four person staff level estimates. 2) With increased EV charging do you expect transmission level constraint? Currently there are no major constraints on transmission should residents choose to charge their EVs simultaneously. However, there may be constraints on distribution if residents choose to charge their EVs during the evening residential peak time. On the commercial side, there are many factors to consider, but there are unlikely to be constraints. 3) Do you plan to do Vehicle to Grid program for EVs? No, there are no plans to do V2G services in the next 5 years as part of the DER plan. Commissioner Segal suggested staff draft metrics to quantify the success of DER strategies. In response to Commissioner Segal's inquiry about what types of services could be provided to customers in the next 5 years, until AMI meters arrive, Swaminathan reported smart thermostats and electric vehicles can provide data without the use of smart meters. A pilot program for either of those would require a great deal of vendor and customer contact. Depending on the amount of customer engagement, staff could focus on programs for EVs and smart thermostats in next 5 years. Commissioner Schwartz explained that smart meters are necessary for sending price signals for time-of-use charging. Commissioner Segal clarified that she meant general information for the community such as the best time to charge your EV. Staff acknowledged more could be done in to inform customers. In reply to Commissioner Forssell's query if the City could use a social cost of carbon in evaluating different customer program, Jonathan Abendschein, Assistant Director of Utilities Resource Management, indicated the social cost of carbon is both a utility topic and a Citywide topic in relation to the Sustainability and Climate Action Plan, and that internal discussions are underway on the merits of adopting such a social cost of carbon. Commissioner Forssell added that a considerably higher social cost of carbon will affect the cost effectiveness of strategies. Utilities Advisory Commission Minutes Approved on: Page 5 of 11 Commissioner Forssell was not convinced the utility should pursue PACE on-bill financing as it is susceptible to predatory lending practices. Swaminathan explained on-bill financing as the City placing a separate charge on utility bills. Council Member Schwartz added that a utility lender is unlikely to utilize predatory lending practices. Council Member Filseth remarked that commuters will charge their EVs at night when they are at home. Commuters are not going to respond to time-of-day incentives for charging; however, residents working in the City may be very susceptible to time-of-day incentives. He suggested staff, when developing projections, consider the proportion of people living and working in Palo Alto versus people living in Palo Alto and commuting elsewhere. In answer to Council Member Filseth's query about how realistic is the solar PV forecast which projects a tripling of solar PV installation, Swaminathan advised that the forecast for a large expansion in solar PV is a best estimate. As the cost of PV declines and the utility retail rates increase, the economics will continue to become more favorable for PV. Council Member Filseth noted the overwhelming majority of program expense is in the implementation of AMI. He hoped communications will be concise about the return on investment for the community. Dean Batchelor, Chief Operating Officer, advised that staff will have a better projection of the number of residents owning Electric Vehicles after public outreach. Staff needs to discuss the best time to conduct public outreach. Chair Danaher requested staff return to the UAC with a rank order of the types of programs and the cost effectiveness of carbon reduction and other measures. The DER program should include frequent evaluation of cost effectiveness. Abendschein reported staff has performed those analyses. Staff is working on a good way to present the analyses to the UAC in a form similar to other analyses. Chair Danaher requested review of analyses prior to a joint meeting with the City Council. Chair Danaher suggested staff place more emphasis on anticipating technologies. For example, EV chargers installed in the next few years may have components compatible with vehicle to grid, which is at least five years in the future. New homes can be wired for EV chargers or other things to enable DERs over time. The UAC should review EV charging speed in relation to subsidizing or incenting installation of chargers. With respect to enabling customers to capture additional value by serving CAISO market needs, the UAC should also think about the utility capturing additional value by serving CAISO market needs. If the projection of 19,000 EVs in Palo Alto by 2030 is correct, then EVs deserve a separate section in the DER Plan. Councilmember Filseth calculated 10,000 EVs charging simultaneously at 10 kilowatts an hour as requiring 100 megawatts, which is a sizable load. Swaminathan stated staff is projecting 40 megawatts. Commissioner Forssell hoped the DER strategy includes encouragement of workplace charging and an incentive for employers to install chargers. Staff is facilitating the installation of charging stations but not providing any rebates at this time. Commissioner Schwartz suggested staff design a program to incentivize EV charging after peak residential usage, i.e., between 10:00 p.m. and morning. Swaminathan indicated the time-of-use rate encourages charging after 10:00 p.m. Commissioner Schwartz remarked that the utility has opportunities to meet the needs of citizens and to develop groundbreaking concepts. ACTION: No action. Utilities Advisory Commission Minutes Approved on: Page 6 of 11 ITEM 4. DISCUSSION: Smart Grid Assessment and Developing Utility Tech Roadmap Update Shiva Swaminathan, Senior Resource Planner, presented the City’s Smart Grid Assessment and Utility Technology Roadmap. The City is developing a customer portal and app, which will be able to display AMI data. The portal should be available in the summer of 2018. Staff has received six responses to a Request for Proposals to upgrade the customer information system (CIS). The upgrade will be available by 2020 with enterprise resource planning (ERP) software implemented thereafter. Through advanced metering infrastructure (AMI), electric meters will be replaced, but devices will be attached to water and gas meters to transmit data to the meter data management system (MDMS), which feeds data to CIS. The customer portal will obtain data directly from MDMS. Capital expenditures are estimated at $16.5 million, which includes electric meters, devices for water and gas meters, network integration, MDMS, and implementation. The electric portion of capital expenditures is approximately half of the total expenditure. Operational benefits are projected at approximately $3.3 million and incremental costs up to $0.3 million for an ongoing operational savings of approximately $1 million. The net present value (NPV) calculated over 18 years results in a loss of approximately $7.3 million. The NPV is a