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2016-04-12 Utilities Advisory Commission Agenda Packet
NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956 I. ROLL CALL II. ORAL COMMUNICATIONS Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable time restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from discussing or acting upon any topic initially presented during oral communication. III. APPROVAL OF THE MINUTES Approval of the Minutes of the Utilities Advisory Commission Meeting held on March 2, 2016 IV. AGENDA REVIEW AND REVISIONS V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS VI. DIRECTOR OF UTILITIES REPORT VII. COMMISSIONER COMMENTS VIII. UNFINISHED BUSINESS None. IX. NEW BUSINESS 1. Staff Recommendation that the Utilities Advisory Commission Recommend that the City Action Council Adopt 1) a Resolution Approving the Fiscal Year 2017 Electric Financial Plan and Amending the Electric Utility Reserves Management Practices, and 2) a Resolution Increasing Electric Rates by Amending the E-1, E-2, E-2-G, E-4, E-4-G, E-4-TOU, E-7, E-7-G, E-7-TOU, E-14, and E-16 Rate Schedules, and Repealing Rate Schedules E-18 and E-18-G 2. Staff Request that the Utilities Advisory Commission Recommend that City Council Action Approve the Proposed Net Energy Metering Successor Rate E-EEC-1 and Net Energy Metering Grandfathering Policy 3. Staff Recommendation that the Utilities Advisory Commission Recommend that the City Action Council Adopt: (1) a Resolution Approving the Fiscal Year 2017 Gas Utility Financial Plan; and (2) a Resolution Increasing Gas Rates by Amending Rate Schedules G-1 (Residential Gas Service), G-1-G (Residential Green Gas Service), G-2 (Residential Master-Metered and Commercial Gas Service), G-2-G (Residential Master-Metered and Commercial Green Gas Service), G-3 (Large Commercial Gas Service), G-3-G (Large Commercial Green Gas Service, G-10 (Compressed Natural Gas Service) and G-10-G (Compressed Natural Green Gas Service) 4. Staff Recommendation that the Utilities Advisory Commission Recommend that the City Action Council Adopt a Resolution Approving the 2015 Urban Water Management Plan and Adopt an Ordinance Amending Municipal Code Sections 12.32.010 (Water Use Restrictions) and 12.32.020 (Enforcement) 5. Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action 6. Update and Discussion on Impacts of Statewide Drought on Water and Discussion Hydroelectric Supplies X. NEXT SCHEDULED MEETING: May 4, 2016 – Special Daytime Meeting UTILITIES ADVISORY COMMISSION – SPECIAL MEETING TUESDAY, APRIL 12, 2016 – 7:00 P.M. COUNCIL CHAMBERS Palo Alto City Hall – 250 Hamilton Avenue Chairman: Jonathan Foster Vice Chair: James F. Cook: Commissioners: Arne Ballantine, Michael Danaher, Steve Eglash, Garth Hall, and Judith Schwartz Council Liaison: Gregory Scharff Utilities Advisory Commission Minutes Approved on: Page 1 of 12 UTILITIES ADVISORY COMMISSION MEETING MINUTES OF MARCH 2, 2016 CALL TO ORDER Chair Foster called to order at 7:03 p.m. the meeting of the Utilities Advisory Commission (UAC). Present: Chair Foster, Commissioners Ballantine, Danaher, Eglash, Schwartz, and Council Liaison Scharff Absent: Vice Chair Cook and Commissioner Hall ORAL COMMUNICATIONS David Carnahan, Deputy City Clerk, announced that the City is searching to fill openings on the City’s boards and commissions, including the UAC. He encouraged community members to apply to serve on these boards and commissions and noted that applications are due March 18. APPROVAL OF THE MINUTES Commissioner Danaher moved to approve the minutes from February 3, 2016 UAC meeting as presented and Chair Foster seconded the motion. The motion carried unanimously (5-0) with Chair Foster, Commissioners Ballantine, Danaher, Eglash, and Schwartz voting yes and Vice Chair Cook and Commissioner Hall absent. AGENDA REVIEW AND REVISIONS Chair Foster advised that New Business Item #2 (Selection of Potential Topic(s) for Discussion at Future UAC Meeting) would be moved to after New Business Item #4 (Update and Discussion on Impacts of Statewide Drought on Water and Hydroelectric Supplies). REPORTS FROM COMMISSION MEETINGS/EVENTS Commissioner Schwartz reported that she participated as an expert on a California Public Utilities Commission panel on making time-of-use (TOU) rates the default rate for customers in 2019. The discussion was about the best practices across the country. She spoke about the coercion aspect of forcing all folks onto a particular rate. She said that it is preferable to provide customers a choice and could be similar to requiring customers to be in the PaloAltoGreen Gas program. She said that what is relevant for Palo Alto is related to smart grid pilot programs and the feeling that we need to treat them like double blind science experiments. She said that makes no sense and people should be able to choose between options. Commissioner Schwartz gave a webinar today on lessons from “shady” industries and how they use marketing targeted at low income consumers. She said that the techniques are very DRAFT Utilities Advisory Commission Minutes Approved on: Page 2 of 12 effective and could be considered by Palo Alto whe n it markets its programs. She said that CPAU should look to other industries to learn about good marketing ideas for CPAU when it markets its programs. Commissioner Schwartz attended the March 1 Finance Committee meeting when Utilities staff presented the preliminary financial forecasts and had similar questions that the UAC did when it reviewed the forecasts at its February meeting. Committee members asked about the level of reserves and whether they could be further drawn down to reduce the rate increa se. They were receptive to the idea of conducting customer usage analytics to identify who is affected most by the rate changes. UTILITIES DIRECTOR REPORT 1. Finance Committee Actions on February 16 Two items were considered by the Finance Committee that the UAC recommended. The first was the Wilsona Solar Power Purchase Agreement with Hecate Energy. The Finance Committee joined the UAC in supporting this very low priced, long-term solar renewable energy contract. The second item was the Palo Alto CLEAN program with staff’s and the UAC’s recommendation to continue the 16.5 cents per kilowatt -hour contract price for local solar projects. However, the Finance Committee voted unanimously to recommend that Council reduce the contract price to the avoided cost of 8.9 cents per kWh for a 20-year contract and 9.0 cents per kWh for a 25-year contract. The Finance Committee wanted to make sure that the five CLEAN applications already received would get the 16.5 cents per kWh price that was in place when they applied. The applications are for a local church and for four City-owned parking structures. These applications would result in almost 1.3 megawatts of local solar, or almost half of the 3 MW CLEAN program cap. Council will consider the Finance Committee recommendations for both the Wilsona Solar agreement and the CLEAN program at its March 21 meeting. 2. Communications Gas Safety Awareness Telephone Surveys – Beginning March 8, CPAU will participate in the federally mandated Gas Overall Awareness Level (GOAL) survey, a nationwide program to assess the public’s gas safety knowledge. This automated telephone polling survey administered by the American Public Gas Association is conducted to insure that people living along the pipeline have adequate gas safety information. Depending on the response rate, the survey should be completed by March 10. Natural Gas Utility Worker Day is March 18 – The American Public Gas Association recognizes natural gas utility workers for their hard work and accomplishments. March 18 is the date of the New London, Texas school explosion in 1937 that led to the widespread odorization of natural gas and an increased emphasis on safety. Let’s celebrate our hardworking employees in Palo Alto who help us keep our burners lit and pipeli nes safe! March 14-20 is “Fix a Leak” Week – Household leaks can waste more than 1 trillion gallons of water each year nationwide. EPA WaterSense sponsors this campaign to raise awareness about Utilities Advisory Commission Minutes Approved on: Page 3 of 12 repairing leaks for water conservation. The City provides instructions and tips on how to read a water meter, check for leaks and find other easy ways to save at www.cityofpaloalto.org/water. City of Palo Alto Utilities Recognized with the Tree Line USA Award - For the second year in a row, CPAU has been recognized with the Tree Line USA award by the National Arbor Day Foundation. Tree Line USA recognizes the Utility for demonstrating how trees and utilities can co-exist for community and citizen benefits by exceeding the five core standards criteria: quality tree care, annual worker training, tree planting and public education, tree -based energy conservation program and Arbor Day support. Customer Engagement Portal for Energy and Water Use and Management –In partnership with Nexant, CPAU launched a new pilot online utility portal on February 1 for data management, analytics and customer engagement. Through the portal, residents will be able to better manage and control their energy and water usage. For instance, portal users will be able to view historical monthly consumption data, receive information on CPAU’s efficiency programs and rebates, and learn more about renewable energy and related program opportunities. Access the portal from Cityofpaloalto.org/smartenergy. 3. Upcoming Events On March 17th, Palo Alto will host the second of five regional Georgetown University Energy Prize workshops at the Mitchell Park Community Center. This workshop is designed for elected officials and other community leaders to discuss strategies of how to engage people in energy efficiency measures. Mayor Burt will deliver the welcoming address and Chief Sustainability Officer Gil Friend will be the keynote speaker. On March 26, there will be a Rainwater Harvesting and Rain Barrel Workshop Commissioner Schwartz asked about the Georgetown workshop and whether granular data will be available since the City has only monthly data about usage, people can only do “straight conservation” so what is the plan for communicating ideas to customers. Assistant Director Jane Ratchye said that this is not CPAU’s workshop and is not f or the general public, but is a forum for sharing ideas among the cities competing for the Georgetown University Energy Prize. Chair Foster said that the Finance Committee has taken a different recommendation than UAC on the Palo Alto CLEAN program. He asked if there is any way for the UAC to do something about the issue. Senior Deputy City Attorney Jessica Mullan said that citizens can contact Council and provide comments at the Council meeting. Commissioner Danaher reminded Chair Foster that he was struggling with the justification for the high CLEAN price given the low prices obtained for long-term renewable contracts and advised him not to speak too vehemently when representing all commissioners at the Council meeting. Chair Foster asked that the minutes from the discussion could be send to him. Commissioner Ballantine said that the Palo Alto CLEAN program does nothing to improve the reliability of the City’s distribution system unless smart inverters are required. Utilities Advisory Commission Minutes Approved on: Page 4 of 12 COMMISSIONER COMMENTS Chair Foster said that he would not be able to attend the next scheduled meeting on April 6 and noted that there may not be a quorum. Interim Director of Utilities Shikada said that staff will determine options for alternative days and poll commissioners. Chair Foster appointed Commissioners Danaher and Ballantine to an ad hoc budget committee to review CPAU’s FY 2017 CIP and operating budgets. UNFINISHED BUSINESS None. NEW BUSINESS ITEM 1: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that the City Action Council Adopt: (1) a Resolution Approving the Fiscal Year 2017 Wastewater Collection Financial Plan; and (2) a Resolution Increasing Wastewater Rates by Amending Rate Schedules S-1 (Residential Wastewater Collection and Disposal), S-2 (Commercial Wastewater Collection and Disposal), S-6 (Restaurant Wastewater Collection and Disposal) and S-7 (Commercial Wastewater Collection and Disposal – Industrial Discharger) Acting Rates Manager Eric Keniston provided a summary of the written report. He said that the forecast of costs and rate changes has not changed from what the UAC saw last month when it reviewed the preliminary financial projections. He said that the primary driver for the 9% rate increase requested as well as the rate increases projected for the next several years is that the costs of wastewater treatment are rising quickly. He noted that the Rate Stabilization Reserve would be exhausted by the end of f iscal year (FY 2016 and that the Operations Reserve is being drawn down as well. He said that the long-term rate projections assumed continuing increases in treatment costs as well as operational costs. Keniston noted that the 9% rate increase proposed is exactly what was projected in last year’s Financial Plan. He noted that the rate trajectory in this year’s Financial Plan result in the Operations Reserve going down to the minimum level in FY 2018 and FY 2019 before increasing to the target level by FY 2022. He said that the 9% increase is the same for all customer groups and that the increase for residential customers is $2.88 per month. Keniston said that at its meeting last month, the UAC asked for scenarios showing the Operations Reserve held to the minimum level and at the target level. He showed the in the minimum reserve scenario, the FY 2017 rate increase could be held to 5% instead of 9%, but that the rate increase for FY 2018 would be 19%. For the target reserve scenario, the FY 2017 rate increase would have to be 16% for FY 2017, following by a 9% increase in FY 2018 with somewhat lower rate increases in the following years. After developing these alternate scenarios, staff did not change its recommendation for a 9% rate increase for FY 20 17. Commissioner Danaher, noting that the reserve minimum is only about $2 million, asked what would be done if the revenues were not sufficient and more money was needed. Keniston said that a rate increase would be pursued if that ever arose. Such a mi d-year rate increase would need to go through the normal review process starting with the UAC, then consideration by the Utilities Advisory Commission Minutes Approved on: Page 5 of 12 Finance Committee—and the Proposition 218 45-day noticing process—with final decision by the Council. Commissioner Ballantine asked if there is always enough notice of what its needs are going to be. Keniston noted that in the Wastewater Collection Utility, the expense profile is fairly flat and known ahead of the year and there shouldn’t be a surprise need for extra money. Commissioner Ballantine asked if revenues could fall due to drought due to lowered water usage. Keniston said that rates for this fund are generally independent of water usage with only the commercial wastewater collection customers having revenues depend on relati vely steady wintertime water usage. Residential revenues are the majority of the fund’s revenues and are based on a flat monthly charge so there is no variability due to changes in water usage. Commissioner Danaher asked, if usage falls, do costs go down. Keniston responded that the costs are fixed and revenues are also mostly fixed in the Wastewater Collection Utility and, therefore, not dependent on the flow rate. Keniston said that the residential rates have no element that is based on water flows. Commissioner Eglash noted that the real cause for the dramatic rate increase seems to be the wastewater treatment costs. He asked why those costs rose so much from FY 2014 to FY 2015 and from FY 2015 to FY 2016. Keniston introduced Jamie Allen, Regional Water Quality Control Plant Manager, to describe the components of the treatment plant costs that are passed on the plant partners, including Palo Alto. Allen explained that there was an accounting change that lowered the costs for one year in FY 2014 so that year’s costs are anomalous. He said that the majority of the wastewater treatment costs are operations costs with two categories of capital improvement program (CIP) costs—“minor”, or rate-funded CIP and major CIP debt service. Operations costs are expected to grow at the same rate it has for the last 5 years —at about 5.5% per year and CIP costs are discussed with the plant partners and minor CIP costs grow at about the rate of inflation, about 2.6% per year. Major CIP debt service is for planned plant upgrades. Allen showed a breakdown of the FY 2017 wastewater treatment costs: 47% for salaries and benefits for operators, engineers, chemists, etc.; 12% for allocated charges for services provided by the City such as HR, attorney, IT, finance, etc.; 9% for utilities expenses (electric, gas, water); 11% for minor CIP projects; 7% for contract services; 3% for debt service for major CIP projects; and 10% for general expense and supplies and materials. Commissioner Eglash summarized this to say that minor CIP are only modestly growing, major CIP expenses are growing from about $0.5 million per year to $2 million per year and that operations expenses are growing by 5.5% per year, a modest and steady rate. He noted that the charts showed that expenses were lower than revenues for FY 2014 and FY 2015, which replenished the reserves. In FY 2016, costs were above revenues. He said that rate increases on the order of 9% per year for the forecast horizon period don’t make sense and are impossible to explain to the public when treatment costs are only rising 5.5% per year. Keniston said that CIP expenditures were lower for the wastewater collection (not for wastewater treatment) in FY 2014 and FY 2015, but that CIP costs are projected to increase over the forecast pe riod. Utilities Advisory Commission Minutes Approved on: Page 6 of 12 Commissioner Eglash concluded that, based on the numbers, an increase in treatment cost is not the real cause of the high rate increases forecast, but instead there was a period of time when costs were rising, but no rate increases were put into pla ce, which resulted in a drawing down of reserves. Keniston said that reserves will be drawn down in FY 2016 through FY 2018 until revenues balance expenses. Commissioner Eglash agreed that reserves have been depleted over time. Commissioner Danaher asked for an explanation of the difference between wastewater treatment costs and wastewater collection costs. Keniston said that the wastewater treatment fund’s expenses are paid by the plant partners including Palo Alto and that those wastewater treatment costs are an expense for the wastewater collection utility. Interim Utilities Director Shikada said that the wastewater conveyance is a Utilities activity and that wastewater treatment is a Public Works activity and that the combined costs are paid for by ra tepayers. Wastewater Collection Utility expenses include the treatment costs, which are a pass through expense from the wastewater treatment plant. Commissioner Schwartz noted that the wastewater collection operations costs increased significantly from FY 2015 to FY 2016. Keniston said that this was due to a one-year accounting anomaly. Assistant Director Jane Ratchye said that the three primary costs buckets for the wastewater collection fund include: 1) operations costs for wastewater collection, whic h are rising at 2-3% per year; 2) CIP costs for wastewater collection, which are rising at 2-3% per year; and 3) wastewater treatment costs, which are rising at 5-6% per year. The treatment costs that are passed through to the wastewater collection utilit y are the main driver for increasing costs—and, therefore, rates. Allen pointed out that his breakdown of the wastewater treatment expenses showed the costs in terms of operations, minor CIP and major CIP debt service. He noted that there was a major jump in major CIP debt service in FY 2019 when the dewatering facility would go on line. Commissioner Eglash reiterated the difficulty in explaining that total wastewater collection expenses are rising at 4-5% per year, but we are asking for rate increases of 9-10% per year without driving the reserves below the minimum. He said that a better explanation must be forthcoming or the projected expenses should be reduced. Public Comment Herb Borock said that wastewater treatment plant costs estimates for the future are increasing dramatically, but that no explanation has been provided for the CIP plans at the treatment plant. He said that Council has approved a plan to replace the incinerator with a dewatering and load-out facility and that the current plan is to have an anaerobic digester at the plant. He said that the cost for the anaerobic digester keep increasing dramatically. He said it’s unclear what assumption is in the cost projections regarding what happens after the incinerator is dismantled – will we keep using the haul out facility, or will something be built on site to handle the sludge. Trying to predict future costs depends on the plan and how easy it would be for Council to change direction. He said that the long-term facilities plan at treatment plant should be reviewed again by Council since there are choices about what to do that have impacts on greenhouse gas emissions. He also commented on the Proposition 218 noticing process saying Utilities Advisory Commission Minutes Approved on: Page 7 of 12 that the Council should support the rate proposals prior to s taff issuing the Proposition 218 notices. Commissioner Eglash said that in order to support the proposal, he would need a better understanding of the revenues and expenses over the years. Ratchye pointed to page 24 of the Wastewater Collection Financial Plan (Appendix A: Wastewater Collection Financial Forecast Detail) that is attached to the UAC memo and reminded the UAC that the reserve structure was changed in FY 2015 to lower the reserve amounts and that at the time of the change, there was significant money in the reserves that was placed initially in the new Rate Stabilization Reserve, which would normally have a zero balance. Over FY 2015 and FY 2016, all the funds in the Rate Stabilization Reserve will be drawn down to zero. She said that reserves were being drawn down in FY 2011, FY 2012, and FY 2013, then there were two anomalous lower cost years —in FY 2014 when there was a one-year hiatus in new CIP budgeting and in FY 2015 when reduced operations expenses due to an accounting anomaly—when reserves were somewhat replenished. However, underlying those anomalies, costs were rising and revenues were not keeping pace. As shown on page 24 of the plan, reserves will be drawn down again in FY 2016, FY 2017 and FY 2018 before revenues catch up with expenses. She said that rate increases need to be significant to get revenues to the levels that are needed to cover expenses. Commissioner Eglash said that his understanding from that explanation is that we’ve allowed revenues to fall below expenses during the last few years and we did that because costs were increasing steadily and we chose not to increase rates. The reason we did not increase rates is that reserves were available to draw on. In addition, there were two years with anomalously low cost that somewhat replenished reserves, but we are now at the point when we must increase revenues. He said that he can now see this on page 24 of the plan (line 20: into/(out of) reserves), which shows that reserves were drawn down in FY 2011 through FY 2013, were replenished in the anomalous years of FY 2014 and FY 2015, but that reserves will be drawn down again in FY 2016, FY 2017 and FY 2018 before revenues cover expenses. He said that reviewing line 18: (total uses of funds) sho ws that expenses increased slightly from FY 2012 to FY 2013, but increased about $3.6 million from FY 2013 to FY 2016 ignoring the anomalous years of FY 2014 and FY 2015. Then costs increase by about 5% from FY 2017 and onward. He said that the costs increases have been hidden from customers. He said that even with adding $4 million to reserves in FY 2014 and FY 2015, that a 9% increase in revenue is needed. He said that it seems like with costs increasing at about 5% per year, we should be fine with 5% per year rate increases. Ratchye pointed out that a one -time adjustment into reserves doesn’t help much with ongoing cost increases whereas a 9% rate increase raises revenue to a new base level upon with a subsequent 9-10% rate increase will increase revenues even more with the power of compounding. Commissioner Eglash said that he was beginning to understand the issue by examining the lines on page 24 of the plan showing the “Total Sources of Funds” and the “Total Uses of Funds,” which show that revenues have not been keeping up with expenses for years. Keniston says that revenues have not kept up with expenses for a period beyond the years shown on the chart on page 24 and was the case in FY 2009 and FY 2010 as well. Commissioner Eglash said that we have been in a long period when rates provided insufficient revenues to cover normal year expenses (ignoring FY 2014 and FY 2015). He asked how revenues could lag expenses for Utilities Advisory Commission Minutes Approved on: Page 8 of 12 up to 7 years. Ratchye said that the answer to that question is that reserves were h igh and that the anomalous two years of lower expenses made calling for rate increases hard to justify. In addition, the change to the reserve structure in FY 2015 lowered the amount of reserves that were considered sufficient—and this is the case for all funds, not just the Wastewater Collection Fund. Commissioner Eglash said that the reserves were reduced when we realized that we had more than we needed and we’ve been slowing consuming them over the years and that all customers have been the beneficiaries for several years of holding the line on rates by using the financial reserves. The day of reckoning has been delayed due to the two anomalous years of low expenses. He said that with no rate increase, we would have a $3 million deficit and we don’t have enough reserves to cover that and we need to get back to a place where income covers expenses and staff’s proposal phases in rate increases so that we don’t get to that place until FY 2019. Commissioner Schwartz agreed that the public has been insulated from the increasing costs so now we need to raise rates to cover costs. This can be presented as saving the customers over the last several years when rate increases were low. Commissioner Eglash said that a chart comparing revenues to costs would show t he years when there was a deficit and costs were not covered by revenues and for how long this went on. It is the same as if your salary was staying the same, but rent climbs and when you deplete your savings, you have a problem and can’t afford the rent. Chair Foster said that the Council made decisions in past to delay rate increases and now the rates must increase. He said that he recalls that in the past several years, moderate rate increases could have been proposed, but the case for them was somewha t borderline and that there was value in a zero rate increase for the community knowing that , sooner or later, the rates would have to increase. Ratchye agreed and recalled that these conversations occurred every year; for example, last year, staff proposed a 3% gas rate increase followed by a 4% increase the following year, but the feedback was that a 3% increase was so low that it’s not worth it and would be better to have no rate increase and a 7% in the following year. Chair Foster said that there is a desire to insulate customers from rate increases and that, even with a delayed higher rate increase, the customers are not actually paying more over the whole period. Commissioner Ballantine noted that (on the chart on page 24) the allocated charges (line 12) are anomalously low in FY 2015 and that for FY 2016 and forward, those costs are rising. He said that the low cost in FY 2015 could be due to an operational cost saving that year that could be found in future years, but the future forecasts do not include any cost savings that may actually accrue. Commissioner Eglash pointed out the reduced cost for FY 2014 could be repeated in the future, but that the projections show costs only increasing, which may not reflect reality. Ratchye pointed out that the reduced CIP costs in FY 2014 was a cause for con sternation in the past as the UAC and Council was concerned that it signaled a slowdown in infrastructure replacement. Utilities Advisory Commission Minutes Approved on: Page 9 of 12 However, it was only a pause in new funding for CIP to allow staff to catch up to CIP projects in the queue. She also pointed out that the allocated cost line item referred to by Commissioner Ballantine is not related to operational cost savings, but are the costs allocated from the services provided by the City such as HR, City attorney, finance department , etc. and that the reduced charges in FY 2015 were related to an accounting anomaly. Both these one -time cost reductions are not related to finding efficiencies were found and that these efficiencies won’t be found in the future. Commissioner Eglash said that he was now adequately satisfied with the explanations for the need for the rate increase and supports going forward with the staff recommendation. ACTION: Commissioner Danaher made a motion that the UAC recommend that the Council adopt resolutions approving the FY 2017 Wastewater Collection Financial Plan and increasing wastewater rates by amending Rate Schedules S-1 (Residential Wastewater Collection and Disposal), S-2 (Commercial Wastewater Collection and Disposal), S-6 (Restaurant Wastewater Collection and Disposal) and S-7 (Commercial Wastewater Collection and Disposal – Industrial Discharger). Commissioner Schwartz seconded the motion. The motion carried unanimously (5-0) with Chair Foster, Commissioners Ballantine, Danaher, Eglash, and Schwartz voting yes and Vice Chair Cook and Commissioner Hall absent. ITEM 2. ACTION: Selection of Potential Topic(s) for Discussion at Future UAC Meeting ACTION: None. ITEM 3. ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that the City Council Adopt: (1) a Resolution Approving the Fiscal Year 2017 Water Utility Financial Plan; and (2) a Resolution Increasing Water Rates by Amending Rate Schedules W-1 (General Residential Water Service), W-2 (Water Service from Fire Hydrants), W-3 (Fire Service Connections), W-4 (Residential Master-Metered and General Non-Residential Water Service), and W-7 (Non-Residential Irrigation Water Service) Interim Rates Manager Eric Keniston summarized the written report and noted that the wholesale cost of water from the San Francisco Public Utilities Commission (SFPUC) for FY 2017 was reduced since the February meeting when the UAC reviewed the preliminary financial forecast. That means that the rate increase proposed for FY 2017 is 6%, rather than the 9% projected in the preliminary forecast. Keniston noted that, as in wastewater collection, expenses have been lower than revenues for several years and that there was a hiatus in new CIP funding in FY 2013, which lowered overall costs that year. The biggest driver for increasing water costs is the cost of SFPUC water due both to higher SFPUC costs and the impact of the drought. Reserves have been reduced over the last several years, but the Rate Stabilization Reserve will be exhausted by the end of Fy 2016. Staff’s rate proposal is to continue the drought surcharge that Council imposed as of September 1, 2015. The plan to separate out the cost of water supply is not being proposed this year, but will be revisited next year. Utilities Advisory Commission Minutes Approved on: Page 10 of 12 Keniston noted that the proposed 6% rate change for FY 2017 is less than the 8% rate adjustment that was projected in last year’s financial plan, but a rate adjustment of 9% is projected for FY 2018, which is higher than the 8% FY 2018 rate increase projected in last year’s financial plan. However, he cautioned that the rate projections are very dependent on the drought situation. The plan results in the Water Operations Reserve being above the minimum reserve level over the entire forecast period. The bill impact for the proposed rate increase will be almost the same for all customer classes and will add about $4.73 per month for the median residential customer. Keniston said that staff evaluated an alternate scenario with the Operations Reserve held at the minimum level. This would allow for no rate increase in FY 2017, but that would require an 18% rate increase in FY 2018, which staff does not recommend. A scenario with the Operations Reserve held at the target level would require a 3% rate increase in FY 2017 followed by a 20% rate increase in FY 2018, which staff does not recommend. Public comment Herb Borock said that under Proposition 218, residents can object to rate increases and, therefore, Council should be the one making a decision as to whether the rate proposal is the one that is noticed to property owners. Now this notice is sent out after Finance Committee weighs in, rather than before returning to Council. This comment goes to when the process should start. Now Council does not see the proposal until it’s the final decision. An extra step of going to Council should be figured into the process and timing. Commissioner Danaher referred to Appendix A of the FY 2017 Water Financial Plan and asked why line 25 (Other Revenues and Transfers in) was so variable over time. Keniston said that these transfers come from a large variety of sources and can range from reimbursement from other funds for projects or grant funds and that there can be large swings year to year for that line item. Pointing to line 29 (Water Purchases), Commissioner Danaher asked if this is for the water purchased from the SFPUC and asked if these costs were rising as the wholesale cost of water increased. Keniston confirmed that understanding. Commissioner Danaher noted that line 43 (Capital Program Contribution) rose in FY 2016 and asked if this was planned. Keniston confirmed that understanding. Commissioner noted that even after the proposed 6% rate increase, revenues would still be over $5 million less than expenses in FY 2017. Keniston confirmed that conclusion. Commissioner Danaher asked if staff is comfortable with a 6% increase in FY 2017. Keniston said that staff is comfortable with the proposal at this point. Commissioner Schwartz said that since this situation has been years in the making, it would be best to show more historical years on the charts. Also, is there a chance to time the rate increases so that they don’t all come into place at the same time. She said that implementing a water rate increase in the summer when people use more water is more painful and implementing a gas rate increase in the winter when people use more gas is more painful and that, if there is some flexibility, timing the increases could be beneficial. Interim D irector Shikada explained that the budgetary timing is important since the budgets are built on the idea of a full budget year of revenues as well as expenses. He said that the impact on the customers as well as the funds need to be considered, since if a rate increase is delayed, a larger increase may be required in the future. Commissioner Schwartz said that we need to be responsible and Utilities Advisory Commission Minutes Approved on: Page 11 of 12 cover our expenses, but timing could be considered. How does our water rates compare to other neighbors. Keniston referred to the bill comparisons in the Financial Plan (page 13) which shows that Palo Alto’s current rates are higher than in the neighboring communities. Commissioner Schwartz said that, given the experience of Flint Michigan, we want to make sure to spend the money to continue to have the top quality water. We don’t want to reduce expenses dramatically in this area. At the State of the City address by Mayor Burt, Commissioner Schwartz talked to someone who perceived that there have been large rate increases over the last several years, but when told that the increases were not large and sometimes zero, we are making sure costs are covered—this is something people can understand since it’s something we have to responsibly do. Commissioner Eglash asked why we have the highest monthly water bill. Keniston referred to a benchmark study done a couple of years ago, which showed that CPAU does more infrastructure improvements and system maintenance than other agencies. A recent large expense was the emergency water supply and storage project to rehabilitate wells, drill new wells and construct a new water storage reservoir increased costs as well. These proactive measures make a reliable system, but cause our rates to be higher. Commissioner Eglash said that expenses rose 15% from FY 2015 to FY 2016 and rates did rise 12%, but revenues actually dropped by 4% since customers used much less water in response to the State’s call for water use reductions in the drought. So, clearly, a significant gap is developing and this supports the recommendation for the 6% rate increase, which would avoid the problem we have with wastewater collection where we let a too large deficit develop requiring large continued rate increases. In the case of the water utility, this is exa cerbated by the loss in revenue associated with reduced usage. Commissioner Ballantine asked if the City has any lead pipe in its distribution system. Keniston said that the City has no lead pipes in its system. Commissioner Ballantine asked why the bill impact shown in Table 8 of the Financial Plan (page 8) shows a smaller impact for the largest water users, but he did the math and found that the difference is not actually very in percentage terms. The 6% bill impacts shown actually range from 5.6% to 5.8% and the 5% impact for the largest users is actually 5.49%. Keniston confirmed that the chart rounds off the bill impact to the nearest whole number percentage value. Commissioner Ballantine asked if the difference from low users to high users is due to the fact that all customers must pay a fixed monthly service charge. Keniston confirmed that this is the case. ACTION: Chair Foster made a motion that the UAC recommend that the Council adopt resolutions approving the FY 2017 Water Financial Plan and increasing water rates by amending Rate Schedules W-1 (General Residential Water Service), W-2 (Water Service from Fire Hydrants), W- 3 (Fire Service Connections), W-4 (Residential Master-Metered and General Non-Residential Water Service), and W-7 (Non-Residential Irrigation Water Service). Commissioner Danaher seconded the motion. The motion carried unanimously (5-0) with Chair Foster, Commissioners Ballantine, Danaher, Eglash, and Schwartz voting yes and Vice Chair Cook and Commissioner Utilities Advisory Commission Minutes Approved on: Page 12 of 12 Hall absent. The motion carried unanimously (5-0) with Chair Foster, Commissioners Ballantine, Danaher, Eglash, and Schwartz voting yes and Vice Chair Cook and Commissioner Hall absent. ITEM 4. DISCUSSION: Update and Discussion on Impacts of Statewide Drought on Water and Hydroelectric Supplies Assistant Director Ratchye provided an update on the ongoing drought. She said that there is not much new this month since February was very dry, but March should be wetter. Customers continue to save water and the City continues to exceed its state mandate for water use reduction for the compliance period of June 2015 through October 2016. The entire SFPUC service area has exceeded the combined savings goals as well. The precipitation at Hetch Hetchy is above normal through the middle of February. The impact of the drought on the electric utility, which normally gets about half its supplies from hydroelectric resources , is an increase in costs for FY 2016 costs of about $9.6 million. Meeting adjourned at 8:51 p.m. Respectfully submitted, Marites Ward City of Palo Alto Utilities Page 1 of 16 1 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: April 12, 2016 SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend that the City Council Adopt 1) a Resolution Approving the Fiscal Year 2017 Electric Financial Plan and Amending the Electric Utility Reserves Management Practices, and 2) a Resolution Increasing Electric Rates by Amending the E-1, E- 2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU, E-14, and E-16 Rate Schedules, and Repealing Rate Schedules E-18 and E-18-G REQUEST Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council: 1. Adopt a resolution (Attachment A) amending the Electric Utility Reserve Management Practices and approving the fiscal year (FY) 2017 Electric Financial Plan (Attachment B); and 2. Adopt a resolution (Attachment D) amending Rate Schedules E-1 (Residential Electric Service), E-2 (Small Commercial Electric Service), E-2-G (Small Commercial Green Power Electric Service), E-4 (Medium Commercial Electric Service), E-4-G (Medium Commercial Green Power Electric Service), E-4 TOU (Medium Commercial Time of Use Electric Service), E-7 (Large Commercial Electric Service), E-7-G (Large Commercial Green Power Electric Service), E-7 TOU (Large Commercial Time of Use Electric Service), E-14 (Street Lights), and E-16 (Unmetered Electrical Service) and Repealing Rate Schedules E-18 (Municipal Electric Service) and E-18-G (Municipal Green Power Electric Service). EXECUTIVE SUMMARY The FY 2017 Electric Utility Financial Plan includes projections of the utility’s costs and revenues through FY 2023. Costs are projected to rise substantially for the next several years for several reasons. First, costs for electric supply purchases are increasing as a result of new renewable energy projects coming online. Increases in transmission costs are also projected. Substantial additional capital investment in the electric distribution system is planned for FY 2017 through FY 2023, and operational costs are increasing. Page 2 of 16 To offset these rising costs, an increase in sales revenues is required. An 11% rate increase is proposed for July 1, 2016, and another 10% increase is projected July 1, 2017. While staff would normally attempt to spread these rate increases across more than two years to reduce the single-year ratepayer impact, higher power supply purchase costs due to the drought have reduced operational and other reserves substantially, making this infeasible. Staff proposes various reserves transfers to limit the rate impact to 11%, as described later in this report. While 11% is the overall increase in sales revenues, actual rate increases for each customer class will differ as a result of rebalancing of the cost allocation between customer groups as determined by the new cost of service analysis (COSA). In anticipation of the July 1, 2016 rate change, staff hired EES Consulting to perform a COSA to determine the cost of service for various customer classes and what revenues should be collected fro m each group. The analysis showed that some customer groups are closer to cost of service than others, so some groups will experience increases higher than 11%, while others will see lower increases. In addition, customers with different consumption patterns will see different changes in their bills as a result of a restructuring of the rate design for some customer classes. In addition to the recommended rate and revenue changes, staff recommends a change to the Electric Utility Reserves Management Practices to modify the minimum and maximum guidelines for the CIP Reserve. BACKGROUND Every year staff presents the UAC with Financial Plans for its Electric, Gas, Water, and Wastewater Collection Utilities and recommends any rate adjustments required to maintain their financial health. These Financial Plans include a comprehensive overview of the utility’s operations, both retrospective and prospective, and are intended to be a reference for UAC and Council members as they review the budget and staff’s rate recommendations. Each Financial Plan also contains a set of Reserves Management Practices describing the reserves for each utility and the management practices for those reserves. Staff occasionally proposes amendments to these reserves as part of the Financial Plans. When the Financial Plan reveals that operational costs are increasing beyond sales revenues , staff typically recommends rate changes. These rates are designed to collect revenues equal to the cost to serve each customer or customer group. It is industry practice to periodically perform a COSA to ensure that a utility’s rates recover revenues equal to the costs to serve customers. This is particularly important for the electric utility due to ch anges to the state constitution that have taken place since the last time electric rates were changed on July 1, 2009. Since then, Proposition 26 (2010) amended the California Constitution, which defines all government-imposed charges, including electric rates, as taxes requiring voter approval, unless certain exceptions are met. Cost-based electric rates may be adopted by the City Council. The COSA helps the utility ensure that rates match the cost to serve customers. Page 3 of 16 DISCUSSION Summary of Proposed Actions The two resolutions recommended for Council adoption will accomplish the following: 1. Increase overall electric rates by 11% effective July 1, 2016. 