conservative number that does not include benefits that are difficult to quantify. Expenditures include additional staff to manage the system, hardware, and software. Benefits include elimination of the meter reader positions, reduced calls for customer service, and conservation savings. In reply to Chair Danaher's question if the operating costs were escalating over time, Swaminathan advised that ongoing cost savings include 3% inflation of costs and 1% annual increase in value. The consultant's prior experience with smart meter evaluation and implementation was considered in projections. In response to Commissioner Schwartz's query about future role of meter readers, Swaminathan indicated that employees currently filling meter reader positions can be retrained for other positions within the City. Swaminathan reviewed a long list of benefits that are difficult to quantify. In answer to Chair Danaher's inquiry if the demand reduction due to DERs was quantified, Swaminathan reported that demand reduction and DER flexibility was not quantified. Commissioner Schwartz commented on the enormous value of being able to detect outages and leaks. Swaminathan concurred and indicated this topic is part of reliability. Additional value streams could be quantified, but the calculations require too many assumptions. Swaminathan summarized the findings by saying, based on the consultant’s experience with this type of project, staff is confident the estimates of capital expenditure are reasonable. However, the operational costs and benefits are estimates that can vary widely. Non-quantifiable values can be also large. With community engagement, this project can be better utilized in Palo Alto than in other communities because of the penetration of distributed energy resources and sustainability goals. Since AMI is a strategic and enabling technology, staff recommended the implementation of AMI over the next 5 years. Councilmember Filseth commented that elimination of meter reader positions will result in additional cost savings. Commissioner Schwartz expressed enthusiasm for this project. This is fundamental technology for many other projects. She encouraged Commissioners to support it. ACTION: Commissioner Danaher moved to recommend Council approval of the staff recommendation. Commissioner Forssell seconded the motion. The motion passed (5-1) with Chair Danaher and Commissioners Forssell, Schwartz, Segal, and Johnston voting yes, Commissioner Trumbull voting no and Vice Chair Ballantine absent. Utilities Advisory Commission Minutes Approved on: Page 7 of 11 Commissioner Trumbull advised that he is not prepared to spend $7 million of City money after his poor experience with a smart meter at his home the prior year. The smart meter was useless and poorly constructed. ITEM 3: ACTION: Recommendation that the Utilities Advisory Commission Recommend that the City Council Approve the 2018 Update of the Utilities Legislative Guidelines Heather Dauler, Senior Resource Planner, presented the proposed 2018 legislative guidelines. In the 2017 legislative session, the bill to extend the current Cap and Trade program passed. A bill to modify integrated resource plan (IRP) requirements was proposed. The IRP is similar to the LEAP and is due in 2019. SB 100 contained goals to achieve statewide 100% clean energy by 2045 and 60% RPS by 2030. It did not pass. The small cell bill, SB 649, did pass but was vetoed. The park bond bill proposed $4 billion in general obligation bonds. A bill was introduced that would clarify the process for funding storm water projects as the same process for funding other water and sewer projects under Proposition 218. A bill to impose fees on the water bills of all water users died. A bill regarding lead testing in schools passed. A bill to regionalize the Western Grid did not pass. Staff is tracking some federal bills regarding streamlining licensing reform. In 2018, SB 100 could return. The water fee bill will likely return, because the Committee Chair indicated it will be a two-year bill. Staff is preparing to fight it because it will add a fee for all water users. In response to Chair Danaher's question, Dauler reported that the bill would establish a drinking water fee that would be assessed each month on each water user. The funds from the fee would be utilized for disadvantaged communities with failing water systems. If the next iteration contains the same provisions, 98% of residential customers will pay an additional $1 per month, and the remaining 2% will pay an additional $4 per month. Approximately 47% of all other customers would pay an additional $1 per month, 31% $4, and 11% $10. In reply to Commissioner Schwartz's query, Dauler indicated the energy data transparency bill required the City to provide energy information to certain building owners. This bill may return in 2018. Staff expressed concerns about maintaining the confidentiality of data. Dauler reported staff is tracking proposals to reform federal income taxes to ensure the tax exemption for bonds is retained. Hydroelectric/energy bills focus on streamlining licensing requirements. A bill regarding cybersecurity may or may not return. SB 100 may or may not return because de Leon has announced his candidacy for Congress and may resign as Speaker Pro Tem. Election year always impacts legislation. 2018 will be Governor Brown's final year in office, and he may focus on high-priority issues. Bills from 2017, the first year of a two-year cycle, may return in 2018. Debra Lloyd, Acting Assistant Director of Utilities Engineering, remarked that the proposed guidelines are simplified, more general, and provide more flexibility for staff to respond to changing legislative conditions. Dauler advised that the proposed guidelines have been reduced from 15 pages to 1 page and merged into broad guidelines. Staff eliminated wordiness to reduce misinterpretation and to apply to all utilities. The proposed guidelines retain important topics. The Utilities General Manager or his designee retains final authority. Staff will return to the UAC to seek clarification or for discussion of guidelines. Commissioner Schwartz felt the revised guideline in the example is too broad and generic; it doesn't provide any guidance. Dauler indicated the guideline can be clarified to provide more guidance. Ed Shikada, Utilities General Manager, added that he could not recall the City ever opposing a funding bill that might provide funds to the City. Chair Danaher suggested Number 10 refer to support of government actions that support water conservation and fair pricing. With respect to Number 8, he prefers tiered rates to penalize overconsumption rather than cost recovery rates. In Number 12, confidentiality should be balanced with obtaining and using data to support actions. Utilities Advisory Commission Minutes Approved on: Page 8 of 11 Commissioner Schwartz agreed with Chair Danaher regarding confidentiality. Guideline 12 may be too simplistic. Dauler indicated staff could add language regarding "without barriers to gaining adequate information." Chair Danaher suggested there could be support for bills that improve