2. Align rates for individual rate classes with the attached COSA to ensure all ratepayers are charged according to the cost of serving them; 3. Approve various reserves transfers for FY 2016 and FY 2017; 4. Add a minimum charge to all rate schedules to ensure that, at minimum, the direct customer service costs are collected; 5. Modify the residential rate schedule to include two tiers instead of three; 6. Eliminate the municipal rate schedules, E-18 and E-18-G. All municipal customers will be moved to the appropriate commercial rate schedule; 7. Update street light and traffic signal rate schedules to reflect lighting and signal infrastructure currently installed, including LED lighting; and 8. Amend the Electric Utility Reserves Management Practices to modify the minimum and maximum guidelines for the CIP Reserve. Proposed and Projected Sales Revenue Requirement, FY 2017 through FY 2023 Table 1 shows the sales revenue increases needed to recover costs of operation over the forecast period in the FY 2017 Electric Financial Plan. Table 1: Projected Electric Rate Adjustments, FY 2017 to FY 2023 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 11% 10% 2% 0% 1% 0% 0% These sales revenue increases are for the utility as a whole, but the rate changes will differ for individual customer classes. Proposed rate increases for each customer class are discussed below. Changes from Prior Financial Forecasts This projection has changed since the FY 2016 Electric Utility Financial Plan presented last year. Staff has projected future electric rate increases for many years. Table 2 compares current rate projections to those projected in the last two year’s Financial Plans. As shown, the FY 2017 rate projections are higher than projected the last two years wh en the ongoing drought was not projected to be as long or severe as it has been, so the current rate increase projections are generally higher than in prior years. Page 4 of 16 Table 2: Projected Electric Rate Trajectory for FY 2017 to FY 2023 Projection FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Current (FY 2017 Financial Plan) 11% 10% 2% 0% 1% 0% 0% Last year (FY 2016 Financial Plan) 6% 6% 1% 1% 0% 0% 2% Two years ago (FY 2015 Financial Plan) 3% 3% 2% N/A N/A N/A N/A The original 6% rate increases were primarily related to increases in power supply purchase costs resulting from increasing transmission costs and the cost of renewable projects coming online. These same factors are driving the higher rate projections in the FY 2017 Electric Utility Financial Plan, but some additional operational and capital costs have been added. One key issue is the extent and duration of the ongoing drought, which has increased costs and drawn down reserves more than anticipated. Additionally, substantial additional capital investment in the electric distribution system is planned for FY 2017 through FY 2023, as will be apparent in the FY 2017 Proposed Capital Budget. Operational costs are also increasing more than projected. This is partially due to an increase in allocated administrative overhead costs and partially due to deferred maintenance resulting from challenges in retaining staff in certain maintenance classifications. Even when large rate increases are needed, staff typ ically attempts to keep increases below 10% per year, but this is not possible for FY 2017 and FY 2018. The proposed rate increases for FY 2017 and FY 2018 might have been phased in more gradually with adequate reserves, but higher power supply purchase costs due to the drought have reduced operational and other reserves substantially. Because of lower output from hydroelectric resources, the City has had to purchase additional energy in the markets, and the cost of these market power purchases have come from reserves. As a result, these reserves cannot be used to phase in the rate increases over more years as they have served to insulate ratepayers from cost increases experienced in the last two years. This Financial Plan still contains some measures to mitigate the impact on ratepayers, however. The July 1, 2016 rate increases would have to be substantially higher without a proposed transfer from the Supply Rate Stabilization Reserve (see below). In addition, this Financial Plan allows the Supply Operations Reserves to be up to $3.9 million below the minimum Supply Operations Reserve level for FY 2017 through FY 2020. To keep the Supply Operations Reserve above the minimum guideline, a 14% rate increase would be required in FY 2017. Staff recommends allowing Supply Operations Reserves to temporarily go below minimums for two reasons: first, due to the presence of a strong El Niño condition in the Pacific Ocean, there is a chance of high spring rains that may change this forecast, resulting in higher reserv es, and second, the presence of the $51 million Electric Special Projects Reserve means that a relatively small temporary shortfall in the Supply Operations Reserve should not affect the Electric Utility’s bond ratings. In the event the drought continues, staff will re-evaluate its projections Page 5 of 16 for FY 2018 and may recommend additional rate increases or the adoption of a hydroelectric rate adjuster. Note that the Financial Plan’s Reserves Management Practices allow the Operations Reserve to fall below the minimum guideline level as long as the plan provides for replenishing the reserve over time. Rate Changes by Customer Class Table 3 shows the sales revenue changes needed for each customer class. All recommended sales revenue changes and the rates used to recover that revenue are based on the cost of service methodology established in the attached “City of Palo Alto Electric Cost of S ervice and Rate Study” by EES Consulting, Inc. (Attachment C). As mentioned above, while total sales revenue needs to increase 11% for FY 2017, the increase in sales revenue is different for each customer class. This is a result of changes in consumption patterns since the last rate change. More specifically: Energy consumption and demand1 has decreased for the E-1 (Residential)2 class of service. E-2 (Small Non-residential) energy consumption and demand has increased . E-4 (Medium Non-residential) energy consumption has decreased, but demand has increased. E-7 (Large Non-residential) energy consumption and demand has increased . The energy consumption for the E-18 class of service has stayed roughly the same, but the demand has increased. The street light and traffic signal class reflects additional revenues associated with charging for maintenance and operation of City-owned street lighting, which was not included in previous rate schedules. 1 Demand represents the customer class’s highest power consumption in a specified period of time (e.g. the highest 15-minute average power consumption within a month) and is measured in kW. This is in contrast to an energy charge, which is measured in kWh, and represents the total energy consumption over the entire period. 2 While this class of service is named “Residential Electric Service,” it does not include 100% of residential use. Some master-metered multi-family residential buildings take service under other rate schedules. Page 6 of 16 Table 3: Revenue Changes Required for Each Customer Class Customer Class Projected FY 2016-17 Revenues under Rates Currently in Effect FY 2016-17 Revenue Requirement Per COSA Revenue Increase needed E-1 (Residential) $18,406,003 $20,785,989 13% E-2 (Small Non-Residential) 9,421,113 10,019,138 6% E-4 (Medium Non-Residential) 38,382,821 42,680,642 11% E-7 (Large Non-Residential) 41,216,279 42,441,354 3% E-18 (Municipal) 3,044,789 4,463,490 47%3 E-14/E-16 (Street/Traffic Lights) 60,477 2,097,367 3368%4 Total Sales Revenue Requirement $110,531,481 $122,487,979 11% Table 4 shows the rates that will be used to recover the sale revenues for each customer class The Municipal (E-18) rate class, the Street Lighting (E-14) class, the Non-Metered Service (E-16) class, and the E-4 and E-7 Time of Use (TOU) rates are not shown in the table, but can be seen in the attached COSA (Attachment C). These three schedules are omitted for various reasons: the Municipal class is recommended for repeal as of July 1, 2016, the E-14 and E-16 rate schedules are not easy to summarize, and the E-4 and E-7 TOU rates are not easy to summarize and are only used by one customer. Note that many of the components of the rate schedules are being realigned. For example, tiers two and three of the E-1 residential rate schedule are being combined, and summer and winter energy rates for non-residential customers are being realigned. This means that the rate changes will have different effects on customers depending on their consumption patterns. These realignments are needed to accurately collect the costs of serving these customer groups. Both the tier structure and the amount of energy included in Tier 1 are changing. The new Tier 1 allowance is based on the year-round baseload usage of the median customer. The second tier represents peak consumption and the costs associated with that peak. Another significant change to the rate schedules is the addition of a minimum charge. Palo Alto’s current electric rates are very unusual among California utilities, since Palo Alto is one of the only electric utilities without a fixed or a minimum charge. A minimum charge, unlike a fixed charge, is only incurred when a customer’s bill falls below a minimum level, and it has less of an impact on low and medium energy users than a fixed charge. A minimum charge ensures the collection of revenue to cover the direct costs of operations that are incurred regardless of how low usage is. This includes items like customer billing, meter reading, accounting, and certain types of distribution costs. For E-1 customers, this charge is around $9.21/month, equal to roughly 85 kWh of consumption per month. Roughly 7% of residential customers have bills 3 This rate class is recommended for repeal. Customers in this class will be moved to the E-2, E-4, and E-7 customer classes. 4 This increase in revenue will primarily come from expanding the billing of street lights and traffic signals to cover all lights and signals rather than through rate increases. Page 7 of 16 lower than 85 kWh at one time or another throughout the year, but only 2% of residential customers have such low bills on an ongoing basis. Table 4: Electric Rates (Current and Proposed) Current Rates Proposed Rates (7/1/16) Change $ % E-1 (Residential) Tier 1 Energy ($/kWh) 0.09524 0.11029 0.01505 16% Tier 2 Energy ($/kWh) 0.1302 0.16901 0.03881 30% Tier 3 Energy ($/kWh) 0.17399 0.169011 (0.00498) -3% Minimum Charge ($/day) - 0.3067 0.3067 E-2 (Small Non-Residential) Summer Energy ($/kWh) 0.14045 0.16845 0.02800 20% Winter Energy ($/kWh) 0.12661 0.11445 (0.01216) -10% Minimum Charge ($/day) - 0.7657 0.7657 E-4 (Medium Non-Residential) Summer Energy ($/kWh) 0.08171 0.10229 0.02058 25% Winter Energy ($/kWh) 0.07318 0.08049 0.00731 10% Summer Demand ($/kW) 20.54 19.68 (0.86) -4% Winter Demand ($/kW) 13.84 14.04 0.20 1% Minimum Charge ($/day) - 16.3216 16.3216 E-7 (Large Non-Residential) Summer Energy ($/kWh) 0.07808 0.08749 0.00941 12% Winter Energy ($/kWh) 0.07209 0.06242 (0.00967) -13% Summer Demand ($/kW) 18.97 18.34 (0.63) -3% Winter Demand ($/kW) 11.54 15.65 4.11 36% Minimum Charge ($/day) - 48.5054 48.5054 1 Proposed E-1 Rates have two tiers Table 5 shows the impact of the proposed July 1, 2016 rate changes (excluding any drought surcharges) on the residential and non-residential bills for various consumption levels. While the overall rate change for the residential class is roughly 14%, bills will increase more for residents with lower electric usage than those with higher usage. Page 8 of 16 Table 5: Impact of Proposed Electric Rate Changes on Customer Bills Rate Schedule Usage (kwh/mo) Bill under Current Rates ($/mo) Bill Under Rates Proposed 7/1/16 ($/mo) Change $/mo % E-1 300 28.57 33.09 4.51 16% (Summer Median) 330 32.48 36.39 3.92 12% (Winter Median) 453 48.49 57.18 8.69 18% 650 76.33 90.48 14.14 19% 1200 172.03 183.43 11.40 7% E-2 1,000 134 142 8 6% E-4 160,000 18,364 21,553 2,167 11% E-7 500,000 43,319 43,862 1,318 3% E-7 2,000,000 216,594 219,310 6,591 3% Figure 1 shows an estimate of the impacts of the proposed rate changes on customers at various income levels. Income is shown as a percentage of Palo Alto median income ($172,000 for a single-family customer and $133,000 for a multi-family customer).5 The estimate assumes that customers in the lowest incomes levels6 are on the City’s Rate Assistance Program (RAP). There are roughly 700 RAP customers in Palo Alto, 400 in multi-family dwellings and 300 in single-family dwellings. Currently the large majority of customers pay 1% or less of their income for electricity. These rate increases and redesigns will increase that by roughly 15%-18% for most customer classes (e.g. from 1% of income to 1.15% of income), and will not affect low-income customers substantially differently than higher income customers even though, on average, customers in the City’s RAP use less electricity than other custo mers. Customers in multi-family homes mostly consume electricity in the first tier, and they will see a smaller rate increase than customers in single-family homes because the first tier is increasing by a smaller percentage than the second tier. This comparison holds true both for RAP customers and non -RAP customers. Even with these increases, Palo Alto still provides an economic electricity service to low -income utility customers. In neighboring Mountain View, for example, which is served by PG&E, a single family customer with an income level that would qualify them for RAP in Palo Alto (HUD Very 5 The median income for Palo Alto is based on the U.S. Census’s American Community Survey (ACS). This survey does not break down income between single - and multi-family housing, but does break it down by income levels. Therefore, this estimate assumes that income levels for customers in multi-family units roughly match the ACS income levels for a two person household (the average household size for multi -family dwellings in Palo Alto), while the single-family customers match the ACS income levels for a three person household. 6 Very Low ($42,550 /$47,850 for a two / three person household) or Extremely Low ($25,550 /$28,750 for a two / three person household) under the Federal Department of Housing and Urban Development’s income guidelines for Santa Clara County Page 9 of 16 Low income) would pay 1.6% of their income for electric service7, as compared to 1.2% in Palo Alto. In addition, Public Utilities Code 386 requires all publicly owned utilities (like Palo Alto) to ensure that low-income families have access to affordable electricity. This requirement is fulfilled through the City’s RAP and Residential Energy Assistance Program (REAP). Figure 1: Impact of Rate Changes on Customers of Various Income Levels Staff also analyzed the impacts of the proposed cost-based rate changes on existing solar customers, particularly the impact of the minimum bill. The minimum bill would have some impact on residential customers who have already installed solar and are on the City’s net metering rate. For the majority of solar customers (57%) the annual impact would be less than $30. For nearly 80% of customers the annual impact would be less than $80 per year. The remaining customers pay little or nothing for their annual e lectric bill. These customers would pay $81-$120 per year under the proposed rate structure. Staff also analyzed the impacts of the minimum charge and rate changes on prospective solar net energy metering customers. For the average customer in Palo Alto, the proposed rate 7 Calculated using PG&E E-1 CARE rate. Page 10 of 16 changes actually reduce the payback period.8 This is because the increases in the Tier 1 and Tier 2 rates increased the bill savings for the average customer and reduced it for the highest users , offsetting the impact of the minimum bill. For the highest use customers, the payback period would increase. Customers would see substantial savings from installing solar even as they contribute to their portion of the utility’s costs of serving them via the minimum bill and rate changes, as shown in Table 6. Customers looking to optimize their return on investment (shorten the payback period) might avoid oversizing their systems and may install systems that generate a bit less than 100% of their annual usag e. This is the strategy already undertaken by the large majority of solar customers, so the minimum bill is unlikely to have a major impact on new installations. With solar prices continuing to fall and future customers benefitting from the recent extension of the Investment Tax Credit, staff is confident that the minimum bill will not significantly affect the growth of rooftop solar in Palo Alto. Table 6: Sample Solar Customer Bill Under Proposed Rates and Minimum Bill Month 1. Total Energy Consumption (kWh) 2. Solar Energy Production (kWh) 3. Monthly Bill with Solar Under NEM 4. Monthly Bill Without Solar January 700 327 $43 $99 February 602 314 $32 $82 March 531 519 $10 $70 April 459 610 $9 $58 May 442 704 $10 $55 June 441 659 $9 $55 July 465 711 $10 $59 August 447 582 $10 $56 September 465 551 $9 $59 October 471 467 $10 $60 November 477 348 $9 $61 December 592 299 $10 $81 Total: 6,092 6,092 $169 $796 Cost of Service Analysis and Rate Study The rates discussed in the previous section are based on the cost of service methodology established in the attached “City of Palo Alto Electric Cost of Service and Rate Study” by EES Consulting, Inc. (Attachment C). This section provides a brief overview of that methodology and the resulting rate design changes. More detail is available in the report itself. A typical COSA has three steps: 1. Establish the revenue requirement. This involves breaking the City’s costs into industry- standard categories and calculating the amount of sales revenue to be recovered. 8 Payback period refers to the number of years until the savings from the solar installation equals the initial cost. Page 11 of 16 2. Cost of service analysis. This step establishes the cost responsibility of each customer class. Costs are allocated based on cost causation. For example, costs such as power supply are driven by total annual energy consumption and are allocated to each customer class based on that class’s annual energy use. Other costs are driven by peak demand, number of customers, or other types of allocations. This step of the analysis generated the customer class revenue requirements shown in Table 2, above. 3. Rate Study. In this step, rates are designed to recover the revenues for each customer class calculated in Step 2. Most importantly in this step rates must be based on the cost to serve customers, though staff has also attempted to take into account City policy goals. The design of the rates generated by the COSA and proposed for July 1, 2016 adoption is very similar to the current rates. Residential rates are tiered, while non-residential rates are seasonal, and larger non-residential customers are subject to demand charges. However, there are a number of design changes that were needed to ensure rates matched the cost to serve customers: The E-1 residential rates have gone from three tiers to two. Two tiers are needed to capture differences in commodity costs and seasonal capacity needs, but not three. The Tier 1 allowance for the E-1 rate has gone from 10 kWh per day to 11 kWh per day. This was based on an analysis of residential baseload energy use. A minimum charge has been added to all rate classes. This ensures that at minimum the direct costs of providing customer service, metering, and billing are recovered. The E-18 (Municipal) rate class has been repealed. Customers in this class shared similar characteristics to the E-2, E-4, and E-7 nonresidential classes, and will be moved to those classes. The E-14 (Street Lighting) rate schedule has been updated to apply to all street lights served by the electric utility, and to reflect current street light inventories. The E-16 (Unmetered Electric Service) rate schedule has been updated to remove traffic signal rates. Since the City is the only customer these rates currently apply to, it is simpler to bill the City directly for traffic signal maintenance rather than calculate separate rates. The COSA and rate study largely align with the “Design Guidelines for the 2015 (Phase One) Electric Utility Cost of Service Analysis” adopted by the Council on September 15, 2015 (Staff Report 6061). Some additional work may be required to fulfill some of the guidelines. Each guideline is listed in Table 7 below, as well as the way in which the proposed rates align with the guidelines. Table 7: Implementation of COSA Design Guidelines Guideline Implementation 1. Rates must be based on the cost to serve customers. This is the overriding principle for the COSA; all other rate design considerations are subsidiary to this basic premise. The COSA and Rate Design study is based on the cost to serve customers. The methodology used is detailed in the report (Attachment C). Page 12 of 16 Table 7: Implementation of COSA Design Guidelines Guideline Implementation 2. For this cost of service study, and to the extent feasible, energy charges should be based on existing rate structures. This includes: a. A tiered rate design structure for residents b. A flat general service rate for small non- residential users c. A flat demand and energy rate for large non-residential users Proposed residential rates are based on a two tiered rate design structure. Small non-residential rates are a flat seasonal rate. Large non-residential rates have flat seasonal demand and energy components. 3. The COSA should involve a review of all existing rate schedules for inclusion in the COSA or repeal. All rate classes were reviewed except the voluntary E-1 TOU schedule (also see note regarding E-15 schedule in Section 8, below). Analysis of the voluntary E-1 TOU rate schedule will follow in the fall. Only one adjustment was made to the other rate classes: the E-18 (Municipal) and E-18-G (Municipal Green) rates are recommended for repeal. 4. The COSA should take into account the impact of rate designs on electric vehicles and electric heating customers, and should investigate: a. the extent to which these customers have different load profiles from other residential customers; and b. the extent to which existing rate designs should be adjusted for these differing load profiles Staff did not have enough time to complete this analysis and still meet the July 1, 2016 rate adoption goal. However, some of the concerns behind this guideline centered on the impact of the third tier on these types of customers. The elimination of the third tier from the residential rates and the increase in the first tier daily energy allowance should alleviate these impacts. 5. The COSA should evaluate the need for a minimum charge. The proposed rate designs include a minimum charge to ensure that the direct costs of customer service, billing, meter reading, and some types of distribution costs are collected from all customers. 6. A hydroelectric rate adjustment mechanism should be evaluated. Staff did not have enough time to complete this analysis in time to have rates available for a July 1, 2016 rate adoption date, but intends to bring this to the UAC and Council in the fall of 2016. Page 13 of 16 Table 7: Implementation of COSA Design Guidelines Guideline Implementation 7. The COSA should evaluate the impact of rate designs on the economics of local solar for current and future customers and should be coordinated with an analysis of long-term solar policies to be put into effect after the existing net energy metering tariff reaches capacity. See discussion earlier in this report for impacts on existing and prospective net energy metering customers. Staff is developing a successor to the net energy metering program to take effect once the net energy metering cap is reached. Staff has established a set of guidelines for this analysis (see Staff Report 6473), and will bring the results to the Council in the spring of 2016. The economics of solar under the proposed rates will be evaluated in that report. 8. A connection fee study should be performed and policies regarding residential transformer upgrades should be reviewed, either as part of the COSA or as part of a parallel analysis. The COSA methodology should be coordinated with any potential connection fee changes or policy changes. The E-15 Rate Schedule lists the City’s Connection Fees. Staff did not have enough time to complete this analysis in time to have rates available for a July 1, 2016 rate adoption date, but intends to bring this to the UAC and Council in the fall of 2016. 9. The impact of any proposed changes on low income customers should be evaluated Completed, see Figure 1. Reserves Transfers, FY 2016 and FY 2017 The FY 2017 Electric Utility Financial Plan includes several proposed reserves transfers, shown in Table 8. These reserves transfers have a variety of purposes, but overall they enable the revenue trajectory projected in the Electric Utility Financial Plan. Without these transfers additional rate increases would be required. Page 14 of 16 Table 8: FY 2016 and FY 2017 Reserves Transfers Fiscal Year Transfer Amount Transfer From Transfer To Purpose FY 2016 $5.6 million Hydroelectric Stabilization Reserve Supply Operations Reserve Funds additional market energy purchases in FY 2016. These purchases were required because hydroelectric output was lower than average due to drought. $2.0 million Supply Operations Reserve Distribution Operations Reserve Ensures Distribution Operations Reserve is above minimum guidelines at the end of FY 2016. $5.6 million CIP Reserve Distribution Operations Reserve Minimum guidelines for the CIP Reserve are recommended to be reduced, and some of the funds used to fund additional FY 2016 capital investment. FY 2017 $5.4 million Supply Rate Stabilization Reserve Supply Operations Reserve This transfer allows the City to reduce the July 1, 2016 rate increases, delaying part of the rate increase to July 1, 2017. Up to $9.0 million Hydroelectric Stabilization Reserve Supply Operations Reserve Funds additional market energy purchases that may be needed if hydroelectric output is lower than average due to continuing drought. Up to $4.5 million Supply Operations Reserve Distribution Operations Reserve Keeps Distribution Operations Reserve above minimum guidelines. Proposed Changes to Electric Utility Reserves Management Practices The proposed FY 2017 Electric Utility Financial Plan includes one change to the Electric Utility Reserves Management Practices (see Appendix B of the Financial Plan). In the FY 2016 Electric Utility Financial Plan, the CIP Reserve was modified to be the working capital reserve for the CIP Program. This change was in response to modifications of the accounting process for the CIP program that were made during the FY 2016 budget process. At the time, the minimum and maximum guidelines were set at six months and one year of budgeted capital investment, respectively. Staff is proposing to amend these guidelines, so the minimum guideline is 60 days and the maximum 120 days. This is in line with the Government Finance Officer’s Association guidelines for operational reserves and with the requirements for the electric utility’s other operational reserves. Electric Bill Comparison with Surrounding Cities Table 9 compares electric bills under current rates as of February 1, 2016 for residential customers to those in surrounding communities. Under current rates, CPAU’s customer bills are far below PG&E’s and are lower than others for commercial customers, but slightly higher than Santa Clara’s for higher using residential customers. Page 15 of 16 Table 9: Residential Electric Bill Comparison ($/month) As of February 1, 2016 Customers Usage (KWh/mo) Palo Alto (Current) Palo Alto (Proposed) PG&E Santa Clara Roseville Residential Customers 300 28.57 33.09 54.45 34.16 53.79 330 (Summer Median) 32.48 36.39 62.05 36.65 56.97 453 (Winter Median) 48.49 57.18 88.13 52.21 70.00 650 76.33 90.48 142.09 75.47 98.61 1200 172.03 183.43 333.61 140.38 185.21 Commercial Customers 1,000 134 142 202 175 139 160,000 18,364 21,553 23,348 19,961 20,029 500,000 43,319 43,862 64,325 61,120 49,694 2,000,000 216,594 219,310 272,313 236,299 188,852 NEXT STEPS The Finance Committee is scheduled to review the FY 2017 Electric Financial Plan in May 2016. The City Council will consider the recommendations with the FY 2017 budget. RESOURCE IMPACT The proposed July 1, 2017 rate changes are projected to increase sales revenues by $12 million per year over the forecast period. POLICY IMPLICATIONS The proposed electric rate adjustments were developed using a cost of service study and methodology. The attached Financial Plan includes amended Reserve Management Practices that will modify Council policy with respect to the structure of the financial reserves of the Electric Utility. These Reserve Management Practices replace the current Reserve Management Practices, which were last adopted by Council in June 2015 (Resolution 9521). ENVIRONMENTAL REVIEW The UAC’s review and recommendation to Council on the FY 2017 Electric Financial Plans and rate adjustments does not meet the California Environmental Quality Act’s definition of a project, pursuant to Public Resources Code Section 21065, thus no environmental review is required. ATTACHMENTS A. Resolution of the Council of the City of Palo Alto Approving the FY 2016 Electric Utility Financial Plan and Amending the Electric Utility Reserves Management Practices B. Proposed FY 2016 Electric Utility Financial Plan and Electric Utility Reserves Management Practices C. Report from EES Consulting Titled "City of Palo Alto Electric Cost of Service and Rate Study" {2016) D. Resolution of the Council of the City of Palo Alto Adopting an Electric Rate Increase and Amending Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU, E-14, and E-16 and Repealing Rate Schedules E-18 and E-18-G E. Proposed Amendments to Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7- G, E-7 TOU, E-14, and E-16 PREPARED BY: REVIEWED BY: APPROVED BY: JONATHAN ABENDSCHEIN, Senior Resource Planner ~~Director, Resource M .anagement ED SHIKADA Interim Director of Utilities Page 16of16 Attachment A NOT YET APPROVED 160330 jb 6053708 Resolution No. _________ Resolution of the Council of the City of Palo Alto Approving the FY 2017 Electric Utility Financial Plan and Amending the Electric Utility Reserves Management Practices R E C I T A L S A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of its utilities with the goal of ensuring adequate revenue to fund operations. This includes making long-term projections of market conditions, the physical condition of the system, and other factors that could affect utility costs, and setting rates adequate to recover these costs. It does this with the goal of providing safe, reliable, and sustainable utility services at competitive rates. The City adopts Financial Plans to summarize these projections. B. The City uses reserves to protect against contingencies and to manage other aspects of its operations, and regularly assesses the adequacy of these reserves and the management practices governing their operation. The status of utility reserves and their management practices are included in Reserves Management Practices attached to and made part of the Financial Plans. C. The City intends to make changes to its Electric Utility Reserves Management Practices to amend the management practices of the Electric Utility’s Capital Improvement Program (CIP) Reserve. The Council of the City of Palo Alto does hereby RESOLVE as follows: SECTION 1. The Council hereby approves the FY 2017 Electric Utility Financial Plan, including the amended Electric Utility Reserves Management Practices. These Reserves Management Practices replace the Reserves Management Practices previously approved for the Electric Utility as part of the FY 2016 Electric Utility Financial Plan (Resolution 9521). SECTION 2. The Council hereby approves the transfer of $5.6 million in FY 2016 from the Hydro Stabilization Reserve to the Supply Operations Reserve, $2.0 million in FY 2016 from the Supply Operations Reserve to the Distribution Operations Reserve, the transfer of $5.6 million in FY 2016 from the CIP Reserve to the Distribution Operations Reserve, the transfer of $5.4 million from the Supply Rate Stabilization Reserve to the Supply Operations Reserve in FY 2017, up to $9.0 million from the Hydroelectric Stabilization Reserve to the Supply Operations Reserve in FY 2017, and up to $4.5 million from the Supply Operations Reserve to the Distribution Operations Reserve in FY 2017, as described in the FY 2017 Electric Utility Financial Plan approved via this resolution. / / / / / / Attachment A NOT YET APPROVED 160330 jb 6053708 SECTION 3. The Council finds that the adoption of this resolution does not meet the California Environmental Quality Act’s (CEQA) definition of a project under Public Resources Code Section 21065, and therefore, no environmental assessment is required. INTRODUCED AND PASSED: AYES: NOES: ABSENT: ABSTENTIONS: ATTEST: ___________________________ ___________________________ City Clerk Mayor APPROVED AS TO FORM: APPROVED: ___________________________ ___________________________ Senior Deputy City Attorney City Manager ___________________________ Director of Utilities ___________________________ Director of Administrative Services FY 2017 ELECTRIC UTILITY FINANCIAL PLAN FY 2017 TO FY 2023 ATTACHMENT B 2 | P a g e F Y 2017 ELECTRIC UTIL ITY F INANCIAL PLAN FY 201 7 TO FY 20 23 TABLE OF C ONTENTS Section 1: Definitions and Abbreviations................................................................................ 4 Section 2: Executive Summary and Recommendations ........................................................... 5 Section 2A: Overview of Financial Position .................................................................................. 5 Section 2B: Summary of Proposed Actions .................................................................................. 6 Section 3: Detail of FY 2017 Rate and Reserves Proposals ....................................................... 7 Section 3A: Rate Design ............................................................................................................... 7 Section 3B: Current and Proposed Rates ..................................................................................... 7 Section 3C: Reserves Management Practices, Proposed Change ................................................ 7 Section 3D: Proposed Reserve Transfers ..................................................................................... 8 Section 4: Utility Overview .................................................................................................. 10 Section 4A: Electric Utility History ............................................................................................. 11 Section 4B: Customer Base ........................................................................................................ 13 Section 4C: Distribution System ................................................................................................. 13 Section 4D: Cost Structure and Revenue Sources ...................................................................... 14 Section 4E: Reserves Structure ................................................................................................... 15 Section 4F: Competitiveness ...................................................................................................... 16 Section 5: Utility Financial Projections ................................................................................. 18 Section 5A: Load Forecast .......................................................................................................... 18 Section 5B: FY 2009 to FY 2015 Cost and Revenue Trends ........................................................ 19 Section 5C: FY 2015 Results ....................................................................................................... 20 Section 5D: FY 2016 Projections ................................................................................................ 20 Section 5E: FY 2017 – FY 2023 Projections ................................................................................ 21 3 | P a g e Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 23 Section 5G: Long-Term Outlook ................................................................................................. 27 Section 6: Details and Assumptions ..................................................................................... 30 Section 6A: Electricity Purchases ............................................................................................... 30 Section 6B: Operations .............................................................................................................. 32 Section 6C: Capital Improvement Program (CIP) ....................................................................... 33 Section 6D: Debt Service ............................................................................................................ 34 Section 6E: Equity Transfer ........................................................................................................ 35 Section 6F: Wholesale Revenues and Other Revenues .............................................................. 36 Section 6G: Sales Revenues ....................................................................................................... 36 Section 7: Communications Plan .......................................................................................... 37 Appendices ......................................................................................................................... 38 Appendix A: Electric Utility Financial Forecast Detail ................................................................ 39 Appendix B: Electric Utility Reserves Management Practices ................................................... 43 Appendix C: Description of Electric utility Operational Activities .............................................. 48 Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 49 4 | P a g e SECTION 1 : DEFINITIONS AND ABBR EVIATIONS CAISO California Independent System Operator CARB California Air Resources Board CIP Capital Improvement Program CPAU City of Palo Alto Utilities Department CPUC California Public Utilities Commission CVP Central Valley Project GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for discussing total monthly or annual electric load for the entire city, or the monthly or annual output of an electric generator. kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers. kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the highest 15 minute average consumption level in a month), which is used for billing large and mid-size commercial customers. kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a section of the distribution system operates. The transmission system operates at 115-500 kV, and this is lowered to 60 kV in the subtransmission section of the Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution system, and finally 120, 240, or 480 volts at the electric outlet. MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale electricity purchases. MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum electricity demand for all customers in aggregate. PG&E Pacific Gas and Electric REC Renewable Energy Certificate RPS Renewable Portfolio Standard Subtransmission System: The section of the Electric Utility’s distribution system that operates at 60 kV and which interfaces with PG&E’s transmission system. Transmission System: Sections of the electric grid that operate at high voltages, generally 115 kV or more. The voltage at the intersection of the Electric Utility’s distribution system and PG&E’s transmission system is 115 kV. The Electric Utility does not own or operate any transmission lines. UCC Utility Control Center SCADA Supervisory Control and Data Acquisition system, the system of sensors, communications, and monitoring stations that enables system operators to monitor and operate the system remotely. WAPA, or Western: Western Area Power Administration, the agency that markets power from CVP hydroelectric generators and other hydropower owned by the Bureau of Reclamation. 5 | P a g e SECTION 2 : EXECUTIVE SUMMARY AND RECOMMENDATIONS This document presents a Financial Plan for the City’s Electric Utility for the next seven fiscal years. This Financial Plan describes how revenues will cover the costs of operating the utility safely over that time while adequately investing for the future. It also addresses the financial risks facing the utility over the short term and long term, and includes measures to mitigate and manage those risks. SECTION 2 A : OVERVIEW OF FINANC IAL POSITION The Electric Utility’s costs will increase substantially over the next few years, as shown in Table 1. Most of the increases are related to electric supply costs, which are increasing due to increased transmission costs and the cost of new renewable energy projects coming online. There are also inflationary increases in Operations costs, and some additional capital investment costs. Table 1: Electric Utility Expenses for FY 2015 to FY 2023 Expenses ($000) FY 2015 (actual) FY 2016 (est.) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Power Supply Purchases 80,022 75,705 86,378 88,524 89,131 90,304 89,637 88,543 89,919 Operations 47,611 52,170 52,923 53,922 54,579 55,277 56,076 56,898 58,696 Capital Projects 12,713 16,989 27,652 22,058 26,649 15,868 16,320 16,785 17,263 TOTAL 140,346 144,864 166,953 164,504 168,710 161,450 162,034 161,225 165,877 To cover these increases in costs, revenues (and therefore rates) need to increase over the next several years to balance costs and revenues, as shown in Table 2. The table also compares current rate projections to those projected in last year’s Financial Plan. The rate projections are higher this year than last year primarily due to the continued drought that has required additional electric supply purchases to replace hydroelectric supplies. Table 2: Projected Electric Rate Trajectory for FY 2017 to FY 2023 Projection FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Current 11% 10% 3% 0% 1% 0% 2% Last Year 6% 6% 1% 1% 0% 0% 2% Table 3 shows the projected reserve transfers over the forecast period. The Supply Rate Stabilization Reserve is projected to be drawn down entirely by the end of FY 2017. Funds are projected to be transferred from the Electric Special Projects (ESP) Reserve to the Operations Reserve to fund smart grid projects included in the long term CIP budget. Funds are projected to be drawn from the Hydro Stabilization Reserve in FY 2017 and FY 2018 due to lowe r than average hydroelectric generation, though this projection is subject to change with weather conditions. It should be noted that the smart grid costs included in the forecast are 6 | P a g e placeholders, as are the transfers from the ESP Reserve. Any transfers from the ESP Reserve require Council approval. Table 3: Reserves Transfers for FY 2016 to FY 2023 ($000) Reserve FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 to FY 2023 Supply Reserves Electric Special Projects (151) (333) (3,750) - Hydro Stabilization (5,600) (9,000) (2,400) - - Supply Rate Stabilization 9,000* (5,411) - - - Supply Operations 3,600 14,562 2,733 3,750 - Distribution Reserves Capital Improvement Program (5,600) Distribution Operations 7,700 - - - - * A $9 million transfer from the Supply Rate Stabilization Reserve to the Supply Operations Reserve was approved by Council when it adopted the FY 2016 Electric Utility Financial Plan SECTION 2 B : SUMMARY OF PROPOSED ACTIONS Staff proposes the following actions for the Electric Utility in FY 2016: 1. Complete the proposed FY 2016 reserves transfers described Section 3D: Proposed Reserve Transfers. Staff proposes the following actions for the Electric Utility in FY 2017: 1. Complete the proposed FY 2017 reserves transfers described in Section 3D: Proposed Reserve Transfers. 2. Increase rates effective July 1, 2016 to generate an 11% increase in sales revenues. 