access to information. Dauler stated the energy transparency bill would serve to improve information and allow greater access to data. Commissioner Johnston agreed that guidelines are very broad and general. In response to his questions, Dauler advised that the proposed guidelines do provide sufficient guidance. In reviewing bills, staff considers their impact on utilities and applicability of the guidelines. Examples of locally designed electrification programs are vehicle electrification and residential electrification. Locally designed is intended to allow local officials to design programs specific to the jurisdiction. Staff would not necessarily recommend opposing legislation that mandates residential and commercial electrification programs. It depends on the bill's provisions. Staff rarely recommends absolute opposition to a bill. The guidelines allow staff to educate policymakers as to how a bill can be better and more flexible. Staff works with trade associations to craft letters recommending amendments to legislation. If trade associations oppose a bill, then the City has to decide whether to join in opposition. In deciding whether to recommend support or opposition to a bill, staff looks to other relevant guidelines. The guidelines are meant to be considered individually and holistically. In reply to Chair Danaher's query regarding a statewide tax on water consumption, Dauler stated it's difficult to answer in the abstract. Staff might recommend opposition of a bill that increases water fees when that fee funds other water systems. Staff considers the best interest of the ratepayer and the priorities of the City and Utilities Department. Shikada added that 80% of the time a bill is obviously consistent or inconsistent with the guidelines. When a position on a bill is debatable, staff presents it to Council for action. Commissioner Schwartz remarked that she would support a fee of $1 a month if it would make a difference to a disadvantaged community's water supply. Dauler explained that the particular bill does not provide a choice as to what the funds support. Government officials determine disbursement of funds. Two guidelines address bills about rates, the first and sixth. The bill does not provide local government discretion. Whether the bill provides impractical rates or mandates is debatable. If Commissioners would like more nuance in the guidelines about rates, staff will take that direction. In answer to Chair Danaher's question, Dauler reported staff reserves the right to return to the UAC for guidance on conflicting issues. Lloyd explained that staff considers whether a bill will keep rates and use of revenue under local control. Generally staff attempts to educate policymakers on the impacts to local communities when local control is removed. Commissioner Trumbull praised staff for reducing the number and complexity of guidelines. More simplistic would be even better. Staff needs to react quickly to legislation. In response to Commissioner Segal's inquiry , Dauler reported Guideline 13 was added in 2016 as a result of a data energy bill that could affect key accounts. Staff needed to know if they could or should contact the key accounts about the legislation. Commissioner Forssell appreciated the simplicity of the proposed guidelines. She did not wish to lose the opportunity for discussion of legislation that may be proposed. Dauler stated the annual discussion of upcoming legislation will continue. In addition, quarterly reports contain a legislative component to inform the UAC. Commissioner Forssell requested future reports of upcoming legislation contain additional details Utilities Advisory Commission Minutes Approved on: Page 9 of 11 of expected legislation. Dauler clarified that she could not provide many details because the bills either have not been proposed or may not contain the same provisions in a new iteration. Chair Danaher expressed concern that the guidelines emphasize maintaining local control, which may conflict with good State policy. Dauler explained local jurisdictions should be allowed the flexibility to apply the mandate in a way that works best for local businesses and residents. Shikada recalled that the City Council opposed the affordable housing and small-cells legislation the prior year, but the bills moved forward anyway. The legislative process creates a balance between good State policy and local control. In reply to Chair Danaher's request, Shikada reported the proposed guidelines provide staff with the basic authority that allows them to move quickly when necessary. ACTION: Commissioner Trumbull moved to recommend Council approval of the staff recommendation. Commissioner Forssell seconded the motion. The motion passed unanimously (6-0) with Chair Danaher and Commissioners Forssell, Schwartz, Segal, Trumbull, and Johnston voting yes and Vice Chair Ballantine absent. ITEM 2: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend council Adopt a Resolution Amending Utilities Rule and Regulation 11, “Billing, Adjustments and Payment of Bills” to Update the City’s Billing Adjustment Process Ed Shikada, Utilities General Manager, reported this is a follow-up item regarding water leaks. Staff has proposed a policy change. Anthony Enerio, Customer Service Manager, requested UAC feedback regarding the proposed billing adjustment policy. In response to Commissioner Johnston's inquiry about whether any relief would be provided for very high bills exceeding $500 due to leaks, and for more detail on the estimated costs of the water leak adjustment credits, Enerio advised that the cap of $500 would apply regardless of the actual cost in order to be equitable for both the customer and the utility. The annual water leak adjustment cost of $50,000 is data associated with a prior policy. At that time, there was not a limit on the amount that could be forgiven. The $50,000 amount included unknown sources of high water consumption. Shikada understood the credit given the customer under the prior policy excluded the wholesale cost of water. In reply to Chair Danaher's queries about how many bills exceed the cap and how the adjustment would be calculated, Enerio was aware of more than a dozen bills exceeding the $500 cap since the drought ended. The adjustment will be calculated by applying the higher tier rate to the excess water amount. In answer to Commissioner Schwartz's request to clarify what would happen if a customer ended up with a $10,000 bill, Dean Batchelor, Chief Operating Officer, offered a hypothetical situation to explain calculation of the amount to be paid. If a customer receives a bill for $1,500 due to a leak, the first $500 will be credited to the top tier. The customer will owe the remaining $1,000. The policy allows a flat $500 reduction of the total water bill. For a bill of $10,000, the customer will owe $9,500. Shikada advised that staff was directed to provide some forgiveness for a customer who had a water leak and who is searching for some relief of the cost. The policy provides a credit of up to $500 to provide some relief. The policy does not completely absolve the additional cost. A variety of methodologies could be used to provide relief. The proposed policy is administratively simple. Chair Danaher believed a $500 limit is low. For example, the adjustment could be the higher of $1,000 or half of the excess bill. He supported a more generous adjustment. Utilities Advisory Commission Minutes Approved on: Page 10 of 11 Commissioner Segal suggested a better balance between ease of administration and a more generous adjustment. In response to Council Member Filseth's inquiry, Jonathan Abendschein, Assistant Director of Utilities Resource Management, reported the marginal cost of water is $4.10 per hundred cubic feet, and the customer cost is approximately $7.15 per hundred cubic feet. Council Member Filseth remarked that the adjustment could be the marginal cost of the amount of water used. This way, other ratepayers do not pay for the excess water. Shikada indicated that was the method of the former policy. A 50/50 or 60/40 split would effectively be the credit under commodity cost. In order to calculate that credit, staff would have to estimate the volume of water used absent the leak. Chair Danaher proposed an adjustment of $1,000 or, if higher, one-half of the excess charges. A customer would pay $1,500 on a total bill of $3,000. Commissioner Segal wished to share the cost with the customer while relieving the customer of some of the burden and retaining administrative simplicity. Abendschein suggested a large facility could experience a water leak that costs tens of thousands of dollars. The Commission may not wish to include large facilities in this policy. In response to Commissioner Schwartz's inquiry about distinguishing between customer types, Shikada believed the City Attorney would advise that one policy apply to both residential and commercial customers. Commissioner Segal proposed a tiered forgiveness system. Chair Danaher proposed an adjustment of half the billed amount up to a maximum of $5,000. The maximum credit would be $2,500. Shikada suggested staff review accounts to determine a typical bill amount resulting from water leaks. Commissioner Johnston felt it was unlikely residential customers were receiving water bills of more than $1,000. Chair Danaher requested that staff to return with a revised policy based on the Commission's comments. Commissioner Forssell supported a more generous policy, but not as much as $2,500. She asked how baseline consumption was estimated given that use fluctuates over the year. In response to her inquiry, Enerio explained that staff uses data for the same month over the prior three years to calculate water volume used. ACTION: No action. ITEM 6. ACTION: Selection of Potential Topics(s) for Discussion at Future UAC Meeting Chair Danaher noted the informational report regarding customer demographics and recommended Commissioners read it. It could be used for reference in the future. He thanked staff for the report. Ed Shikada, Utilities General Manager, reported the Strategic Plan and cross bore next steps will return in December. Utilities Advisory Commission Minutes Approved on: Page 11 of 11 In response to Commissioner Schwartz's query about the date for the rescheduled joint UAC/Council meeting, Shikada indicated he is working to obtain tentative dates for a joint meeting with the Council. Commissioner Segal requested staff provide data regarding the number of residents who work in Palo Alto and who commute outside the City, if it's available. Commissioner Schwartz recommended agendizing a discussion of customer demographics in the future. ACTION: No action Meeting adjourned at 9:33 p.m. Respectfully Submitted, Marites Ward City of Palo Alto Utilities Page 1 of 2 3 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: DECEMBER 6, 2017 SUBJECT: 2018 Utilities Strategic Plan REQUEST Staff seeks feedback on various elements of the draft 2018 Utilities Strategic Plan (Attachment A)before final consideration is sought from the Utilities Advisory Commission in January 2018. No action is requested. SUMMARY: Since the last major Utilities Strategic Plan update occurred in 2011, several internal and external forces (i.e. climate changes, legislative and regulatory requirements, emerging technologies, aging workforce) have increased the demands and complexities associated with meeting the needs and expectations of customers, employees, the City and other stakeholders. As such, in early 2017, the Utilities Department (CPAU) staff embarked on a process to develop the 2018 Utilities Strategic Plan (“Strategic Plan”) through an extensive stakeholder engagement process with a focus on simplifying, balancing and prioritizing all stakeholder needs and expectations while addressing several key drivers, challenges and opportunities. The goal of the Strategic Plan is to ensure maximum alignment between CPAU’s resources and activities with the City Council’s policy direction and to guide CPAU in successfully advancing the City’s vision and priorities over the next five to ten years. Utilities Advisory Commission (UAC) feedback is sought on the following Strategic Plan elements: •Mission Statement; •Strategic Direction; •Priority Focus Areas – 1) Workforce, 2) Collaboration, 3) Technology; and 4) Finances and Resources; •Strategies and Actions; and •Key Performance Indicators (KPI) The Strategic Plan will also result in the identification of an implementation plan consisting of tasks to carry out specific actions, identification of high priority action items, timelines and a refined system for tracking and reporting performance. Additionally, through the implementation of the Strategic Plan, CPAU staff will work towards improvement of the work culture to ensure alignment of the City's and CPAU's stated values. These elements are i ntended to be operational in nature; therefore staff is not seeking UAC feedback at this time. The attached presentation (Attachment B) summarizes staff's efforts in developing a new strategic plan for the Utilities Department and highlights the key focus areas, strategies and actions necessary to achieve CPAU's mission and strategic direction . ATTACHMENTS: A. Proposed Draft 2018 Utilities Strategic Plan: Mission Statement; Strategic Direction; Priority Focus Areas; Strategies and Actions; and Key Performance Indicators B. 2018 Utilities Strategic Plan Presentation PREPARED BY: MON ICA V. PADI LLA, Sen i or Resource Plann~ REVIEWED BY: DEAN BATC H ELOR, Ch i ef Operating Offic ~ ~~ APPROVED BY : EDSH IKADA General Manager of Utilities Page 2 of 2 DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 1 of 13 Mission Statement: The City of Palo Alto Utilities' mission is to provide safe, reliable, environmentally sustainable and cost effective services. Strategic Destination: At CPAU, our people empower tomorrow's ambitions while caring for today's needs! We make this possible with our outstanding professional workforce, leading through collaboration and optimizing resources to ensure a sustainable and resilient Palo Alto. Priority Focus Areas: Priority 1: Workforce Priority 2: Collaboration Priority 3: Technology Priority 4: Finances and Resources Strategies and