3. Amend the Electric Utility Reserves Management Practices to modify the minimums and maximums for the CIP Reserve. Note that while the projected rate increases and reserves transfers in this FY 2017 Financial Plan are adequate to recover costs over the forecast period, the Su pply Operations Reserves are projected to be as much as $3.9 million below the minimum Supply Operations Reserve level for FY 2017 through FY 2020. Staff still recommends proceeding with this plan for two reasons: first, due to the presence of a strong El Niño condition in the Pacific Ocean, there is a chance of high spring rains that may change this forecast, resulting in higher reserves, and second, the presence of the Electric Special Projects Reserve with a balance of $51 million means that a small temporary shortfall in the Supply Operations Reserve should not affect the Electric Utility’s financial health and bond ratings. In the event drought continues, staff will re- evaluate its projections for FY 2018 and may recommend additional rate increases or t he adoption of a hydroelectric rate adjuster. 7 | P a g e SECTION 3 : DETAIL OF FY 2017 RATE AND RESERVES PR OPOSALS SECTION 3 A : RATE DESIGN The Electric Utility’s current rate structure and methodology are consistent with the cost of service analysis (COSA) update in 2007 by Boris Metrics. Staff is completing a new COSA with revised rates to become effective July 1, 2016. The new COSA is based on design guidelines adopted by Council on September 15, 2015 (Staff Report 6061). SECTION 3 B : CURRENT AND PROPOSED RATES The current rates were adopted on July 1, 2009, when CPAU increased electric rates by 10%. Table 4, below, summarizes the current rates for the four largest customer classes. The Electric Utility also has specialty rates for smaller groups of customers. These include variations on its primary rates, such as time of use rates, the PaloAltoGreen rates, and solar net metering. Another specialty rate is the E-18 municipal electric rate. Table 4: Current Electric Rates (Adopted July 1, 2009) Rate Component Units E-1 (Residential) E-2 (Small Commercial) E-4 (Medium Commercial) E-7 (Large Commercial) Demand (Summer) $/kW N/A N/A 20.54 18.97 Demand (Winter) $/kW N/A N/A 13.84 11.54 Energy (Summer) Tier 1 $/kWh 0.09524 0.14045 0.08171 0.07808 Tier 2 $/kWh 0.13020 N/A N/A N/A Tier 3 $/kWh 0.17399 N/A N/A N/A Energy (Winter) Tier 1 $/kWh Same as summer energy 0.12661 0.07318 0.07209 Tier 2 $/kWh N/A N/A N/A Tier 3 $/kWh N/A N/A N/A Tier amounts: Tier 1 kWh/day 0-10 N/A N/A N/A Tier 2 kWh/day 11-20 N/A N/A N/A Tier 3 kWh/day >20 N/A N/A N/A Staff proposes an 11% overall increase in revenue along with changes in rate design and changes in the allocation of costs between customer classes to ensure that the rates are based on the cost of service for each customer group. These proposals are detailed in the consultant report titled “City of Palo Alto Electric Cost of Service and Rate Study,” by EES Consulting (2016). SECTION 3 C : RESERVES MANAGEMENT PRACTICES, PROPOSED CHANGE Staff proposes one change to the Electric Utility Reserves Management Practices (See Appendix B: Electric Utility Reserves Management Practices) in this Financial Plan. Staff recommends 8 | P a g e revising the CIP Reserve minimum to be 60 days of capital expenses, with a maximum of 120 days of expenses, which aligns with the Government Financial Officers of America rule of thumb for operating reserves and the minimum and maximum guidelines for the Distribution Operations Reserve. Staff recommends transferring $5.6 million from the CIP Reserve to the Distribution Operations Reserve. Also see Section 3D: Proposed Reserve Transfers. SECTION 3 D : PROPOSED RESERVE TRA NSFERS In the FY 2016 Electric Financial Plan Council approved a $9 million transfer from the Supply Rate Stabilization Reserve to the Supply Operations Reserve. Staff proposes the following additional transfers in FY 2016: Transfer $5.6 million from the Hydroelectric Stabilization Reserve fund to the Supply Operations Reserve to cover additional costs associated with low hydroelectric generation due to the drought. Transfer $2.0 million from the Supply Operations Reserve to the Distribution Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve. Transfer $5.6 million from the CIP Reserve to the Distribution Operations Reserve as part of the change to Reserves Management Practices described above. For FY 2017, staff proposes the following transfers: Transfer $5.4 million from the Supply Rate Stabilization Reserve to the Supply Operations Reserve. This transfer is to enable the City to spread necessary long term rate increases over multiple years to reduce the short-term impact on ratepayers. Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offs et potential costs associated with low hydroelectric generation. Some or all of this transfer may be unnecessary if weather conditions change, but if drought continues, this transfer will enable the City to fund the associated additional energy costs. Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution Operations Reserve if necessary to ensure reserve adequacy in the Distribution Operations Reserve. The impact of these transfers on reserves levels can be seen in Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E: FY 2017 – FY 2023 Projections. Table 5 shows the projected balance of each of the Electric Utility reserves for the period covered by this Financial Plan. The projected balances are also provided in. Appendix A: Electric Utility Financial Forecast Detail 9 | P a g e Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2016 to FY 2023 Ending Reserve Balance ($000) FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Reappropriations - - - - - - - - Commitments 3,102 3,102 3,102 3,102 3,102 3,102 3,102 3,102 Underground Loan 730 730 730 730 730 730 730 730 Public Benefits 2,574 2,700 2,790 2,799 2,717 2,545 2,434 2,374 Special Projects 51,838 51,535 51,383 51,050 47,300 47,300 47,300 47,300 Hydro Stabilization 17,000 11,400 2,400 0 0 0 0 0 Capital 0 2,864 2,864 2,864 2,864 2,864 2,864 2,864 Rate Stabilization 14,411 5,411 0 0 0 0 0 0 Operations 22,498 22,734 22,015 22,281 24,814 27,033 30,783 34,269 Unassigned 0 0 0 0 0 0 0 0 TOTAL 112,153 100,476 85,284 82,827 81,528 83,574 87,214 90,639 10 | P a g e SECTION 4 : UTILITY OVERVIEW This section provides an overview of the utility and its operations. It is intended as general background information to help readers better understand the forecasts in Section 5: Utility Financial Projections and 11 | P a g e Section 6: Details and Assumptions. SECTION 4 A : ELECTRIC UTILITY HISTORY On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E proved more economical than the diesel engines, and by the late 1920s CPAU was using its own diesel engines only during peak demand periods. At that time CPAU owned 45 miles of distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual consumption. The diesel engines remained in operation until 1948, when they were retired. From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto, which doubled the number of customers. Some was related to the proliferation of electric appliances, as evidenced by the fact that residential customers were using three times more electricity in 1970 than they had been in 1950. But the most notable factor was the growth of industry in Palo Alto during that time. By 1970, commercial customers were using 20 times more electricity per customer than they had bee n in 1950. These decades also saw several other notable events, including: 1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of Reclamation to purchase power from the Central Valley Project (CVP), a contract which later was managed by the Western Area Power Administration (WAPA) an office of the Department of Energy created in the 1970s to market power from various hydroelectric projects operated by the Federal Government, including the CVP. 1965: The City began a long-term program to underground its overhead utility lines (Ordinance 2231). 1968: Palo Alto joined several other small municipal utilities to form the Northern California Power Agency (NCPA), a joint action agency intended to make the group less vulnerable to actions by private utilities and to enable investment in energy supply projects. Palo Alto’s first new power plant investment in over 50 years came in the mid -80s. Palo Alto joined other NCPA members to invest in the construction and operation of the Calaveras Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project commenced operation in 1990. The 1980s also saw an increased focus on infrastructure maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which enabled utility staff to monitor the distribution system in real time, improving response time to outages. CPAU also commenced a preventative maintenance and planned replacement program for its underground system in the early 1990s. 12 | P a g e In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and in 1996 the State legislature passed Assembly Bill 1890, which, among other things, created the California Independent System Operator (CAISO) to operate the transmission system and the Power Exchange to facilitate wholesale energy transactions. This restructuring was anticipated to bring lower costs to consumers, and while CPAU was not required to participate in the industry restructuring, in 1997 the Council approved a Direct Access Program for the Electric Utility1 that enabled CPAU to sell electricity outside its service territory and allowed customers within CPAU’s service territory to choose other providers. The utility unbundled its electric rates, creating separate supply and distribution components, which would enable customers to receive only distribution service while purchasing the electricity itself from another provider. The energy crisis in 2000 to 2001 led to the suspension of direct access by the CPUC in September 2001 as wholesale energy prices skyrocketed. The Electric Utility was less impacted than other utilities by the 2000 to 2001 energy crisis thanks to the Calaveras pr oject and its contract with WAPA for CVP hydropower. In 2001 CPAU began planning for the impacts associated with the new terms of its contract with WAPA, set to take effect in 2005. The previous contract had provided 90% of Palo Alto’s power supply at favorable rates, and PG&E, as a party to the contract, had provided supplemental power to balance the monthly and annual variability of CVP generation. The new contract would provide only a third of Palo Alto’s requirement, and the monthly and annual variability in CVP generation would be passed directly to Palo Alto. As a result, electric supply costs would increase and CPAU needed to more actively managing its supply portfolio. CPAU began purchasing power from marketers and also investigated building a power plant in Palo Alto or partnering in the development of a gas-fired power plant elsewhere. Climate change was also becoming more of a concern to the community, and gradually CPAU shifted its focus to the procurement of renewable energy. In 2002 CPAU adopted a goal of achieving 20% of its energy supply from renewables by 2015. Subsequently CPAU signed its first contract for renewable power, a contract for energy from a wind generator commencing deliveries in 2005. In 2011 the renewable energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a plan to make its electric supply 100% carbon neutral, which it achieves through the combination of its carbon-free hydroelectric supplies, purchases of long-term renewable energy supplies, and short-term renewable energy purchases (RECs) to meet the balance of its needs. 1 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997 13 | P a g e Figure 1: Customer Base (FY 2015) Residential 16% Small Comm 8% Med Comm 32% Large Comm 41% Municipal 3% SECTION 4 B : CUSTOMER BASE The City of Palo Alto’s Electric Utility provides electric service to the residents, businesses, and other electric customers in Palo Alto. There are roughly 29,300 customers connected to the electric system, 26,400 (90%) of which are residential and 2900 (10%) of which are non- residential. Residential customers consumed 173 gigawatt-hours (GWh) in FY 2015, approximately 18% of the electricity sold, while non-residential customers consumed 82% or 763 GWh. Residential customers use electricity primarily for lighting, refrigeration, electronics, and air conditioning.2 Non-residential customers use the majority of their electricity for cooling, ventilation, lighting, office equipment (offices), cooking (restaurants), and refrigeration (grocery stores).3 As shown in Figure 1 large customer loads represent a larger proportion of sales for the Electric Utility than they do for the City’s other utilities. The largest customers (the 66 customers on the E-7 rate schedule) account for over 40% of CPAU’s sales. The next largest customer group (the 740 commercial customers on the E-4 rate schedule) represents another 32% of sales. In total, that means that less than 3% of customers account for nearly three quarters of the electric load. SECTION 4 C : DISTRIBUTION SYSTEM The Electric Utility receives electricity at a single connection point with PG&E’s transmission system. From there the electricity is delivered to customers through nearly 470 miles of distribution lines, of which 223 miles (48%) are overhead lines and 245 miles (52%) are underground. The Electric Utility also maintains six substations, roughly 2,000 overhead line transformers, 1,075 underground and substation transformers, and the associated electric services (which connect the distribution lines to the cu stomers’ homes and businesses). These lines, substations, transformers, and services, along with their associated poles, meters, and 2 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010 3 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. 14 | P a g e Figure 2: Cost Structure (FY 2015) Figure 3: Hydroelectric Variability (FY 2016) 0% 20% 40% 60% 80% 100% 120% 140% Low Hydro Average High Hydro Surplus Hydro (sales) Market Power/RECs Hydro Renewables Load Figure 4: Revenue Structure (FY 2015) other associated electric equipment, represent the vast majority of the infrastructure used to deliver electricity in Palo Alto. SECTION 4 D : COST STRUCTURE AND R EVENUE SOURCES As shown in Figure 2, electric commodity purchases accounted for roughly 55% of the Electric Utility’s costs in FY 2015. Operational costs represented roughly 31%, and capital investment was responsible for the remaining 10%. CPAU’s non-hydro long-term commodity supply is heavily dependent on long-term contracts which have little variability in price. On average, costs for these long-term contracts are not predicted to increase as quickly as operations and CIP costs, and will steadily become a smaller proportion of the Electric Utility’s costs. Commodity supply costs are projected to be roughly 47% of total costs in FY 2023. While average year purchase costs for the electric utility are predictable due to its long- term contracts, variability in hydroelectric generation can result in increased or decreased costs. This is by far the largest source of variability the utility faces. Figure 3 shows the difference in costs under high, average, and low hydroelectric generation scenarios. Additional costs associated with a very low generation scenario can range from $10-12 million per year. For the current hydroelectric risk assessment see Section 5F: Risk Assessment and Reserves Adequacy. As shown in Figure 4 the Electric Utility receives 87% of its revenue from sales of electricity and the remainder from connection fees, interest on reserves, cost recovery transfers from other funds for shared services provided by the electric utility, and other sources. Some revenue sources are primarily accounting entries that reflect things such as CPAU’s participation in a pre-funding program associated with its contract with WAPA, as well 15 | P a g e as accounting entries associated with occasional sales of surplus hydroelectric energy during wet years. Without these entries sales revenues represent roughly 93% of total revenues. Appendix A: Electric Utility Financial Forecast Detail shows more detail on the utility’s cost and revenue structures. As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales are to the 800 largest customers, which provide a similar share of the utility’s revenue stream. The utility’s retail rate schedules have no fixed charges, although about 25% of the utility’s revenue comes from peak demand charges on large commercial customers. Due to moderate weather and the prevalence of natural gas heating, however, loads (and therefore revenues) are very stable for this utility, without the large seasonal air conditioning or winter heating loads seen at some other utilities. SECTION 4 E : RESERVES STRUCTURE CPAU maintains several reserves for its Electric Utility to manage various types of contingencies. It also maintains two funds, the Supply Fund and the Distribution Fund, to manage costs associated with electricity supply and electricity distribution, respectively. This separation of supply and distribution costs was established as the City prepared to allow its customers a choice of electricity providers (referred to as “Direct Access”) back in the late 1990s and early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues to maintain separate funds to facilitate separation of supply and distribution costs in the r ates. This could be important in case California ever decides to reintroduce Direct Access, and may also be useful for rate design as the nature of utility services evolves in response to higher penetrations of distributed generation. The various reserves are summarized below, but see Appendix B: Electric Utility Reserves Management Practices for more detailed definitions and guidelines for reserve management: Reserves for Commitments: Reserves equal to the utility’s outstanding contract liabilities for the current fiscal year. Most City funds, including the General Fund, have a Commitments Reserve. Reserves for Reappropriations: Reserves for funds dedicated to projects reappropriated by the City Council, nearly all of which are capital projects. Most City funds, including the General Fund, have a Reappropriations Reserve. This is currently an important reserve for all utility funds, but changes in budgeting practices will change that in future years, as described in Section 3C (Reserves Management Practices, Proposed Change). Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras Reserve, which was accumulated during deregulation of California’s electric system to fund the stranded costs associated primarily with the Calaveras hydroelectric resource and the California-Oregon Transmission Project. When that reserve was no longer needed for that purpose, the reserve was renamed and the purpose was changed to 16 | P a g e fund projects with significant impact that provide demonstrable value to electric ratepayers. Hydroelectric Stabilization Reserve: This contingency reserve is used for managing additional costs due to below average hydroelectric generation, or to hold surpluses resulting from above average hydroelectric generation. Underground Loan Reserve: This reserve is an accounting tool used to offset receivables associated with loans made through the underground loan program. It is adjusted according to principal payments made on those loans. Public Benefits Reserve: CPAU’s electric rates include a separate charge called the “Public Benefits Charge” which generates revenue to be used for energy efficiency, demand-side renewable energy, research and development, and low-income energy efficiency services. Any funds not expended in the current year are added to the Public Benefits Reserve for use in future years. Capital Improvement Program (CIP) Reserve: The CIP reserve is used to provide working capital and contingency funds for the CIP program, as well as to accumulate funds for major future one-time expenditures. This type of reserve is used in other utility funds (Electric, Gas, and Wastewater Collection) as well. Supply and Distribution Rate Stabilization Reserves: These reserves are intended to be empty unless one or more large rate increases are anticipated in the forecast period. In that case, funds can be accumulated to spread the impact of those future rate increases across multiple years. This type of reserve is used in other utility funds (Gas, Wastewater Collection, and Water) as well. Supply and Distribution Operations Reserves: These are the primary contingency reserves for the Electric Utility, and are used to manage yearly variances from budget for operational costs and electric supply costs (aside from variances related to hydroelectric generation). This type of reserve is used in other utility funds (Gas, Wastewater Collection, and Water) as well. Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves are for any financial resources not assigned to the other reserves and are normally empty. SECTION 4 F : COMPETITIVENESS For the median consumption level the annual residential electric bill for calendar year 2015 was $513.17 under current CPAU rates, 36% lower than the annual bill for a PG&E customer with the same consumption and 9% lower than the annual bill for a City of Santa Clara customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X , which includes most surrounding comparison communities. Table 6 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara (Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown below were in effect as of January 1, 2016. Note that rates for PG&E customers increased 17 | P a g e substantially on that date, and with rates currently in effect, the bill for the median residential user is roughly 45% below PG&E’s rates. Over the next several years low usage customers in PG&E territory are expected to continue to see higher percentage rate increases than high usage customers as PG&E compresses its tiers from the highly exaggerated levels that have been in place since the energy crisis. This is likely to make the bill for the median Palo Alto consumer look even more favorable compared to most PG&E customers. Even with the compressed tiers, bills for high usage Palo Alto consumers are likely to remain substantially lower than the bills for high usage PG&E customers. The bill calculations show bills under the existing rates, not the proposed July 1, 2016 rates. However, even with the proposed rate increases, Palo Alto’s residential bills will remain substantially below PG&E’s current rates, but slightly above Santa Clara’s. Table 6: Residential Monthly Electric Bill Comparison (Effective 1/1/16, $/mo) Season Usage (kwh) Palo Alto PG&E Santa Clara Winter (December) 300 28.57 54.45 34.16 (Median) 453 48.49 88.39 52.21 650 76.33 142.09 75.47 1200 172.03 333.61 140.38 Summer (July) 300 28.57 54.45 34.16 (Median) 330 32.48 62.05 36.65 650 76.33 148.02 75.47 1200 172.03 339.84 140.38 Table 7 shows the average monthly electric bill for commercial customers for various usage levels. Bills for small commercial customers in Palo Alto are 37% below what they would be in PG&E territory and 20% below what they would be in Santa Clara (Silicon Valley Power). For large commercial customers, rates are 30% to 35% below PG&E’s and are 4% to 10% lower than Santa Clara’s. Even with the proposed rate increases, Palo Alto’s commercial bills will remain substantially below PG&E’s, and below Santa Clara’s for most commercial customers. Table 7: Commercial Monthly Electric Bill Comparison (1/1/16, $/mo) Usage (kwh/mo) Palo Alto PG&E Santa Clara 1,000 134 212 167 160,000 18,364 27,221 19,228 500,000 43,319 66,152 47,913 2,000,000 216,594 311,640 234,322 18 | P a g e SECTION 5 : UTILITY FINANCIAL PROJECTIONS SECTION 5 A : LOAD FORECAST Figure 5 shows a 40-year history of Palo Alto electricity consumption. Average electricity consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then electricity consumption has declined slowly as a result of a continuing focus on energy efficiency, as well as the adoption of more stringent appliance efficiency standards and energy standards in building codes. Figure 5: Historical Electricity Consumption Figure 6 shows the forecast of electricity consumption through FY 2023, as well as what electricity consumption would have been without energy efficiency rebates, appliance efficiency standards, stricter building codes, and rooftop solar photovoltaic (PV) generation. The forecast assumes that current trends continue and sales through the forecast period decline slightly. As of the end of December 2015, net metered PV installations in Palo Alto provided roughly 1% of the total electricity consumed in the City. The Council -adopted Local Solar Plan’s goal is to increase the energy generated by local solar to 4% of the City’s needs by 2023. 19 | P a g e Figure 6: Forecasted Electricity Consumption SECTION 5 B : FY 2009 TO FY 2015 COST AND REVENUE TRE NDS The annual expenses for the Electric Utility declined between FY 2009 and FY 2012, as shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail . These decreases were partly related to declines in electricity market prices due to the impact of shale gas and partly due to above average output from hydroelectric resources . These factors are discussed in more detail in Section 6A: Electricity Purchases. Since FY 2012, total expenses for the utility have been increasing as renewable resources come online. In FY 2014 through FY 2015 costs were higher due to lower than average output from hydroelectric resources. Commodity costs are responsible for most of the changes in the utility’s expenses over the last six years. Operational costs and capital investment increased at less than 1% per year over that time. 20 | P a g e Figure 7: Electric Utility Expenses, Revenues, and Rate Changes: Actual Costs through FY 2015 and Projections through FY 2023 SECTION 5 C : FY 2015 RESULTS In spring of 2014 staff recommended no rate change for July 1, 2014, the start of FY 2015. Although staff forecast a $5.7 million deficit for FY 2015 without a rate change, reserves were adequate to absorb this deficit. However, drought conditions worsened in the spring of 2014 and continued through the winter of 2014/2015, resulting in a deficit of $17.0 million for FY 2015. The increased deficit was entirely related to the low output from hydroelectric resources , which necessitated electricity market purchases to replace the lower than expected hydroelectric energy. SECTION 5 D : FY 2016 PROJECTIONS In spring of 2015, staff recommended (and Council approved) no rate change for July 1, 2015, the start of FY 2016. Based on hydroelectric conditions at the time, staff forecasted a $10.3 million deficit for FY 2016. This deficit was primarily related to low hydroelectric output, and was to be funded from the Operations and Hydroelectric Stabilization reserves. Staff’s current 21 | P a g e forecast for FY 2016 is for a deficit of $20.1 million, $9.8 million more than forecasted in spring of 2015. This change is mainly related to two factors: 1) capital improvement program costs have increased by roughly $7 million, and 2) energy costs have increased by roughly $3 million due to continuing drought and resulting low hydroelectric generation. The $7 million increase in CIP costs is largely related to the delay of projects from previous fiscal years to FY 2016 rather than mid-year adjustments requesting new funding. Staff proposes partially funding this portion of the deficit using a $5.6 million transfer from the CIP Reserve, which contains $8.4 million collected in previous fiscal years to fund capital projects. The additional $3 million related to energy costs would be funded from the Hydroelectric Stabilization Reserve. These transfers are discussed in Section 3D: Proposed Reserve Transfers. SECTION 5 E : FY 2017 – FY 2023 PROJECTIONS As shown in Figure 7 above, costs for the Electric Utility are projected to increase in FY 2017 and level off in subsequent years. Revenues will have to increase 11% in FY 2017 and another 10% in FY 2018 to keep up with these cost increases. The increases are primarily related to electricity purchase costs, which have been increasing since FY 2013 and will continue to increase through FY 2018 as new renewable projects come online to fulfill the City’s environmental goals and as transmission costs increase. Operations costs are expected to increase substantially in FY 2017 to begin catching up on deferred maintenance, but subsequently are expected to increase at or below the inflation rate (2-3 %/year) through the forecast period. Projected capital expenses for FY 2017 through FY 2023 are $30 million higher than last year’s forecast due mostly to several large one-time projects, some customer driven, but also due to an increase in spending on system improvemen ts. The increased costs are partially offset by $13.4 million in revenue from reimbursements associated with those projects. Aside from those one-time costs, capital expenses are projected to increase in FY 2017 and then stay roughly level through the forecast period. This forecast also assumes that smart grid costs are funded from the Electric Special Projects Reserves. Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund reserves) and Figure 9 (for Distribution Fund reserves), below. The Supply Rate Stabilization Reserve is projected to be empty by the end of FY 2016. Assuming the projected increases in revenue, the Distribution Operations reserve will remain adequate through the forecast period, comfortably above minimum levels and adequate to meet all identified risks. The Supply Operations Reserve, however, is forecasted to be below minimum levels. This is discussed in more detail in Section 5F: Risk Assessment and Reserves Adequacy. With respect to the Hydro Stabilization Reserve, these projections assume average rainfall next winter, although hydro generation is still predicted to be below average due to low reservoir levels. The current forecast does not take into account potential rainfall associated with El Niño conditions in the spring of 2016, nor potential drought in the 2016/2017 year, which may follow the El Niño conditions of 2016. This scenario may help reserves, hurt reserves, or have little net effect depending on the associated rainfall levels. 22 | P a g e Figure 8: Electric Utility Reserves (Supply Fund): Actual Reserve Levels through FY 2015 and Projections through FY 2023 Figure 9: Electric Utility Reserves (Distribution Fund): Actual Reserve Levels through FY 2015 and Projections through FY 2023 23 | P a g e SECTION 5 F : RISK ASSESSMENT AND RESERVES ADEQUAC Y The Electric Utility currently has two contingency reserves, the Supply Operations Reserve and the Distribution Operations Reserve. This Financial Plan maintains reserves in excess of the reserve minimum for the Distribution Operations Reserve throughout the forecast period. Reserve levels also exceed the short-term risk assessment level for the Distribution Fund. The Supply Operations Reserve, however, may end up below minimum levels and below the short - term risk assessment level. There are a variety of risks associated with the Supply Fund as are shown in Table 8. Because of the high range of uncertainty in energy price predictions more than three years in the future, this risk assessment is only performed for the first two fiscal years of the forecast period. It is important to note that the likelihood of all of these adverse scenarios occurring simultaneously and to the degree described in Table 8 is very low. Table 8: Electric Supply Fund Risk Assessment Categories of Electric Supply Cost Uncertainties Estimates of Adverse Outcomes (M$) Notes FY 2017 FY 2018 1. Load Net Revenue 1.2 1.3 Revenue loss from load decreases (net of reduction in energy purchases) 2. Production from Hydroelectric Resources: Western & Calaveras 3.4 2.4 Lower than forecasted hydro 3. Renewable Production: Landfill & Wind 0.5 2.1 Additional cost of renewable output that is higher than forecasted 4. Carbon Neutral Cost 0.1 - Higher than forecasted market prices for RECs 5. Market Price (Energy) 1.1 0.5 Higher than forecasted market prices for energy 6. Local Capacity 0.4 0.7 Higher than forecasted market prices for local capacity 7. Transmission/CAISO 2.8 3.0 High-end transmission forecast scenario 8. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage 9. Western Cost 3.0 3.5 Risk of rate adjustments from Western Electric Supply Fund Risks $13.6 million $14.3 million Projected Supply Operations + Hydro Stabilization Reserve Levels $16.4 million $12.8 million Of the risks faced by the Electric Utility’s Supply Fund in FY 2016, the risk of a dry year with very low hydroelectric output is normally the largest, accounting for nearly half the total cost of all adverse outcomes. Since the utility’s costs for its hydroelectric resources are almost entirely fixed, costs do not decline when the output of those resourc es are low, but the utility needs to buy power to replace the lost output. The converse happens when hydroelectric output is higher than average. However, for FY 2017 and FY 2018, lower than average hydroelectric output is already expected, so the adverse risk is smaller than usual. Risks associated with hydroelectric output account for $3.4 million (25%) of FY 2017 contingencies. 24 | P a g e Of the remaining risks for FY 2017, $2.8 million (20%) is related to the projected costs if transmission cost increases are higher than staff’s current forecast. Another $3.0 million (22%) is related to the possibility of drought-related changes to Western rates for CVP hydropower, and $1.1 million (8%) is related to fluctuations in market prices for capacity, energy, and RECs. As shown in Figure 10, the Supply Operations Reserve will drop below the minimum reserve guidelines by as much as $3.9 million over the course of the forecast period. In addition, as shown in Figure 11, the combined hydro stabilization and supply operations reserves will drop below the risk assessment level. It is acceptable under the Electric Utility Reserves Management Practices to drop below minimum reserve guidelines so long as Council approves the Financial Plan. Staff recommends proceeding with this plan for two reasons: first, due to the presence of a strong El Niño condition in the Pacific Ocean, there is a chance of hi gh spring rains that may change this forecast, resulting in higher reserves, and second, the presence of the $51 million Electric Special Projects Reserve means that a small temporary shortfall in the Supply Operations Reserve should not affect the Electric Utility’s bond ratings. In the event drought continues, staff will re-evaluate its projections for FY 2018 and may recommend additional rate increases or the adoption of a hydroelectric rate adjuster. Figure 10: Electric Supply Operations Reserve Adequacy 25 | P a g e Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined Table 9 summarizes the risk assessment calculation for the Distribution Operations Reserve through FY 2021. As shown in Figure 12, the Distribution Operations Reserve will stay within the reserve guidelines over the course of the forecast period. The risk assessment includes the revenue shortfall that could accrue due to: 1. Lower than forecasted sales revenue; and 2. An increase of 10% of planned system improvement CIP expenditures for the budget year. Table 9: Electric Distribution Fund Risk Assessment ($000) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 Total non-commodity revenue $49,651 $52,233 $52,275 $52,237 $53,804 Max. revenue variance, previous ten years 8% 8% 8% 8% 8% Risk of revenue loss $3,919 $4,122 $4,126 $4,123 $4,246 CIP Budget $27,652 $22,058 $26,649 $15,868 $16,320 CIP Contingency @10% $2,765 $2,206 $2,665 $1,587 $1,632 Total Risk Assessment value $6,684 $6,328 $6,791 $5,710 $5,879 26 | P a g e Figure 12: Electric Distribution Operations Reserve Adequacy As shown in Figure 13, the CIP Reserve is projected to be well within the proposed revised minimum and maximum guidelines over the forecast period. While the Reserve is above maximum levels in later years, CIP Commitments are nearly impossible to project that far out, and adjustments to the reserve can be made in future years. 27 | P a g e Figure 13: Electric Distribution Operations Reserve Adequacy SECTI ON 5 G : LONG -TERM OUTLOOK This forecast covers the period from FY 2017 through FY 2023, but various long-term developments may create new costs for the utility over the next 5 to 35 years. While it is challenging to accurately forecast the impact these events will have on the utility’s costs, it is worth noting them as future milestones and keeping them in mind for long-term planning purposes. For the supply portfolio, the 2020s will see a number of notable events. The contract with Western for power from the CVP will expire in 2024. Determining the future relationship with Western after 2024 will be important in the years leading up to the contract expiration, especially because this resource represents nearly 40% of the electric portfolio, and is the utility’s largest source of carbon-free electricity. The utility’s three earliest and lowest cost renewable contracts will also begin expiring around that time, with the first contract expiring in 2021 and the last in 2028. These three contracts, plus one more expiring in 2030, currently provide 17% to 18% of the energy for the utility’s supply portfolio at prices under $65 per megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those 28 | P a g e contracts expire. Although recent prices have been in that range (or even lower), and costs may decrease in the future, current renewable projects also benefit from a wide range of tax and other incentives that may or may not be available in the 2020s and beyond. However, staff is in the process of procuring a replacement for the contract expiring in 2021 at a lower price than any of the City’s current renewable contracts. The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032 (assuming no new debt is issued). The project will only be 40 years old at that time. Calaveras debt service represents roughly 70% of the annual costs of that project (and nearly 7% of the utility’s total costs), so when the debt is retired, the project could b e a low-cost asset for the utility, providing carbon-free energy equal to 13% of the Electric Utility’s supply needs in an average year. Another factor that may affect the utility’s supply costs in the long run is carbon allowance revenue. Currently the Electric Utility receives $3 to 5 million per year in revenue from allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to pay for energy efficiency and to purchase renewable energy to support the utility’s Carbon Neutral Plan. That revenue source is expected to continue through 2020, but there is no provision for the continuation of these allocations past 2020. If the Electric Utility no longer received these allowances, it would have to fund these programs from sales revenues. Transmission costs are also continuing to rise. If the State continues to increase mandates or incentives for renewable energy development, integrating these new projects into the transmission grid will be an ever increasing challenge, some costs of which will be borne by Palo Alto. The planned expansion of the CAISO to a larger regional grid control area may result in additional transmission costs that could further increase CPAU’s transmission costs. In addition to the costs of new transmission lines that will need to be built, flexible resources will be required to balance rapid changes in wind or solar output throughout the day. Palo Alto will likely bear some of the costs of these new lines and resources. CPAU is also currently investigating installing a second transmission interconnection for Palo Alto, which could be funded by the Electric Special Projects reserve. Over the next several years the Electric Utility will continue to execute its usual monitoring, repair, and replacement routine for the distribution system, but will also begin the rollout of various smart grid technologies. The utility continues to monitor the growth of electric vehicle ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these factors may begin to create notable increases in electric consumption and have a variety of impacts on the distribution system. As housing stock is turned over, however, stricter building codes may help to counteract load growth, as may increasing numbers of rooftop solar installations. The utility has already started to take some of these factors into account in its long-term planning processes, but will need to con tinue to incorporate them into its planning methodologies. 29 | P a g e Looking out toward 2050 and beyond, if the State were to adopt climate goals consistent with Executive Orders S-3-05 and B-16-2012 (with a goal of reducing GHG emissions to 80 percent below 1990 levels by 2050), or if similar (or more aggressive) local goals were adopted, it is conceivable that electricity could replace natural gas and petroleum almost entirely. Many, if not most, vehicles would use electricity, though hydrogen is another potential fuel source under development and other technologies might be developed . Initial analysis of these types of scenarios is being undertaken in the context of the Sustainability and Climate Action Plan (S/CAP) development process. These types of scenarios require careful planning for the associated load growth to make sure the distribution system did not end up overloaded, or conversely, to avoid overinvestment. 30 | P a g e SECTION 6 : DETAILS AND ASSUMPTI ONS SECTION 6 A : ELECTRICITY PURCHASE S As shown in Figure 14 the utility gets roughly 50% of its energy from hydroelectric projects in a normal year (FY 2014 and FY2015 were dry). Contracts with renewable sources made up just over 20% of the portfolio in FY 2015, and are projected to rise to roughly 50% in FY 2017. The remainder comes from unspecified market sources. Under the City’s Carbon Neutral Plan, CPAU purchases RECs corresponding to the amount of market energy it purchases. Figure 14: Electricity Supply by Source 31 | P a g e Figure 15 shows the historical and projected costs for the electric supply portfolio,4 as well as average and actual hydroelectric generation.5 Electric supply costs decreased in FY 2010 and FY 2011 due to decreases in market prices related to shale gas. In addition, FY 2009 was a dry year with low hydroelectric production, so FY 2010 and FY 2011 looked better by comparison. Costs increased in FY 2013, FY 2014, and FY 2015 due to the drought, which reduced the amount of generation from hydroelectric resources. Costs are projected to decrease slightly in FY 2016 due to slightly higher hydroelectric generation, and may decrease substantially depending on rainfall. Even if hydroelectric generation returns to normal levels, costs will increase in FY 2017 due to increases in renewable energy costs as various renewable projects come online to fulfill the City’s carbon neutral and RPS goals. Transmission charges are also projected to increase as new transmission lines are built throughout California to accom modate new renewable projects. In total, electric supply costs are projected to increase to $75.2 million by FY 2018, at which point all currently contracted renewable projects will be online. Supply costs are only projected to change slightly in subsequent years. 4 Costs are shown net of wholesale revenues, and cannot be directly compared with the electric supply purchase figures shown in Appendix Error! Reference source not found. (Error! Reference source not found.). 5 Average hydroelectric generation increased in January of 2015 due to an increase in the utility’s contractual share of the output of the CVP Federal hydropower project. 32 | P a g e Figure 15: Electric Supply Portfolio Costs, Historical and Projected SECTION 6 B : OPERATIONS CPAU’s Electric Utility operations include the following activities: Administration, including financial management of charges allocated to the Electric Utility for administrative services provided by the General Fund and for Utilities Department administration, as well as debt service and other transfers. Additional detail on Electric Utility debt service is provided in Section 6D (Debt Service) Customer Service Engineering work for maintenance activities (as opposed to capital activities) Operations and Maintenance of the distribution system; and Resource Management Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of the work associated with each of these activities. 