Actions: Priority 1. We must create a vibrant and competitive environment that attracts, retains, and invests in a skilled and engaged workforce. Strategy 1. Establish CPAU as an organization where employees are proud to work and recruit other strong performers. Action 1. Support pilot rollout of annual professional/journeyman individual development plans (IDP) and rollup to department training priorities, to develop internal talent. Complete by December 2018. Action 2. Review and expand training/education and certificate programs that emphasize mastery of trade, profession, or management position and promote development and longevity in areas of expected need. Complete by June 2018. Action 3. Update Divisional Succession Plans to prepare staff for promotional opportunities and to retain institutional knowledge within the organization (update existing 5 year succession plan). Complete by December 2019. ATTACHMENT A DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 2 of 13 Action 4. Promote a culture that reinforces City and Department values. Complete by June 2018. Strategy 2. Create a workplace that attracts and retains skilled employees. Action 1. Prioritize resolution of collective bargaining issues and finalize an agreement that ensures CPAU will attract and retain high caliber skilled employees that will advance the Department’s mission. Complete by December 2018. Action 2. Reduce processing time to hire new staff to ensure potential candidates are offered positions in a reasonable time frame. Complete by December 2018. Action 3. Support CPAU staff communication outreach in recruitment strategy for hiring utilities employees. Complete by December 2018. Strategy 3. Evaluate and consider alternative workforce solutions to achieve organizational business objectives. Action 1. Create opportunities to empower and support individual employees and work groups to offer a work-life balance through alternative work schedules or other options. Complete by December 2018. Action 2. Determine the potential for projects and/or functions to be effectively outsourced while continuing to meet organizational needs and objectives. Complete by December 2019. Action 3. Consider developing a hybrid workforce of full time employees and non-benefitted staff. Complete by December 2020. Action 4. Create an internal labor pool from within the City to fill temporary business needs. Complete by June 2019. Key Performance Indicators: •Employee turnover rates •Number of vacant positions and days to fill •Number of employees with Individual Development Plans •Employee satisfaction DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 3 of 13 Priority 2. We must collaborate with internal teams and external stakeholders to achieve our shared objectives of enhanced communication, coordination, education and delivery of services. Strategy 1. Increasing communication with the community enhances customer satisfaction and community trust and will help us deliver programs and content based on community desires. Action 1. Establish a routine practice of involving stakeholders on strategic projects and initiatives to support customer satisfaction, customer choice, and program outcomes. Ongoing. Action 2. Proactively communicate about capital improvement projects to mitigate the impacts of construction, while maximizing public support and the allocated financial resources. Ongoing. Action 3. Identify and develop proactive strategies and customer education that allows CPAU to support customer needs for Distributed Energy Resources (DER), including storage, solar, EVs, energy efficiency. Ongoing with DER plan timeline; phase 1 to be complete by December 2018. Action 4. Partner with community stakeholders to facilitate large scale residential building electrification (beyond rebate scale). No timeline; beginning conversations and research now. Action 5. Enhance customer service through deployment of technology such as upgraded online bill payment, account access system and advanced metering infrastructure (AMI). Ongoing with Utilities technology roadmap. Action 6. Build customer support for programs and understanding of how we provide cost-effective services. Ongoing. Action 7. Create interdepartmental work groups to identify and resolve ongoing workflow and priorities involving permitting, procurement and legal. Ongoing. DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 4 of 13 Strategy 2. Strengthening coordination and integration across City departments aligns Utilities and City goals while improving performance and efficiency. Action 1. Enhance current coordination of scheduling, synchronization and communication of capital improvement, maintenance, operations projects and other Utilities programs and services with other departments to improve implementation and efficiency. Ongoing. Action 2. Explore opportunities to improve City processes, policies and information sharing that allows the community to easily understand and implement DER opportunities such as EVs, solar, storage, energy efficiency, and building electrification. Ongoing with DER timeline; phase 1 to be complete by December 2018. Action 3. Share information and opportunities across departments to expand outreach about CPAU employment. Ongoing. Action 4. Promote regular interdepartmental information sharing throughout the City to assist employees understand City (and common) goals. Ongoing. Strategy 3. Fostering a culture of cooperative work within Utilities improves productivity and awareness, and understanding of our common goals. Action 1. Support the implementation of the Utilities’ technology roadmap with comprehensive communication of: technological advancements and the department's short-term and long-term goals; how these advancements reflect customer and operational needs; how projects are prioritized; and how decisions are made. Ongoing with timeline of Utilities technology roadmap; full implementation scheduled for completion by December 2022. Action 2. Strengthen existing tools for intradepartmental communication to ensure transparency and informed staff that understand the Strategic Plan and other key CPAU issues and how they directly relate to the work of our employees. Ongoing; some tasks by April 2018 with completion of the Strategic Plan. DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 5 of 13 Action 3. Collaborate with staff involved in deployment of AMI and develop a comprehensive outreach plan to communicate AMI and supporting technologies, impact to staffing resources, staff responsibilities, and how the customer engagement platform operates. Ongoing with timeline of Utilities technology roadmap; AMI full deployment scheduled to be complete by October 2018. Action 4. Support upgrade of MUA by communicating the customer and utility operational benefits and functionalities. Ongoing with timeline of MUA; phase 1 complete by July 2018. Action 5. Establish intradepartmental team to evaluate and determine best practices for an OMS, including communication across divisions to reduce restoration time and provide customers with more real-time outage information. Integrate with Technology