33 | P a g e From FY 2009 to FY 2015, Operations costs increased by $2.2 million, or less than 1% per year on average. In 2013 there was a one-time increase in expenses associated with an adjustment to the value of the City’s investment portfolio. Excluding debt service and transfers, which stay relatively stable over time, costs increased roughly 2.5% per year over that time. In FY 2016, however, Operations costs increased $4.5 million (9.6%). This was primarily due to increases in overhead and salary and benefit costs. Operations costs are projected to increase by an additional $1M per year starting in FY 2017 as work is done to begin catching up on deferred maintenance that has accumulated due to difficulty filling certain maintenance positions. Aside from those increases, costs are projected to increase with inflation over the remainder of the forecast period. Figure 16: Historical and Projected Electric Utility Operational Costs SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP) CIP spending for FY 2017 through FY 2019 is projected to increase substantially, primarily due to major one-time projects, including service connection upgrades for a few major customers, pole replacements related to the Fiber to the Home project, and Smart Grid upgrades. Ongoing capital investment in the electric distribution system is also increasing. The one-time projects will mostly be funded by customer-specific fees and transfers from other funds. Only $3.4 million of the funding for the one-time projects is projected to come from utility rates. This forecast assumes that smart grid projects are financed from the Electric Special Projects 34 | P a g e Reserve and with additional funding from the water and gas funds, but it would also be possible to use bond financing. Excluding the one-time projects listed above, the CIP plan for FY 2017 to FY 2023 is primarily funded by utility rates, but other sources of funds include connection fees (for Customer Connections), phone and cable companies (primarily for undergrounding), and other funds (for smart grid). The details of the CIP budget will be available in the Proposed FY 2017 Utilities Capital Budget. Figure 16 shows the adopted / proposed / projected capital budgets as well as actual and projected capitalized administrative overhead associated with the program. Figure 17: Electric Utility CIP Spending SECTION 6 D : DEBT SERVICE The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently makes payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax Credit Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction costs of solar demonstration projects at the Municipal Services Center, Baylands Interpretive Center, and Cubberley Community Center. The capacity of these projects totaled 250 kW. In exchange for funding part of the construction costs Electric Utility receives the RECs from these 35 | P a g e projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are int erest free (the investors receive a tax credit from the federal government). T his bond issuance is secured by the net revenues of the Electric Utility. Debt service for this bond continues through 2021, and for the financial forecast period is as follows: Table 10: Electric Utility Debt Service ($000) FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 2007 Clean Renewable Energy Bonds 100 100 100 100 100 100 - - The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage ratio of 125% of debt service. The current Financial Plan maintains compliance with these covenants throughout the forecast period, as shown in Appendix C. The Electric Utility’s reserves and net revenue are also pledged as security for the bond issuances listed in Table 11, even though the Electric Utility is not responsible for the debt service payments. The Electric Utility’s reserves or net revenues would only be called upon if the responsible utilities are unable to make their debt service payments. Staff does not currently foresee this occurring. Table 11: Other Issuances Secured by Electric Utility’s Revenues or Reserves Bond Issuance Responsible Utilities Annual Debt Service ($000) Secured by Electric Utility’s: Net Revenues Reserves 1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No 1999 Utility Revenue Bonds, Series A Storm Drain Wastewater Collection Wastewater Treatment $1,207 No Yes 2009 Water Revenue Bonds (Build America Bonds) Water $1,977* No Yes 2011 Utility Revenue Refunding Bonds, Series A Gas Water $1,457 No Yes *Net of Federal interest subsidy SECTION 6 E : EQUITY TRANSFER The City calculates the equity transfer from its Electric Utility based on a methodology adopted by Council in 2009, which has remained unchanged since6. Each year it is calculated according to the 2009 Council-adopted methodology, and does not require additional Council action. 6 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed changes to equity transfer methodology. 36 | P a g e SECTION 6 F : WHOLESALE REVENUES A ND OTHER REVENUES The Electric Utility receives most of its revenues from sales of electricity, but about 12% comes from other sources. Of these other sources, about a third represent wholesale “revenues” that is included solely for accounting purposes. These revenues have offsetting electric supply purchase costs, and do not normally affect the utility’s net position. Of the remaining revenues, the largest revenue sources are interest on reserves, connection fees for new or replacement electric services, and carbon allowance revenues associated with the State’s cap-and-trade program. In FY 2015 these sources represented roughly 50% of revenue from sources other than electricity sales. The remaining FY 2015 revenues consisted of a variety of one-time transfers. Revenues from connection fees have more than doubled since FY 2009. Revenue from these sources decreased slightly during the recession, but has increased substantially since then, peaking in FY 2014. Staff is forecasting slightly lower revenue from this source in subsequent years. Carbon allowance revenues are projected to stay stable through the forecast period, as is interest income. However, both of these revenue sources are subject to some uncerta inty. The State’s cap-and-trade program regulations only describe the program through 2020. This forecast assumes the program will remain in place with similar program design following 2020, but that may not be the case. CARB is in the process of establishing post-2020 rules. The forecast for interest income assumes current interest rates continue and there are no major reserve reductions aside from what is anticipated in this Financial Plan. If interest rates rise, interest income could increase, and if reserves decreased (due to drought or a withdrawal from the ESP reserve for a major project), interest income would decrease. SECTION 6 G : SALES REVENUES Sales revenue projections are based on the load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7. As discussed in Section 5A, sales revenues for this utility stay relatively stable due to the mild climate in Palo Alto . In addition, Palo Alto is a built out City, with incremental growth in population and relatively stable commercial customer loads. 37 | P a g e SECTION 7 : COMMUNICATIONS PLAN CPAU communication methods include use of the Utilities website, utility bill inserts, messaging on bills and envelopes, email newsletters, print ads in local publications, videos and participation in community outreach events. The FY 2017 Electric Utility communications strategy covers these primary areas: rates, drought impacts, efficiency, renewables, operations, infrastructure and safety. In FY 2017, CPAU is proposing an 11% increase in electric utility rates. Electric utility rates have not increased since 2009, as the City has been drawing down reserves from the Electric Fund. The rate increase is necessary this year, as these reserves are below the minimum reserve level. Communications will focus on the reasons why a rate increase is necessary, and why the percentage increase is higher than projected in past financial forecasts, particularly due to the impact of the drought. Palo Alto purchases a significant portion of its electricity from hydroelectric resources. Severe drought conditions over the past few years have reduced available hydroelectric supplies, requiring the City to purchase more costly replacement electric supplies. Reliability and safety are primary concerns for CPAU and City Council has placed increasing emphasis on capital improvement investments for utility infrastructure. In order to maintain system integrity, continued capital improvement costs are necessary. De ferring such costs to future years would not be prudent, as deferred investment in maintenance, operations and capital improvement upgrades could potentially jeopardize the safety and reliability of the electric utility system. Despite these costs and increasing rates, CPAU’s rates are far lower than PG&E’s. Keeping costs low is one of the benefits CPAU offers its customers as a public utility provider. CPAU will continue to communicate about the City’s carbon neutral electric supply portfolio. Outreach includes apprising the public of major renewable energy purchase agreements, which contribute toward Palo Alto’s long-term energy security and commitment to sustainability. Recent power purchase agreements have allowed CPAU to procure long -term renewable electric supplies at low costs. CPAU will highlight these environmental attributes and value in our communications. Throughout the year, communications staff promotes CPAU’s electric efficiency services, rebates and local renewable energy programs. Since January 2015, CPAU has been encouraging community participation in the Georgetown University Energy Prize competition, a friendly, national campaign for energy efficiency. This two-year campaign encourages the community to reduce energy use and compete for a $5 million prize. Just recently, CPAU launched new programs that will allow customers to better understand and manage their energy use. Such programs include a free utility bill analysis service with option for a subsidized in -depth home energy assessment, and an online utility portal for customers to view consumption history, learn about efficiency tips and CPAU programs they can take advantage of for home energy efficiency. 38 | P a g e APPENDICES Appendix A: Electric Utility Financial Forecast Detail Appendix B: Electric Utility Reserves Management Practices Appendix C: Description of Electric utility Operational Activities Appendix D: Samples of Recent Electric Utility Outreach Communications 6053706 APPENDIX A : ELECTRIC UTILITY FINANCIAL FORECAST D ETAIL 6053706 (page intentionally left blank) 6053706 1 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 2 3 ELECTRIC LOAD 4 Purchases (MWh)1,040,851 1,019,788 978,833 969,519 976,319 980,894 979,005 977,292 993,844 997,125 998,260 997,531 997,596 999,464 986,864 5 Sales (MWh)995,811 965,048 946,518 942,562 946,841 950,784 936,773 946,996 963,035 966,215 967,314 966,608 966,670 968,481 956,271 6 7 BILL AND RATE CHANGES 8 System Average Rate ($/kWh)0.1048$ 0.1155$ 0.1168$ 0.1156$ 0.1154$ 0.1164$ 0.1158$ 0.1158$ 0.1274$ 0.1398$ 0.1435$ 0.1435$ 0.1452$ 0.1452$ 0.1477$ 9 Change in System Average Rate 10%1%-1%0%1%0%0%11%10%3%0%1%0%2% 10 Change in Average Residential Bill 11%-5%-1%-4%-1%-5%10%8%10%2%0%1%0%1% 11 12 STARTING RESERVES 13 Reappropriations (Non-CIP)- - 2,760,000 343,000 1,886,000 305,000 - - - - - - - - - 14 Commitments (Non-CIP)2,241,000 1,916,000 1,463,000 1,593,000 2,737,000 3,528,000 3,164,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 15 Restricted for Debt Service - - - - - - - - - - - - - - - 16 Emergency Plant Replacement 3,057,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - 17 Central Valley Project Reserve 22,000 153,000 306,000 305,000 314,000 313,000 329,000 - - - - - - - - 18 Underground Loan Reserve 709,000 717,000 731,000 736,000 742,000 738,000 734,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 19 Public Benefits Reserves 2,109,000 4,280,000 3,750,000 3,139,000 1,149,000 2,197,000 2,064,000 2,574,000 2,700,394 2,790,356 2,799,046 2,717,399 2,544,810 2,434,376 2,373,578 20 Electric Special Projects Reserve 70,397,000 64,535,000 59,865,000 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,534,944 51,383,460 51,050,127 47,300,127 47,300,127 47,300,127 47,300,127 21 Hydro Stabilization Reserve - - - - - - - 17,000,000 11,400,000 2,400,000 - - - - - 22 Capital Reserves - - - - - - - - 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 23 Rate Stabilization Reserves 55,418,000 47,783,000 54,339,000 66,331,000 74,609,000 69,029,000 70,049,000 14,411,000 5,411,000 - - - - - - 24 Operations Reserves - - - - - - - 22,498,000 22,733,825 22,014,607 22,281,475 24,814,237 27,032,576 30,783,222 34,269,008 25 Unassigned - - - - - - - - - - 0 - - - - 26 TOTAL STARTING RESERVES 133,953,000 120,384,000 124,214,000 129,005,000 132,757,000 128,948,000 129,178,000 112,153,000 100,476,163 85,284,424 82,826,649 81,527,763 83,573,514 87,213,725 90,638,713 27 28 REVENUES 29 Net Sales 105,312,712 113,129,269 111,948,267 109,309,318 109,974,337 110,301,711 108,674,986 109,644,507 122,721,963 135,111,161 138,828,086 138,726,658 140,313,744 140,576,542 141,259,300 30 Wholesale Revenues 10,618,388 7,903,940 8,443,016 7,189,218 6,635,790 6,010,409 6,267,000 6,763,000 11,732,580 13,249,634 14,128,345 15,816,411 16,063,130 15,367,103 15,992,486 31 Other Revenues and Transfers In 11,744,330 8,458,392 6,374,799 6,316,048 8,736,976 9,772,185 8,379,507 8,315,879 17,306,372 13,685,157 16,104,331 8,952,387 9,297,064 9,706,437 10,042,027 32 TOTAL REVENUES 127,675,429 129,491,602 126,766,082 122,814,584 125,347,103 126,084,305 123,321,493 124,723,385 151,760,915 162,045,951 169,060,763 163,495,456 165,673,937 165,650,082 167,293,813 33 34 EXPENSES 35 Electric Supply Purchases 82,348,075 68,714,475 61,247,248 58,724,136 61,313,637 68,785,977 80,022,010 75,705,000 86,377,737 88,523,524 89,131,094 90,303,886 89,637,135 88,542,665 89,918,517 36 Operating Expenses 37 Administration 38 Allocated Charges 3,585,068 2,667,704 2,807,991 3,416,423 4,399,674 4,139,837 4,511,222 3,651,896 3,743,559 3,837,533 3,933,853 4,032,597 4,133,584 4,236,960 4,342,932 39 Rent 3,428,294 3,963,377 3,721,542 3,839,201 3,875,836 4,051,044 4,147,742 4,991,328 5,141,068 5,295,300 5,454,159 5,617,784 5,786,317 5,959,907 6,138,704 40 Debt Service 8,185,819 7,919,136 7,343,352 8,902,751 9,265,736 9,020,651 9,037,000 9,139,768 8,953,886 8,955,164 8,808,619 8,818,349 8,783,507 8,792,388 9,624,493 41 Transfers and Other Adjustments 13,282,668 10,860,269 13,056,927 11,603,695 16,797,054 11,385,421 10,789,119 11,778,415 11,781,400 11,784,460 11,787,597 11,790,812 11,794,107 11,797,485 11,800,947 42 Subtotal, Administration 28,481,848 25,410,486 26,929,812 27,762,069 34,338,299 28,596,953 28,485,082 29,561,407 29,619,914 29,872,457 29,984,228 30,259,541 30,497,516 30,786,740 31,907,076 43 Resource Management 2,062,511 3,033,428 2,380,313 2,654,024 3,024,268 3,541,524 2,138,615 2,966,005 3,071,752 3,182,092 3,295,330 3,413,039 3,513,915 3,605,059 3,699,533 44 Demand Side Management 3,336,356 4,048,114 3,490,676 4,541,531 3,529,529 3,187,875 3,491,470 4,476,424 3,612,447 3,694,961 3,558,989 3,275,399 3,213,446 3,169,620 3,251,901 45 Operations and Mtc 8,975,462 8,892,002 9,339,340 9,288,490 9,601,481 9,488,627 10,716,881 12,216,961 13,621,453 14,075,224 14,540,523 15,022,687 15,450,353 15,847,643 16,258,382 46 Engineering (Operating)879,303 1,094,766 1,070,441 1,057,783 1,114,945 1,102,008 1,230,160 1,929,843 1,981,771 2,035,192 2,089,931 2,146,191 2,201,598 2,257,007 2,313,920 47 Customer Service 1,650,731 1,896,956 1,881,881 1,908,493 2,007,322 2,032,231 1,548,851 2,348,349 2,436,928 2,529,629 2,624,844 2,724,064 2,806,984 2,880,302 2,956,458 48 Allowance for Unspent Budget - - - - - - - (1,328,747) (1,421,462) (1,467,484) (1,514,688) (1,563,571) (1,607,504) (1,648,717) (1,691,289) 49 Subtotal, Operating Expenses 45,386,213 44,375,751 45,092,464 47,212,389 53,615,844 47,949,218 47,611,059 52,170,242 52,922,803 53,922,071 54,579,157 55,277,350 56,076,307 56,897,655 58,695,982 50 Capital Program Contribution 13,510,141 12,571,376 15,635,370 13,126,059 14,226,622 9,119,111 12,713,425 16,988,980 27,652,114 22,058,131 26,649,398 15,868,470 16,320,285 16,784,774 17,262,590 51 TOTAL EXPENSES 141,244,429 125,661,602 121,975,082 119,062,584 129,156,103 125,854,305 140,346,493 144,864,222 166,952,654 164,503,726 170,359,649 161,449,705 162,033,726 162,225,093 165,877,088 52 53 ENDING RESERVES 54 Reappropriations (Non-CIP)- 2,760,000 343,000 1,886,000 305,000 - - - - - - - - - - 55 Commitments (Non-CIP)1,916,000 1,463,000 1,593,000 2,737,000 3,528,000 3,164,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 56 Restricted for Debt Service - - - - - - - - - - - - - - - 57 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - - 58 Central Valley Project Reserve 153,000 306,000 305,000 314,000 313,000 329,000 - - - - - - - - - 59 Underground Loan Reserve 717,000 731,000 736,000 742,000 738,000 734,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 60 Public Benefits Reserves 4,280,000 3,750,000 3,139,000 1,149,000 2,197,000 2,064,000 2,574,000 2,700,394 2,790,356 2,799,046 2,717,399 2,544,810 2,434,376 2,373,578 2,191,308 61 Electric Special Projects Reserve 64,535,000 59,865,000 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,534,944 51,383,460 51,050,127 47,300,127 47,300,127 47,300,127 47,300,127 47,300,127 62 Hydro Stabilization Reserve - - - - - - 17,000,000 11,400,000 2,400,000 - - - - - - 58 Capital Reserve - - - - - - - 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 59 Rate Stabilization Reserve 47,783,000 54,339,000 66,331,000 74,609,000 69,029,000 70,049,000 14,411,000 5,411,000 - - - - - - - 60 Operations Reserve - - - - - - 22,498,000 22,733,825 22,014,607 22,281,475 24,814,237 27,032,576 30,783,222 34,269,008 35,868,004 61 Unassigned - - - - - - - - - 0 - - - - - 62 TOTAL ENDING RESERVES 120,384,000 124,214,000 129,005,000 132,757,000 128,948,000 129,178,000 112,153,000 100,476,163 85,284,424 82,826,649 81,527,763 83,573,514 87,213,725 90,638,713 92,055,438 6053706 1 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 2 3 REVENUES 4 Net Sales 82%87%88%89%88%87%88%88%81%83%82%85%85%85%84% 5 Other Revenues and Transfers In 18%13%12%11%12%13%12%12%19%17%18%15%15%15%16% 6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100% 7 8 EXPENSES 9 Commodity Purchases 56%54%46%47%46%54%56%51%46%46%45%47%47%47%46% 10 Operating Expenses 11 Administration 12 Allocated Charges 3%2%2%3%3%3%3%3%2%2%2%2%3%3%3% 13 Rent 2%3%3%3%3%3%3%3%3%3%3%3%4%4%4% 14 Debt Service 6%6%6%7%7%7%6%6%5%5%5%5%5%5%6% 15 Transfers and Other Adjustments 9%9%11%10%13%9%8%8%7%7%7%7%7%7%7% 16 Subtotal, Administration 20%20%22%23%27%23%20%20%18%18%18%19%19%19%19% 17 Resource Management 1%2%2%2%2%3%2%2%2%2%2%2%2%2%2% 18 Operations and Mtc 6%7%8%8%7%8%8%8%8%9%9%9%10%10%10% 19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1% 20 Customer Service 1%2%2%2%2%2%1%2%1%2%2%2%2%2%2% 21 Allowance for Unspent Budget 0%0%0%0%0%0%0%-1%-1%-1%-1%-1%-1%-1%-1% 22 Subtotal, Operating Expenses 30%32%34%36%39%36%31%33%30%31%30%32%33%33%33% 23 Capital Program Contribution 10%10%13%11%11%7%9%12%17%13%16%10%10%10%10% 24 TOTAL EXPENSES 95%96%93%93%96%97%96%95%92%90%90%89%89%90%90% 25 26 RISK ASSESSMENT DETAIL (SUPPLY FUND) 27 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 28 1. Load Net Revenue 77,428 652,853 1,208,477 29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 3,397,119 30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 539,073 31 4. Carbon Neutral Cost 331,630 303,022 114,983 32 5. Market Price 909,196 775,584 1,138,589 33 6. Local Capacity 475,962 408,388 446,695 34 7. Transmission/CAISO 4,555,915 3,741,647 2,806,120 35 8. Plant Outage 1,000,000 1,000,000 1,000,000 36 9. Western Cost 3,130,000 2,704,738 2,973,619 37 10. Regulatory & Legal - - - 38 11. Supplier Default - - - 39 TOTAL 20,170,708 19,380,490 13,624,674 40 Supply Operations + Hydro Stabilization Reserves, % of Risk Assessment 196%176%179% 41 42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND) 43 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 44 Distribution Revenue Variance 3,240,845 3,290,258 3,918,697 4,122,469 4,163,694 4,160,651 4,285,471 4,293,497 4,422,302 45 10% CIP Program Contingency 1,271,343 1,698,898 2,765,211 2,205,813 2,664,940 1,586,847 1,632,028 1,678,477 1,726,259 46 Total Risk Asssessment Value 4,512,188 4,989,156 6,683,908 6,328,282 6,828,634 5,747,498 5,917,499 5,971,975 6,148,561 47 Projected Operations Reserve 22,498,000 22,733,825 22,014,607 22,281,475 24,814,237 27,032,576 30,783,222 34,269,008 35,868,004 48 Operations Reserve, % of Risk Value 499%456%329%352%363%470%520%574%583% 49 44 SUPPLY OPERATIONS RESERVE 45 Min (60 days of non-capital expenses)- - - - - - 8,339,587 6,424,305 6,557,102 6,698,857 6,808,081 6,897,553 7,013,278 7,126,792 7,248,481 46 Target (90 days of non-capital expenses)- - - - - - 10,338,923 9,636,457 9,835,653 10,048,285 10,212,121 10,346,329 10,519,917 10,690,188 10,872,721 47 Max (120 days of non-capital expenses)- - - - - - 12,338,259 12,848,609 13,114,204 13,397,714 13,616,162 13,795,105 14,026,555 14,253,584 14,496,961 48 49 DISTRIBUTION OPERATIONS RESERVE 50 Min (60 days of non-capital expenses)- - - - - - 8,339,587 6,424,305 6,557,102 6,698,857 6,808,081 6,897,553 7,013,278 7,126,792 7,248,481 51 Target (90 days of non-capital expenses)- - - - - - 10,338,923 9,636,457 9,835,653 10,048,285 10,212,121 10,346,329 10,519,917 10,690,188 10,872,721 52 Max (120 days of non-capital expenses)- - - - - - 12,338,259 12,848,609 13,114,204 13,397,714 13,616,162 13,795,105 14,026,555 14,253,584 14,496,961 53 Risk Assessment Value 4,512,188 4,989,156 6,683,908 6,328,282 6,828,634 5,747,498 5,917,499 5,971,975 6,148,561 ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 43 | P a g e APPENDIX B : ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES (This section includes the proposed amendments to this section. This section will be finalized following Council adoption of the final amended version.) The following reserves management practices are used when developing the Electric Utility Financial Plan: Section 1. Definitions a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal years covered by the Financial Plan. For example, if the Financial Plan delivered in conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015 to FY 2019 would be the Financial Planning Period. b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers to the Utility’s Unrestricted Net Assets. c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets as the difference between its assets and liabilities. d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital assets (net of related debt) or restricted for debt service or other restricted purposes. Section 2. Supply Fund Reserves The Electric Supply Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserve for Commitments) b) For operating budgets reappropriated from previous years, as described in Section 5 (Reserve for Reappropriations) c) For special projects for the benefit of the Electric Utility ratepayers, as described in Section 6 (Electric Special Projects Reserve) d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric resources, as described in Section 7 (Hydroelectric Stabilization Reserve) e) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves) f) For operating contingencies, as described in Section 12 (Operations Reserves) g) Any funds not included in the other reserves will be considered Unassigned Reserves and shall be returned to ratepayers or assigned a specific purpose as described in Section 13 (Unassigned Reserves). Section 3. Distribution Fund Reserves The Electric Distribution Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserves for Commitments) b) For operating and capital budgets reappropriated from previous years, as described in Section 5 (Reserves for Reappropriations) c) As an offset to underground loan receivables, as described in Section 8 (Underground Loan Reserve) d) To hold Public Benefit Program funds collected but not yet spent, as described in Section 9 (Public Benefits Reserve) ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 44 | P a g e e) For cash flow management and contingencies related to the Electric Utility’s Capital Improvement Program (CIP), as described in Section 10 (CIP Reserve) f) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves) g) For operating contingencies, as described in Section 12 (Operations Reserves) h) Any funds not included in the other reserves will be considered Unassigned Reserves and shall be returned to ratepayers or assigned a specific purpose as described in Section 14 (Unassigned Reserves). Section 4. Reserves for Commitments At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves for Commitments will be set to an amount equal to the total remaining spending authority for all contracts in force for the Electric Supply Fund and Electric Distribution Fund, respectively, at that time. Section 5. Reserves for Reappropriations At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves for Reappropriations will be set to an amount equal to the amount of all remaining capital and non-capital budgets that will be reappropriated to the following fiscal year for each Fund in accordance with Palo Alto Municipal Code Section 2.28.090. Section 6. Electric Special Projects Reserve The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve and Adoption of Electric Special Project Reserve Guidelines). These policies and time lines are included from Resolution 9206 as amended to refer to the reserves structure set forth in these Reserves Management Practices: a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers; b) The ESP Reserve funds must be used for projects of significant impact; c) Projects proposed for funding must demonstrate a need and value to electric ratepayers. The projects must have verifiable value and must not be speculative, or high-risk in nature; d) Projects proposed for funding must be substantial in size, requiring funding of at least $1 million; e) The preferred projects to be funded by the ESP Reserve must be identified by end of FY 2015; f) Any uncommitted funds remaining at the end of FY 2020 will be transferred to the Electric Supply Operations Reserve and the ESP Reserve will be closed; and g) Funds may be used for analysis and pilot projects which would be the basis for planned large projects. Section 7. Hydroelectric Stabilization Reserve Supply cost savings and surplus energy sales revenue associated with higher than average generation from hydroelectric resources may be added to the Electric Supply Fund’s Hydroelectric Stabilization Reserve by action of the City Council and held to offset higher ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 45 | P a g e commodity supply costs during years of lower than ave rage generation. Withdrawal of funds from the Hydroelectric Stabilization Reserve requires action by the City Council. Section 8. Underground Loan Reserve At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the principal payments made against outstanding underground loans. Section 9. Public Benefits Reserve The Public Benefits Reserve will be increased by the amount of unspent Public Benefits Revenues remaining at the end of each fiscal year. Expenditure of these funds requires action by the City Council. Section 10. CIP Reserve The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for capital contingencies. Staff will manage the CIP Reserve according to the following practices: a) The following guideline levels are set forth for the CIP Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period based on the levels of CIP expense budgeted for that year. Minimum Level 60 days 6 months of budgeted CIP expense Maximum Level 120 days 12 months of budgeted CIP expense b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and the Reserve for Commitments when funds are added to or removed from the Reserve for Commitments as a result of a change in contractual commitments related to CIP projects. Any other additions to or withdrawals from the CIP reserve require Council action. c) Minimum Level: i) Funds held in the Reserve for Commitments may be counted as part of the CIP Reserve for the purpose of determining comp liance with the CIP Reserve minimum guideline level. ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present a plan to the City Council to replenish the reserve. The plan shall be delivered by the end of the following fiscal year, and shall, at a minimum, result in the reserve reaching its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is below its minimum level at the end of FY 2017, staff must present a plan by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff may present, and the Council may adopt, an alternative plan that takes longer than one year to replenish the reserve, or that does so in a shorter period of time. d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds may be added to this reserve. If there are funds in this reserve in excess of the maximum level staff must propose to transfer these funds to another reserve or return them to ratepayers in the next Financial Plan. Staff may also seek City Council to ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 46 | P a g e approve holding funds in this reserve in excess of the maximum level if they are held for a specific future purpose related to the CIP. Section 11. Rate Stabilization Reserves Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves by action of the City Council and held to manage the trajectory of future year rate increases. Withdrawal of funds from either Rate Stabilization Reserve requires action by the City Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year, any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the Financial Planning Period. Section 12. Operations Reserves The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to manage normal variations in the costs of providing electric service and as a reserve for contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves described in Section 4 to d) above will be included in the appropriate Operations Reserve unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff will manage the Operations Reserves according to the following practices: a) The following guideline levels are set forth for the Electric Supply Fund Operations Reserve. These guideline levels are calculated for each fiscal year of the Fi nancial Planning Period based on the levels of Operations and Maintenance (O&M) and commodity expense forecasted for that year in the Financial Plan. Minimum Level 60 days of Supply Fund O&M and commodity expense Target Level 90 days of Supply Fund O&M and commodity expense Maximum Level 120 days of Supply Fund O&M and commodity expense b) The following guideline levels are set forth for the Electric Distribution Fund Operations Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period based on the levels of O&M expense forecasted for that year in the Financial Plan. Minimum Level 60 days of Distribution Fund O&M expense Target Level 90 days of Distribution Fund O&M expense Maximum Level 120 days of Distribution Fund O&M expense c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund or Distribution Fund’s Operations Reserve are lower than the minimum level set forth above, staff shall present a plan to the City Council to replenish the reserve. The plan shall be delivered within six months of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its minimum level by the end of the following fiscal year. For example, if the Operations Reserve is below its minimum level at the end of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In addition, staff may present an alternative plan that takes longer than one year to replenish the reserve. d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or lower than the target level, any Financial Plan created for the Electric Utility shall be ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 47 | P a g e designed to return both Operations Reserves to their target levels by the end of the forecast period. e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level, no funds may be added to this Reserve. Any further increase in that fund’s Fund Balance shall be automatically included in the Unassigned Reserve described in Section 13, below. Section 13. Unassigned Reserves If the Operations Reserve in either the Electric Supply Fund or the Electric Distri bution Fund reaches its maximum level, any further additions to that fund’s Fund Balance will be held in the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council must include a plan to assign them to a specific purpose or return them to the Electric Utility ratepayers by the end of the first fiscal year of the next Financial Planning Period. For example, if there were funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign the funds in the Unassigned Reserve by the end of FY 201 7. Staff may present an alternative plan that retains these funds or returns them over a longer period of time. Section 14. Intra-Utility Transfers between Supply and Distribution Funds Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are permitted if consistent with the purposes of the two reserves involved in the transfer. Such transfers require action by the City Council. ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 48 | P a g e APPENDIX C : DESCRIPTION OF ELE CTRIC UTILITY OPERAT IONAL ACTIVITIES This appendix describes the activities associated with the various cost categories referred to in this Financial Plan. Customer Service: This category includes the Electric Utility’s share of the call center, meter reading, collections, and billing support functions. Billing support encompasses staff time associated with bill investigations and quality control on certain aspects of the billing process. It does not include maintenance of the billing system itself, which is included in Administration. This category also includes CPAU’s key account representat ives, who work with large commercial customers who have more complex requirements for their electric services. Resource Management: This category includes supply portfolio management, energy procurement, rate setting, and tracking of legislation and regulation related to the electric industry. Operations and Maintenance: This category includes the costs of a variety of distribution system maintenance activities, including: monitoring the substations and performing routine maintenance; performing preventative maintenance on the system; monitoring the system’s status from the UCC using SCADA; maintaining the SCADA system; investigating outages and other customer complaints and performing emergency repairs; clearing vegetation near overhead power lines; and testing and replacing meters to ensure accurate sales metering. Administration: Accounting, purchasing, legal, and other administrative functions provided by the City’s General Fund staff, as well as shared communications services, Utilities Department administrative overhead and billing system maintenance costs. Demand Side Management: Includes the cost of administering energy efficiency programs and the direct cost of rebates paid. Includes solar rebates. Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small portion of their time is spent assisting with distribution system maintenance. APPENDIX D : SAMPLES OF RECENT EL ECTRIC UTILITY OUTRE ACH COMMUNICATIONS City of Palo Alto Prepared by: 570 Kirkland Way, Suite 100 Kirkland, Washington 98033 A registered professional engineering corporation with offices in Kirkland, WA and Portland, OR Telephone: (425) 889-2700 Facsimile: (425) 889-2725 City of Palo Alto Electric Cost of Service and Rate Study Draft April 5, 2016 ATTACHMENT C CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY i Contents CONTENTS .............................................................................................................................................................. I EXECUTIVE SUMMARY ........................................................................................................................................... 1 REVENUE REQUIREMENT ................................................................................................................................................. 1 COST OF SERVICE ANALYSIS.............................................................................................................................................. 2 RATE DESIGN OVERVIEW ................................................................................................................................................. 4 RECOMMENDATION ....................................................................................................................................................... 5 OVERVIEW OF RATE SETTING PRINCIPLES .............................................................................................................. 6 OVERVIEW AND ORGANIZATION OF REPORT ........................................................................................................................ 6 OVERVIEW OF THE ANALYSES ........................................................................................................................................... 6 OVERVIEW OF REVENUE REQUIREMENT METHODOLOGIES ..................................................................................................... 7 OVERVIEW OF COST ALLOCATION PROCEDURES ................................................................................................................... 7 RATE DESIGN AND ECONOMIC THEORY .............................................................................................................................. 7 DEVELOPMENT OF THE REVENUE REQUIREMENT .................................................................................................. 9 OVERVIEW OF CPA’S REVENUE REQUIREMENT METHODOLOGY ............................................................................................. 9 DEVELOPMENT OF POWER SUPPLY COSTS......................................................................................................................... 10 OTHER OPERATIONS AND MAINTENANCE EXPENSES ........................................................................................................... 10 GENERAL FUND TRANSFER ............................................................................................................................................. 11 RATE-FUNDED CAPITAL IMPROVEMENT PROGRAM (CIP) .................................................................................................... 11 MISCELLANEOUS REVENUES ........................................................................................................................................... 11 TRANSFERS FROM RESERVES .......................................................................................................................................... 11 SUMMARY OF REVENUE REQUIREMENT ............................................................................................................................ 11 RECOMMENDATION ..................................................................................................................................................... 12 COST OF SERVICE ANALYSIS ................................................................................................................................. 13 COSA DEFINITION AND GENERAL PRINCIPLES ................................................................................................................... 13 FUNCTIONALIZATION OF COSTS ....................................................................................................................................... 14 CLASSIFICATION AND ALLOCATION OF COSTS ..................................................................................................................... 15 COST OF SERVICE RESULTS ............................................................................................................................................. 23 REVIEW OF CUSTOMER CLASSES OF SERVICE ..................................................................................................................... 26 RATE DESIGN ....................................................................................................................................................... 27 RATE DESIGN – NON-COMMODITY ................................................................................................................................. 27 RATE DESIGN – COMMODITY ......................................................................................................................................... 28 PROPOSED RATE DESIGN ............................................................................................................................................... 28 MUNICIPAL E-18 ......................................................................................................................................................... 32 MINIMUM BILL ANALYSIS .............................................................................................................................................. 32 TIME OF USE RATE SCHEDULES ....................................................................................................................................... 32 PUBLIC BENEFITS CHARGE ............................................................................................................................................. 34 NET ENERGY METERING ................................................................................................................................................ 35 STREET LIGHTING AND TRAFFIC SIGNALS ........................................................................................................................... 36 TECHNICAL APPENDIX .......................................................................................................................................... 38 COST OF SERVICE MODEL CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 1 Executive Summary The City of Palo Alto (CPA) retained EES Consulting, Inc. (EES Consulting) to perform an electric cost of service analysis (COSA) and rate study as part of its ongoing efforts to maintain fiscally prudent and fair, cost-based rates for its electric customers. The purpose of this report is to discuss the data inputs, assumptions and results that were part of developing the rate study. A comprehensive rate study generally consists of three separate, yet interrelated analyses. These three analyses are the revenue requirement, the COSA, and the rate design. Revenue Requirement A revenue requirement analysis compares the overall revenues of the utility to its expenses and helps determine whether an overall adjustment to rate levels is required. For this analysis, a “cash basis” method was used for determining CPA’s revenue requirement. Recorded annual operating expenses for fiscal year (FY) 2014-2015 as well as the FY 2016-17 budget forecast provided by CPA were used to determine the revenue requirement. A base case was defined to develop the COSA. This base case assumed the following: Historic/recorded year is FY 2014-15 (July 2014 – June 2015). Test year/allocation year is FY 2016-17. Billing determinants were based on FY 2016-17 forecasts. Expenses were based on forecasted FY 2016-17 expenses. Transfers from reserves and budget savings of $17.9 million were assumed for FY 2016-17, as assumed in the CPA financial forecasts. If CPA’s rates currently in effect remain unchanged, FY 2016-17 revenues from all sources would equal $118.9 million, while budgeted expenses are $148.7 million.1 After taking the reserve transfers and budget savings into account, as well as other revenues, the revenue requirement for FY 2016-17 is $122.5 million. This is the amount of revenue needed from rates in FY 2016-17. With no rate change, forecasted sales revenues for FY 2016-17 are $110.5 million, as shown in Schedule 1.9. This means there remains a 10.1 percent shortfall in revenues relative to costs. This translates into a 10.8 percent increase in the CPA’s system average retail rate, as shown in Schedule 1.1, though the increase for individual customer classes of service will vary, as discussed in the section on the COSA. A summary of the draft revenue requirement is shown in Table 1. Additional detail can be found in Schedules 1.4 and 3.1. 1 Expenses exclude capital expenses reimbursed by connection fees or other direct reimbursement agreements. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 2 Table 1 Summary of the Revenue Requirement FY: 2016-2017 Revenue Requirement Production (Purchased Power) $90,065,328 Distribution $13,195,107 Customer Accounts and Services $5,946,916 Administration and General $13,931,304 Capital Projects from Rates $13,501,2502 General Fund Transfer $12,101,000 Total Expenses $148,740,905 Transfers from Reserves and Allowance for Unspent Budget $17,870,017 Other Revenues 8,382,909 Total Revenue Required from Rates (Revenue Requirement) $122,487,979 Revenues Based on Rates Currently in Effect $110,531,481 Additional Rate Revenue Needed $11,956,498 Total Required Rate Revenue Increase (Decrease) 10.8% Cost of Service Analysis A COSA is concerned with the equitable allocation of the revenue requirement to the various customer classes of service. As is standard procedure for COSAs, the revenue requirement shown in Table 1 for CPA was functionalized, classified and allocated. This process is described in detail in the section below titled “Cost of Service Analysis.” Table 2 shows the results of the COSA. It shows the revenues that would be realized in FY 2016-17 without any rate changes (i.e. keeping the rates currently in effect), the share of the FY 2016-17 revenue requirement that should be allocated to each rate class as determined by the COSA, and the deficiency in revenue if current rates are left unchanged. Without a rate change, FY 2016-17 revenues will be less than allocated FY 2016-17 costs for every class of service. In addition, the variance between revenues and costs is greater for some classes than others. The last column of Table 2 shows the increase in revenue required for each rate class. For most classes this increase will be achieved by increasing rates. The results of the COSA are summarized in Table 2. More detail is presented in Schedules 1.1, 1.2, and 1.4, and the COSA methodology is described in more detail below in the “Cost of Service Analysis” section of this report. 2 Excludes capital expenses reimbursed by connection fees or other direct reimbursement agreements . CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 3 Table 2 Summary of Cost of Service Analysis for FY 2016-17 Test Year Projected FY 2016-17 Revenues under Rates Currently in Effect Net Revenue Requirement Projected Deficiency in FY 2016-17 Revenue Based on Rates Currently in Effect Revenue Increase needed3 Residential E-1 $18,406,003 $20,785,989 ($2,379,986) 12.9% Small Non-residential E-2 9,421,113 10,019,138 (598,025) 6.3% Medium Non-residential E-4 38,382,821 42,680,642 (4,297,821) 11.2% Large Non-residential E-7 41,216,279 42,441,354 (1,225,074) 3.0% City Accounts E-18 3,044,789 4,463,490 (1,418,701) 46.6% Street/Traffic Lights 60,477 2,097,367 (2,036,890) 3368.1%4 TOTAL $110,531,481 $122,487,979 ($11,956,498) 10.8% Overall CPA needs a 10.8 percent revenue increase for FY 2016-17. The results show that while customers on Rate Schedule E-7 are paying close to cost of service already, most of the rate classes will need a significant rate increase. The E-1 rate class and the E-4 rate class show the largest increases. This is a result of significant changes in customer usage characteristics since the last COSA and rate redesign. In the last few years some rate classes have increased energy consumption or peak demand, while others have decreased consumption or demand. As is typical with most rate schedules, particularly those without large fixed charges, when energy consumption increases or decreases significantly, a COSA may reveal the need for realignment of revenue collection among classes of service. Classes whose consumption and demand have decreased since the last COSA will typically see higher rate increases so they are paying their share of fixed system costs, while classes with increasing consumption and demand will see lower rate increases. As part of the COSA, the composition of each rate class was reviewed to determine whether classes should be combined or additional classes created. Each rate class was found to have distinct consumption characteristics that indicated th ose customers should be grouped together under a single rate schedule, except for the E -18 (Municipal) rate class. The customers in the E-18 class have similar consumption characteristics to the E-2 (Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential) rate classes, and are recommended to be merged into those other rate classes. 3 Projected FY 2016-17 revenue deficiency divided by projected FY 2016 -17 revenue based on rates currently in effect. 4 This increase in revenue will primarily come from charging all City customers for lighting service rather than through rate increases to the general public. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 4 Rate Design Overview The rates for the residential and non-residential customers are designed to take into account differences in energy costs for various generating resources as well as the impacts seasonal changes in energy use and peak demand have on the utility’s distribution capacity needs. The E-1 (Residential) rate class is fairly homogenous compared to the other rate classes, and the se varying costs are best captured in a tiered energy rate design. For the non-residential classes, E- 2 (Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential), these costs are best captured by a seasonal rate structure. Note that while these methodologies capture seasonal variations in cost, they do not capture hourly cost variations. This requires time of use rates, which require more advanced metering that is only available to a small subset of Palo Alto customers. Optional time of use rates are made available to these customers, and reflect both seasonal and hourly capacity needs and energy consumed . Rate Design - Non-Commodity The allocation of distribution costs is based on an analysis of the base and excess monthly energy and capacity costs associated with that rate class, the Average and Excess method. The Average and Excess method compares the baseline capacity and energy used (the “average,” or “baseline”) against the maximum capacity and energy used on a seasonal basis (the “excess”). This captures the level of system capacity required to serve the customer during peak times as opposed to average times. The rate design for the E -1 (Residential) class is tiered, with the first tier reflecting the baseline usage, which is defined as energy usage below 11 kWh per day. This is the median summer usage, since this customer class’s peak usage is in the winter . This is reversed for the E-2 (Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential) customer classes, with the baseline consumption in the winter season and the peak in the summer. Costs associated with demand-related system costs (such as transformers or lines) were separated into tier or season using the average and excess demand inf ormation from the COSA. The methodology assigns costs associated with baseload demand to all tiers or seasons, while costs related to the distribution capacity required to serve peak demands is allocated to Tier 2 (for the residential class) or the summer season (for the non-residential classes). Customer- related costs are allocated equally to each tier or season based on the energy billing determinants. Rate Design - Commodity The commodity component of the rate design is based on differences in the cost of energy from the utility’s various sources of supply, as well as the impact of peak demand on capacity costs. For the E-1 (Residential) class, lower-cost resources are allocated to Tier 1 usage, while higher cost resources are allocated to Tier 2. Because this rate class is winter peaking, generating capacity costs were not reflected differently in each tier. This is because generating capacity CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 5 requirements are driven by the system peak demand rather than the customer class peak demand, and the system peak demand occurs in the summer, when residential use is lower. In order to develop commodity rates for rate classes E-2 (Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential), the costs for each generating resource were assigned to the season in which the costs were incurred. Demand rates were calculated by allocating baseload capacity costs to both summer and winter rates, while the remainder of the capacity-related costs were allocated to the summer (peak demand) period. Recommendation Based on the projected revenue requirement and COSA analysis, the following observations can be made for CPA: CPA will need to increase overall revenues by 10.8 percent for FY 2016-17 in order to recover sufficient revenues to meet costs. Revenues for each rate class should be aligned with the costs allocated to that rate class . Customers under rate schedule E-18 (Municipal Electric Use) should be moved to the E-2, E-4, and E-7 rate schedules as appropriate and the E-18 rate schedule should be retired. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 6 Overview of Rate Setting Principles EES Consulting, Inc. (EES Consulting) was retained by the City of Palo Alto (CPA) to perform a comprehensive electric cost of service and rate study. Performing an electric rate study is necessary to assure that CPA’s rates are structured to be fair, equitable and based on the cost of providing service to all City customers. In conducting a cost of service and rate study, three inter-related analyses are performed: 1. Revenue Requirement Analysis: This analysis examines the various sources and uses of funds for the utility and determines the overall revenue required to operate the utility. 2. Cost of Service Analysis (COSA): The COSA is used to determine the fair and equitable allocation of the total revenue requirement to the various customer classes of service (e.g. residential, small non-residential, medium non-residential, etc.). This analysis provides a determination of the level of revenue responsibility of each class of service and the adjustments from current revenues required to meet the cost of service. 3. Rate Design Analysis: The third analysis involves evaluating the rate design options available and designing rate schedules that can be applied to each rate class to equitably collect revenues that match the cost to serve each customer in that class. Overview and Organization of Report This report is divided into sections that follow these three analyses. This first section is a generic discussion of the theory and financial principles behind setting rates. This is followed by a section discussing the development of the revenue requirement analysis for CPA. The next section discusses the COSA. Finally, rate design options are presented in the fourth and final section. A technical appendix is attached at the end of this report that provides details of the various analyses. The schedules contained in the technical appendix are referenced throughout the report. The purpose of this section of the report is to provide a brief overview of the fundamentals of cost identification and allocation for purposes of developing electric rates. From this base -level of knowledge, more insight and understanding can be obtained from the following sections of the report that discuss the specifics of the Revenue Requirement, Cost of Service, and Rate Design analyses mentioned above. Overview of the Analyses All electric utility rate cost allocation methodologies share the same basic framework. That is, in allocating electric costs multiple separate yet interrelated analyses (revenue requirement CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 7 analysis, COSA, and rate design analysis) are performed. A variety of reasonable methodologies exist within each of these separate analyses. Overview of Revenue Requirement Methodologies For this study, a cash basis was used to determine CPA’s electric utility’s revenue requirement. The cash basis methodology aligns well to most Publicly Owned Utility (POU) budgetary processes and is more easily understood by POU managers and policy makers . Overview of Cost Allocation Procedures After the total revenue requirement has been determined, it is allocated to the various customer classes of service based upon a cost-based methodology that reflects cost causation and cost-causal relationships between customer characteristics and the production and delivery of the services. This analytical exercise usually takes the form of a COSA. A COSA begins by assigning each cost in a utility’s revenue requirement into major categories that reflect the utility’s capital investment and services provided to customers, such as power supply, transmission, distribution and customer. This is called “functionalization.” Next, the functionalized costs are linked to categories (such as demand-, energy-, and customer-related costs) and a direct assignment category. This is called “classification.” Allocation factors are then used to allocate each cost to each class of service. At that point the revenue requirement has been allocated to each class of service and a determination of the necessary revenue adjustments between classes of service can be made. Rate Design and Economic Theory The final step in the rate study process is to design rates for each class of service. Rates can be structured in many ways, but ultimately they should reflect the types of costs that the utility incurs to serve the customer (e.g. demand-, energy- and customer-related costs), and should collect the required level of revenues to safely and reliably operate the utility. Traditional rate designs use time-of-day, seasonal or marginal cost-based utility rates to provide accurate, cost- based price signals for the cost of power supply and to equitably allocate the cost of providing distribution service. The utility, in designing power supply rates, will need to take into consideration the characteristics of the power supply it acquires, as well as the characteristics of the customer to whom the utility will sell. POUs are subject to a wide variety of state statutes and regulations on topics including renewable portfolio mandates, cap and trade , energy efficiency programs, public goods charges and net metering, each presenting compliance costs. Particularly relevant to the rates studied by this COSA are the following: Article XIII C of the California Constitution amended by Proposition 26 (2010), which defines all imposed government charges, including electric rates, as taxes requiring voter approval unless certain exceptions are met; and CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 8 Public Utilities Code Section 385-387.8, which requires all POUs to have a public benefits charge built in to their rates to be used for a variety of programs, including: 1) demand side- management services to promote efficiency and conservation, 2) new investment in renewable energy and technologies, 3) research and development programs for the public interest, and 4) services and discounts for low income electricity customers. Public Utilities Code Section 2827, which sets out requirements that POUs offer net metering rates for certain types of customer-owned generators until the number of customer taking that rate reaches a specified limit. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 9 Development of the Revenue Requirement This section of the report presents the development of the electric revenue requirement for CPA. Simply stated, a revenue requirement analysis compares the overall revenues of the utility to its expenses and determines the overall adjustment to rate levels that is required. Overview of CPA’s Revenue Requirement Methodology As discussed in the previous section of the report, CPA utilizes the “cash basis” approach for determining its revenue requirement. In summary form, CPA’s components to its revenue requirement include the elements shown in Table 4. Table 4 Elements of a Cash Basis Revenue Requirement + Operation and Maintenance Expenses (O&M) Power Supply Expense Distribution Expense Customer Accounting Expenses Administrative and General Expense + Capital Improvements funded from Rates + General Fund Transfer = Total Revenue Requirement - Transfers from Reserves - Miscellaneous Revenue Sources = Net Revenues Required From Rates From this basic analytical framework, the next step in determining the revenue requirement methodology is to select a time period over which to review revenue and expenses. In the case of CPA, a fiscal year test period was utilized (July through June) rather than a calendar year test period. The test period may either be a past fiscal year or a future fiscal year. The former is appropriate when costs do not change significantly from year to year, while the latter is more appropriate when costs are expected to change significantly. Various costs for CPA are projected to increase in the FY 2016-17 fiscal year (July 2016 through June 2017), so this fiscal year was chosen as the test period for the COSA. CPA provided budgeted costs for FY 2016-17. The next step in the analysis was to translate the CPA budgeted costs into the system used by the Federal Electric Regulatory Commission (FERC), the FERC System of Accounts. The FERC System of Accounts provides a set of industry-standard methodologies for classification of electric costs and allocating to classes of service. For example, costs associated with the secondary distribution system (lines and customer transformers) are traditionally allocated primarily using customer peak demand, regardless of what time of d ay that occurs (called “non- CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 10 coincident peak demand”). These methodologies will be discussed in the “Cost of Service Analysis” section later in this report, but it is important when reviewing the schedules in the technical appendix to be aware that all cost s are categorized by FERC Accounts. A summary of the FY 2016-17 revenue requirement (using the FERC System of Accounts) is provided in Schedule 1.4, and the detail is shown in Schedule 3.1. Development of Power Supply Costs As with most electric utilities, the major expense associated with operating the utility is power supply. Approximately $90 million or 69 percent of the FY 2016-17 total revenue requirement of the utility is power supply costs, as shown in Schedule 3.1. Power supply costs include costs from renewable and non-renewable resources, including Western Area Power Administration (WAPA), Northern California Power Agency (NCPA) resources and power purchase agreements. In addition, power supply costs include California Independent System Operator (CAISO) transmission and ancillary charges. CPA’s proposed FY 2016-17 Operating Budget was used for the derivation of power supply costs. Other Operations and Maintenance Expenses CPA’s proposed FY 2016-17 Operating Budget was also used for the derivation of all other operations and maintenance (O&M) expenses. Total FY 2016-17 O&M expenses (excluding power supply) are projected to be $33 million. As shown in Schedules 1.4 and 3.1, this is made up of the following: Distribution expenses of $13.2 million. These costs include maintenance of distribution system infrastructure such as lines, transformers, meters, and substations. Customer Service related costs of $5.9 million. These costs include meter reading, billing, key account representatives and general customer service. Administrative and general costs of $13.9 million. These costs include functions like accounting, benefit overhead, insurance, and other types of administrative overhead. FY 2016-17 O&M and Power Supply costs together total $123.1 million, as shown in Schedules 1.4 and 3.1. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 11 General Fund Transfer CPA calculates the equity transfer from its Electric Utility based on a methodology adopted by Council in 2009,5 which has remained unchanged since then. The General Fund Transfer will be $12.1 million in FY 2016-17, as shown in Schedule 3.1. Rate-Funded Capital Improvement Program (CIP) For FY 2016-17, the budgeted CIP is $13.5 million, as shown in Schedules 1.4 and 3.1. This excludes any capital expenses reimbursed by customers through connection fees or other reimbursement agreements. Miscellaneous Revenues CPA receives additional operating and non-operating revenues and contributions. These come in the form of interest revenues, miscellaneous service revenues, rents and other revenue. Interest revenues represent interest on the utility’s reserves. Miscellaneous service revenues include minor revenue sources like pole attachment fees for other utilities such as telecommunications, transfers from other City-owned utilities for shared services, and charges for damaged utility property. Rents represent rent paid to the General Fund for the use of City - owned property for utility purposes. Other revenues include wholesale sales of surplus energy. For FY 2016-17 the projection for such revenues and contributions is $8.4 million, as shown in Schedules 1.4 and 3.1. Transfers from Reserves In its FY 2016-17 Electric Utility Financial Plan, CPA is anticipating that $15.1 million will be withdrawn from reserves in FY 2016-17 for rate stabilization. In addition, CPA estimates that roughly $2.8 million in budgeted operational and capital expenses remain unspent each year in the normal course of business. These savings and reserves withdrawals are included in the line titled “Transfers from Reserves and Allowance for Unspent Budget” in Schedules 1.4 and 3.1. Summary of Revenue Requirement Once all of the components of the cash basis revenue requirement have been determined, the parts can be summed to equal the total revenue requirement. CPA’s revenue requirement for 5 City of Palo Alto City Manager’s Report (CMR) 280:09, “Adoption of an Ordinance Adopting the Fiscal Years 2010 and 2011 Budget, Including the Fiscal Year 2010 Capital Improvement Program, Changes to the Municipal Fee Schedule, Utility Rates and Charges, Equity Transfer Methodology Change and Changes to Compensation Plans,” June 15, 2009 and CMR 260:09, “Recommendation to City Council to Change the Methodology Used to Calculate the Equity Transfer from Utilities Funds to the General Fund,” May 26, 2009. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 12 the FY 2016-17 test period is summarized in Table 5. More detail on the individual components of the revenue requirement can be found in Schedules 1.4 and 3.1. Table 5 Summary of the Revenue Requirement FY: 2016-2017 Revenue Requirement Production (Purchased Power) $90,065,328 Distribution $13,195,107 Customer Accounts and Services $5,946,916 Administration and General $13,931,304 Capital Improvement Projects from Rates $13,501,2506 General Fund Transfer $12,101,000 Total Expenses $148,740,905 Transfers from Reserves and Allowance for Unspent Budget ($17,870,017) Other Revenues ($8,382,909) Total Revenue Required from Rates (Revenue Requirement) $122,487,909 Revenues Based on Rates Currently in Effect $110,531,481 Additional Rate Revenue Needed $11,956,498 Total Required Rate Revenue Increase (Decrease) 10.8% Recommendation CPA’s revenues are not sufficient to cover its cost obligations in FY 2016-17 using current rates. It is important to note that CPA’s revenue-to-cost balance needs to be continually monitored. Both short and longer term supply and operating cost considerations will need to be evaluated and analyzed as CPA’s management and the City Council pursue CPA’s operating and financial objectives. 6 Excludes capital expenses reimbursed by connection fees or other direct reimbursement agreements . CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 13 Cost of Service Analysis The objective of the cost of service analysis (COSA) is to allocate the costs in the revenue requirement to each customer class of service to determine the cost to serve those customers. An essential principle of cost allocation is the concept of cost-causation. Cost-causation evaluates which customer or group of customers causes the utility to incur certain costs by linking system facility investments and the operating costs to serve certain facilities to the way customers use those facilities and services. This section of the report will discuss the general approach used to apportion the CPA’s costs, and will provide a summary of the results. COSA Definition and General Principles A COSA study allocates the costs of providing utility service to the various customer classes served by the utility based upon the cost-causal relationship associated with specific expense items. This approach is taken to develop a fair and equitable designation of costs to each class of service. Because the majority of costs are not incurred by any one type of customer, the COSA allocates joint and common costs among the various classes using factors appropriate to each type of expense. The COSA is the second step in a traditional three-step process for developing electric service rates, after development of the revenue requirement but before designing rates. A COSA study can be performed using embedded costs or marginal costs. Embedded costs generally reflect the actual costs incurred by the utility and closely track the costs kept in its accounting records. Marginal costs reflect the cost associated with adding a new customer, and are based on costs of facilities and services if incurred at the present time. This study uses an embedded COSA as its standard methodology, however it uses some marginal concepts, (for example, the examination of the relative cost of new meters in determining cost allocation between rate classes). There are three basic steps to follow in developing a COSA, namely: Functionalization Classification Allocation Functionalization separates costs into major categories that reflect the different services provided to customers and the types of assets used to provide those services. The primary functional categories for CPA are production (power supply) and distribution. Shared services (overhead) to be allocated across multiple functional categories are also identified in this phase. Classification determines the portion of each cost that is related to specific cost-causal factors, or “classifiers.” These classifiers might be demand-related (related to the class of service’s peak CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 14 energy usage over a given period), energy-related (related to the total energy used by the class of service over a given period), or customer-related (costs incurred as a result of receiving service, regardless of the energy use or peak demand). Production (Power Supply) costs are related to generating and supplying power to customers on the system, and are often demand- or energy-related. The distribution system is designed to extend service to all customers attached to the system and to meet the peak demand requirement of each customer, meaning that costs are often demand-related. Some operational costs, such as billing, are generally customer-related. Costs can also be classified based on system revenues or directly assigned to a customer or group of customers if appropriate (for example, for street lighting customers). Allocation of costs to specific classes of service happens after those costs have been classified. Allocation factors are chosen to allocate the costs assigned to each classification, and the share of costs allocated to each class of service are based on the class’s contribution to the specific allocation factor selected. For example, certain production (power supply) costs might be classified as partially demand-related and partially energy-related. The demand-related power supply costs would be allocated to the classes of service using each class’s contribution to the annual system peak demand (the highest demand for the system as a whole at any time during the year), while the energy-related costs would be allocated to classes based on their annual energy usage. In this example, the allocation factors are 1) each class of service’s contribution to the annual system peak demand and 2) the annual energy usage of each class of service. An analysis of customer requirements, loads, and usage characteristics is completed to develop allocation factors reflecting each of the classifiers employed within the COSA. Functionalization of Costs As discussed above, the first step in the COSA process following finalization of the revenue requirement is to functionalize the revenue requirement. Certain types of costs in the revenue requirement (primarily O&M costs associated with various types of capital assets) are allocated based on the use of the underlying capital assets by customer class. To determine this, the underlying capital assets of the utility (the “rate base”) are functionalized into cost categories and allocated to customer classes. The functionalization, classification, and allocation of the rate base will be used as a basis for functionalization, classification, and allocation of certain types of operating expenses in the revenue requirement, such as maintenance of the capital assets included in the rate base. In CPA’s case, the rate base and revenue requirement are functionalized into Production (Power Supply), Distribution, and Shared Services categories. Schedule 3.1 shows the functional category for each cost in the revenue requirement, while Schedule 3.3 shows the results of the functionalization and classification of each cost. Schedules 4.1 and 4.2 show the same information for the rate base. The functional categories are described in more detail below: Production (Power Supply). The power supply function category includes all power-related services that are obtained by the utility through generation and direct purchase. CPA does not produce power itself, but instead purchases power from a variety of renewable and CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 15 hydroelectric generating sources, as well as purchasing power in the energy markets. The transmission services that CPA must acquire to deliver the purchased power supply to the service area are included in purchased power costs. Distribution. Distribution services include all services required to move the electricity from the point of interconnection between the transmission system and the distribution system to the end user of the power. These include substations, primary and secondary pole s and conductors, line transformers, services and meters as well as customer costs and any direct assignment items. Shared Services. Shared services include assets used across multiple functions or costs that apply across multiple functions, such as facilities used for general management of the operation or insurance or benefits costs. Assets and costs in the shared services category are not shown in the attached schedules as a separate functional category. Instead, they are allocated across the Production and Distribution functions as overhead. Classification and Allocation of Costs The next step in performing a COSA is to classify and allocate the functionalized expenses. The classifications and allocations are directly related to specific consumption behavior or system configuration measurements such as coincident peak (CP) or non-coincident peak (NCP)7 demand, energy consumption, or number of customers. Each cost in the revenue requirement will be classified into one or more categories, and will then be allocated to customer classes of service based on a specific allocator. For example, 7% of the costs associated with the Calaveras hydroelectric generating resource were classified into the demand classification and 93% were classified into the energy classification, with the demand classifier allocated to classes of service based on each class’s CP demand, and the energy portion of the cost allocated based on each class’s annual energy consumption. The classification and allocation factors used for each component of the rate base and revenue requirement are shown in Tables 6 and 7 and are discussed in more detail below. Descriptions of each factor are included in Table 8. The following are the specific classifiers used in CPA’s COSA within the Production and Distribution functions. As noted earlier, the Shared Services function is spread across the Production and Distribution functions as overhead, so it does not have its o wn classifiers: 7 Coincident peak represents the customer class’s contribution to the system peak demand (i.e. its demand coincident with, or at the time of, the system peak), while non-coincident peak represents the customer class’s peak demand regardless of when it occurs. A customer class’s demand at the time o f the system peak demand may be lower than its peak demand, which may occur at some other time of the year. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 16 Production (Power Supply) Function Within this study, power supply costs are classified to demand and energy based on discussion with CPA staff related to cost causation. The specific classifiers used for the power supply function include: Energy. Energy-related costs are those that vary with the total amount of electricity consumed by a customer. Electricity usage measured in kWh is used in this portion of the analysis. Energy costs are the costs of consumption over a specified period o f time, such as a month or year. Demand. Demand-related costs are those that vary with the maximum demand or the maximum rates of power supply to classes of service. Customer and system demands for this analysis were measured in kW. Demand costs are generally related to the size (capacity) of facilities needed to meet a customer’s maximum demand at any point in time. In order to classify power supply costs, each resource or type of cost was evaluated based on how CPA is charged and whether the resource provides energy or capacity8 to CPA. Power purchase agreements for the output from the Western Area Power Administration (WAPA) and Calaveras hydroelectric generating resources and all renewable resources provide both energy and capacity, and so were classified according to the relative market value of the energy and capacity provided by each resource. An analysis of the amount of capacity and energy provided by each resources was done, and the market value of each of those was calculated based on historical energy and capacity prices. The ratio of energy to capacity value was used to classify the cost of the resource. Costs associated with services provided to CPA by Northern California Power Agency (NCPA) (such as scheduling generating resources and interacting with the California Independent System Operator (CAISO) on CPA’s behalf) are classified as energy costs because these services are necessitated by City’s energy purchases. Purchases of energy from marketers9 are classified as energy-related costs, while purchases of capacity are classified as demand-related costs.10 CAISO transmission costs are classified as energy-related costs, as this is the way those costs are allocated to distribution utilities by the CAISO and the CAISO transmission costs therefore vary with the total CPA system energy. 8 When referring to a generating resource, “capacity” refers to its potential generating capacity regardless of whether it is actually generating energy. Capacity must be held to meet customer peak demand, regardless of whether it is used to generate energy at all times of the year. Capacity costs are usually assigned to the demand classifier. 9 CPA purchases energy and capacity from various marketers and other agencies (BP Energy Company, Cargill Power Markets, Exelon Generation Co., Iberdrola Renewables, Nextera Energy Marketing, Pacificorp, Powerex, Shell Energy North America, and Turlock Irrigation District) through its Electric Master Agreements. 10 Energy purchases require that energy is delivered to the system during some specified period of time, while capacity purchases enable CPA to count generating capacity from a specific generating unit owned by another agency or marketer toward the generating capacity requirements imposed on it by the CAISO. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 17 Distribution Function Distribution services include all services required to get energy supply from the point of interconnection between the transmission system and the utility’s service area to the end user of the power. Most distribution costs are split between demand and customer components. The demand component is the cost of facilities like distribution substations, lines, or line transformers built to serve a particular peak demand. The customer component is the cost of facilities that varies with the number of customers, such as meters. The following are the specific classifiers used for CPA’s distribution function: Demand. Demand-related costs are those that vary with the maximum demand or the maximum rates of power supply to classes of service. Customer and system demands for this analysis are measured in kW. Demand costs are generally related to the size of facilities needed to meet a customer’s maximum demand at any point in time. Customer. Customer-related costs are those that vary with the number of customers. Customer costs may be weighted to account for differences in the cost of providing services to those customers. For example, the service drop and metering associated with serving a large commercial customer is more costly and requires substantially more work and material than the service and meter for a small residential customer. Direct Assignment. Some costs are directly assigned to specific classes of service. Costs associated with providing account representatives to large customers are allocated directly to those classes of service. Direct maintenance costs associated with street lights and traffic signals are directly allocated to the street light / traffic signal class. Schedules 3.5 and 4.4 provide the background information for all directly assigned costs associated with the revenue requirement and rate base. The methodology for functionalization, classification, and allocation of CPA’s rate base is summarized in Table 6 and in Technical Appendix Schedule 4.1. The results of the process for the rate base can be found in Schedule 4.2. The same information for the revenue requirement can be found in Table 7, Schedule 3.1, and Schedule 3.3. More detail on the classification and allocation factor codes used in the classification and allocation process can be found in Table 8. Schedule 6.1 shows how each code is used to separate costs into functions (production and distribution) and classifications (demand, energy, customer, and direct assignment). Schedule 6.2 shows the way each code then allocates the costs within each classification across classes of service. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 18 Table 6 Rate Base11 Functionalization, Classification, and Allocation FERC Account Asset Description Functionalization Category Classification and Allocation Factor Code12 Distribution Plant 361.0 Structures and Improvements Distribution NCPP 362.0 Station Equipment – Distribution Distribution NCPP 364.0 Poles, Towers & Fixtures Distribution 100% DP 365.0 Overhead Conductor & Devices Distribution 100% DC 366.0 Underground Conduit Distribution 100% DC 367.0 Underground Conductors Distribution 100% DC 368.0 Line Transformers Distribution 100% DT 369.0 Services Distribution SERV 370.0 Meters Distribution CUSTW 373.0 Street Lighting Systems Distribution DA1 General Plant 394.0 Tools, Shop & Garage Equipment Shared Services GPLT 397.0 Communication Equipment Shared Services GPLT 398.0 Miscellaneous Equipment Shared Services GPLT Accumulated Depreciation Distribution Plant Distribution RBD-ST Working Capital 90 days O&M Shared Services OMWOP 90 days Purchased Power Supply Cost Production OMP 90 days Purchased Transmission Charges Production OMPT Construction Work in Progress Construction Work in Progress Distribution RBD 11 Rate base as of June 30, 2015, the most recent year for which capitalized asset data is available. 12 See Table 8 for more detail and fully spelled-out acronyms CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 19 Table 7 Revenue Requirement Functionalization, Classification, and Allocation FERC Account Plant Description Functionalization Category Classification and Allocation Factor Code13 Power Purchases 555.70 Western Power Purchases Power Supply WEST 555.72 NCPA Pooling Power Supply kWh 555.73 NCPA Facilities Power Supply kWh 555.74 Local Capacity Purchase Power Supply CP12 555.76 Renewable Energy Power Supply REN 555.77 Carbon Neutral Purchases (RECs) Power Supply kWh 555.78 Market Power Purchases Power Supply kWh 555.50 Demand-Side Renewable Energy Power Supply DSRE XXXX Calaveras O&M and Debt Service Power Supply CALA XXXX Transmission Costs Power Supply kWh Other 555.20 Salaries & Benefits - Resource Mgmt. Power Supply kWh 555.30 Carbon Allowance Revenues Power Supply kWh 555.40 General Expense (Resource Mgmt.) Power Supply kWh 555.45 Allocated Administrative/General Costs Power Supply kWh Distribution 580.0 Operations Supervision and Engineering Distribution RBD-NoDA 585.0 Street Lighting Distribution DA1 588.0 Miscellaneous Distribution Distribution RBD-NoDA 589.0 Rents Distribution RBD-NoDA 590.0 Maintenance Supervision and Engineering Distribution RBD-NoDA 593.0 Overhead Lines Distribution RBOH 596.0 Street Lighting Distribution DA1 598.1 Communication O&M Distribution RBD-NoDA Customer Service, Accounts & Sales 901.0 Supervision Distribution CUSTW 902.0 Meter Reading Expenses Distribution CUSTMR 903.0 Cust. Records Collection Expense Distribution CREDIT 904.0 Uncollectable Accounts Distribution CREDIT 906.0 Customer Service & Information Distribution CUST SERV 906.1 Key Accounts Distribution DA2 906.2 Energy Efficiency & Demand-Side Management (DSM) Power Supply DSMEE 916.0 Misc. Sales Expense Distribution CUST SERV Administrative and General (A&G) Expenses 920.0 Salaries Shared Services OMAG 921.0 Office Supplies and Expense Shared Services OMAG 923.0 Outside Services Shared Services OMAG 925.0 Injuries and Damages Shared Services OMAG 926.0 Employee Pension and Benefits Shared Services OMAG 13 See Table 8 for more detail. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 20 Table 7 Revenue Requirement Functionalization, Classification, and Allocation FERC Account Plant Description Functionalization Category Classification and Allocation Factor Code13 930.2 Miscellaneous General Expense Shared Services OMAG 930.3 Environmental Fees Shared Services OMAG 931.0 Rents Shared Services OMAG Capital Projects From Rates Distribution Distribution RBD-NoDA Other Contributions General Fund Transfer Shared Services NETPLT Misc. & Other Revenues and Income 454.0 Rent, Electric Properties Shared Services OMAG 456.0 Other Misc. Electric Revenue Shared Services OMAG 458.0 Low Hydro Transfers Shared Services kWh 415/416 Income from Equity Investments Shared Services OMAG 421.0 Traffic Signal Transfer from General Fund Distribution DA 3 446.0 Green Power (Palo Alto Green) Power Supply kWh XXXX Surplus Energy Revenues Power Supply kWh XXXX Transfers from Reserves and Allowance for Unspent Budget Shared Services OM CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 21 Table 8 Classification and Allocation Factors Factor Code Factor Name Classification Allocation Basis Rate Base Classification and Allocation Factors NCPP Non-coincident Peak - Primary 100% Demand The total peak kW demand, regardless of when it occurs. 100% DP 100% Demand (Poles, Towers, Fixtures) 100% Demand The total peak kW demand, regardless of when it occurs. 100% DC 100% Demand (Overhead and Underground Conduit) 100% Demand The total peak kW demand, regardless of when it occurs. 100% DT 100% Demand (Transformers) 100% Demand The total peak kW demand, regardless of when it occurs. SERV Services14 100% Customer # customers weighted for the cost of installing and replacing services CUSTW Customers weighted for accounting / metering 100% Customer # customers weighted for cost of installing, maintaining and reading meters, billing, and account management DA1 Street Light Rate Base Assignment 100% Direct Assignment Street lighting assets allocated directly to street light customer class of service GPLT General Plant 73.5% Demand, 18.4% Customer 8.1% Direct Assignment Shared services assets15 that are the rate base equivalent of administrative overhead. Allocated to classes of service according to the other operational assets (e.g. lines and transformers) allocated to each class. RBD-ST Rate Base: Distribution Adjusted for Street Light Direct Assignments( 64.7% Demand, 23.3% Customer 12.0% Direct Assignment Classified and allocated to classes of service based on the value of all operational and shared services assets assigned to each class of service. Used for accumulated depreciation OMWOP O&M without Power Supply 48.7% Demand, 31.5% Customer 7.2% Direct Assignment Allocated based on O&M without Power Supply costs OMP O&M: Purchase Power 48.7% Demand, 31.5% Customer 7.2% Direct Assignment Allocated based on Purchased Power costs OMPT O&M: Purchased Transmission 48.7% Demand, 31.5% Customer 7.2% Direct Assignment Allocated based on Purchased Transmission costs RBD Rate Base: Distribution 73.5% Demand, 18.4% Customer 8.1% Direct Assignment Classified and allocated to classes of service based on the net book value of all shared services assets and other capital assets assigned to each class of service 14 This is a technical term referring to the connection from the line transformer to the customer’s electrical panel. 