S3, A4. Complete by June 2019. Action 6. Support the workforce priorities by aligning organizational values and reiterating employee roles within the framework of the Utilities Strategic Plan. Ongoing. Strategy 4. Collaborating with government, trade, and regional agencies enhances our sphere of influence, allows us to identify common ground, and leverage economies of scale. Action 1. Continue to work with Industry/trade/regional groups (NCPA, League of Cities, CMUA, BAWSCA, E Source etc.) to collaborate on shared objectives. Ongoing. Action 2. Coordinate on regional utility programs to streamline processes, achieve mutual objectives, and realize greater impacts. Ongoing; some tasks can be completed by December 2019. Action 3. Communicate our public awareness efforts and resources with government agencies (DOE, EPA, CEC, etc.) to improve public and stakeholder awareness of utility issues, programs, and shared goals. Ongoing. Action 4. Collaborate with educational institutions and companies to attract local candidates for CPAU positions. Ongoing; some tasks can be completed by December 2019. DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 6 of 13 Key Performance Indicators: •Customer satisfaction •Employee collaboration •Customer awareness of programs and services DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 7 of 13 Priority 3. We must invest in and utilize technology to enhance the customer experience and maximize operational efficiency. Strategy 1. Finalize and implement technology road map to clearly identify CPAU’s short-term and long-term goals, reflect customer and operational needs, prioritize projects and guide decisions. Action 1. Involve customers’ defining priorities and operational needs to improve customer satisfaction and operational efficiency. Ongoing. Action 2. Implement Technology Road Map including project prioritization, 10 year timeline, and co-dependencies. 2018 through 2022. Strategy 2. Deploy advanced metering infrastructure (AMI) to increase reliability, enhance customer service, and improve response time. Action 1. Finalize Business Case including cost and benefit analysis, scenarios, and staffing impacts. Complete by June 2018. Action 2. Develop AMI/MDM System Requirements to identify functional and system requirements. Complete by June 2019. Action 3. Evaluate Multi-Agency AMI/MDM with NCPA to pool resources, share ideas and increase purchasing power. Complete by June 2019. Action 4. Alpha Phase to deploy 5–10 meters to ensure network infrastructure and system integrations are established. Complete by March 2021. Action 5. Beta Phase to deploy 2,000-5,000 meters to install all network equipment, develop future state business processes, provide testing and training, and pilot customer engagement. Complete by September 2021. Action 6. Citywide AMI/MDM Deployment of 73,000 electric, gas and water meters. Complete by September 2022. Strategy 3. Invest in technology infrastructure to enhance customer engagement and satisfaction. DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 8 of 13 Action 1. Upgrade Utilities customer portal: My Utilities Account (MUA 2.0) to provide customers additional 24/7 self-services and customer information to better manage their consumption and choices. Complete by September 2018. Action 2. Leverage City’s mobile app (Palo Alto 311) to provide residents, businesses and visitors more access to City services and information. Complete by December 2019. Action 3. Implement a Street Work Notification customer portal for long-term construction projects that may result in traffic, parking or other impacts to neighborhoods. Complete by March 2019. Action 4. Evaluate and upgrade Outage Management System (OMS) to reduce restoration time and provide customers near real-time outage information. Complete by June 2019. Strategy 4. Implement technologies to improve response time, security and operational efficiency. Action 1. Deploy Mobile/Field Technologies (devices and software) to reduce operational costs and improve service delivery. Complete by December 2018. Action 2. Upgrade Customer Information/Billing System (CIS) to improve responsiveness and ensure customer data is accurate and secure. Complete by September 2030. Action 3. Maintain Supervisory Control and Data Acquisition (SCADA) system to ensure a safe, reliable, and efficient distribution system. Complete by December 2018. Action 4. Integrate with new GIS System (ESRI) to ensure accurate infrastructure information for customer service and infrastructure improvements. Complete by June 2019. Action 5. Ensure that CPAU systems keep pace with customer adoption of new technologies to enhance the customer experience and choice. Ongoing. Strategy 5. Ensure and empower employees with current Technologies to perform work efficiently. DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 9 of 13 Action 1. Streamline business processes to facilitate adoption of new technological solutions that improve performance in targeted priority functions. Complete by December 2018. Action 2. Implement continuous education and evaluation of new technology applications and related utility trends to ensure CPAU maintains an effective, competitive, and optimal use of technology applications. Ongoing. Action 3. Train employees to adopt and maximize utilization of new technologies. Ongoing. Key Performance Indicators: •Number of customers utilizing the My Utilities Account •Number of staff with access to mobile tools •Staff training DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 10 of 13 Priority 4. Financial Efficiency and Resource Optimization - We must manage our finances optimally and use resources efficiently to meet our customers’ service priorities. Strategy 1. Establish a proactive infrastructure replacement program, based on planned replacement before failure to support reliability and resiliency. Action 1. Initiate a program to update data in the utility asset management system to establish infrastructure replacement programs and support maintenance plans. Complete by December 2018. Action 2. Develop, prioritize, and propose planned infrastructure replacement programs based on currently available key asset information for implementation in FY 2020 and begin reporting of planned infrastructure replacement status. Complete by September 2018. Action 3. Establish a system of regular reporting on planned replacement progress, including management reports appropriate to every level of the organization. First report by September 2018. Action 4. Develop a plan to fill data gaps and ensure data accuracy identified in A1 and implement collection process. Complete by September 2019. Action 5. Use updated data in comprehensive asset management system and database to improve planned replacement programs and status reporting. Start implementation in July 2020. Strategy 2. Develop financial planning processes that provide stability and clear communication of service priorities and the cost of achieving those priorities. Action 1. For FY 2019 budget process, collaborate between Rates, Admin, and Water-Gas-Wastewater Engineering to pilot an infrastructure budget