15 Facilities used for administration and other general utility management functions . CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 22 Table 8 Classification and Allocation Factors Factor Code Factor Name Classification Allocation Basis Revenue Requirement Classification and Allocation Factors WEST Western Base Resource allocation 16% Demand, 84% Energy Western Base Resource costs. Classified according to the relative market value of the capacity and energy provided by the resource, and allocated to classes of service based on each class’s energy consumption and coincident peak demand. kWh Energy consumption (kWh) 100% Energy Energy consumption of each class of service in kWh CP12 12-month Coincident Peak 100% Demand Customer class of service’s contribution to the utility’s annual system peak demand CALA Calaveras Hydroelectric Resource allocation 7% Demand, 93% Energy Calaveras hydroelectric resource costs. Classified according to the relative market value of the capacity and energy provided by the resource, and allocated to classes of service based on each class’s energy consumption and coincident peak demand. REN Renewable Power Purchase Agreements 3% Demand, 97% Energy Renewable Power Purchase Agreement costs. Classified according to the relative market value of the capacity and energy provided by the resource, and allocated to classes of service based on each class’s energy consumption and coincident peak demand. RBD-NoDA Distribution Rate Base Excluding Street Lighting and Traffic Signals 73.5% Demand, 26.5% Customer Used for allocation of most distribution system infrastructure O&M costs other than street light/traffic signal maintenance. Classified and allocated to classes of service based on the net book value of all shared services assets and other capital assets assigned to each class of service, excluding street lighting and traffic signals. DA1 Street Light and Traffic Signal Direct Assignment 100% Direct Assignment Costs associated with operating and maintaining street light and traffic signal assets RBOH Rate Base (Overhead Lines) 100% Demand Used for allocation of maintenance costs for overhead lines. Classified and allocated to classes of service based on the net book value of overhead lines assigned to each class of service. CUSTW Customers weighted for accounting / metering 100% Customer # customers weighted for cost of installing, maintaining and reading meters, billing, and account management CUSTMR Customers weighted for meter reading 100% Customer # customers weighted for cost of reading meters CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 23 Table 8 Classification and Allocation Factors Factor Code Factor Name Classification Allocation Basis CREDIT Credit and Collections 100% Customer # customers weighted for credit and collections costs CUST SERV Customer Service 100% Customer # customers weighted for customer service costs DA2 Direct Assignment for Key Account costs 100% Direct Assignment Direct assignment of key account costs to large non-residential classes of service CUST Actual Customers 100% Customer Actual (unweighted) customer count OMAG O&M omitting A&G and Power Supply Shared Services On the basis of all other O&M costs allocated to each class of service excluding A&G and Power Supply. Allocated to Production Function (12.6% Energy) and Distribution Function (48.7% Demand, 31.5% Customer, 7.2% Direct Assignment) OM All O&M Shared Services Allocated on the basis of all other O&M costs in the revenue requirement. Allocated to Production Function (4.9% Demand, 12.6% Energy) and Distribution Function (48.7% Demand, 31.5% Customer, 7.2% Direct Assignment) DSRE Demand-Side Renewable Energy Allocator Power Supply Allocated based on PV Partners solar rebate budget allocation DSMEE DSM / EE Allocator Power Supply Based on historical residential / non- residential program expenditures. Residential direct assignment, non- residential based on annual kWh. No allocation to Street/Traffic Lights DA3 Direct Assignment for Traffic Lights revenues 100% Direct Assignment Direct assignment of General Fund Transfers of Traffic Light revenues. NETPLT Net Plant 80.5% Demand, 14.5% Customer, 5.1% Direct Assignment Allocated on the basis of the net book value of all capital assets (initial cost less accumulated depreciation) assigned to each class of service. Cost of Service Results Given the key assumptions listed above, the COSA was completed. Schedules 3.4 and 4.3 in the appendix show the functionalized and classified rate base and revenue requirement allocated to each class of service. These schedules are calculated by multiplying the applicable classification and allocation factors to each cost in the revenue requirement or rate base. Given the above assumptions regarding the COSA, the various costs were classified and allocated to the customer classes of service. Table 9 provides the COSA results. Summary data and additional detail is presented in Schedules 1.1 and 1.2. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 24 Table 9 Summary of Cost of Service Analysis for FY 2016-17 Test Year Projected FY 2016-17 Revenues under Rates Currently in Effect Net Revenue Requirement Projected Deficiency in FY 2016-17 Revenue Based on Rates Currently in Effect Revenue Increase needed16 Residential E-1 $18,406,003 $20,785,989 ($2,379,986) 12.9% Small Non-residential E-2 9,421,113 10,019,138 (598,025) 6.3% Medium Non-residential E-4 38,382,821 42,680,642 (4,297,821) 11.2% Large Non-residential E-7 41,216,279 42,441,354 (1,225,074) 3.0% City Accounts E-18 3,044,789 4,463,490 (1,418,701) 46.6% Street/Traffic Lights 60,477 2,097,367 (2,036,890) 3368.1%17 TOTAL $110,531,481 $122,487,979 ($11,956,498) 10.8% The results show that with present rates, CPA will not collect sufficient revenues to meet FY 2016-17 costs. As discussed previously in the report, the amount of additional revenue required varies by class of service. While customers on Rate Schedule E-7 are paying close to cost of service already, most of the rate classes will need a significant rate increase. The E -1 rate class and the E-4 rate class show the largest increases. The varying rate changes are a result of significant changes in customer usage characteristics since the last COSA and rate redesign. In the last few years some rate classes have increased energy consumption or peak demand, while others have decreased consumption or demand. These changing consumption patterns affect usage of the system and the way costs are allocated among customers. As described throughout this section, costs are allocated to customers based on their consumption patterns, particularly energy consumption and peak demand . As customer consumption patterns change, some of the utility’s costs change as well, but others are fixed over the short term. For example, some charges to the utility, like market energy purchases, are directly related to energy consumption. These costs decrease as customer energy consumption decreases, usually in real-time. If a customer class uses less energy, fewer of these costs will be allocated to them and their revenue requirement will decrease. O ther costs only change slowly over time, such as the amount of distribution capacity the utility builds and maintains. These costs are largely fixed, and change over the long term with changes in peak demand or energy use. The majority of the City of Palo Alto’s cost change slowly over the long term. Rates for each customer class are set based on the energy and peak demand patterns over the study period. If energy use and peak demand decrease or increase after the rate study is completed, costs that change only over the long term might not change. When a subsequent 16 Projected FY 2016-17 revenue deficiency divided by projected FY 2016-17 revenue based on rates currently in effect. Numbers rounded to the nearest tenth of a percent. 17 This increase in revenue will primarily come from charging all City customers for service rather than through rate increases to the general public. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 25 COSA is performed, different revenue adjustments may need to be made for each customer class. The impacts to each class required as a result of the analysis done in the COSA are described below: Energy consumption and demand has decreased for the E-1 (Residential)18 class of service. The share of costs allocated to this customer class decreased as a result. The decrease in energy consumption, however, means that the existing rates do not collect adequate revenue to fund certain types of fixed costs. The latter factor means that revenues need to increase more than average for this class of service. Small Non-residential (E-2) energy consumption and demand has increased. The share of costs allocated to this customer class increased as a result. The increase in energy consumption, however, means that the existing rates collect close to the amount of revenue needed to fund fixed costs. The latter factor means that revenues need to increase less than average for this class of service. Medium Non-residential (E-4) energy consumption has decreased, but demand has increased. The share of energy-related costs allocated to this customer class increased, while the share of demand-related costs decreased. These factors roughly offset each other, and revenue increases needed roughly match the average increase for the city as a whole. Large Non-residential (E-7) energy consumption and demand has increased. The share of costs allocated to this class increased as a result. However, revenue from existing rates also increased substantially as a result of the increased consumption and demand. Existing revenue collection is close to the amount of revenue needed based on the COSA, so the necessary revenue increase from this customer class is small. The energy consumption for the E-18 class of service has stayed roughly the same, but the demand has increased. The share of costs allocated to this customer class increased as a result. The unchanged energy consumption, in light of the increased demand, however, means that the existing rates did not collect adequate revenue to fund fixed costs. The street light and traffic signal class reflects additional revenues associated with charging for maintenance and operation of City-owned street lighting, which was not included in previous rate schedules. When examining the results, it is important to note that the inter -class cost allocation is based on load data estimates and usage pattern assumptions. Since these can vary from year to year, the results of applying this COSA may deviate from these allocations over time. To avoid these deviations, the COSA model built for CPA can be updated when necessitated by significant changes to customer consumption patterns or the CPA’s costs. 18 While this class of service is named “Residential Electric Service,” it does not include 100% of residential use. Some master-metered multi-family residential buildings take service under other rate schedules. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 26 Review of Customer Classes of Service Customer classes of service refer to the arrangement of customers into groups that reflect common usage characteristics or facility requirement. The classes of service used within this study were as follows: Residential E-1 Small Non-Residential E-2 Medium Non-Residential E-3 Large Non-Residential E-7 Municipal Electric Service E-18 Street and Traffic Lights Rate schedule E-18 (Municipal Electric Service) was modeled separately in the COSA, but the analysis showed that the customer characteristics of municipal service accounts are not significantly different from the characteristics of other non-residential customers. Municipal accounts should be moved to the appropriate non -residential rate schedule based on energy consumption and peak demand. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 27 Rate Design The final step in the rate study process is to design rates for each class of service. In California, local governments are subject to Article XIII C of the California Constitution , amended by Proposition 26 (2010). As a result, CPA has set rates to match the COSA results for each class. It is important to note that the results of the revenue requirement and COSA study are based on forecasted load data estimates and usage pattern assumptions. Actual load and usage p atterns may differ from forecast. For this study, rates are developed based on the forecast loads and observed historical usage patterns for each rate class. The rates for the residential and non-residential customers are designed to take into account differences in energy costs for various generating resources as well as the impacts seasonal changes in energy use and peak demand have on the utility’s distribution capacity needs. The E-1 (Residential) rate class is fairly homogenous compared to the other rate classes, and these varying costs can be captured in a tiered energy rate design. For the non -residential classes, E-2 (Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential), these costs are captured in a seasonal rate. Note that while these methodologies capture seasonal variations in cost, they do not capture hourly cost variations. This requires time of use rates, which require more advanced metering that is only available to a smaller subset of Palo Alto customers. Optional time of use rates are made available to these customers, and reflect both seasonal and hourly capacity needs and energy consumed. Rate Design – Non-Commodity The allocation of distribution costs is based on an analysis of the base and excess monthly energy and capacity costs associated with that rate class, also known as the Average and Excess method. The Average and Excess method compares the baseline capacity and energy used (the “average,” or “baseline”) against the maximum capacity and energy used on a seasonal basis (the “excess”). This captures the level of system capacity required to serve the customer during peak times as opposed to average times. The rate design for the E -1 (Residential) class is tiered, with the first tier reflecting the baseline usage, which is defined as energy usage below 11 kWh per day. This was calculated by analyzing the median summer usage for the class. Summer was chosen as the year-round baseline rather than winter because the residential customer class’s peak usage is in the winter, unlike the other customer classes. This is reversed for the E-2 (Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential) customer classes, with the baseline consumption in the winter season and the peak in the summer. Costs associated with demand-related system costs (such as transformers or lines) were separated into tier or season using the average and excess demand information from the COSA. The methodology assigns costs associated with baseload de mand to all tiers or seasons, while costs related to the distribution capacity required to serve peak demands is allocated to Tier 2 (for the residential class) or the summer season (for the non-residential classes). Customer- CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 28 related costs are allocated equally to each tier or season based on the energy billing determinants. Rate Design – Commodity The commodity component of the rate design is based on differences in the cost of energy from the utility’s various sources of supply, as well as the impact of peak demand on capacity costs. For the E-1 (Residential) class, lower-cost resources are allocated to Tier 1 usage, while higher cost resources are allocated to Tier 2. Because this rate class is winter peaking, generating capacity costs were not reflected differently in each tier. This is because generating capacity costs are determined based on the Palo Alto’s system peak, which is in the summer. That means that the residential peak usage, which is in the winter, does not impact capacity costs in the same way the peak usage for other customer classes does. In order to develop commodity rates for rate classes E-2 (Small Non-Residential), E-4 (Medium Non-Residential), and E-7 (Large Non-Residential), the costs for each generating resource were assigned to the season in which the costs were incurred. Demand rates were calculated by allocating baseload capacity costs to both summer and winter rates, while the remainder of the capacity-related costs were allocated to the summer (peak demand) period. Proposed Rate Design This section of the report will review the present rate structures for CPA and will provide a comparison with the proposed rates based on this cost of service study. Residential E-1 The present Residential rate design is composed of a t hree tier energy rate for commodity, distribution and Public Benefit Charges, which are charges the utility is required by State Law to impose to fund energy efficiency and other programs (as discussed earlier in the “Overview of Rate Setting” section). Tier 1 energy is based on an average of 10 kWh per day (or 300 kWh per month), while Tier 2 applies to usage between 300 and 600 kWh per month. Finally, Tier 3 rates apply to usage above 600 kWh per month. The proposed rate structure for the Residential Schedule E-1 consists of two tiers. As discussed earlier, the first tier represents the lower cost energy, as well as the distribution capacity required to serve customers year-round. The second tier represents the higher cost energy, as well as the distribution capacity required to serve customers during the winter (peak) season. In the commodity portion of the rates, only the costs for generating resources differ across tiers. Other power supply costs (such as transmission and energy scheduling services) are distributed uniformly across both tiers of the commodity rate on a per-kWh basis. For distribution rates, CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 29 only physical infrastructure costs are distributed differently between tiers. Customer -related costs are allocated uniformly to both tiers on a per-kWh basis. After reviewing the median daily consumption during summer months for E-1 customers, the Tier 1 usage was increased from 10 kWh per day to 11 kWh per day or 330 kWh per month. This represents the year-round, baseload usage for the median residential customer. Tier 2 rates are then applied to any usage above 330 kWh per month. Presented below, in Table 10, are the present and proposed rates for the Residential E-1 customers. Table 10 Comparison of Proposed Rates to Current –Residential E-1 Residential Commodity Distribution Public Benefits Charge Total Rate Current Energy Charge ($/kWh) Tier 1: First 300 kWh $0.05448 $0.03755 $0.00321 $0.09524 Tier 2: 301-600 kWh $0.07654 $0.05045 $0.00321 $0.13020 Tier 3: > 600 kWh $0.10349 $0.06729 $0.00321 $0.17399 Proposed Energy Charge ($/kWh) Tier 1: First 330 kWh $0.05883 $0.04795 $0.00351 $0.11029 Tier 2: > 330 kWh $0.09728 $0.06822 $0.00351 $0.16901 Overall Rate Change 12.9% Small Non-Residential E-2 The present Small Non-Residential E-2 rate design is composed of a summer and winter energy rate for commodity, distribution and Public Benefit Charges. The proposed rate structure for the Small Non-Residential Schedule E-2 is the same, though the summer and winter rates have been updated to properly reflect the difference in the cost of serving this class in both seasons. Consumption for this class peaks in the summer, and the costs of the additional distribution capacity associated with serving this higher summer load have been allocated to the summer energy rate component. Costs for energy from generating resources are assigned to summer and winter rates based on the season in which those costs are incurred by the utility. All other costs are assigned uniformly across both rate components. Presented below, in Table 11, are the present and proposed rates for the Small Non-Residential E-2 customers. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 30 Table 11 Comparison of Proposed Rates to Current –Small Non-Residential E-2 Small Non-Residential Commodity Distribution PBC Total Rate Current Energy Charge ($/kWh) E-2 Summer $0.08219 $0.05505 $0.00321 $0.14045 E-2 Winter $0.07406 $0.04934 $0.00321 $0.12661 Proposed Energy Charge ($/kWh) E-2 Summer $0.09094 $0.07400 $0.00351 $0.16845 E-2 Winter $0.06417 $0.04677 $0.00351 $0.11445 Overall Rate Change 6.3% Medium Non-Residential E-4 The present Medium Non-Residential E-4 rate design is composed of a summer and winter energy and demand rate for commodity, distribution and Public Benefit Charges. The proposed rate structure for the Medium Non-Residential Schedule E-4 is the same. As for the E-2 rate, the summer and winter components of the rate have been updated to reflect current costs and consumption patterns. However, unlike for the E -2 customer class, all of the demand-related distribution system costs are captured in a demand charg e,19 while customer-related costs are captured in the energy component of the distribution charges. This is feasible for E -4 and E-7 customers but not for E-2 customers due to the limitations of the metering technology currently deployed in Palo Alto. Costs for energy from generating resources are assigned to summer and winter rate components based on the time of year those costs are incurred by the utility. Generating capacity costs are collected through a commodity demand charge. All other costs are assigned uniformly across both rate components. Presented below, in Table 12, are the present and proposed rates for the Medium Non- Residential E-4 customers. Table 12 Comparison of Proposed Rates to Current –Medium Non-Residential E-4 Medium Non-Residential Commodity Distribution PBC Total Rate Current Energy Charge ($/kWh) E-4 Summer $0.06083 $0.01767 $0.00351 $0.08171 E-4 Winter $0.05281 $0.01716 $0.00351 $0.07318 19 A demand charge is a charge based on the highest power consumption in a specified period of time, and is measured in kW. The E-4 and E-7 demand charges are based on the usage in the highest 15-minute period over the course of the billing period, roughly one month. This is in contrast to an energ y charge, which is measured in kWh, and represents the total energy consumption over the entire month. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 31 Current Demand Charge ($/kWh) E-4 Summer $2.31 $15.23 $20.54 E-4 Winter $4.80 $9.04 $13.84 Proposed Energy Charge ($/kWh) E-4 Summer $0.08218 $0.01661 $0.00351 $0.10229 E-4 Winter $0.06037 $0.01661 $0.00351 $0.08049 Proposed Demand Charge ($/kWh) E-4 Summer $2.53 $17.14 $19.68 E-4 Winter $1.55 $12.49 $14.04 Overall Rate Change 11.2% Large Non-Residential E-7 The present Large Non-Residential E-7 rate design is composed of a summer and winter energy and demand rate for commodity, distribution and Public Benefit Charges. The proposed rate structure for the Large Non-Residential Schedule E-7 is the same. The rate design and methodology for allocating costs to rates is the same as for the E -4 rate schedule. The two rate classes are distinct, however, due to the different consumption patterns of the E -4 and E-7 customer classes. The E-7 customer class has a higher load factor (a measure of the ratio of peak demand to annual energy use). The higher a class’s load factor, the more efficiently it makes use of the capacity dedicated to serving it. A customer class with a higher load factor will have a lower share of the demand-related system costs allocated to it than a low load factor customer class that uses the same amount of energy, so it is best to distinguish the two as separate customer classes. Presented below, in Table 13, are the present and proposed rates for the Large Non-Residential E-7 customers. Table 13 Comparison of Proposed Rates to Current –Large Non-Residential E-7 Large Non-Residential Commodity Distribution PBC Total Rate Current Energy Charge ($/kWh) E-7 Summer $0.05662 $0.01825 $0.00321 $0.07808 E-7 Winter $0.04990 $0.01898 $0.00321 $0.07209 Current Demand Charge ($/kWh) E-7 Summer $6.42 $12.55 $18.97 E-7 Winter $5.50 $6.04 $11.54 Proposed Energy Charge ($/kWh) E-7 Summer $0.08311 $0.00087 $0.00351 $0.08749 E-7 Winter $0.05804 $0.00087 $0.00351 $0.06242 CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 32 Proposed Demand Charge ($/kWh) E-7 Summer $2.50 $15.85 $18.34 E-7 Winter $1.53 $14.11 $15.65 Overall Rate Change 3.0% Municipal E-18 As discussed previously, the E-18 rate schedule is recommended for retirement. Customers in this rate class share characteristics with the E-2, E-4, and E-7 rate classes, and should be allocated to those classes. Minimum Bill Analysis To ensure the collection of monthly meter reading, billing and customer service costs from all customers, a minimum bill charge for all rate schedules should be implemented. Meter reading, billing, customer service, and some distribution system O&M cost elements in the COSA are divided by the number of customers for each rate class to generate the minimum bill for each class. The minimum bill mechanism is a new approach to determining a customer’s electricity bill for CPA, but is used frequently in the electric utility industry. The monthly bill would be calculated in the following manner under the minimum bill mechanism: 1. Calculate the customer’s monthly bill based on usage 2. If the calculated bill is less than the minimum bill amount, the customer p ays the minimum bill charge for the month. The proposed minimum bill was developed by determining the customer -related distribution, CIP and customer service costs in the COSA. These are the costs that should be collected from all customers regardless of usage. Based on the cost of service study, the following minimum bill charges are proposed: Residential E-1: $0.3067 per day Small Non-Residential E-2: $0.7657 per day Medium Non-Residential E-4: $16.3216 per day Large Non-Residential E-7: $48.5054 per day Time of Use Rate Schedules CPA also offers optional time of use (TOU) rates to its E -1, E-4, and E-7 customers. A TOU rate applies different charges to customer usage during different time periods. These time periods CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 33 correspond to times of day with differing energy costs. The peak time period (summer weekday afternoons) corresponds to the time of highest demand on the system. Capacity requirements are set based on system peaks during this time period. The off -peak period represents nighttime periods when energy costs are lower. Mid-peak periods represent all other hours. The E-1 TOU rate is a voluntary pilot rate currently limited to customers participating in the City’s CustomerConnect advanced metering pilot program. It differs from the E -4 TOU and E-7 TOU rates in that it is designed as a modifier that adds to or subtracts from the underlying E -1 rate schedule, based on the customer’s hourly usage. In contrast, the E -4 TOU and E-7 TOU rate schedules are standalone rate schedules. The E-1 TOU rate schedule will be updated in a subsequent analysis. The E-4 TOU and E-7 TOU rates are offered on a voluntary basis to all E -4 and E-7 customers, but only one customer is currently on one of these rate schedules. The E -4 TOU and E-7 TOU rate designs allocate costs seasonally or to tiers using the same methodology as the underlying non-TOU rate designs, but they also take into account hourly variations in energy prices. Most generating capacity costs are allocated to the summer peak periods, since CPA’s system peak demand occurs during that time. Most of CPA’s resource adequacy (generating capacity) costs result from requirements imposed by the CAISO based on the CPA annual system peak demand. Resource Adequacy costs are allocated to the peak periods based on the impact peak demand has on those costs. Distribution costs are not allocated on an hourly basis since inadequate data exists at this time to separate costs associated with the primary (sub -transmission) system from costs associated with the secondary system. The former serves all customers and can benefit when some customers use energy in off-peak rather than peak periods. The latter serves individual customers or small groups of customers, and is therefore affected by customer peak demand regardless of when that peak demand occurs. The Time-of-Use rates developed for E-4 and E-7 are provided in Table 14. CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 34 Table 14 Present and Proposed E-4 and E-7 Time-of-Use Rates Existing Rates Proposed Rates Commodity Distribution PBC Total Commodity Distribution PBC Total E-4 Summer Energy Peak $0.10963 $0.03242 $0.00321 $0.14526 $0.08819 $0.01661 $0.00351 $0.10830 Mid-Peak $0.05617 $0.01623 $0.00321 $0.07561 $0.08367 $0.01661 $0.00351 $0.10378 Off-Peak $0.04298 $0.01218 $0.00321 $0.05837 $0.07332 $0.01661 $0.00351 $0.09344 E-4 Winter Energy Peak $0.07003 $0.02296 $0.00321 $0.09620 $0.06566 $0.01661 $0.00351 $0.08577 Off-Peak $0.04088 $0.01313 $0.00321 $0.05722 $0.06167 $0.01661 $0.00351 $0.08178 E-4 Summer Demand Peak $3.12 $8.96 $12.08 $1.52 $5.91 $7.42 Mid-Peak $1.99 $5.65 $7.64 $0.54 $5.91 $6.44 Off-Peak $1.13 $3.26 $4.39 $0.54 $5.91 $6.44 E-4 Winter Demand Peak $2.77 $5.10 $7.87 $0.87 $6.96 $7.83 Off-Peak $1.49 $2.94 $4.43 $0.87 $6.96 $7.83 E-7 Summer Energy Peak $0.07029 $0.02296 $0.00321 $0.09646 $0.09267 $0.00087 $0.00351 $0.09705 Mid-Peak $0.05867 $0.01901 $0.00321 $0.08089 $0.08792 $0.00087 $0.00351 $0.09230 Off-Peak $0.04870 $0.01567 $0.00321 $0.06758 $0.07705 $0.00087 $0.00351 $0.08143 E-7 Winter Energy Peak $0.05617 $0.02142 $0.00321 $0.08080 $0.06009 $0.00087 $0.00351 $0.06447 Off-Peak $0.04663 $0.01767 $0.00321 $0.06751 $0.05643 $0.00087 $0.00351 $0.06081 E-7 Summer Demand Peak $4.24 $8.25 $12.49 $1.48 $5.33 $6.80 Mid-Peak $2.06 $4.13 $6.19 $0.51 $5.33 $5.84 Off-Peak $1.17 $2.06 $3.23 $0.51 $5.33 $5.84 E-7 Winter Demand Peak $3.04 $3.38 $6.42 $0.78 $7.15 $7.92 Off-Peak $1,59 $1.68 $3.27 $0.78 $7.15 $7.92 Public Benefits Charge Public Utilities Code Section 385 requires all POUs to have a public benefits charge built in to their rates. The rate must recover revenue equal to a set percentage of all other sales revenue based on a formula in that law. Most California POUs have interpreted this formula to require collection of an additional 2.85% of sales revenue for this purpose, as has CPA. The revenue collected must be spent on a specified set of energy efficiency and other demand -side measures, including: 1) demand side-management services to promote efficiency and conservation, 2) new investment in renewable energy and technologi es, 3) research and development programs for the public interest, and 4) services and discounts for low income electricity customers. The public benefits charge is collected as a flat charge assessed on every kWh that results in the revenue level described above. The COSA analysis confirmed that all customer classes received benefits greater than or equal to the Public Benefits Charge revenues collected from them. The CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 35 results of this analysis are shown in Table 15 below. Public benefit program costs not directly funded by PBC revenues are funded by other sales revenues, which complies with the CPA - adopted Long Term Energy Acquisition Plan and Public Utilities Code Section 9615, which requires local publicly owned utilities to fund cost-effective energy efficiency measures before funding new energy supply purchases. Table 15 Public Benefit Charge Expenses and Revenues Total Residential E-1 Small Non- Residential E-2 Medium Non- Residential E-4 Large Non- Residential E-7 City Accounts E-18 Street/ Traffic Lights 906.20 Energy Efficiency & DSM $2,723,852 $418,856 $203,104 $875,794 $1,142,094 $84,004 $0 555.50 Demand- Side Renewable Energy $1,555,878 $324,484 $114,004 $491,591 $528,951 $96,847 $0 Total PBC Expenses $4,279,730 $743,341 $317,108 $1,367,385 $1,671,045 $180,851 $0 Total PBC Revenues $3,399,398 $537,721 $251,223 $1,083,285 $1,412,677 $103,905 $0 Net Energy Metering Public Utilities Code Section 2827 requires that utilities, including POUs, offer net energy metering (NEM) for certain types of customer-owned generators until the installed capacity of NEM customers’ generation reaches a specified limit, or cap. PUC 2827(g) also requires POUs to offer identical rates to both eligible NEM customers taking service under the cap, and to non- NEM customers in the same rate class. New or additional charges that might otherwise be imposed solely upon NEM customers to fully recover the utility’s cost of serving them (such as the costs of maintaining the distribution system) are prohibited. Until the cap is reached, CPA offers NEM under terms and conditions compliant with PUC 2827 under CPA Rule and Regulation 29. Once the cap is reached, utilities are not obligated to provide NEM to new customers (PUC 2827(C)(4)(A)), although CPA plans to continue offering NEM under a NEM successor program currently being developed. In CPA’s service territory, customers have only taken advantage of Rule 29 using solar systems; no other types of eligible generators have been installed and applied for NEM. Table 16 shows the expenses and revenues for NEM customers under the proposed E-1 and E-2 Rate Schedules. NEM program expenses are comprised of the revenues that would be received from the relevant customer group without NEM, less the value of the surplus energy provided by all customers’ solar systems on an hourly basis. The regulatory compliance cost of offering NEM to customers under PUC 2827 is roughly $67,291 per year for the 725 customers in the NEM program as of this report. Commercial rate classes with larger customers and demand charges (E-4 and E-7) have solar system outputs that coincide well with customer consumption CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 36 patterns because their installed solar systems are smaller relative to the customer load. These customers are omitted from Table 16 because revenues from E-4 and E-7 NEM customers match the cost of service. In the E-1 (Residential) and E-2 (Small Non-Residential) classes, consumption does not coincide as well with solar system output and so the customer meter runs backwards more frequently (creating “surplus generation”) and offsetting a larger percentage of customer consumption during the non-solar producing hours. Table 16 NEM Program Expenses and Revenues E-1 E-2 TOTAL NEM Expenses Revenue without NEM $708,113 $105,612 $813,725 Value of Surplus Energy Generated $102,765 $7,905 $110,670 Net Cost $605,348 $138,219 $743,567 Revenue Monthly Revenue with NEM $583,240 $99,025 $682,625 Bill Credits for Monthly Net Surplus Energy $32,613 $98 $32,711 Payments for Annual Net Surplus Energy $5,885 $0 $5,885 Total Revenue Received $544,742 $98,926 $643,668 Net Program Expense $60,606 $6,685 $67,291 Street Lighting and Traffic Signals CPA’s electric utility also provides lighting and traffic signal maintenance services, which are captured in the E-14 (Street Lighting) and E-16 (Unmetered Electric Service) rate schedules. These services are primarily provided to CPA itself, but also to a few other governmental agencies. These rate schedules were modeled combined and then separated based on estimated usage. Street lighting costs are equal to $2.1 million, and are provided to several agencies, including CPA, while traffic signal costs are equal to $234,000 and are only provided to CPA. Given that CPA is the only customer for traffic signal maintenance services, it is recommended that CPA bill itself using an internal transfer rather than a rate schedule. Traffic signal rates are recommended to be removed from the E-16 rate schedule. The E-14 rate schedule, on the other hand, which is used to bill agencies other than CPA, was updated to reflect CPA’s current lighting inventory and the inventory of lighting it maintains for other agencies. Actual street lighting rates are calculated by assigning the costs of street lighting O&M across all street lights, then allocating the costs of energy consumption based on actual energy use (calculated usi ng lamp wattages). CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 37 Table 17 Schedule E-14 Proposed Rates Device Number Maintenance Service Provided Bulb Current Rate $/mo. Proposed Rate $/mo. 1 Yes HPS 70W $11.85 $28.61 2 Yes HPS 100W $15.48 $30.79 3 Yes HPS 150W $18.43 $34.43 4 Yes HPS 200W $20.55 $0.00 5 Yes HPS 250W $23.32 $41.70 6 Yes HPS 310W $27.32 $0.00 7 Yes HPS 400W $33.47 $0.00 8 Yes LED 70W-EQ $0.00 $23.79 9 Yes LED 100W-EQ $0.00 $25.44 10 Yes LED 150W-EQ $0.00 $26.96 11 Yes LED 250W-EQ $0.00 $31.12 12 Yes Mercury-Vapor 100W $13.56 $0.00 13 Yes Mercury-Vapor 175W $16.31 $0.00 14 Yes Mercury-Vapor 250W $20.32 $0.00 15 Yes Mercury-Vapor 400W $30.29 $0.00 16 Yes Incandescent 2500L $14.41 $0.00 17 Yes Incandescent 4000L $18.43 $0.00 18 Yes Fluorescent 40W $5.30 $0.00 19 Yes Fluorescent 60W $6.36 $0.00 20 No HPS 100W $15.48 $8.59 22 No HPS 200W $20.55 $15.87 23 No HPS 250W $23.32 $19.50 24 No HPS 310W $27.32 $24.13 25 No HPS 400W $33.47 $31.07 26 Yes Mercury-Vapor 400W $20.32 $32.58 CITY OF PALO ALTO —ELECTRIC COST OF SERVICE AND RATE STUDY 38 Technical Appendix Date:March 10, 2016 Version:Final Draft Test Period:FY 2017 570 Kirkland Way, Suite 100 Kirkland, Washington 98033 Telephone: 425 889‐2700 Facsimile: 425 889‐2725 A registered professional engineering corporation with offices in the Seattle and Portland areas. City of Palo Alto Cost of Service Schedules Consulting, Inc. EES Prepared By EES Consulting, Inc.City of Palo Alto Name of Schedule Worksheet Schedule No. SUMMARY SUMMARY OF PRESENT AND PROPOSED RATE REVENUE Summary 1.1 FUNCTIONALIZATION AND CLASSIFICATION OF REVENUE REQUIREMENT Summary 1.2 FUNCTIONALIZATION AND CLASSIFICATION OF RATE BASE SUMMARY Summary 1.3 SUMMARY OF REVENUE REQUIREMENT COST ALLOCATION Summary 1.4 SUMMARY OF RATE BASE COST ALLOCATIONS Summary 1.5 SUMMARY OF HISTORIC LOAD DATA Summary 1.6 SUMMARY OF FORECAST LOAD DATA Summary 1.7 SUMMARY OF POWER SUPPLY COSTS Summary 1.8 UNIT COST SUMMARY OF REVENUE REQUIREMENT UNIT COSTS Unit Cost 2.1 SUMMARY OF RATE BASE UNIT COST Unit Cost 2.2 REVENUE REQUIREMENT INPUT REVENUE REQUIREMENT Rev Req 3.1 PROJECTED REVENUE REQUIREMENTS Rev Req 3.2 REVENUE REQUIREMENT COST ALLOCATION FUNCTIONALIZATION AND CLASSIFICATION Rev Req 3.3 REVENUE REQUIREMENT COST ALLOCATION CLASSIFICATION BY CUSTOMER Rev Req 3.4 REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Rev Req 3.5 RATE BASE INPUT RATE BASE Rate Base 4.1 RATE BASE FOR COST ALLOCATION FUNCTIONALIZATION AND CLASSIFICATION Rate Base 4.2 RATE BASE COST ALLOCATION CLASSIFICATION BY CUSTOMER Rate Base 4.3 RATE BASE COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Rate Base 4.4 TABLE OF CONTENTS Last Updated: 3/10/2016 1:15 PM Table Of Contents Page 1 of 2 Prepared By EES Consulting, Inc.City of Palo Alto TABLE OF CONTENTS POWER SUPPLY SUMMARY OF POWER SUPPLY COSTS Power Supply 5.1 FUNCTIONALIZATION, CLASSIFICATION AND ALLOCATION CLASSIFICATION AND ALLOCATION BY FUNCTION C&A by Funct 6.1 CLASSIFICATION AND ALLOCATION BY CUSTOMER C&A by Cust 6.2 COINCIDENT PEAK DEMAND ALLOCATION C&A Calculations 6.3 NON‐COINCIDENT PEAK DEMAND ALLOCATION C&A Calculations 6.4 CLASSIFICATION AND ALLOCATION OF DIRECT ASSIGNMENT BY CUSTOMER C&A Calculations 6.5 REVENUES FROM RATES FORECAST OF REVENUES FROM CURRENT RATES Revenues 7.1 LOAD DATA FORECAST CUSTOMERS AND ENERGY SALES Load Summary 8.1 FORECAST CUSTOMER DEMAND Load Summary 8.2 FORECAST kWh AT INPUT Load Summary 8.3 RECORDED CUSTOMERS AND ENERGY SALES Load Summary 8.4 RECORDED CUSTOMER DEMAND Load Summary 8.5 RECORDED kWh AT INPUT Load Summary 8.6 Last Updated: 3/10/2016 1:15 PM Table Of Contents Page 2 of 2 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Forecast Year: 2017 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Revenues Based on Rates Currently in Effect $110,531,481 $18,406,003 $9,421,113 $38,382,821 $41,216,279 $3,044,789 $60,477 Less Allocated Revenue Requirement $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367 Difference ‐$11,956,498 ‐$2,379,986 ‐$598,025 ‐$4,297,821 ‐$1,225,074 ‐$1,418,701 ‐$2,036,890 Revenue To Cost Ratio 90.2% 88.6% 94.0% 89.9% 97.1% 68.2% 2.9% % Increase in Rates to Needed to Meet Revenue Requirement 10.8% 12.9% 6.3% 11.2% 3.0% 46.6% 3368.1% Unit Cost Summary Unit Cost: Rates Currently in Effect ($/kWh) $0.1140 $0.1203 $0.1337 $0.1196 $0.1045 $0.1042 $0.0319 Unit Cost: COSA Rates ($/kWh) $0.1263 $0.1358 $0.1422 $0.1330 $0.1076 $0.1527 $1.1054 Difference from Present Rates 10.8% 12.9% 6.3% 11.2% 3.0% 46.6% 3368.1% SUMMARY OF PRESENT AND PROPOSED RATE REVENUE BY CUSTOMER CLASS Schedule 1.1 Last Updated: 3/10/2016 1:15 PM Schedule 1.1 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Forecast Year: 2017 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Production Demand (PD) $4,205,945 $497,669 $409,908 $1,605,067 $1,528,121 $159,647 $5,534 Energy (PE) $69,412,241 $11,064,767 $5,080,769 $23,048,647 $27,943,724 $2,148,631 $125,704 Direct Assignment (PDA) Distribution Demand (DD) $32,680,740 $4,943,138 $3,208,606 $11,570,988 $11,242,417 $1,619,102 $96,489 Energy (DE) Customer (DC) $13,828,371 $4,280,415 $1,319,855 $6,259,437 $1,432,336 $536,110 $217 Direct Assignment (DDA) $2,360,683 $196,504 $294,755 $1,869,424 Total $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367 Total Cost / Function Production $73,618,185 $11,562,435 $5,490,676 $24,653,713 $29,471,845 $2,308,278 $131,237 Distribution $48,869,794 $9,223,553 $4,528,462 $18,026,928 $12,969,508 $2,155,212 $1,966,130 Total Cost / Function $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367 Total Cost / Classifier Demand $36,886,684 $5,440,807 $3,618,514 $13,176,055 $12,770,538 $1,778,749 $102,022 Energy $69,412,241 $11,064,767 $5,080,769 $23,048,647 $27,943,724 $2,148,631 $125,704 Customer $13,828,371 $4,280,415 $1,319,855 $6,259,437 $1,432,336 $536,110 $217 Direct Assignment $2,360,683 $196,504 $294,755 $1,869,424 Total Cost / Classifier $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367 FUNCTIONALIZATION AND CLASSIFICATION OF REVENUE REQUIREMENT SUMMARY BY CUSTOMER CLASS Schedule 1.2 Last Updated: 3/10/2016 1:15 PM Schedule 1.2 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Historic Year: 2015 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Production Demand (PD) $1,254,278 $148,413 $122,241 $478,656 $455,710 $47,609 $1,650 Energy (PE) $22,114,052 $3,524,837 $1,618,382 $7,345,860 $8,900,881 $683,593 $40,498 Direct Assignment (PDA) Distribution Demand (DD) $146,046,015 $22,089,558 $14,338,402 $51,707,642 $50,243,901 $7,235,331 $431,182 Energy (DE) Customer (DC) $28,537,688 $6,707,376 $1,279,106 $15,356,854 $3,751,894 $1,442,359 $99 Direct Assignment (DDA) $9,909,699 $53,302 $79,953 $9,776,444 Total $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874 Total Cost / Function Production $23,368,330 $3,673,250 $1,740,623 $7,824,516 $9,356,591 $731,202 $42,148 Distribution $184,493,403 $28,796,934 $15,617,507 $67,117,798 $54,075,748 $8,677,690 $10,207,725 Total Cost / Function $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874 Total Cost / Classifier Demand $147,300,294 $22,237,971 $14,460,642 $52,186,298 $50,699,611 $7,282,940 $432,832 Energy $22,114,052 $3,524,837 $1,618,382 $7,345,860 $8,900,881 $683,593 $40,498 Customer $28,537,688 $6,707,376 $1,279,106 $15,356,854 $3,751,894 $1,442,359 $99 Direct Assignment $9,909,699 $53,302 $79,953 $9,776,444 Total Cost / Classifier $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874 FUNCTIONALIZATION AND CLASSIFICATION OF RATE BASE SUMMARY BY CUSTOMER CLASS Schedule 1.3 Last Updated: 3/10/2016 1:15 PM Schedule 1.3 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Forecast Year: 2017 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Power Purchases $76,183,327 $11,969,000 $5,693,446 $25,595,699 $30,382,353 $2,399,225 $143,604 Transmission/Ancillary Services Purchases $13,957,173 $2,216,312 $1,020,323 $4,648,913 $5,620,799 $423,347 $27,479 Other ‐$75,172 ‐$11,937 ‐$5,495 ‐$25,039 ‐$30,273 ‐$2,280 ‐$148 Total Production $90,065,328 $14,173,375 $6,708,273 $30,219,573 $35,972,879 $2,820,292 $170,935 Total Distribution $13,195,107 $2,038,394 $1,019,065 $4,848,242 $3,585,597 $608,679 $1,095,130 Total Operation & Maintenance $103,260,435 $16,211,769 $7,727,338 $35,067,816 $39,558,477 $3,428,970 $1,266,066 Total O&M w/o Purchased Power Supply & A&G $19,142,024 $3,863,685 $1,843,484 $6,586,454 $5,027,527 $725,614 $1,095,259 Total Customer Service, Accounts & Sales $5,946,916 $1,825,291 $824,420 $1,738,212 $1,441,929 $116,935 $129 Total Administrative & General $13,931,304 $2,811,937 $1,341,663 $4,793,532 $3,658,965 $528,092 $797,115 Total O&M plus A&G $123,138,655 $20,848,997 $9,893,420 $41,599,559 $44,659,372 $4,073,998 $2,063,309 Total Capital Projects Funded From Rates $13,501,250 $2,301,482 $1,107,223 $5,484,931 $3,899,486 $678,825 $29,304 Total General Fund Transfer $12,101,000 $1,864,587 $1,021,317 $4,412,352 $3,588,443 $574,072 $640,229 Revenue Requirement Before Reserve Transfers and Other Revenues $148,740,905 $25,015,066 $12,021,959 $51,496,843 $52,147,301 $5,326,895 $2,732,842 Revenue Req. Before Taxes, Reserve Transfers and Other Revenues $148,740,905 $25,015,066 $12,021,959 $51,496,843 $52,147,301 $5,326,895 $2,732,842 Total Transfers from Reserves and Allowances for Unspent Budget ‐$17,870,017 ‐$2,805,572 ‐$1,337,276 ‐$6,068,757 ‐$6,845,900 ‐$593,410 ‐$219,102 Total Other Revenues $8,382,909 $1,423,505 $665,546 $2,747,444 $2,860,047 $269,995 $416,373 REVENUE REQUIREMENT for COST ALLOCATION $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367 SUMMARY OF REVENUE REQUIREMENT COST ALLOCATION Schedule 1.4 Last Updated: 3/10/2016 1:15 PM Schedule 1.4 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Historic Year: 2015 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Total Distribution Plant $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962 Total General Plant $23,436,856 $3,569,196 $1,851,291 $8,472,309 $6,510,824 $1,078,770 $1,954,465 Total Plant Before General Plant & Intangible $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962 Total Gross Plant in Service $297,800,603 $45,352,022 $23,523,450 $107,653,467 $82,729,835 $13,707,402 $24,834,427 Total Accumulated Depreciation $131,788,193 $19,771,944 $9,512,109 $47,120,845 $33,500,340 $5,831,760 $16,051,195 Total Net Plant $166,012,410 $25,580,078 $14,011,342 $60,532,622 $49,229,494 $7,875,642 $8,783,232 Total Working Capital $30,362,956 $5,140,849 $2,439,473 $10,257,426 $11,011,900 $1,004,547 $508,761 TOTAL RATE BASE $196,375,366 $30,720,927 $16,450,815 $70,790,048 $60,241,394 $8,880,189 $9,291,993 Total Construction Work In Progress $11,486,367 $1,749,258 $907,315 $4,152,266 $3,190,945 $528,704 $957,880 TOTAL RATE BASE plus Construction Work In Progress $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874 SUMMARY OF RATE BASE COST ALLOCATIONS Schedule 1.5 Last Updated: 3/10/2016 1:15 PM Schedule 1.5 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Historic Year: 2015 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Recorded Load Data Energy Sales (kWh)952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346 Total Billing Capacity (kVa)1,521,344 773,606 747,738 Avg. Monthly Billing Capacity (kVa)126,779 64,467 62,312 Number of Customers 29,339 25,341 3,073 736 66 123 1 Ratio of NCP to Avg. Billing Capacity 99% 99% Rate Classes NCP Demand at Meter 177,573 27,808 17,374 63,599 61,411 6,775 607 Estimates Based on Recorded Data Annual NCP Load Factor 61% 62% 46% 55% 74% 49% 36% Rate Classes CP Demand at Input Voltage 169,623 21,594 17,963 62,227 61,674 5,712 454 Annual CP Load Factor 64% 80% 45% 56% 73% 58% 48% Average On‐Peak kWh as a % of Total kWh 66% 66% 66% 66% 66% 66% Average Off‐Peak kWh as a % of Total kWh 34% 34% 34% 34% 34% 34% SUMMARY OF HISTORIC LOAD DATA Schedule 1.6 Last Updated: 3/10/2016 1:15 PM Schedule 1.6 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Forecast Year: 2017 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Forecast Load Data Energy Sales (kWh)969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346 Total Billing Capacity (kVa)1,521,344 773,606 747,738 Avg. Monthly Billing Capacity (kVa)126,779 64,467 62,312 Number of Customers 29,339 25,341 3,073 736 66 123 1 Ratio of NCP to Avg. Billing 197% 99% 99% Rate Classes NCP Demand at Meter 181,222 27,600 18,470 63,599 61,411 9,534 607 Forecast Based on Recorded and Forecast Data Annual NCP Load Factor 61% 63% 44% 58% 73% 35% 36% Rate Classes CP Demand at Input Voltage 168,329 21,188 18,821 62,227 61,674 3,980 439 Annual CP Load Factor 66% 82% 43% 59% 73% 84% 49% Schedule 1.7 SUMMARY OF FORECAST LOAD DATA Last Updated: 3/10/2016 1:15 PM Schedule 1.7 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Forecast Year: 2017 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Western Power Purchases $12,806,834 $1,950,721 $986,135 $4,365,205 $5,076,817 $404,080 $23,876 NCPA Pooling $2,472,030 $392,543 $180,715 $823,394 $995,530 $74,981 $4,867 NCPA Facilities $2,721,836 $432,211 $198,977 $906,601 $1,096,131 $82,558 $5,359 Local Capacity Purchase $1,055,340 $124,873 $102,853 $402,737 $383,430 $40,058 $1,388 Load Advance Renewable Energy $36,272,543 $5,713,498 $2,679,559 $12,137,404 $14,562,469 $1,108,948 $70,665 Carbon Neutral Purchases (REC)$229,965 $36,517 $16,811 $76,598 $92,611 $6,975 $453 Market Power Purchases $7,112,993 $1,129,499 $519,987 $2,369,225 $2,864,528 $215,750 $14,004 Demand Side Renewable Energy $1,555,878 $324,484 $114,004 $491,591 $528,951 $96,847 Calaveras O&M $11,955,908 $1,864,655 $894,406 $4,022,943 $4,781,886 $369,027 $22,992 Transmission/Ancillary Services Purchases Transmission Costs $13,957,173 $2,216,312 $1,020,323 $4,648,913 $5,620,799 $423,347 $27,479 Salaries & Benefits ‐ Resource Mgmt $2,073,843 $329,313 $151,606 $690,764 $835,173 $62,903 $4,083 Carbon Allowance Revenues ‐$4,296,000 ‐$682,178 ‐$314,054 ‐$1,430,930 ‐$1,730,075 ‐$130,306 ‐$8,458 General Expense (Resource Mgmt)$796,548 $126,487 $58,231 $265,318 $320,784 $24,161 $1,568 Allocated G&A $1,350,437 $214,441 $98,722 $449,809 $543,845 $40,961 $2,659 Total Power Supply $90,065,328 $14,173,375 $6,708,273 $30,219,573 $35,972,879 $2,820,292 $170,935 SUMMARY OF POWER SUPPLY COSTS Schedule 1.8 Last Updated: 3/10/2016 1:15 PM Schedule 1.8 Page 1 of 1 Prepared By EES Consulting, Inc. Last Updated: 3/10/2016 1:15 PM Schedule 1.9 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Forecast Year: 2017 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7City Accounts E‐18 Street/Traffic Lights Billing Determinants Total kVa 1,521,344 773,606 747,738 Total Demand (kW) 2,098,690 304,102 190,983 773,606 747,738 76,890 5,371 Total Energy (kWh) 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346 Average Monthly Customers 29,339 25,341 3,073 736 66 123 1 Functional Cost Total Cost Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7City Accounts E‐18 Street/Traffic Lights Production Demand (PD)$4,205,945 $497,669 $409,908 $1,605,067 $1,528,121 $159,647 $5,534 $/kW $1.64 $2.15 $2.07 $2.04 $2.08 $1.03 or $/kVa $2.07 $2.04 Energy (PE)$69,412,241 $11,064,767 $5,080,769 $23,048,647 $27,943,724 $2,148,631 $125,704 $/kWh $0.072 $0.072 $0.072 $0.071 $0.074 $0.066 Distribution Demand (DD)$32,680,740 $4,943,138 $3,208,606 $11,570,988 $11,242,417 $1,619,102 $96,489 $/kW $16.25 $16.80 $14.96 $15.04 $21.06 $17.96 or $/kVa $14.96 $15.04 Customer (DC)$13,828,371 $4,280,415 $1,319,855 $6,259,437 $1,432,336 $536,110 $217 $/Customer/Month $14 $36 $709 $1,811 $365 $18 Direct Assignment (DDA)$2,360,683 $196,504 $294,755 $1,869,424 $/kW $0.25 $0.39 $348.06 $/kVa $0.25 $0.39 $/kWh $0.001 $0.001 $0.985 Total $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367 Total $/kW $17.89 $18.95 $17.29 $17.47 $23.13 $367.06 $/kWh $0.07230 $0.072 $0.072 $0.072 $0.074 $1.052 $/Customer/Month $14.08 $35.79 $708.80 $1,810.79 $364.70 $18.12 SUMMARY OF REVENUE REQUIREMENT UNIT COSTS BY CUSTOMER CLASS Schedule 2.1 Last Updated: 3/10/2016 1:15 PM Schedule 2.1 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto ‐ 100% Demand Forecast Year: 2016 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7City Accounts E‐18 Street/Traffic Lights Billing Determinants Total kVa 1,521,344 773,606 747,738 Total Demand (kW) 2,098,690 304,102 190,983 773,606 747,738 76,890 5,371 Total Energy (kWh) 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346 Average Monthly Customers 29,339 25,341 3,073 736 66 123 1 Functional Cost Total Cost Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7City Accounts E‐18 Street/Traffic Lights Production Demand (PD)$1,254,278 $148,413 $122,241 $478,656 $455,710 $47,609 $1,650 $/kW $0.49 $0.64 $0.62 $0.61 $0.62 $0.31 Energy (PE)$22,114,052 $3,524,837 $1,618,382 $7,345,860 $8,900,881 $683,593 $40,498 $/kWh $0.023 $0.023 $0.023 $0.023 $0.023 $0.023 $0.021 Distribution Demand (DD)$146,046,015 $22,089,558 $14,338,402 $51,707,642 $50,243,901 $7,235,331 $431,182 $/kW $72.64 $75.08 $66.84 $67.19 $94.10 $80.28 Customer (DC)$28,537,688 $6,707,376 $1,279,106 $15,356,854 $3,751,894 $1,442,359 $99 $/Customer/Month $22 $35 $1,739 $4,743 $981 $8 Direct Assignment (DDA)$9,909,699 $53,302 $79,953 $9,776,444 $/kW $0.07 $0.11 $1,820.25 $/kWh $0.000 $0.000 $5.153 Total $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874 SUMMARY OF RATE BASE UNIT COST BY CUSTOMER CLASS Schedule 2.2 Last Updated: 3/10/2016 1:15 PM Schedule 2.2 Page 1 of 1 Prepared By EES Consulting, Inc. City of Palo Alto INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2017 & Allocation Cost, $FunctionFactor Classification & Allocation Method FERC Account Operation & Maintenance Expense Power Purchases 555.70 Western Power Purchases $12,806,834 PWESTWestern Cost (84% E, 16% D) 555.71 Contra Surplus Energy PkWhAnnual Energy (kWh) 555.72 NCPA Pooling $2,472,030 PkWhAnnual Energy (kWh) 555.73 NCPA Facilities $2,721,836 PkWhAnnual Energy (kWh) 555.74 Local Capacity Purchase $1,055,340 PCP1212 Coincident Utility Peak 555.75 Load Advance PkWhAnnual Energy (kWh) 555.76 Renewable Energy $36,272,543 PRENRenewable (92% E, 3% D) 555.77 Carbon Neutral Purchases (REC)$229,965 PkWhAnnual Energy (kWh) 555.78 Market Power Purchases $7,112,993 PkWhAnnual Energy (kWh) OTHER RESOURCES 555.50 Demand Side Renewable Energy $1,555,878 PDSREDemand‐Side Renewable Energy Allocator 555.60 Alt Resources Renewable Energy DSM PkWhAnnual Energy (kWh) XXXX Calaveras O&M $11,955,908 PCALACalaveras Cost (93% E, 7% D) Transmission/Ancillary Services Purchases XXXX Transmission Costs $13,957,173 PkWhAnnual Energy (kWh) Other 555.20 Salaries & Benefits ‐ Resource Mgmt $2,073,843 PkWhAnnual Energy (kWh) 555.30 Carbon Allowance Revenues ‐$4,296,000 PkWhAnnual Energy (kWh) 555.40 General Expense (Resource Mgmt)$796,548 PkWhAnnual Energy (kWh) 555.45 Allocated G&A $1,350,437 PKWhAnnual Energy (kWh) Total Purchased Power $90,065,328 Total Production $90,065,328 Distribution 580.00 Op. Supervision & Engineering $3,314,847 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting 581.00 Load Dispatching DRBSEOn the Basis of Station Equipment Rate Base 582.00 Line and Station Expenses DRBSEOn the Basis of Station Equipment Rate Base 583.00 Overhead Lines DRBOHOn the Basis of all Overhead Rate Base 584.00 Underground Lines DRBUGOn the Basis of all Underground Rate Base 585.00 Street Lighting & Signal System $869,624 DDA1Direct Assignment for Streetlights 586.00 Meters DCUSTWCustomers Weighted for Accounting/Metering 587.00 Customer Installations DCUSTWCustomers Weighted for Accounting/Metering 588.00 Misc. Distribution $3,537,760 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting 589.00 Rents $318,470 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting 590.00 Maint. Supervision & Engineering $3,092,997 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting 591.00 Maint. of Structures DRBSEOn the Basis of Station Equipment Rate Base 592.00 Maint. of Station Equipment DRBSEOn the Basis of Station Equipment Rate Base 592.10 Maint. of Structures and Equipment DRBSEOn the Basis of Station Equipment Rate Base 593.00 Maint. of Overhead Lines $1,510,766 DRBOHOn the Basis of all Overhead Rate Base 594.00 Maint. Of Underground Lines DRBUGOn the Basis of all Underground Rate Base 594.10 Maint. of Lines DRBUGOn the Basis of all Underground Rate Base Last Updated: 3/10/2016 1:15 PM Schedule 3.1 Page 1 of 3 Prepared By EES Consulting, Inc. City of Palo Alto INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2017 & Allocation Cost, $FunctionFactor Classification & Allocation Method 595.00 Maint. of Line Transformers DRBTROn the Basis of all Transformer Rate Base 595.00 Maint. of Line Transformers ‐ Underground DRBTROn the Basis of all Transformer Rate Base 596.00 Maint. of Street Lighting & Signal System $198,001 DDA1Direct Assignment for Streetlights 597.00 Maint. of Meters DCUSTMCustomers Weighted for Meters and Services 598.00 Maint. of Misc. Distribution Plant DRBD‐NoDA As Distribution Ratebase without DA Street Lighting 598.10 Communication O&M $352,642 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting XXXX Other DRBD‐NoDA As Distribution Ratebase without DA Street Lighting XXXX Other DRBD‐NoDA As Distribution Ratebase without DA Street Lighting Total Distribution $13,195,107 Total Operation & Maintenance $103,260,435 Customer Service, Accounts, & Sales 901/907/911 Supervision $718,334 DCUSTWCustomers Weighted for Accounting/Metering 902.00 Meter Reading $390,328 DCUSTMRCustomers Weighted for Meter Reading 903.00 Customer Records Collection $487,803 DCREDITCredit & Collections (35% Residential) 904.00 Uncollectable Accounts $141,023 DCREDITCredit & Collections (35% Residential) 905.00 Misc. Customer Accounts DCUSTActual Customers 906.00 Customer Service & Information $176,793 DCUST SERV Customer Service (60% Residential) 907.00 Customer Communication & Education DCUSTActual Customers 908.00 Customer Assistance DCUSTActual Customers 910.00 Misc. Customer Service & Information DCUSTActual Customers 912.00 Demonstrating & Selling DCUSTActual Customers 913.00 Advertising DCUSTActual Customers 916.00 Misc. Sales Expenses $996,000 DCUST SERV Customer Service (60% Residential) 917.00 Sales Expenses DOMOn the Basis of All O&M 906.10 Key Accounts $312,784 DDA2Direct Assignment for Key Accounts 906.20 Energy Efficiency & DSM $2,417,900 PDSMEEDSM / EE Allocator: 906.30 Low Income Residential Energy Assistance Program $305,952 PDSMEEDSM / EE Allocator: Total Customer Service, Accounts & Sales $5,946,916 Total O&M w/o Purchased Power Supply & A&G $19,142,024 Administrative & General 920.00 Administrative & General Salaries $5,245,712 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 921.00 Office Supplies $36,700 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 922.00 Administrative Transfer ‐ Credit SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 923.00 Outside Services $487,748 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 924.00 Property Insurance SS NETPLT On the Basis of Net Plant 925.00 Injuries and Damages $10,864 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 926.00 Employee Pension & Benefits $1,142,543 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 927.00 Franchise Requirements SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 928.00 Regulatory Expense SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 929.00 Duplicate Charge ‐ Credit SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 930.10 General Advertising SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 930.20 Misc. General Expense $1,934,446 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 930.30 Environmental $77,118 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 931.00 Rents $4,996,173 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) Last Updated: 3/10/2016 1:15 PM Schedule 3.1 Page 2 of 3 Prepared By EES Consulting, Inc. City of Palo Alto INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2017 & Allocation Cost, $FunctionFactor Classification & Allocation Method 932.00 Maint. of General Plant & Communication Equipment SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 933.00 Transportation SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 935.00 Maintenance of General Plant SS OMAG On the Basis of O&M (w/o Power Supply and A&G) Total Administrative & General $13,931,304 Total O&M plus A&G $123,138,655 Taxes 408.00 Property Tax SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) Total Taxes Capital Projects Funded From Rates Production PRBGOn the Basis of Generation Rate Base Transmission TRBTOn the Basis of Transmission Rate Base Distribution $13,501,250 DRBD‐NoDA As Distribution Ratebase without DA Street Lighting General SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) Total Capital Projects Funded From Rates $13,501,250 Revenue Requirement Before Transfers and Other Revenues Other Contributions Transfers from Reserves and Allowances for Unspent Budget ‐$17,870,017 SS OM On the Basis of All O&M General Fund Transfer $12,101,000 SS NETPLT On the Basis of Net Plant Total Other Contributions ‐$5,769,017 Revenue Requirement Before Reserve Transfers and Other Revenues $148,740,905 Revenue Req. Before Taxes, Reserve Transfers and Other Revenues $148,740,905 Other Revenues 450.00 Forfeited Deposits SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 451.00 Misc. Service Revenues $167,200 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 454.00 Rent ‐ Electric Properties SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 456.00 Misc. Revenue (Other)$2,507,700 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 457.00 Transfer Credits $135,386 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 458.00 Low Hydro Transfers PkwhAnnual Energy (kWh) 419&424 Dividends from Affiliates, Interest SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 449.00 Other Revenue SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 415&416 Income (Loss) from Equity Investments $198,500 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 444.20 Street Light Revenue DCUSTMCustomers Weighted for Meters and Services 421&429 Traffic Signal Transfer from General Fund $233,984 DDA1Direct Assignment for Streetlights 446.00 Green Power $45,085 PkWhAnnual Energy (kWh) XXXX Surplus Energy Revenues $5,084,054 PkWhAnnual Energy (kWh) Total Other Revenues $8,382,909 REVENUE REQUIREMENT for COST ALLOCATION $122,487,979 Last Updated: 3/10/2016 1:15 PM Schedule 3.1 Page 3 of 3 Prepared By EES Consulting, Inc. FERC Account 555.70 555.71 555.72 555.73 555.74 555.75 555.76 555.77 555.78 555.50 555.60 XXXX XXXX 555.20 555.30 555.40 555.45 580.00 581.00 582.00 583.00 584.00 585.00 City of Palo Alto Total 2015 Expenses 2016 2017 2018 2019 2020 Operation & Maintenance Expense Power Purchases Western Power Purchases $11,251,000 $11,521,895 $12,806,834 $12,806,834 $12,806,834 $12,806,834 Contra Surplus Energy NCPA Pooling $2,609,000 $2,489,570 $2,472,030 $2,472,030 $2,472,030 $2,472,030 NCPA Facilities $1,958,000 $3,799,711 $2,721,836 $2,721,836 $2,721,836 $2,721,836 Local Capacity Purchase $1,383,000 $1,059,322 $1,055,340 $1,055,340 $1,055,340 $1,055,340 Load Advance Renewable Energy $16,361,000 $22,711,901 $36,272,543 $36,272,543 $36,272,543 $36,272,543 Carbon Neutral Purchases (REC)$542,000 $606,088 $229,965 $229,965 $229,965 $229,965 Market Power Purchases $14,249,000 $12,952,695 $7,112,993 $7,112,993 $7,112,993 $7,112,993 OTHER RESOURCES Demand Side Renewable Energy $2,250,171 $2,256,075 $1,555,878 $1,555,878 $1,555,878 $1,555,878 Alt Resources Renewable Energy DSM Calaveras O&M $11,756,000 $12,151,449 $11,955,908 $11,955,908 $11,955,908 $11,955,908 Transmission/Ancillary Services Purchases Transmission Costs $14,850,000 $12,005,787 $13,957,173 $13,957,173 $13,957,173 $13,957,173 Other Salaries & Benefits ‐ Resource Mgmt $1,454,687 $2,066,695 $2,073,843 $2,073,843 $2,073,843 $2,073,843 Carbon Allowance Revenues ‐$4,296,000 ‐$4,296,000 ‐$4,296,000 ‐$4,296,000 ‐$4,296,000 ‐$4,296,000 General Expense (Resource Mgmt)$710,740 $729,232 $796,548 $796,548 $796,548 $796,548 Allocated G&A $1,254,368 $1,350,437 $1,350,437 $1,350,437 $1,350,437 $1,350,437 Total Purchased Power $76,332,966 $81,404,857 $90,065,328 $90,065,328 $90,065,328 $90,065,328 Total Production $76,332,966 $81,404,857 $90,065,328 $90,065,328 $90,065,328 $90,065,328 Distribution Op. Supervision & Engineering $2,749,336 $3,315,025 $3,314,847 $3,381,144 $3,448,767 $3,517,743 Load Dispatching Line and Station Expenses Overhead Lines Underground Lines Street Lighting & Signal System $860,619 $843,545 $869,624 $887,016 $904,757 $922,852 PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Last Updated: 3/10/2016 1:16 PM Schedule 3.2 Page 1 of 4 Prepared By EES Consulting, Inc. 586.00 587.00 588.00 589.00 590.00 591.00 592.00 592.10 593.00 594.00 594.10 595.00 595.00 596.00 597.00 598.00 598.10 XXXX XXXX 901/907/911 902.00 903.00 904.00 905.00 906.00 907.00 908.00 910.00 912.00 City of Palo Alto Total 2015 Expenses 2016 2017 2018 2019 2020 PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Meters Customer Installations Misc. Distribution $2,299,091 $2,304,516 $3,537,760 $3,608,515 $3,680,686 $3,754,299 Rents $214,400 $310,400 $318,470 $324,839 $331,336 $337,963 Maint. Supervision & Engineering $2,697,138 $3,093,886 $3,092,997 $3,154,857 $3,217,954 $3,282,314 Maint. of Structures Maint. of Station Equipment Maint. of Structures and Equipment Maint. of Overhead Lines $1,479,858 $1,502,814 $1,510,766 $1,540,981 $1,571,801 $1,603,237 Maint. Of Underground Lines Maint. of Lines Maint. of Line Transformers Maint. of Line Transformers ‐ Underground Maint. of Street Lighting & Signal System $185,979 $198,001 $198,001 $201,961 $206,000 $210,120 Maint. of Meters Maint. of Misc. Distribution Plant Communication O&M $318,092 $338,641 $352,642 $337,177 $343,539 $349,901 Other Other Total Distribution $10,804,513 $11,906,828 $13,195,107 $13,436,492 $13,704,840 $13,978,428 Total Operation & Maintenance $87,137,479 $93,311,685 $103,260,435 $103,501,819 $103,770,167 $104,043,755 Customer Service, Accounts, & Sales Supervision $664,307 $724,258 $718,334 $732,701 $747,355 $762,302 Meter Reading $298,424 $373,288 $390,328 $398,135 $406,097 $414,219 Customer Records Collection $547,945 $487,803 $487,803 $497,560 $507,511 $517,661 Uncollectable Accounts $135,704 $141,644 $141,023 $143,843 $146,720 $149,654 Misc. Customer Accounts Customer Service & Information $190,513 $176,793 $176,793 $180,329 $183,935 $187,614 Customer Communication & Education Customer Assistance Misc. Customer Service & Information Demonstrating & Selling Last Updated: 3/10/2016 1:16 PM Schedule 3.2 Page 2 of 4 Prepared By EES Consulting, Inc. 913.00 916.00 917.00 906.10 906.20 906.30 920.00 921.00 922.00 923.00 924.00 925.00 926.00 927.00 928.00 929.00 930.10 930.20 930.30 931.00 932.00 933.00 935.00 408.00 City of Palo Alto Total 2015 Expenses 2016 2017 2018 2019 2020 PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Advertising Misc. Sales Expenses $996,000 $996,000 $996,000 $1,015,920 $1,036,238 $1,056,963 Sales Expenses Key Accounts $299,195 $313,752 $312,784 $319,039 $325,420 $331,928 Energy Efficiency & DSM $2,115,545 $2,245,302 $2,417,900 $2,466,258 $2,515,583 $2,565,894 Low Income Residential Energy Assistance Program $292,243 $305,952 $305,952 $312,071 $318,313 $324,679 Total Customer Service, Accounts & Sales $5,539,876 $5,764,791 $5,946,916 $6,065,855 $6,187,172 $6,310,915 Total O&M w/o Purchased Power Supply & A&G $16,344,389 $17,671,620 $19,142,024 $19,502,346 $19,892,012 $13,978,428 Administrative & General Administrative & General Salaries $4,781,200 $5,245,712 $5,245,712 $5,350,626 $5,457,639 $5,566,792 Office Supplies $40,000 $36,700 $36,700 $37,434 $38,183 $38,946 Administrative Transfer ‐ Credit Outside Services $30,000 $487,748 $487,748 $497,503 $507,453 $517,602 Property Insurance Injuries and Damages $5,794 $10,864 $10,864 $11,081 $11,303 $11,529 Employee Pension & Benefits $1,004,817 $1,142,543 $1,142,543 $1,165,394 $1,188,702 $1,212,476 Franchise Requirements Regulatory Expense Duplicate Charge ‐ Credit General Advertising Misc. General Expense $1,874,081 $1,935,081 $1,934,446 $1,973,135 $2,012,598 $2,052,850 Environmental $77,118 $77,118 $77,118 $78,660 $80,234 $81,838 Rents $3,850,594 $4,869,565 $4,996,173 $5,096,096 $5,198,018 $5,301,979 Maint. of General Plant & Communication Equipment Transportation Maintenance of General Plant Total Administrative & General $11,663,603 $13,805,331 $13,931,304 $14,209,930 $14,494,128 $14,784,011 Total O&M plus A&G $104,340,959 $112,881,807 $123,138,655 $123,777,604 $124,451,468 $125,138,682 Taxes Property Tax Total Taxes Capital Projects Funded From Rates Last Updated: 3/10/2016 1:16 PM Schedule 3.2 Page 3 of 4 Prepared By EES Consulting, Inc. 450.00 451.00 454.00 456.00 457.00 458.00 419&424 449.00 415&416 444.20 421&429 446.00 XXXX City of Palo Alto Total 2015 Expenses 2016 2017 2018 2019 2020 PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Production Transmission Distribution $7,781,000 $14,666,639 $13,501,250 $16,306,888 $20,477,804 $10,735,893 General Total Capital Projects Funded From Rates $7,781,000 $14,666,639 $13,501,250 $16,306,888 $20,477,804 $10,735,893 Revenue Requirement Before Transfers and Other Revenu Other Contributions Transfers from Reserves and Allowances for Unspent Budget ‐$17,870,017 ‐$9,245,124 ‐$7,849,878 $909,000 General Fund Transfer $11,397,790 $11,725,000 $12,101,000 $12,343,020 $12,589,880 $12,841,678 Total Other Contributions $11,397,790 $11,725,000 ‐$5,769,017 $3,097,896 $4,740,002 $13,750,678 Revenue Requirement Before Reserve Transfers and Other $123,519,749 $139,273,446 $148,740,905 $152,427,512 $157,519,152 $148,716,253 Revenue Req. Before Taxes, Reserve Transfers and Other R $123,519,749 $139,273,446 $148,740,905 $152,427,512 $157,519,152 $148,716,253 Other Revenues Forfeited Deposits Misc. Service Revenues $167,200 $167,200 $167,200 $170,544 $173,955 $177,434 Rent ‐ Electric Properties Misc. Revenue (Other)$11,000 $11,000 $2,507,700 $2,557,854 $2,609,011 $2,661,191 Transfer Credits $666,667 $135,386 $135,386 Low Hydro Transfers $15,000,000 Dividends from Affiliates, Interest Other Revenue $300,676 $198,500 Income (Loss) from Equity Investments $198,500 $202,470 $206,519 $210,650 Street Light Revenue Traffic Signal Transfer from General Fund $233,984 $233,984 $233,984 $233,984 $233,984 Green Power $165,900 $56,000 $45,085 $45,987 $46,906 $47,845 Surplus Energy Revenues $2,316,000 $3,684,054 $5,084,054 $5,084,054 $5,084,054 $5,084,054 Total Other Revenues $6,325,543 $21,993,824 $8,382,909 $8,306,113 $8,365,874 $8,426,831 REVENUE REQUIREMENT for COST ALLOCATION $117,194,206 $117,279,622 $122,487,979 $134,876,275 $141,303,399 $141,198,422 Last Updated: 3/10/2016 1:16 PM Schedule 3.2 Page 4 of 4 Prepared By EES Consulting, Inc. FERC Account 555.70 555.71 555.72 555.73 555.74 555.75 555.76 555.77 555.78 555.50 555.60 XXXX XXXX 555.20 555.30 555.40 555.45 580.00 581.00 582.00 583.00 584.00 585.00 586.00 587.00 588.00 589.00 590.00 591.00 592.00 592.10 593.00 594.00 594.10 595.00 595.00 596.00 597.00 598.00 Allocation Date 2017 Direct Direct Total Demand Energy Demand Energy Assignment Demand Customer Assignment Expenses PD PE TD TE TDA DD DC DDA Total Check Operation & Maintenance Expense Power Purchases Western Power Purchases $12,806,834 $2,049,093 $10,757,741 Contra Surplus Energy NCPA Pooling $2,472,030 $2,472,030 NCPA Facilities $2,721,836 $2,721,836 Local Capacity Purchase $1,055,340 $1,055,340 Load Advance Renewable Energy $36,272,543 $1,145,449 $35,127,094 Carbon Neutral Purchases (REC) $229,965 $229,965 Market Power Purchases $7,112,993 $7,112,993 OTHER RESOURCES Demand Side Renewable Energy $1,555,878 $1,555,878 Alt Resources Renewable Energy DSM Calaveras O&M $11,955,908 $836,914 $11,118,995 Transmission/Ancillary Services Purchases Transmission Costs $13,957,173 $13,957,173 Other Salaries & Benefits ‐ Resource Mgmt $2,073,843 $2,073,843 Carbon Allowance Revenues ‐$4,296,000 ‐$4,296,000 General Expense (Resource Mgmt) $796,548 $796,548 Allocated G&A $1,350,437 $1,350,437 Total Purchased Power $90,065,328 $5,086,796 $84,978,532 Total Production $90,065,328 $5,086,796 $84,978,532 Distribution Op. Supervision & Engineering $3,314,847 $2,436,476 $878,372 Load Dispatching Line and Station Expenses Overhead Lines Underground Lines Street Lighting & Signal System $869,624 $869,624 Meters Customer Installations Misc. Distribution $3,537,760 $2,600,321 $937,439 Rents $318,470 $234,082 $84,388 Maint. Supervision & Engineering $3,092,997 $2,273,412 $819,585 Maint. of Structures Maint. of Station Equipment Maint. of Structures and Equipment Maint. of Overhead Lines $1,510,766 $1,510,766 Maint. Of Underground Lines Maint. of Lines Maint. of Line Transformers Maint. of Line Transformers ‐ Underground Maint. of Street Lighting & Signal System $198,001 $198,001 Maint. of Meters Maint. of Misc. Distribution Plant Production Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 REVENUE REQUIREMENT COST ALLOCATION Last Updated: 3/10/2016 1:16 PM Schedule 3.3 Page 1 of 3 Prepared By EES Consulting, Inc. 598.10 XXXX XXXX 901/907/911 902.00 903.00 904.00 905.00 906.00 907.00 908.00 910.00 912.00 913.00 916.00 917.00 906.10 906.20 906.30 920.00 921.00 922.00 923.00 924.00 925.00 926.00 927.00 928.00 929.00 930.10 930.20 930.30 931.00 932.00 933.00 935.00 408.00 Allocation Date 2017 Direct Direct Total Demand Energy Demand Energy Assignment Demand Customer Assignment Expenses PD PE TD TE TDA DD DC DDA Total Check Production Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 REVENUE REQUIREMENT COST ALLOCATION Communication O&M $352,642 $259,199 $93,443 Other Other Total Distribution $13,195,107 $9,314,255 $2,813,228 $1,067,625 Total Operation & Maintenance $103,260,435 $5,086,796 $84,978,532 $9,314,255 $2,813,228 $1,067,625 Customer Service, Accounts, & Sales Supervision $718,334 $718,334 Meter Reading $390,328 $390,328 Customer Records Collection $487,803 $487,803 Uncollectable Accounts $141,023 $141,023 Misc. Customer Accounts Customer Service & Information $176,793 $176,793 Customer Communication & Education Customer Assistance Misc. Customer Service & Information Demonstrating & Selling Advertising Misc. Sales Expenses $996,000 $996,000 Sales Expenses Key Accounts $312,784 $312,784 Energy Efficiency & DSM $2,417,900 $2,417,900 Low Income Residential Energy Assistance Program $305,952 $305,952 Total Customer Service, Accounts & Sales $5,946,916 $2,723,852 $2,910,281 $312,784 Total O&M w/o Purchased Power Supply & A&G $19,142,024 $2,723,852 $9,314,255 $5,723,509 $1,380,408 Administrative & General Administrative & General Salaries $5,245,712 $746,449 $2,552,494 $1,568,480 $378,289 Office Supplies $36,700 $5,222 $17,858 $10,973 $2,647 Administrative Transfer ‐ Credit Outside Services $487,748 $69,405 $237,332 $145,838 $35,173 Property Insurance Injuries and Damages $10,864 $1,546 $5,286 $3,248 $783 Employee Pension & Benefits $1,142,543 $162,580 $555,946 $341,623 $82,393 Franchise Requirements Regulatory Expense Duplicate Charge ‐ Credit General Advertising Misc. General Expense $1,934,446 $275,266 $941,276 $578,404 $139,501 Environmental $77,118 $10,974 $37,525 $23,058 $5,561 Rents $4,996,173 $710,940 $2,431,071 $1,493,867 $360,294 Maint. of General Plant & Communication Equipment Transportation Maintenance of General Plant Total Administrative & General $13,931,304 $1,982,382 $6,778,788 $4,165,492 $1,004,642 Total O&M plus A&G $123,138,655 $5,086,796 $89,684,766 $16,093,042 $9,889,001 $2,385,050 Taxes Property Tax Total Taxes Capital Projects Funded From Rates Last Updated: 3/10/2016 1:16 PM Schedule 3.3 Page 2 of 3 Prepared By EES Consulting, Inc. 450.00 451.00 454.00 456.00 457.00 458.00 419&424 449.00 415&416 444.20 421&429 446.00 XXXX Allocation Date 2017 Direct Direct Total Demand Energy Demand Energy Assignment Demand Customer Assignment Expenses PD PE TD TE TDA DD DC DDA Total Check Production Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 REVENUE REQUIREMENT COST ALLOCATION Production Transmission Distribution $13,501,250 $9,923,675 $3,577,575 General Total Capital Projects Funded From Rates $13,501,250 $9,923,675 $3,577,575 Revenue Requirement Before Transfers and Other Revenu Other Contributions Transfers from Reserves and Allowances for Unspent Budge ‐$17,870,017 ‐$880,309 ‐$14,706,192 ‐$1,611,904 ‐$486,851 ‐$184,761 General Fund Transfer $12,101,000 $9,740,954 $1,748,579 $611,467 Total Other Contributions ‐$5,769,017 ‐$880,309 ‐$14,706,192 $8,129,050 $1,261,729 $426,706 Revenue Requirement Before Reserve Transfers and Othe $148,740,905 $5,086,796 $89,684,766 $35,757,671 $15,215,155 $2,996,517 Revenue Req. Before Taxes, Reserve Transfers and Other R $148,740,905 $5,086,796 $89,684,766 $35,757,671 $15,215,155 $2,996,517 Other Revenues Forfeited Deposits Misc. Service Revenues $167,200 $23,792 $81,357 $49,993 $12,057 Rent ‐ Electric Properties Misc. Revenue (Other) $2,507,700 $356,838 $1,220,214 $749,808 $180,840 Transfer Credits $135,386 $19,265 $65,877 $40,481 $9,763 Low Hydro Transfers Dividends from Affiliates, Interest Other Revenue Income (Loss) from Equity Investments $198,500 $28,246 $96,587 $59,352 $14,315 Street Light Revenue Traffic Signal Transfer from General Fund $233,984 $233,984 Green Power $45,085 $45,085 Surplus Energy Revenues $5,084,054 $5,084,054 Total Other Revenues $8,382,909 $542 $5,566,333 $1,465,028 $899,934 $451,074 REVENUE REQUIREMENT for COST ALLOCATION $122,487,979 $4,205,945 $69,412,241 $32,680,740 $13,828,371 $2,360,683 Last Updated: 3/10/2016 1:16 PM Schedule 3.3 Page 3 of 3 Prepared By EES Consulting, Inc. FERC Account 555.70 555.71 555.72 555.73 555.74 555.75 555.76 555.77 555.78 555.50 555.60 XXXX XXXX 555.20 555.30 555.40 555.45 580.00 581.00 582.00 583.00 584.00 585.00 586.00 587.00 588.00 589.00 590.00 591.00 592.00 592.10 593.00 594.00 City of Palo Alto ‐ 100% Demand Allocation Date 2017 Total Expenses Operation & Maintenance Expense Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7City Accounts E‐18 Street/Traffic Lights Total Check Power Purchases Western Power Purchases $12,806,834 $1,950,721 $986,135 $4,365,205 $5,076,817 $404,080 $23,876 Contra Surplus Energy NCPA Pooling $2,472,030 $392,543 $180,715 $823,394 $995,530 $74,981 $4,867 NCPA Facilities $2,721,836 $432,211 $198,977 $906,601 $1,096,131 $82,558 $5,359 Local Capacity Purchase $1,055,340 $124,873 $102,853 $402,737 $383,430 $40,058 $1,388 Load Advance Renewable Energy $36,272,543 $5,713,498 $2,679,559 $12,137,404 $14,562,469 $1,108,948 $70,665 Carbon Neutral Purchases (REC) $229,965 $36,517 $16,811 $76,598 $92,611 $6,975 $453 Market Power Purchases $7,112,993 $1,129,499 $519,987 $2,369,225 $2,864,528 $215,750 $14,004 OTHER RESOURCES Demand Side Renewable Energy $1,555,878 $324,484 $114,004 $491,591 $528,951 $96,847 Alt Resources Renewable Energy DSM Calaveras O&M $11,955,908 $1,864,655 $894,406 $4,022,943 $4,781,886 $369,027 $22,992 Transmission/Ancillary Services Purchases Transmission Costs $13,957,173 $2,216,312 $1,020,323 $4,648,913 $5,620,799 $423,347 $27,479 Other Salaries & Benefits ‐ Resource Mgmt $2,073,843 $329,313 $151,606 $690,764 $835,173 $62,903 $4,083 Carbon Allowance Revenues ‐$4,296,000 ‐$682,178 ‐$314,054 ‐$1,430,930 ‐$1,730,075 ‐$130,306 ‐$8,458 General Expense (Resource Mgmt) $796,548 $126,487 $58,231 $265,318 $320,784 $24,161 $1,568 Allocated G&A $1,350,437 $214,441 $98,722 $449,809 $543,845 $40,961 $2,659 Total Purchased Power $90,065,328 $14,173,375 $6,708,273 $30,219,573 $35,972,879 $2,820,292 $170,935 Total Production $90,065,328 $14,173,375 $6,708,273 $30,219,573 $35,972,879 $2,820,292 $170,935 Distribution Op. Supervision & Engineering $3,314,847 $565,063 $271,847 $1,346,669 $957,408 $166,666 $7,195 Load Dispatching Line and Station Expenses Overhead Lines Underground Lines Street Lighting & Signal System $869,624 $869,624 Meters Customer Installations Misc. Distribution $3,537,760 $603,062 $290,128 $1,437,228 $1,021,790 $177,874 $7,679 Rents $318,470 $54,288 $26,117 $129,380 $91,982 $16,012 $691 Maint. Supervision & Engineering $3,092,997 $527,246 $253,653 $1,256,541 $893,332 $155,512 $6,713 Maint. of Structures Maint. of Station Equipment Maint. of Structures and Equipment Maint. of Overhead Lines $1,510,766 $228,622 $148,399 $535,163 $519,234 $74,884 $4,463 Maint. Of Underground Lines REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Last Updated: 3/10/2016 1:16 PM Schedule 3.4 Page 1 of 4 Prepared By EES Consulting, Inc. FERC Account 594.10 595.00 595.00 596.00 597.00 598.00 598.10 XXXX XXXX 901/907/911 902.00 903.00 904.00 905.00 906.00 907.00 908.00 910.00 912.00 913.00 916.00 917.00 906.10 906.20 906.30 920.00 921.00 922.00 923.00 924.00 925.00 926.00 927.00 928.00 City of Palo Alto ‐ 100% Demand Allocation Date 2017 Total Expenses Operation & Maintenance Expense Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7City Accounts E‐18 Street/Traffic Lights Total Check REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Maint. of Lines Maint. of Line Transformers Maint. of Line Transformers ‐ Underground Maint. of Street Lighting & Signal System $198,001 $198,001 Maint. of Meters Maint. of Misc. Distribution Plant Communication O&M $352,642 $60,113 $28,920 $143,262 $101,852 $17,730 $765 Other Other Total Distribution $13,195,107 $2,038,394 $1,019,065 $4,848,242 $3,585,597 $608,679 $1,095,130 Total Operation & Maintenance $103,260,435 $16,211,769 $7,727,338 $35,067,816 $39,558,477 $3,428,970 $1,266,066 Customer Service, Accounts, & Sales Supervision $718,334 $312,734 $113,769 $245,213 $39,047 $7,559 $12 Meter Reading $390,328 $169,936 $61,821 $133,246 $21,218 $4,107 Customer Records Collection $487,803 $170,731 $243,691 $58,360 $5,227 $9,715 $79 Uncollectable Accounts $141,023 $49,358 $70,450 $16,872 $1,511 $2,808 $23 Misc. Customer Accounts Customer Service & Information $176,793 $106,076 $19,836 $42,753 $6,808 $1,318 $2 Customer Communication & Education Customer Assistance Misc. Customer Service & Information Demonstrating & Selling Advertising Misc. Sales Expenses $996,000 $597,600 $111,749 $240,860 $38,354 $7,425 $12 Sales Expenses Key Accounts $312,784 $125,113 $187,670 Energy Efficiency & DSM $2,417,900 $371,809 $180,291 $777,422 $1,013,810 $74,568 Low Income Residential Energy Assistance Program $305,952 $47,047 $22,813 $98,372 $128,284 $9,436 Total Customer Service, Accounts & Sales $5,946,916 $1,825,291 $824,420 $1,738,212 $1,441,929 $116,935 $129 Total O&M w/o Purchased Power Supply & A&G $19,142,024 $3,863,685 $1,843,484 $6,586,454 $5,027,527 $725,614 $1,095,259 Administrative & General Administrative & General Salaries $5,245,712 $1,058,811 $505,191 $1,804,963 $1,377,752 $198,848 $300,147 Office Supplies $36,700 $7,408 $3,534 $12,628 $9,639 $1,391 $2,100 Administrative Transfer ‐ Credit Outside Services $487,748 $98,449 $46,973 $167,826 $128,104 $18,489 $27,908 Property Insurance Injuries and Damages $10,864 $2,193 $1,046 $3,738 $2,853 $412 $622 Employee Pension & Benefits $1,142,543 $230,614 $110,033 $393,130 $300,081 $43,310 $65,373 Franchise Requirements Regulatory Expense Last Updated: 3/10/2016 1:16 PM Schedule 3.4 Page 2 of 4 Prepared By EES Consulting, Inc. FERC Account 929.00 930.10 930.20 930.30 931.00 932.00 933.00 935.00 408.00 450.00 451.00 454.00 456.00 457.00 458.00 419&424 449.00 415&416 444.20 City of Palo Alto ‐ 100% Demand Allocation Date 2017 Total Expenses Operation & Maintenance Expense Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7City Accounts E‐18 Street/Traffic Lights Total Check REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Duplicate Charge ‐ Credit General Advertising Misc. General Expense $1,934,446 $390,455 $186,298 $665,611 $508,070 $73,329 $110,684 Environmental $77,118 $15,566 $7,427 $26,535 $20,255 $2,923 $4,413 Rents $4,996,173 $1,008,443 $481,159 $1,719,101 $1,312,212 $189,389 $285,869 Maint. of General Plant & Communication Equipment Transportation Maintenance of General Plant Total Administrative & General $13,931,304 $2,811,937 $1,341,663 $4,793,532 $3,658,965 $528,092 $797,115 Total O&M plus A&G $123,138,655 $20,848,997 $9,893,420 $41,599,559 $44,659,372 $4,073,998 $2,063,309 Taxes Property Tax Total Taxes Capital Projects Funded From Rates Production Transmission Distribution $13,501,250 $2,301,482 $1,107,223 $5,484,931 $3,899,486 $678,825 $29,304 General Total Capital Projects Funded From Rates $13,501,250 $2,301,482 $1,107,223 $5,484,931 $3,899,486 $678,825 $29,304 Revenue Requirement Before Transfers and Other Revenue Other Contributions Transfers from Reserves and Allowances for Unspent Budget ‐$17,870,017 ‐$2,805,572 ‐$1,337,276 ‐$6,068,757 ‐$6,845,900 ‐$593,410 ‐$219,102 General Fund Transfer $12,101,000 $1,864,587 $1,021,317 $4,412,352 $3,588,443 $574,072 $640,229 Total Other Contributions ‐$5,769,017 ‐$940,985 ‐$315,959 ‐$1,656,404 ‐$3,257,457 ‐$19,337 $421,126 Revenue Requirement Before Reserve Transfers and Other $148,740,905 $25,015,066 $12,021,959 $51,496,843 $52,147,301 $5,326,895 $2,732,842 Revenue Req. Before Taxes, Reserve Transfers and Other R $148,740,905 $25,015,066 $12,021,959 $51,496,843 $52,147,301 $5,326,895 $2,732,842 Other Revenues Forfeited Deposits Misc. Service Revenues $167,200 $33,748 $16,102 $57,531 $43,914 $6,338 $9,567 Rent ‐ Electric Properties Misc. Revenue (Other) $2,507,700 $506,162 $241,506 $862,858 $658,631 $95,059 $143,484 Transfer Credits $135,386 $27,327 $13,038 $46,584 $35,558 $5,132 $7,746 Low Hydro Transfers Dividends from Affiliates, Interest Other Revenue Income (Loss) from Equity Investments $198,500 $40,066 $19,117 $68,301 $52,135 $7,525 $11,358 Street Light Revenue Last Updated: 3/10/2016 1:16 PM Schedule 3.4 Page 3 of 4 Prepared By EES Consulting, Inc. FERC Account 421&429 446.00 XXXX City of Palo Alto ‐ 100% Demand Allocation Date 2017 Total Expenses Operation & Maintenance Expense Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7City Accounts E‐18 Street/Traffic Lights Total Check REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Traffic Signal Transfer from General Fund $233,984 $233,984 Green Power $45,085 $7,159 $3,296 $15,017 $18,157 $1,368 $89 Surplus Energy Revenues $5,084,054 $807,316 $371,664 $1,693,418 $2,047,438 $154,209 $10,010 Total Other Revenues $8,382,909 $1,423,505 $665,546 $2,747,444 $2,860,047 $269,995 $416,373 REVENUE REQUIREMENT for COST ALLOCATION $122,487,979 $20,785,989 $10,019,138 $42,680,642 $42,441,354 $4,463,490 $2,097,367 Last Updated: 3/10/2016 1:16 PM Schedule 3.4 Page 4 of 4 Prepared By EES Consulting, Inc. FERC Account 555.70 555.71 555.72 555.73 555.74 555.75 555.76 555.77 555.78 555.50 555.60 XXXX XXXX 555.20 555.30 555.40 555.45 580.00 581.00 582.00 583.00 584.00 585.00 586.00 587.00 588.00 589.00 590.00 591.00 592.00 City of Palo Alto ‐ 100% Demand Allocation Date 2016 Total Expenses Operation & Maintenance Expense Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Total Check Power Purchases Western Power Purchases Contra Surplus Energy NCPA Pooling NCPA Facilities Local Capacity Purchase Load Advance Renewable Energy Carbon Neutral Purchases (REC) Market Power Purchases OTHER RESOURCES Demand Side Renewable Energy Alt Resources Renewable Energy DSM Calaveras O&M Transmission/Ancillary Services Purchases Transmission Costs Other Salaries & Benefits ‐ Resource Mgmt Carbon Allowance Revenues General Expense (Resource Mgmt) Allocated G&A Total Purchased Power Total Production Distribution Op. Supervision & Engineering Load Dispatching Line and Station Expenses Overhead Lines Underground Lines Street Lighting & Signal System $869,624 $869,624 Meters Customer Installations Misc. Distribution Rents Maint. Supervision & Engineering Maint. of Structures Maint. of Station Equipment REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Last Updated: 3/10/2016 1:16 PM Schedule 3.5 Page 1 of 4 Prepared By EES Consulting, Inc. FERC Account 592.10 593.00 594.00 594.10 595.00 595.00 596.00 597.00 598.00 598.10 XXXX XXXX 901/907/911 902.00 903.00 904.00 905.00 906.00 907.00 908.00 910.00 912.00 913.00 916.00 917.00 906.10 906.20 906.30 920.00 921.00 922.00 City of Palo Alto ‐ 100% Demand Allocation Date 2016 Total Expenses Operation & Maintenance Expense Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Total Check REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Maint. of Structures and Equipment Maint. of Overhead Lines Maint. Of Underground Lines Maint. of Lines Maint. of Line Transformers Maint. of Line Transformers ‐ Underground Maint. of Street Lighting & Signal System $198,001 $198,001 Maint. of Meters Maint. of Misc. Distribution Plant Communication O&M Other Other Total Distribution $1,067,625 $1,067,625 Total Operation & Maintenance $1,067,625 $1,067,625 Customer Service, Accounts, & Sales Supervision Meter Reading Customer Records Collection Uncollectable Accounts Misc. Customer Accounts Customer Service & Information Customer Communication & Education Customer Assistance Misc. Customer Service & Information Demonstrating & Selling Advertising Misc. Sales Expenses Sales Expenses Key Accounts $312,784 $125,113 $187,670 Energy Efficiency & DSM Low Income Residential Energy Assistance Program Total Customer Service, Accounts & Sales $312,784 $125,113 $187,670 Total O&M w/o Purchased Power Supply & A&G $1,380,408 $125,113 $187,670 $1,067,625 Administrative & General Administrative & General Salaries $378,289 $34,286 $51,429 $292,574 Office Supplies $2,647 $240 $360 $2,047 Administrative Transfer ‐ Credit Last Updated: 3/10/2016 1:16 PM Schedule 3.5 Page 2 of 4 Prepared By EES Consulting, Inc. FERC Account 923.00 924.00 925.00 926.00 927.00 928.00 929.00 930.10 930.20 930.30 931.00 932.00 933.00 935.00 408.00 450.00 451.00 City of Palo Alto ‐ 100% Demand Allocation Date 2016 Total Expenses Operation & Maintenance Expense Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Total Check REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Outside Services $35,173 $3,188 $4,782 $27,204 Property Insurance Injuries and Damages $783 $71 $107 $606 Employee Pension & Benefits $82,393 $7,468 $11,202 $63,724 Franchise Requirements Regulatory Expense Duplicate Charge ‐ Credit General Advertising Misc. General Expense $139,501 $12,644 $18,965 $107,892 Environmental $5,561 $504 $756 $4,301 Rents $360,294 $32,655 $48,983 $278,656 Maint. of General Plant & Communication Equipment Transportation Maintenance of General Plant Total Administrative & General $1,004,642 $91,056 $136,584 $777,003 Total O&M plus A&G $2,385,050 $216,169 $324,254 $1,844,627 Taxes Property Tax Total Taxes Capital Projects Funded From Rates Production Transmission Distribution General Total Capital Projects Funded From Rates Revenue Requirement Before Transfers and Other Revenue Other Contributions Transfers from Reserves and Allowances for Unspent Budget ‐$184,761 ‐$184,761 General Fund Transfer $611,467 $611,467 Total Other Contributions $426,706 $426,706 Revenue Requirement Before Reserve Transfers and Other $2,996,517 $216,169 $324,254 $2,456,094 Revenue Req. Before Taxes, Reserve Transfers and Other Re $2,996,517 $216,169 $324,254 $2,456,094 Other Revenues Forfeited Deposits Misc. Service Revenues $12,057 $1,093 $1,639 $9,325 Last Updated: 3/10/2016 1:16 