development process for one utility (Water, Gas, or Wastewater Collection) that coordinates CIP budget development with planning for funding sources and reserves management. Complete by March 2018. DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 11 of 13 Action 2. Starting with the FY 2020 budget process, implement an integrated and replicable CIP budgeting process with Admin, Rates, and Water-Gas- Wastewater Engineering to develop a CIP reserve and an annual CIP contribution amount for one utility. Complete by September 2018. Action 3. For FY 2021 budget process, expand and apply the integrated CIP budgeting process to at least one other utility (Electric, Water, Gas, or Wastewater Collection) with remaining funds in FY 2022. Complete by September 2019. Action 4. In 2019, update benchmark study for one utility. Begin a process of regular benchmarking of one utility per year going forward. Complete by December 2019. Strategy 3. Enhance planned maintenance programs for all utilities through clearly defined maintenance plans, improved management reporting, and developing innovative ways to ensure efficient completion of all maintenance. Action 1. Develop an inventory of existing maintenance programs and a reporting framework to monitor progress. Identify areas where planned maintenance is not being completed and areas where more data is needed to design maintenance plans. Complete by December 2018. Action 2. Identify and evaluate asset data requirements and accuracy to develop and monitor proactive maintenance programs and identify any data gaps. Complete by December 2018. Action 3. Identify staffing, software, and other resources required to implement and monitor maintenance programs, identify gaps in existing resources, identify alternative ways to implement the programs and the costs and benefits of different approaches. Complete by September 2018. Action 4. Establish a system of regular reporting on maintenance progress, including management reports appropriate to every level of the organization. Provide first report by September 2018. Action 5. As additional asset data becomes available from data collection efforts identified in S1 A1 and S1 A4, update and improve applicable maintenance plans. Implementation to be determined. DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 12 of 13 Strategy 4. Achieve a sustainable and resilient energy and water supply to meet community needs. Action 1. Work with other City Departments to establish an implementation plan through FY 2020 to achieve the City’s carbon reduction and water management goals while assessing utility operational risks and mitigations associated with electrification. Complete by June 2018. Action 2. Establish and implement a Distributed Energy Resources plan to ensure local generation (e.g. solar), storage, electric vehicles (EVs), and controllable loads (like heat pump water heaters) are integrated into the distribution system in a way that benefits both the customer and the broader community. Complete by December 2018. Action 3. Evaluate recycled water, groundwater, and other non-potable water sources and integrate the results and outcomes with water supply plans. Complete by December 2018. Action 4. Incorporate a review of the changing competitive landscape (such as low-cost local solar and storage, the rise of Community Choice Aggregators, and the potential for competition and Direct Access) into routine electric supply planning processes. Complete by December 2020. Action 5. Adopt and implement for the Electric utility an integrated resource plan for 2018 through 2030. Complete by December 2018. Strategy 5. Engage stakeholders and define CPAU’s role in supporting and facilitating community resiliency. Action 1. Engage in community outreach to identify what aspects of resiliency are important to the community for each utility to support development of a resiliency work plan. Complete by December 2018. Action 2. Define minimum emergency service commitments and targeted full system recovery times in case of a major disaster(s) and communicate general guidance on recovery times to the public. Implementation to be determined and dependent on A1. Action 3. Develop an outreach and education program to facilitate individual customer resiliency efforts. Implementation dependent on A1. DRAFT - City of Palo Alto Utilities 2018 Strategic Plan Strategies & Action Plan Page 13 of 13 Action 4. Identify high priority issues that could interfere with emergency service commitments and recovery times and develop a plan to improve resiliency in these areas. Implementation dependent on A1. Action 5. Complete evaluation of redundant/backup transmission service to CPAU and communicate to stakeholders. Complete by December 2018. Key Performance Indicators: •Identification of critical assets •Critical assets replacement and maintenance rates •Utility bill comparison with surrounding cities •Carbon neutral energy supply and water use reductions STRATEGIC PLAN Utilities Advisory Commission Meeting – December 6, 2017 ATTACHMENT B 2 Overview 1.Process and Stakeholder Engagement 2.Strategic Plan Elements 3.Mission Statement and Strategic Direction 4.Priority Focus Areas 5.Strategies and Actions 6.Key Performance Indicators 7.Next Steps 3 Strategic Planning & Stakeholder Engagement 4 Current Strategic Plan 5 Strategic Plan Key Elements Mission Statement, Strategic Direction, and Values Priority Area 1 Strategy 1.1 Action 1 Action 2 Strategy 1.2 Priority Area 2 Strategy 2.1 Strategies: Means by which the Priority Area is resolved Priority Areas: issues CPAU must address to achieve the Strategic Destination Long Term / Enduring Elements Short/Mid Term / Detailed Elements 6 Mission and Strategic Destination Mission Statement – No Change The City of Palo Alto Utilities' mission is to provide safe, reliable, environmentally sustainable and cost effective services. Strategic Destination - New At CPAU, our people empower tomorrow's ambitions while caring for today's needs! We make this possible with our outstanding professional workforce, leading through collaboration and optimizing resources to ensure a sustainable and resilient Palo Alto. Customer Financial Resources People •Council/UAC •Staff •Stakeholders Technology Internal Business Processes Conceptual Differences from 2011 Strategic Plan: •Be explicit about customer feedback loop •Separate and focus on People (vs. Technology) •Simplify focus on highest priority actions in near term Focus Areas - Before Finances & Resources Workforce Collaboration Technology New Priority Focus Areas Priority 1: Workforce We must create a vibrant and competitive environment that attracts, retains, and invests in a skilled and engaged workforce. Strategies and First Year Actions: S1: Establish CPAU as an organization where employees are proud to work and recruit other strong performers. A1: Develop individual development plans (IDP) A2: Review and expand training/education and certificate programs S2: Improve retention and recruitment efforts A1: Finalize bargaining agreements A2: Reduce hiring/processing time S3: Pursue alternative work and workforce solutions A1: Promote work-life balance solutions Key Performance Indicators: •Employee turnover rates •Number of vacant positions and days to fill •Number of employees with Individual Development Plans •Employee satisfaction Priority 2: Collaboration We must collaborate with internal teams and external stakeholders to achieve our shared objectives of enhanced communication, coordination, education and delivery of services. Strategies and First Year Actions: S1: Enhance community communication A3: Targeted engagement/communication for distributed energy resources S2: Strengthen coordination and interaction with City A2: Improve City processing time to facilitate DER implementation S3: Foster cooperative culture within the department A2: Communicate Strategic Plan and key initiatives to all employees A3: Coordinate AMI outreach plan S4: Collaborate with outside agencies Key Performance Indicators: •Customer satisfaction •Employee collaboration •Customer awareness of programs and services Priority 3: Technology We must invest in and utilize technology to enhance the customer experience and maximize operational efficiency. Strategies and First Year Actions: S1: Complete technology roadmap A1: Engage customers and establish priorities A2: Begin implementation of technology roadmap S2: Deploy automated meter infrastructure (AMI) A1: Finalize business case S3: Enhance customer engagement tools A1: Upgrade My Utilities Account (MUA 2.0) S4: Improve system operational efficiency A1: Deploy mobile/field technologies A3: Supervisory Control and Data Acquisition (SCADA) system S5: Empower employees with technology A1: Streamline priority business processes Key Performance Indicators: •Number of customers utilizing the My Utilities Account •Number of staff with access to mobile tools •Staff training Priority 4: Finances and Resources We must manage our finances optimally and use resources efficiently to meet our customers’ service priorities. Strategies and First Year Actions: S1: Deploy planned infrastructure replacement A1: Update data in the utility asset management system A2: Prioritize planned infrastructure replacement programs A3: Report on planned replacement progress S2: Stabilize CIP funding A1: Pilot an infrastructure budget development process for one utility for FY 19. S3: Implement planned maintenance A1: Conduct a planned maintenance needs analysis A2: Develop and monitor proactive maintenance programs and identify any data gaps. A3: Develop a planned maintenance implementation plan A4: Establish and report on planned maintenance progress Priority 4: Finances and Resources - continued We must manage our finances optimally and use resources efficiently to meet our customers’ service priorities. Strategies and First Year Actions: S4: Achieve sustainable and resilient energy and water supplies A1: Assist with achieving the City’s carbon reduction and water management goals A2: Establish and implement a Distributed Energy Resources plan A3: Evaluate recycled water, groundwater, and other non-potable water sources A4: Adopt Electric utility integrated resource plan S5: Build community resiliency A1: Assess community’s resiliency needs and develop resiliency work plan A5: Complete evaluation of redundant/backup transmission line to Palo Alto Key Performance Indicators: •Identification of critical assets •Critical assets replacement and maintenance rates •Utility bill comparison with surrounding cities •Carbon neutral energy supply and water use reductions 14 15 Next Steps •UAC support: January 2018 •Council approval: February/March 2018 •Organizational alignment and implementation 16 Photo Slide Bulleted Content MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT 4 DATE: DECEMBER 6, 2017 SUBJECT: Discussion of Sustainability and Clim~te Action Implementation Plan REQUEST On December 11, 2017 the Council will consider a second draft of the Sustainability and Climate Action Plan {S/CAP) Implementation Plan {SIP). Staff seeks Utilities Advisory Commission {UAC) feedback on the plan before Council consideration. No action is requested. SUMMARY: On April 5, 2017, the Utilities Advisory Commission {UAC) provided feedback on the first draft of the S/CAP SIP.1 Feedback from the UAC was provided to Council at places on April 11, 2017.2 On June 5, 2017, Staff presented these detailed action items, identified as "Key Actions" for Council consideration. Council directed staff to prepare a shorter, more tightly focused 2018 -2020 Sustainability Implementation Plan (SIP) for · Counci l review, which is the revised SIP in Staff Report #8487 to be presented to Council on December 11, 2017. This staff report will become available online when the December 11, 2017 Council packet is published on Novembe r 30 . The attached 2018 -2020 Susta i nability Implementation Plan {SIP) focuses on two key S/CAP concerns- C02 and H20 {Greenhouse Gasses (GHG) and Water)-and four action areas: Energy, Mobility, Electric Vehicles, and Water. In each of these four areas, staff proposes $pecific near-term key actions to advance the City's S/CAP goals, and broader "strategic moves" to support those actions. Staff is requesting any additional feedback from the UAC on the revised S/CAP SIP. PREPARED BY: JONATHAN ABENDSCHEIN, Assistant Director, Resource Managemen~ DEAN BATCHELOR, Chief Operating Offic~ c::?~~ REVIEWED BY: APPROVED BY: ED SH IKADA, General Manager of Utilities 1 See April 5, 2017 UAC staff report titled "Discussion ofThree Utility-Related Sustainability/Climate Action Plan Implementation Plan Components: Mobility, Efficiency and Electrification, and Water Management." http://www.cityofpaloalto.org/civicax/filebank/documents/56778 2 See memo associated with Item 11 of the April 11, 2017 City Council agenda. http://www.cityofpa loa Ito. org/ civica x/fi I eba n k/ do cum ents/5 7005 · Page 1of1 6054005 Page 1 of 12 5 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: December 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 Neutra l 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 Western 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. W hen 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 Financ e 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 i n 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 co sts 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 pol icy 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 ©weather X change 115 105 95 85 75 x 65 Q) "O .s 55 45 35 25 15 5 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ * ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 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 i nto 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. ENV IRONMENTAL REVIEW Adoption of a Hydro Rate Adjustment mechanism does not meet the definition of a project, under Pub lic 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 ind i rect physical change in the environment, thus no environmental review is required. PREPARED BY: JIM STACK, Senior Resource Planner ~ LY~EIN, Assistant Director, Reso urce M anage.Rent REVIEWED BY: APPROVED BY : ED SHIKADA, General Manager of Utilities 6054005 Page 12of12