PM Schedule 3.5 Page 3 of 4 Prepared By EES Consulting, Inc. FERC Account 454.00 456.00 457.00 458.00 419&424 449.00 415&416 444.20 421&429 446.00 XXXX City of Palo Alto ‐ 100% Demand Allocation Date 2016 Total Expenses Operation & Maintenance Expense Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights Total Check REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Rent ‐ Electric Properties Misc. Revenue (Other)$180,840 $16,390 $24,586 $139,864 Transfer Credits $9,763 $885 $1,327 $7,551 Low Hydro Transfers Dividends from Affiliates, Interest Other Revenue Income (Loss) from Equity Investments $14,315 $1,297 $1,946 $11,071 Street Light Revenue Traffic Signal Transfer from General Fund $233,984 $233,984 Green Power Surplus Energy Revenues Total Other Revenues $451,074 $19,666 $29,498 $401,910 REVENUE REQUIREMENT for COST ALLOCATION $2,360,683 $196,504 $294,755 $1,869,424 Last Updated: 3/10/2016 1:16 PM Schedule 3.5 Page 4 of 4 Prepared By EES Consulting, Inc.City of Palo Alto INPUT RATE BASE Schedule 4.1 Year Classification 2015 & Allocation Cost, $ Function Factor Classification & Allocation Method FERC Account Intangible Plant 301.00 Organization SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 302.00 Franchise and Consents SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 303.00 Miscellaneous Intangible Plant SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) Total Intangible Plant Distribution Plant 360.00 Land & Rights DNCPPNon‐Coincident Peak ‐ Primary 361.00 Structures & Improvements $4,384,759 D NCPP Non‐Coincident Peak ‐ Primary 362.00 Station Equipment ‐ Distribution $40,394,851 D NCPP Non‐Coincident Peak ‐ Primary 363.00 Storage & Battery Equipment DNCPPNon‐Coincident Peak ‐ Primary 364.00 Poles, Towers, & Fixtures $29,237,542 D 100%DP Demand Only ‐ Poles, Towers & Fixtures (100% Demand) 365.00 Overhead Conductors & Devices $18,614,589 D 100%DC Demand Only ‐ Overhead and Underground Conduit (100% Demand) 366.00 Underground Conduit $28,600,165 D 100%DC Demand Only ‐ Overhead and Underground Conduit (100% Demand) 367.00 Underground Conductors & Devices $61,209,198 D 100%DC Demand Only ‐ Overhead and Underground Conduit (100% Demand) 368.00 Line Transformers $19,221,468 D 100%DT Demand Only‐ Transformers (100% Demand) 369.00 Services $45,628,911 D SERV Services 370.00 Meters $4,787,766 D CUSTW Customers Weighted for Accounting/Metering 371.00 Installation on Customer Premises DCUSTMCustomers Weighted for Meters and Services 372.00 Leased Property on Cust. Premises DCUSTMCustomers Weighted for Meters and Services 373.00 Street Lights and Signal Systems $22,284,499 D DA1 Direct Assignment for Streetlights Total Distribution Plant $274,363,748 Total Transmission & Distribution $274,363,748 General Plant 389.00 Land & Land Rights SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 390.00 Structures & Improvements SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 391.00 Office Furniture & Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 392.00 Transportation Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 393.00 Stores Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 394.00 Tools, Shop, & Garage Equipment $2,593,795 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 395.00 Laboratory Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 396.00 Power Operated Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 397.00 Communication Equipment $1,865,281 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 398.00 Misc. Equipment $18,977,780 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 399.00 Other Tangible Property SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) Total General Plant $23,436,856 Total Plant Before General Plant & Intangible $274,363,748 Total Gross Plant in Service $297,800,603 Last Updated: 3/10/2016 1:16 PM Schedule 4.1 Page 1 of 2 Prepared By EES Consulting, Inc.City of Palo Alto INPUT RATE BASE Schedule 4.1 Year Classification 2015 & Allocation Cost, $ Function Factor Classification & Allocation Method Less: Accumulated Depreciation Intangible Plant PRBIGOn the Basis of Intangible Plant Rate Base Distribution Plant $131,788,193 D RBD‐ST As Distribution Ratebase DA Street Lighting General Plant SS RBGP On the Basis of General Plant Rate Base Misc. Plant SS RBGP On the Basis of General Plant Rate Base Total Accumulated Depreciation $131,788,193 Total Net Plant $166,012,410 Working Capital 90 Days of Non Power Supply O&M $8,155,067 SS OMWOP On the Basis of O&M (w/o Purch. Power Supply) 90 Days of Power Supply Cost $22,207,889 POMPOn the Basis of Purchased Power O&M Total Working Capital $30,362,956 TOTAL RATE BASE $196,375,366 Construction Work In Progress (CWIP) Distribution Plant $11,486,367 D RBD On the Basis of Distribution Rate Base Services DRBDOn the Basis of Distribution Rate Base General Plant SS RBGP On the Basis of General Plant Rate Base Other SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) Total Construction Work In Progress $11,486,367 TOTAL RATE BASE plus Construction Work In Progress $207,861,733 Last Updated: 3/10/2016 1:16 PM Schedule 4.1 Page 2 of 2 Prepared By EES Consulting, Inc. FERC Account 301.00 302.00 303.00 360.00 361.00 362.00 363.00 364.00 365.00 366.00 367.00 368.00 369.00 370.00 371.00 372.00 373.00 389.00 390.00 391.00 392.00 393.00 394.00 395.00 396.00 397.00 398.00 399.00 City of Palo Alto ‐ 100% Demand Direct Direct Total Demand Energy Demand Energy Assignment Demand Customer Assignment Account Description Rate Base PD PE TD TE TDA DD DC DDA Total Check Intangible Plant Organization Franchise and Consents Miscellaneous Intangible Plant Total Intangible Plant Distribution Plant Land & Rights Structures & Improvements $4,384,759 $4,384,759 Station Equipment ‐ Distribution $40,394,851 $40,394,851 Storage & Battery Equipment Poles, Towers, & Fixtures $29,237,542 $29,237,542 Overhead Conductors & Devices $18,614,589 $18,614,589 Underground Conduit $28,600,165 $28,600,165 Underground Conductors & Devices $61,209,198 $61,209,198 Line Transformers $19,221,468 $19,221,468 Services $45,628,911 $45,628,911 Meters $4,787,766 $4,787,766 Installation on Customer Premises Leased Property on Cust. Premises Street Lights and Signal Systems $22,284,499 $22,284,499 Total Distribution Plant $274,363,748 $201,662,571 $50,416,678 $22,284,499 Total Transmission & Distribution $274,363,748 $201,662,571 $50,416,678 $22,284,499 General Plant Land & Land Rights Structures & Improvements Office Furniture & Equipment Transportation Equipment Stores Equipment Tools, Shop, & Garage Equipment $2,593,795 $1,906,488 $476,632 $210,674 Laboratory Equipment Power Operated Equipment Communication Equipment $1,865,281 $1,371,017 $342,761 $151,503 Misc. Equipment $18,977,780 $13,949,029 $3,487,329 $1,541,422 Other Tangible Property Total General Plant $23,436,856 $17,226,534 $4,306,722 $1,903,599 Total Plant Before General Plant & Intangible $274,363,748 $201,662,571 $50,416,678 $22,284,499 Total Gross Plant in Service $297,800,603 $218,889,106 $54,723,400 $24,188,098 Less: Accumulated Depreciation Intangible Plant Distribution Plant $131,788,193 $85,253,936 $30,734,813 $15,799,444 RATE BASE FOR COST ALLOCATION DistributionProduction Transmission FUNCTIONALIZATION AND CLASSIFICATION Schedule 4.2 Last Updated: 3/10/2016 1:16 PM Schedule 4.2 Page 1 of 2 Prepared By EES Consulting, Inc. City of Palo Alto ‐ 100% Demand Direct Direct Total Demand Energy Demand Energy Assignment Demand Customer Assignment Account Description Rate Base PD PE TD TE TDA DD DC DDA Total Check RATE BASE FOR COST ALLOCATION DistributionProduction Transmission FUNCTIONALIZATION AND CLASSIFICATION Schedule 4.2 General Plant Misc. Plant Total Accumulated Depreciation $131,788,193 $85,253,936 $30,734,813 $15,799,444 Total Net Plant $166,012,410 $133,635,170 $23,988,587 $8,388,654 Working Capital 90 Days of Non Power Supply O&M $8,155,067 $1,160,441 $3,968,147 $2,438,384 $588,095 90 Days of Power Supply Cost $22,207,889 $1,254,278 $20,953,611 Total Working Capital $30,362,956 $1,254,278 $22,114,052 $3,968,147 $2,438,384 $588,095 TOTAL RATE BASE $196,375,366 $1,254,278 $22,114,052 $137,603,317 $26,426,971 $8,976,748 Construction Work In Progress (CWIP) Distribution Plant $11,486,367 $8,442,698 $2,110,718 $932,951 Services General Plant Other Total Construction Work In Progress $11,486,367 $8,442,698 $2,110,718 $932,951 TOTAL RATE BASE plus Construction Work In Progress $207,861,733 $1,254,278 $22,114,052 $146,046,015 $28,537,688 $9,909,699 Last Updated: 3/10/2016 1:16 PM Schedule 4.2 Page 2 of 2 Prepared By EES Consulting, Inc. FERC Account 301.00 302.00 303.00 360.00 361.00 362.00 363.00 364.00 365.00 366.00 367.00 368.00 369.00 370.00 371.00 372.00 373.00 389.00 390.00 391.00 392.00 393.00 394.00 395.00 396.00 397.00 398.00 399.00 City of Palo Alto ‐ 100% Demand Account Description Total Rate Base Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Total Check Intangible Plant Organization Franchise and Consents Miscellaneous Intangible Plant Total Intangible Plant Distribution Plant Land & Rights Structures & Improvements $4,384,759 $663,540 $430,706 $1,553,226 $1,506,995 $217,339 $12,952 Station Equipment ‐ Distribution $40,394,851 $6,112,901 $3,967,903 $14,309,190 $13,883,284 $2,002,252 $119,322 Storage & Battery Equipment Poles, Towers, & Fixtures $29,237,542 $4,424,479 $2,871,944 $10,356,902 $10,048,634 $1,449,217 $86,365 Overhead Conductors & Devices $18,614,589 $2,816,922 $1,828,473 $6,593,902 $6,397,638 $922,669 $54,985 Underground Conduit $28,600,165 $4,328,026 $2,809,335 $10,131,122 $9,829,575 $1,417,625 $84,482 Underground Conductors & Devices $61,209,198 $9,262,709 $6,012,453 $21,682,318 $21,036,955 $3,033,957 $180,805 Line Transformers $19,221,468 $2,892,953 $1,877,825 $6,771,878 $6,674,768 $947,573 $56,470 Services $45,628,911 $9,196,894 $1,115,240 $26,148,249 $6,580,910 $2,587,618 Meters $4,787,766 $2,084,402 $758,280 $1,634,369 $260,252 $50,381 $82 Installation on Customer Premises Leased Property on Cust. Premises Street Lights and Signal Systems $22,284,499 $22,284,499 Total Distribution Plant $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962 Total Transmission & Distribution $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962 General Plant Land & Land Rights Structures & Improvements Office Furniture & Equipment Transportation Equipment Stores Equipment Tools, Shop, & Garage Equipment $2,593,795 $395,009 $204,885 $937,644 $720,563 $119,389 $216,304 Laboratory Equipment Power Operated Equipment Communication Equipment $1,865,281 $284,063 $147,340 $674,290 $518,180 $85,857 $155,551 Misc. Equipment $18,977,780 $2,890,124 $1,499,066 $6,860,375 $5,272,080 $873,524 $1,582,610 Other Tangible Property RATE BASE COST ALLOCATION CLASSIFICATION BY CUSTOMER Schedule 4.3 Last Updated: 3/10/2016 1:16 PM Schedule 4.3 Page 1 of 2 Prepared By EES Consulting, Inc. FERC Account City of Palo Alto ‐ 100% Demand Account Description Total Rate Base Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Total Check RATE BASE COST ALLOCATION CLASSIFICATION BY CUSTOMER Schedule 4.3 Total General Plant $23,436,856 $3,569,196 $1,851,291 $8,472,309 $6,510,824 $1,078,770 $1,954,465 Total Plant Before General Plant & Intangible $274,363,748 $41,782,826 $21,672,159 $99,181,158 $76,219,011 $12,628,632 $22,879,962 Total Gross Plant in Service $297,800,603 $45,352,022 $23,523,450 $107,653,467 $82,729,835 $13,707,402 $24,834,427 Less: Accumulated Depreciation Intangible Plant Distribution Plant $131,788,193 $19,771,944 $9,512,109 $47,120,845 $33,500,340 $5,831,760 $16,051,195 General Plant Misc. Plant Total Accumulated Depreciation $131,788,193 $19,771,944 $9,512,109 $47,120,845 $33,500,340 $5,831,760 $16,051,195 Total Net Plant $166,012,410 $25,580,078 $14,011,342 $60,532,622 $49,229,494 $7,875,642 $8,783,232 Working Capital 90 Days of Non Power Supply O&M $8,155,067 $1,646,044 $785,379 $2,806,024 $2,141,875 $309,133 $466,613 90 Days of Power Supply Cost $22,207,889 $3,494,805 $1,654,095 $7,451,402 $8,870,025 $695,414 $42,148 Total Working Capital $30,362,956 $5,140,849 $2,439,473 $10,257,426 $11,011,900 $1,004,547 $508,761 TOTAL RATE BASE $196,375,366 $30,720,927 $16,450,815 $70,790,048 $60,241,394 $8,880,189 $9,291,993 Construction Work In Progress (CWIP) Distribution Plant $11,486,367 $1,749,258 $907,315 $4,152,266 $3,190,945 $528,704 $957,880 Services General Plant Other Total Construction Work In Progress $11,486,367 $1,749,258 $907,315 $4,152,266 $3,190,945 $528,704 $957,880 TOTAL RATE BASE plus Construction Work In Progress $207,861,733 $32,470,184 $17,358,130 $74,942,313 $63,432,339 $9,408,893 $10,249,874 Last Updated: 3/10/2016 1:16 PM Schedule 4.3 Page 2 of 2 Prepared By EES Consulting, Inc. FERC Account 301.00 302.00 303.00 360.00 361.00 362.00 363.00 364.00 365.00 366.00 367.00 368.00 369.00 370.00 371.00 372.00 373.00 389.00 390.00 391.00 392.00 393.00 394.00 395.00 396.00 397.00 398.00 399.00 City of Palo Alto ‐ 100% Demand Account Description Total Rate Base Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Total Check Intangible Plant Organization Franchise and Consents Miscellaneous Intangible Plant Total Intangible Plant Distribution Plant Land & Rights Structures & Improvements Station Equipment ‐ Distribution Storage & Battery Equipment Poles, Towers, & Fixtures Overhead Conductors & Devices Underground Conduit Underground Conductors & Devices Line Transformers Services Meters Installation on Customer Premises Leased Property on Cust. Premises Street Lights and Signal Systems $22,284,499 $22,284,499 Total Distribution Plant $22,284,499 $22,284,499 Total Transmission & Distribution $22,284,499 $22,284,499 General Plant Land & Land Rights Structures & Improvements Office Furniture & Equipment Transportation Equipment Stores Equipment Tools, Shop, & Garage Equipment $210,674 $210,674 Laboratory Equipment Power Operated Equipment Communication Equipment $151,503 $151,503 Misc. Equipment $1,541,422 $1,541,422 Other Tangible Property RATE BASE COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 4.4 Last Updated: 3/10/2016 1:16 PM Schedule 4.4 Page 1 of 2 Prepared By EES Consulting, Inc. FERC Account City of Palo Alto ‐ 100% Demand Account Description Total Rate Base Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Total Check RATE BASE COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 4.4 Total General Plant $1,903,599 $1,903,599 Total Plant Before General Plant & Intangible $22,284,499 $22,284,499 Total Gross Plant in Service $24,188,098 $24,188,098 Less: Accumulated Depreciation Intangible Plant Distribution Plant $15,799,444 $15,799,444 General Plant Misc. Plant Total Accumulated Depreciation $15,799,444 $15,799,444 Total Net Plant $8,388,654 $8,388,654 Working Capital 90 Days of Non Power Supply O&M $588,095 $53,302 $79,953 $454,840 90 Days of Power Supply Cost Total Working Capital $588,095 $53,302 $79,953 $454,840 TOTAL RATE BASE $8,976,748 $53,302 $79,953 $8,843,493 Construction Work In Progress (CWIP) Distribution Plant $932,951 $932,951 Services General Plant Other Total Construction Work In Progress $932,951 $932,951 TOTAL RATE BASE plus Construction Work In Progress $9,909,699 $53,302 $79,953 $9,776,444 Last Updated: 3/10/2016 1:16 PM Schedule 4.4 Page 2 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Classification Factors Total % Allocated Demand Energy Direct Assignment Demand Energy Direct Assignment Demand Energy Customer Direct Assignment PD PE PDA TD TE TDA DD DE DC DDA CP12 100.0% 100.0% 100.0%100.0% NCPP 100.0% 100.0% 100.0%100.0% NCPS 100.0% 100.0% 100.0%100.0% kWh 100.0% 100.0% 100.0%100.0% CUST 100.0%100.0% CUSTW 100.0%100.0% CUSTM 100.0%100.0% CUSTMR 100.0%100.0% 100%DP 100.0%100.0% 100%DC 100.0%100.0% 100%DT 100.0%100.0% DA1 100.0% 100.0% DA2 100.0% 100.0% RBG RBD 73.5% 18.4% 8.1%100.0% RBGP 73.5% 18.4% 8.1%100.0% RBGP‐P 73.5% 18.4% 8.1%100.0% RBGP‐T 73.5% 18.4% 8.1%100.0% RBGP‐D 73.5% 18.4% 8.1%100.0% RBSE 100.0%100.0% RBOH 100.0%100.0% RBUG 100.0%100.0% RBTR 100.0%100.0% OM 4.9% 82.3% 9.0% 2.7% 1.0%100.0% OM‐P 4.9% 82.3% 9.0% 2.7% 1.0%100.0% OM‐T 4.9% 82.3% 9.0% 2.7% 1.0%100.0% OM‐D 4.9% 82.3% 9.0% 2.7% 1.0%100.0% OMAG 14.2% 48.7% 29.9% 7.2%100.0% OMAG‐P 14.2% 48.7% 29.9% 7.2%100.0% OMAG‐T 14.2% 48.7% 29.9% 7.2%100.0% OMAG‐D 14.2% 48.7% 29.9% 7.2%100.0% GPLT 73.5% 18.4% 8.1%100.0% GPLT‐P 73.5% 18.4% 8.1%100.0% GPLT‐T 73.5% 18.4% 8.1%100.0% Production Transmission Distribution CLASSIFICATION and ALLOCATION BY FUNCTION Schedule 6.1 Last Updated: 3/10/2016 1:16 PM Schedule 6.1 Page 1 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Classification Factors Total % Allocated Demand Energy Direct Assignment Demand Energy Direct Assignment Demand Energy Customer Direct Assignment PD PE PDA TD TE TDA DD DE DC DDA Production Transmission Distribution CLASSIFICATION and ALLOCATION BY FUNCTION Schedule 6.1 GPLT‐D 73.5% 18.4% 8.1%100.0% NETPLT 80.5% 14.4% 5.1%100.0% NETPLT‐P 80.5% 14.4% 5.1%100.0% NETPLT‐T 80.5% 14.4% 5.1%100.0% NETPLT‐D 80.5% 14.4% 5.1%100.0% OMP 5.6% 94.4%100.0% OMWOP 14.2% 48.7% 29.9% 7.2%100.0% OMWOP‐P 14.2% 48.7% 29.9% 7.2%100.0% OMWOP‐T 14.2% 48.7% 29.9% 7.2%100.0% OMWOP‐D 14.2% 48.7% 29.9% 7.2%100.0% WEST 16.0% 84.0%100.0% REN 3.2% 96.8%100.0% CALA 7.0% 93.0%100.0% CREDIT 100.0% 100.0% CUST SERV 100.0% 100.0% SERV 100.0% 100.0% RBD‐ST 64.7% 23.3% 12.0% 100.0% RBD‐NoDA 73.5% 26.5% 100.0% DSRE 100.0%100.0% DSMEE 100.0%100.0% Last Updated: 3/10/2016 1:16 PM Schedule 6.1 Page 2 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2016 Classification Factors Total Allocated Residential E‐1 Small Non‐residential E‐2 Medium Non‐ residential E‐4 Large Non‐residential E‐7City Accounts E‐18 Street/Traffic Lights CP12 100% 11.8% 9.7% 38.2% 36.3% 3.8% 0.1% NCPP 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% NCPS 100% 15.1% 9.8% 35.2% 34.7% 4.9% 0.3% kWh CUST CUSTW CUSTM CUSTMR 100%DP 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% 100%DC 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% 100%DT 100% 15.1% 9.8% 35.2% 34.7% 4.9% 0.3% DA1 DA2 RBG RBD 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% RBGP 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% RBGP‐P RBGP‐T RBGP‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% RBSE 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% RBOH 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% RBUG 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% RBTR 100% 15.1% 9.8% 35.2% 34.7% 4.9% 0.3% OM 100% 14.0% 9.8% 36.4% 35.1% 4.5% 0.2% OM‐P 100% 11.8% 9.7% 38.2% 36.3% 3.8% 0.1% OM‐T OM‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% OMAG 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% OMAG‐P OMAG‐T OMAG‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% GPLT 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% GPLT‐P GPLT‐T GPLT‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% NETPLT 100.0000% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% NETPLT‐P NETPLT‐T NETPLT‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% OMP 100% 11.8% 9.7% 38.2% 36.3% 3.8% 0.1% CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ DEMAND Schedule 6.2 Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Demand) Page 1 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2016 Classification Factors Total Allocated Residential E‐1 Small Non‐residential E‐2 Medium Non‐ residential E‐4 Large Non‐residential E‐7City Accounts E‐18 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ DEMAND Schedule 6.2 OMWOP 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% OMWOP‐P OMWOP‐T OMWOP‐D 100% 15.1% 9.8% 35.4% 34.4% 5.0% 0.3% WEST 100%11.8% 9.7% 38.2% 36.3% 3.8% 0.1% REN 100%11.8% 9.7% 38.2% 36.3% 3.8% 0.1% CALA 100%11.8% 9.7% 38.2% 36.3% 3.8% 0.1% CREDIT CUST SERV SERV RBD‐ST 100%15.1% 9.8% 35.4% 34.4% 5.0% 0.3% RBD‐NoDA 100%15.1% 9.8% 35.4% 34.4% 5.0% 0.3% DSRE DSMEE Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Demand) Page 2 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2016 Classification Factors Total Allocated Residential E‐1 Small Non‐residential E‐2 Medium Non‐ residential E‐4 Large Non‐residential E‐7City Accounts E‐18 Street/Traffic Lights CP1 NCPP NCPS kWh 100% 15.9% 7.3% 33.3% 40.3% 3.0% 0.2% CUST CUSTW CUSTM CUSTMR 100%DP 100%DC 100%DT DA1 DA2 RBG RBD RBGP RBGP‐P RBGP‐T RBGP‐D RBSE RBOH RBUG RBTR OM 100% 16.0% 7.3% 33.3% 40.2% 3.1% 0.2% OM‐P 100% 16.0% 7.3% 33.3% 40.2% 3.1% 0.2% OM‐T OM‐D OMAG 100% 15.4% 7.5% 32.2% 41.9% 3.1% OMAG‐P 100% 15.4% 7.5% 32.2% 41.9% 3.1% OMAG‐T OMAG‐D GPLT CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ ENERGY Schedule 6.2 Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Energy) Page 1 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2016 Classification Factors Total Allocated Residential E‐1 Small Non‐residential E‐2 Medium Non‐ residential E‐4 Large Non‐residential E‐7City Accounts E‐18 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ ENERGY Schedule 6.2 GPLT‐P GPLT‐T GPLT‐D NETPLT NETPLT‐P NETPLT‐T NETPLT‐D OMP 100% 16.0% 7.3% 33.3% 40.2% 3.1% 0.2% OMWOP 100% 15.4% 7.5% 32.2% 41.9% 3.1% OMWOP‐P 100% 15.4% 7.5% 32.2% 41.9% 3.1% OMWOP‐T OMWOP‐D WEST 100%15.9% 7.3% 33.3% 40.3% 3.0% 0.2% REN 100%15.9% 7.3% 33.3% 40.3% 3.0% 0.2% CALA 100%15.9% 7.3% 33.3% 40.3% 3.0% 0.2% CREDIT CUST SERV SERV RBD‐ST RBD‐NoDA DSRE 100%20.9% 7.3% 31.6% 34.0% 6.2% DSMEE 100%15.4% 7.5% 32.2% 41.9% 3.1% Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Energy) Page 2 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2016 Classification Factors Total Allocated Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights CP1 NCPP NCPS kWh CUST 100% 86.4% 10.5% 2.5% 0.2% 0.4% 0.0% CUSTW 100% 43.5% 15.8% 34.1% 5.4% 1.1% 0.0% CUSTM 100% 84.2% 10.2% 4.1% 1.0% 0.4% CUSTMR 100% 43.5% 15.8% 34.1% 5.4% 1.1% 100%DP 100%DC 100%DT DA1 DA2 RBG RBD 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0% RBGP 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0% RBGP‐P RBGP‐T RBGP‐D RBSE RBOH RBUG RBTR OM 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0% OM‐P OM‐T CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ CUSTOMER Schedule 6.2 Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Customer) Page 1 of 3 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2016 Classification Factors Total Allocated Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ CUSTOMER Schedule 6.2 OM‐D OMAG 100% 35.6% 12.7% 40.0% 8.6% 3.1% 0.0% OMAG‐P OMAG‐T OMAG‐D GPLT 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0% GPLT‐P GPLT‐T GPLT‐D NETPLT 100% 22.4% 3.7% 55.1% 13.6% 5.2% 0.0% NETPLT‐P NETPLT‐T NETPLT‐D OMP OMWOP 100% 35.6% 12.7% 40.0% 8.6% 3.1% 0.0% OMWOP‐P OMWOP‐T OMWOP‐D WEST REN CALA CREDIT 100%35.0% 50.0% 12.0% 1.1% 2.0% 0.0% CUST SERV 100%60.0% 11.2% 24.2% 3.9% 0.7% 0.0% SERV 100%20.2% 2.4% 57.3% 14.4% 5.7% RBD‐ST 100%22.4% 3.7% 55.1% 13.6% 5.2% 0.0% RBD‐NoDA 100%22.4% 3.7% 55.1% 13.6% 5.2% 0.0% DSRE Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Customer) Page 2 of 3 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2016 Classification Factors Total Allocated Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ CUSTOMER Schedule 6.2 DSMEE Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (Customer) Page 3 of 3 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2016 Classification Factors Total Allocated Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ DIRECT ASSIGNMENT Schedule 6.2 CP12 NCPP NCPS kWh CUST CUSTW CUSTM CUSTMR 100%DP 100%DC 100%DT DA1 100.0%100.0% DA2 100.0%40.0% 60.0% RBG RBD 100.0%100.0% RBGP 100.0%100.0% RBGP‐P RBGP‐T RBGP‐D 100.0%100.0% RBSE RBOH RBUG RBTR OM 100.0%100.0% OM‐P OM‐T OM‐D 100.0%100.0% OMAG 100.0% 9.1% 13.6% 77.3% OMAG‐P OMAG‐T Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (DA) Page 1 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2016 Classification Factors Total Allocated Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐18 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER ‐ DIRECT ASSIGNMENT Schedule 6.2 OMAG‐D 100.0% 9.1% 13.6% 77.3% GPLT 100.0%100.0% GPLT‐P GPLT‐T GPLT‐D 100.0%100.0% NETPLT 100.0%100.0% NETPLT‐P NETPLT‐T NETPLT‐D 100.0%100.0% OMP OMWOP 100.0% 9.1% 13.6% 77.3% OMWOP‐P OMWOP‐T OMWOP‐D 100.0% 9.1% 13.6% 77.3% WEST REN CALA CREDIT CUST SERV SERV RBD‐ST 100.0%100.0% RBD‐NoDA DSRE DSMEE Last Updated: 3/10/2016 1:16 PM Schedule 6.2 (DA) Page 2 of 2 Prepared By EES Consulting, Inc. Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Number of Customers Jul‐16 29,547 25,565 3,057 742 60 122 1 Aug‐16 29,529 25,535 3,060 743 67 123 1 Sep‐16 28,949 24,968 3,049 741 68 122 1 Oct‐16 29,679 25,666 3,083 741 67 121 1 Nov‐16 28,235 24,269 3,043 733 67 122 1 Dec‐16 29,346 25,359 3,060 741 67 118 1 Jan‐17 29,667 25,656 3,077 742 67 124 1 Feb‐17 29,562 25,555 3,074 740 67 125 1 Mar‐17 29,628 25,625 3,077 738 63 124 1 Apr‐17 29,575 25,562 3,097 724 67 124 1 May‐17 29,109 25,109 3,088 726 64 121 1 Jun‐17 29,245 25,223 3,110 720 67 124 1 Total / Average 29,339 25,341 3,073 736 66 123 1 Customer Charge Revenues Rate: $/Month Jul‐16 Aug‐16 Sep‐16 Oct‐16 Nov‐16 Dec‐16 Jan‐17 Feb‐17 Mar‐17 Apr‐17 May‐17 Jun‐17 Total Forecast kWh $34,224,095 $152,705,600 $192,576,637 $15,152,723 Jul‐16 81,963,781 11,794,741 6,137,168 28,465,870 33,062,440 2,345,450 158,112 Aug‐16 82,988,623 11,610,462 6,180,235 29,183,253 33,393,107 2,463,453 158,112 Sep‐16 86,437,570 11,622,595 6,368,684 30,123,313 35,387,793 2,777,073 158,112 Oct‐16 80,883,590 12,244,921 5,947,833 27,818,985 33,033,747 1,679,991 158,112 Nov‐16 83,139,914 11,477,370 5,800,156 27,654,416 34,904,226 3,145,634 158,112 Dec‐16 83,571,051 15,245,758 5,692,051 25,691,547 34,342,286 2,441,297 158,112 Jan‐17 81,058,191 17,174,759 5,896,626 25,403,178 30,208,921 2,216,594 158,112 Feb‐17 76,493,499 14,137,692 5,626,886 24,544,236 29,927,066 2,099,507 158,112 Mar‐17 76,431,249 13,215,351 5,440,633 23,829,508 31,789,551 1,998,094 158,112 Apr‐17 78,235,599 12,070,845 5,767,744 25,582,716 31,404,586 3,251,596 158,112 May‐17 77,298,181 11,257,471 5,828,133 26,002,776 31,644,326 2,407,363 158,112 Jun‐17 81,424,554 11,178,348 5,764,361 26,695,073 35,223,773 2,404,886 158,112 Total / Average 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346 Energy Rates Flat Rate: Flat Rate $/kWh Seasonal Rate:Jul $/kWh $0.14045 $0.08171 $0.07808 $0.11479 Aug $/kWh $0.14045 $0.08171 $0.07808 $0.11479 Sep $/kWh $0.14045 $0.08171 $0.07808 $0.11479 Oct $/kWh $0.14045 $0.08171 $0.07808 $0.11479 Nov $/kWh $0.12661 $0.07318 $0.07209 $0.09429 FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Last Updated: 3/10/2016 1:16 PM Schedule 7.1 Page 1 of 3 Prepared By EES Consulting, Inc. Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Dec $/kWh $0.12661 $0.07318 $0.07209 $0.09429 Jan $/kWh $0.12661 $0.07318 $0.07209 $0.09429 Feb $/kWh $0.12661 $0.07318 $0.07209 $0.09429 Mar $/kWh $0.12661 $0.07318 $0.07209 $0.09429 Apr $/kWh $0.12661 $0.07318 $0.07209 $0.09429 May $/kWh $0.14045 $0.08171 $0.07808 $0.11479 Jun $/kWh $0.14045 $0.08171 $0.07808 $0.115 Distribution Charge for $/kWh: Block Rate:1st Block kWh %54% 100% 100% 100% 100% 2nd Block kWh %25% 3rd Block kWh %21% 4th Block kWh % 1st Block $/kWh $0.09524 2nd Block $/kWh $0.13020 3rd Block $/kWh $0.17399 4th Block $/kWh Energy Revenues Jul‐16 $7,457,295 $1,418,634 $861,965 $2,325,946 $2,581,515 $269,234 Aug‐16 $7,539,161 $1,396,470 $868,014 $2,384,564 $2,607,334 $282,780 Sep‐16 $7,835,646 $1,397,929 $894,482 $2,461,376 $2,763,079 $318,780 Oct‐16 $7,353,364 $1,472,780 $835,373 $2,273,089 $2,579,275 $192,846 Nov‐16 $6,951,417 $1,380,462 $734,358 $2,023,750 $2,516,246 $296,602 Dec‐16 $7,140,415 $1,833,712 $720,671 $1,880,107 $2,475,735 $230,190 Jan‐17 $7,058,066 $2,065,726 $746,572 $1,859,005 $2,177,761 $209,003 Feb‐17 $6,564,409 $1,700,437 $712,420 $1,796,147 $2,157,442 $197,963 Mar‐17 $6,502,292 $1,589,501 $688,839 $1,743,843 $2,291,709 $188,400 Apr‐17 $6,624,790 $1,451,843 $730,254 $1,872,143 $2,263,957 $306,593 May‐17 $7,044,391 $1,354,013 $818,561 $2,124,687 $2,470,789 $276,341 Jun‐17 $7,361,684 $1,344,496 $809,605 $2,181,254 $2,750,272 $276,057 Subtotal $85,432,931 $18,406,003 $9,421,113 $24,925,912 $29,635,114 $3,044,789 Surcharge Total $85,432,931 $18,406,003 $9,421,113 $24,925,912 $29,635,114 $3,044,789 Demand kVa or kW Jul‐16 183,197 23,739 14,809 70,573 67,108 6,360 607 Aug‐16 182,882 22,903 16,421 70,808 66,460 5,758 531 Sep‐16 175,133 23,449 16,689 68,874 58,881 6,752 488 Oct‐16 186,783 23,195 19,162 69,274 70,362 4,365 425 Nov‐16 178,554 22,134 19,442 66,391 61,535 8,652 399 Dec‐16 173,216 28,614 14,197 60,673 63,551 5,827 354 Jan‐17 161,171 31,766 12,193 58,366 53,142 5,377 327 Feb‐17 158,353 29,053 15,224 57,248 50,947 5,489 392 Mar‐17 171,252 24,715 14,149 58,641 68,420 4,939 386 Apr‐17 168,043 26,611 16,348 61,809 52,799 10,036 439 May‐17 176,488 23,278 15,667 64,005 67,154 5,912 472 Jun‐17 183,618 24,644 16,679 66,944 67,380 7,422 549 Total / Average Total 2,098,690 304,102 190,983 773,606 747,738 76,890 5,371 Demand Revenues Rate: $/kVa Last Updated: 3/10/2016 1:16 PM Schedule 7.1 Page 2 of 3 Prepared By EES Consulting, Inc. Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Rate: $/kW Jul‐16 $20.54 $18.97 Aug‐16 $20.54 $18.97 Sep‐16 $20.54 $18.97 Oct‐16 $20.54 $18.97 Nov‐16 $13.84 $11.54 Dec‐16 $13.84 $11.54 Jan‐17 $13.84 $11.54 Feb‐17 $13.84 $11.54 Mar‐17 $13.84 $11.54 Apr‐17 $13.84 $11.54 May‐17 $20.54 $18.97 Jun‐17 $20.54 $18.97 Jul‐16 $2,722,615 $1,449,570 $1,273,045 Aug‐16 $2,715,151 $1,454,405 $1,260,746 Sep‐16 $2,531,627 $1,414,663 $1,116,963 Oct‐16 $2,757,661 $1,422,893 $1,334,768 Nov‐16 $1,628,969 $918,858 $710,112 Dec‐16 $1,573,085 $839,710 $733,375 Jan‐17 $1,421,046 $807,791 $613,255 Feb‐17 $1,380,242 $792,312 $587,930 Mar‐17 $1,601,160 $811,592 $789,568 Apr‐17 $1,464,740 $855,434 $609,306 May‐17 $2,588,557 $1,314,653 $1,273,904 Jun‐17 $2,653,220 $1,375,027 $1,278,194 Total $25,038,074 $13,456,909 $11,581,165 Total Revenues Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 $10,179,910 $1,418,634 $861,965 $3,775,517 $3,854,560 $269,234 Aug‐16 $10,254,312 $1,396,470 $868,014 $3,838,969 $3,868,080 $282,780 Sep‐16 $10,367,272 $1,397,929 $894,482 $3,876,039 $3,880,042 $318,780 Oct‐16 $10,111,025 $1,472,780 $835,373 $3,695,982 $3,914,043 $192,846 Nov‐16 $8,580,387 $1,380,462 $734,358 $2,942,608 $3,226,357 $296,602 Dec‐16 $8,713,500 $1,833,712 $720,671 $2,719,818 $3,209,110 $230,190 Jan‐17 $8,479,112 $2,065,726 $746,572 $2,666,796 $2,791,016 $209,003 Feb‐17 $7,944,651 $1,700,437 $712,420 $2,588,459 $2,745,372 $197,963 Mar‐17 $8,103,452 $1,589,501 $688,839 $2,555,435 $3,081,277 $188,400 Apr‐17 $8,089,530 $1,451,843 $730,254 $2,727,577 $2,873,263 $306,593 May‐17 $9,632,949 $1,354,013 $818,561 $3,439,340 $3,744,693 $276,341 Jun‐17 $10,014,905 $1,344,496 $809,605 $3,556,281 $4,028,466 $276,057 Subtotal $110,471,004 $18,406,003 $9,421,113 $38,382,821 $41,216,279 $3,044,789 Surcharge $60,477 $60,477 Total $110,531,481 $18,406,003 $9,421,113 $38,382,821 $41,216,279 $3,044,789 $60,477 Actual Revenue 2015 $110,687,581.09 $18,318,169 $9,422,028 $37,253,029 $42,605,849 $3,028,030 $60,477 difference 0.1% 0.5% 0.0% 2.9%‐3.4% 0.6% Last Updated: 3/10/2016 1:16 PM Schedule 7.1 Page 3 of 3 Prepared By EES Consulting, Inc.City of Palo Alto Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Current kWh Forecast: 2014 952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346 Forecast Year: 2016 953,615,752 152,522,421 70,565,310 321,517,940 377,834,163 29,278,572 1,897,346 Forecast Year: 2017 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346 Forecast Year: 2018 972,609,590 153,080,810 70,473,757 321,100,795 396,816,297 29,240,585 1,897,346 Forecast Year: 2019 973,106,669 152,786,206 70,338,130 320,482,834 398,417,843 29,184,311 1,897,346 Forecast Year: 2020 971,881,787 152,593,513 70,249,420 320,078,644 397,915,361 29,147,504 1,897,346 Current Customer Forecast: 2014 29,339 25,341 3,073 736 66 123 1 Forecast Year: 2016 29,356 25,358 3,073 736 66 123 1 Forecast Year: 2017 29,319 25,321 3,073 736 66 123 1 Forecast Year: 2018 29,339 25,341 3,073 736 66 123 1 Forecast Year: 2019 29,339 25,341 3,073 736 66 123 1 Forecast Year: 2020 29,339 25,341 3,073 736 66 123 1 Forecast Rate Class Customer Count Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 29,547 25,565 3,057 742 60 122 1 Aug‐16 29,529 25,535 3,060 743 67 123 1 Sep‐16 28,949 24,968 3,049 741 68 122 1 Oct‐16 29,679 25,666 3,083 741 67 121 1 Nov‐16 28,235 24,269 3,043 733 67 122 1 Dec‐16 29,346 25,359 3,060 741 67 118 1 Jan‐17 29,667 25,656 3,077 742 67 124 1 Feb‐17 29,562 25,555 3,074 740 67 125 1 Mar‐17 29,628 25,625 3,077 738 63 124 1 Apr‐17 29,575 25,562 3,097 724 67 124 1 May‐17 29,109 25,109 3,088 726 64 121 1 Jun‐17 29,245 25,223 3,110 720 67 124 1 Total Average Forecast Customers 29,339 25,341 3,073 736 66 123 1 Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES Last Updated: 3/10/2016 1:16 PM Schedule 8.1 Page 1 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES Customer Information Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Weighting Factors for: Customers Meters & Services 994.00$994.00$1,672.00$4,698.00$ 994.00$‐$ Customer Billing and Collection 1.00 3.00 27.00 48.00 5.00 1.00 Customer Meter Reading 1.00 3.00 27.00 48.00 5.00 Weighted Number of Customers Customers Meters & Services 29,905,327 25,188,954 3,054,479 1,230,453 309,677 121,765 ‐ Customer Billing and Collection 58,207 25,341 9,219 19,870 3,164 613 1 Customer Meter Reading 58,206 25,341 9,219 19,870 3,164 613 ‐ Provided Services Power Purchased from Utility*111 1 1 1 Reg & Shaping from Utility*111 1 1 1 Uses Utility Transmission*111 1 1 1 Uses Primary Distribution*111 1 1 1 Uses Secondary Distribution*111 1 1 1 Test Date Forecast Rate Class Sales kWh Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 77,965,899 11,789,582 5,880,488 26,024,709 31,803,107 2,309,901 158,112 Aug‐14 82,987,201 11,330,498 5,895,458 27,361,945 35,773,165 2,468,023 158,112 Sep‐14 87,503,059 11,560,737 6,386,405 29,269,602 37,406,835 2,721,368 158,112 Oct‐14 78,632,817 12,077,193 5,493,428 25,803,870 32,767,071 2,333,143 158,112 Nov‐14 79,700,792 11,607,795 5,456,028 24,942,299 34,971,656 2,564,902 158,112 Dec‐14 80,199,169 15,092,762 5,446,408 24,598,609 32,572,571 2,330,707 158,112 Jan‐15 80,513,170 17,342,158 5,951,986 24,061,704 30,479,098 2,520,112 158,112 Feb‐15 81,389,444 14,606,393 5,799,412 24,244,688 34,041,901 2,538,938 158,112 Mar‐15 71,512,256 12,097,303 5,333,019 22,956,678 28,761,884 2,205,260 158,112 Apr‐15 77,355,465 11,477,709 5,894,120 23,923,508 33,608,313 2,293,703 158,112 May‐15 76,149,464 11,077,484 6,431,015 25,223,376 30,780,866 2,478,611 158,112 Jun‐15 78,772,748 10,806,575 6,516,748 25,521,556 33,382,123 2,387,634 158,112 Total Sales 952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346 Forecast Rate Class Sales kWh Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 81,963,781 11,794,741 6,137,168 28,465,870 33,062,440 2,345,450 158,112 Aug‐16 82,988,623 11,610,462 6,180,235 29,183,253 33,393,107 2,463,453 158,112 Sep‐16 86,437,570 11,622,595 6,368,684 30,123,313 35,387,793 2,777,073 158,112 Oct‐16 80,883,590 12,244,921 5,947,833 27,818,985 33,033,747 1,679,991 158,112 Nov‐16 83,139,914 11,477,370 5,800,156 27,654,416 34,904,226 3,145,634 158,112 Dec‐16 83,571,051 15,245,758 5,692,051 25,691,547 34,342,286 2,441,297 158,112 Jan‐17 81,058,191 17,174,759 5,896,626 25,403,178 30,208,921 2,216,594 158,112 Feb‐17 76,493,499 14,137,692 5,626,886 24,544,236 29,927,066 2,099,507 158,112 Mar‐17 76,431,249 13,215,351 5,440,633 23,829,508 31,789,551 1,998,094 158,112 Apr‐17 78,235,599 12,070,845 5,767,744 25,582,716 31,404,586 3,251,596 158,112 May‐17 77,298,181 11,257,471 5,828,133 26,002,776 31,644,326 2,407,363 158,112 Jun‐17 81,424,554 11,178,348 5,764,361 26,695,073 35,223,773 2,404,886 158,112 Total Sales 969,925,801 153,030,312 70,450,509 320,994,871 394,321,824 29,230,939 1,897,346 Last Updated: 3/10/2016 1:16 PM Schedule 8.1 Page 2 of 2 Prepared By EES Consulting, Inc.City of Palo Alto Billing Demand ‐ kVa Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 137,681 70,573 67,108 Aug‐16 137,268 70,808 66,460 Sep‐16 127,754 68,874 58,881 Oct‐16 139,636 69,274 70,362 Nov‐16 127,926 66,391 61,535 Dec‐16 124,223 60,673 63,551 Jan‐17 111,508 58,366 53,142 Feb‐17 108,195 57,248 50,947 Mar‐17 127,061 58,641 68,420 Apr‐17 114,608 61,809 52,799 May‐17 131,158 64,005 67,154 Jun‐17 134,324 66,944 67,380 Total 1,521,344 773,606 747,738 Individual Load Factor Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 67% 56% 50% 64% 50% 35% Aug‐16 68% 51% 58% 80% 58% 40% Sep‐16 69% 53% 57% 85% 57% 45% Oct‐16 71% 42% 52% 65% 52% 50% Nov‐16 72% 41% 50% 76% 50% 55% Dec‐16 72% 54% 56% 71% 56% 60% Jan‐17 73% 65% 55% 77% 55% 65% Feb‐17 72% 55% 57% 90% 57% 60% Mar‐17 72% 52% 54% 58% 54% 55% Apr‐17 63% 49% 52% 86% 45% 50% May‐17 65% 50% 55% 64% 55% 45% Jun‐17 63% 48% 51% 67% 45% 40% Individual NCP (kW) Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 183,197 23,739 14,809 70,573 67,108 6,360 607 Aug‐16 182,882 22,903 16,421 70,808 66,460 5,758 531 Sep‐16 175,133 23,449 16,689 68,874 58,881 6,752 488 Oct‐16 186,783 23,195 19,162 69,274 70,362 4,365 425 Nov‐16 178,554 22,134 19,442 66,391 61,535 8,652 399 Dec‐16 173,216 28,614 14,197 60,673 63,551 5,827 354 Jan‐17 161,171 31,766 12,193 58,366 53,142 5,377 327 Feb‐17 158,353 29,053 15,224 57,248 50,947 5,489 392 Mar‐17 171,252 24,715 14,149 58,641 68,420 4,939 386 Apr‐17 168,043 26,611 16,348 61,809 52,799 10,036 439 May‐17 176,488 23,278 15,667 64,005 67,154 5,912 472 Jun‐17 183,618 24,644 16,679 66,944 67,380 7,422 549 Maximum 186,783 31,766 19,442 70,808 70,362 10,036 607 5,371 FORECAST CUSTOMER DEMAND Schedule 8.2 Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 1 of 5 Prepared By EES Consulting, Inc.City of Palo Alto FORECAST CUSTOMER DEMAND Schedule 8.2 Group Coincidence Factor Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 95% 95% 85% 91% 90% 100% Aug‐16 85% 85% 90% 92% 80% 100% Sep‐16 95% 95% 89% 90% 90% 100% Oct‐16 95% 95% 87% 86% 90% 100% Nov‐16 95% 95% 88% 85% 90% 100% Dec‐16 95% 95% 83% 84% 90% 100% Jan‐17 85% 85% 83% 89% 80% 100% Feb‐17 95% 95% 82% 85% 90% 100% Mar‐17 85% 85% 87% 80% 80% 100% Apr‐17 95% 95% 86% 82% 95% 100% May‐17 95% 95% 85% 84% 90% 100% Jun‐17 95% 95% 86% 84% 95% 100% Rate Class NCP @ Meter (kW) Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 164,373 22,552 14,069 60,018 61,403 5,724 607 Aug‐16 163,574 19,468 13,958 63,599 61,411 4,606 531 Sep‐16 158,817 22,276 15,855 61,012 53,109 6,077 488 Oct‐16 165,377 22,035 18,204 60,186 60,599 3,928 425 Nov‐16 158,676 21,028 18,470 58,652 52,341 7,787 399 Dec‐16 149,774 27,183 13,487 50,353 53,152 5,245 354 Jan‐17 137,978 27,001 10,364 48,640 47,344 4,301 327 Feb‐17 137,967 27,600 14,463 47,228 43,344 4,940 392 Mar‐17 143,230 21,008 12,027 50,965 54,892 3,951 386 Apr‐17 147,176 25,281 15,531 53,007 43,384 9,534 439 May‐17 153,295 22,115 14,884 54,247 56,257 5,320 472 Jun‐17 160,837 23,411 15,845 57,599 56,381 7,051 549 Maximum 165,377 27,600 18,470 63,599 61,411 9,534 607 Rate Class NCP @ Meter (kW) ‐ Winter Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 164,373 22,552 14,069 60,018 61,403 5,724 607 Aug‐16 163,574 19,468 13,958 63,599 61,411 4,606 531 Sep‐16 158,817 22,276 15,855 61,012 53,109 6,077 488 Oct‐16 Nov‐16 Dec‐16 Jan‐17 Feb‐17 Mar‐17 Apr‐17 147,176 25,281 15,531 53,007 43,384 9,534 439 May‐17 153,295 22,115 14,884 54,247 56,257 5,320 472 Jun‐17 160,837 23,411 15,845 57,599 56,381 7,051 549 Maximum 164,373 25,281 15,855 63,599 61,411 9,534 607 Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 2 of 5 Prepared By EES Consulting, Inc.City of Palo Alto FORECAST CUSTOMER DEMAND Schedule 8.2 Rate Class NCP @ Meter (kW) ‐ Summer Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 Aug‐16 Sep‐16 Oct‐16 165,377 22,035 18,204 60,186 60,599 3,928 425 Nov‐16 158,676 21,028 18,470 58,652 52,341 7,787 399 Dec‐16 149,774 27,183 13,487 50,353 53,152 5,245 354 Jan‐17 137,978 27,001 10,364 48,640 47,344 4,301 327 Feb‐17 137,967 27,600 14,463 47,228 43,344 4,940 392 Mar‐17 143,230 21,008 12,027 50,965 54,892 3,951 386 Apr‐17 May‐17 Jun‐17 Maximum 165,377 27,600 18,470 60,186 60,599 7,787 425 Rate Class NCP @ Primary Voltage (kW) Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Line Losses:2.50% 2.50% 2.50% 0.95% 2.50% 2.50% Jul‐16 167,602 23,130 14,429 61,557 61,992 5,871 623 Aug‐16 166,782 19,967 14,316 65,230 62,000 4,725 545 Sep‐16 162,037 22,847 16,261 62,576 53,619 6,233 501 Oct‐16 168,645 22,600 18,671 61,729 61,180 4,029 436 Nov‐16 161,905 21,567 18,944 60,155 52,843 7,987 410 Dec‐16 152,761 27,880 13,833 51,644 53,662 5,379 363 Jan‐17 140,756 27,694 10,630 49,887 47,798 4,412 335 Feb‐17 140,809 28,308 14,834 48,439 43,760 5,066 402 Mar‐17 146,021 21,547 12,335 52,272 55,418 4,053 396 Apr‐17 150,253 25,929 15,929 54,366 43,800 9,778 450 May‐17 156,323 22,682 15,265 55,638 56,797 5,457 484 Jun‐17 164,056 24,012 16,252 59,076 56,922 7,232 563 Maximum 168,645 28,308 18,944 65,230 62,000 9,778 623 NCP @ Primary Voltage (kW) ‐ Winter Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 167,602 23,130 14,429 61,557 61,992 5,871 623 Aug‐16 166,782 19,967 14,316 65,230 62,000 4,725 545 Sep‐16 162,037 22,847 16,261 62,576 53,619 6,233 501 Oct‐16 Nov‐16 Dec‐16 Jan‐17 Feb‐17 Mar‐17 Apr‐17 150,253 25,929 15,929 54,366 43,800 9,778 450 May‐17 156,323 22,682 15,265 55,638 56,797 5,457 484 Jun‐17 164,056 24,012 16,252 59,076 56,922 7,232 563 Maximum 167,602 25,929 16,261 65,230 62,000 9,778 623 Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 3 of 5 Prepared By EES Consulting, Inc.City of Palo Alto FORECAST CUSTOMER DEMAND Schedule 8.2 NCP @ Primary Voltage (kW) ‐ Summer Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 Aug‐16 Sep‐16 Oct‐16 168,645 22,600 18,671 61,729 61,180 4,029 436 Nov‐16 161,905 21,567 18,944 60,155 52,843 7,987 410 Dec‐16 152,761 27,880 13,833 51,644 53,662 5,379 363 Jan‐17 140,756 27,694 10,630 49,887 47,798 4,412 335 Feb‐17 140,809 28,308 14,834 48,439 43,760 5,066 402 Mar‐17 146,021 21,547 12,335 52,272 55,418 4,053 396 Apr‐17 May‐17 Jun‐17 Maximum 168,645 28,308 18,944 61,729 61,180 7,987 436 Rate Class NCP @ Input Voltage (kW) Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Line Losses:0.80% 0.80% 0.80% 0.80% 0.80% 0.80% Jul‐16 168,954 23,317 14,546 62,054 62,492 5,918 628 Aug‐16 168,127 20,128 14,431 65,756 62,500 4,763 549 Sep‐16 163,344 23,032 16,393 63,081 54,051 6,283 505 Oct‐16 170,005 22,783 18,821 62,227 61,674 4,061 439 Nov‐16 163,210 21,741 19,097 60,641 53,269 8,051 413 Dec‐16 153,993 28,105 13,944 52,061 54,094 5,422 366 Jan‐17 141,891 27,917 10,716 50,289 48,184 4,447 338 Feb‐17 141,944 28,536 14,954 48,829 44,112 5,107 405 Mar‐17 147,199 21,720 12,435 52,693 55,865 4,085 399 Apr‐17 151,465 26,138 16,058 54,804 44,154 9,857 454 May‐17 157,584 22,865 15,388 56,087 57,255 5,501 488 Jun‐17 165,380 24,205 16,383 59,552 57,381 7,290 568 Maximum 170,005 28,536 19,097 65,756 62,500 9,857 628 NCP @ Input Voltage (kW) ‐ Winter Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 168,954 23,317 14,546 62,054 62,492 5,918 628 Aug‐16 168,127 20,128 14,431 65,756 62,500 4,763 549 Sep‐16 163,344 23,032 16,393 63,081 54,051 6,283 505 Oct‐16 Nov‐16 Dec‐16 Jan‐17 Feb‐17 Mar‐17 Apr‐17 151,465 26,138 16,058 54,804 44,154 9,857 454 May‐17 157,584 22,865 15,388 56,087 57,255 5,501 488 Jun‐17 165,380 24,205 16,383 59,552 57,381 7,290 568 Maximum 168,954 26,138 16,393 65,756 62,500 9,857 628 Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 4 of 5 Prepared By EES Consulting, Inc.City of Palo Alto FORECAST CUSTOMER DEMAND Schedule 8.2 NCP @ Input Voltage (kW) ‐ Summer Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 Aug‐16 Sep‐16 Oct‐16 170,005 22,783 18,821 62,227 61,674 4,061 439 Nov‐16 163,210 21,741 19,097 60,641 53,269 8,051 413 Dec‐16 153,993 28,105 13,944 52,061 54,094 5,422 366 Jan‐17 141,891 27,917 10,716 50,289 48,184 4,447 338 Feb‐17 141,944 28,536 14,954 48,829 44,112 5,107 405 Mar‐17 147,199 21,720 12,435 52,693 55,865 4,085 399 Apr‐17 May‐17 Jun‐17 Maximum 170,005 28,536 19,097 62,227 61,674 8,051 439 System Coincidence Factor Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 58% 90% 100% 100% 97% Aug‐16 59% 90% 97% 97% 97% Sep‐16 50% 97% 98% 98% 97% Oct‐16 93% 100% 100% 100% 98% 100% Nov‐16 50% 90% 100% 100% 90% 100% Dec‐16 58% 90% 100% 100% 90% 100% Jan‐17 90% 100% 100% 100% 96% 100% Feb‐17 83% 98% 100% 100% 95% 100% Mar‐17 60% 90% 100% 100% 97% 100% Apr‐17 93% 100% 100% 100% 100% May‐17 76% 100% 100% 100% 97% Jun‐17 98% 100% 100% 100% 100% Coincident Peak (CP) @ Input (kW) Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 156,901 13,524 13,091 62,054 62,492 5,741 Aug‐16 153,892 11,875 12,988 63,783 60,625 4,620 Sep‐16 148,481 11,516 15,901 61,945 53,024 6,095 Oct‐16 168,329 21,188 18,821 62,227 61,674 3,980 439 Nov‐16 149,625 10,870 17,187 60,641 53,269 7,246 413 Dec‐16 140,252 16,301 12,550 52,061 54,094 4,880 366 Jan‐17 138,921 25,125 10,716 50,289 48,184 4,269 338 Feb‐17 136,396 23,543 14,654 48,829 44,112 4,852 405 Mar‐17 137,145 13,032 11,191 52,693 55,865 3,963 399 Apr‐17 149,181 24,308 16,058 54,804 44,154 9,857 May‐17 151,443 17,377 15,388 56,087 57,255 5,336 Jun‐17 164,328 23,721 16,383 59,552 57,381 7,290 Total CP Demand ‐ Bottom Up 1,794,894 212,381 174,929 684,965 652,128 68,130 2,361 Peak Month 168,329 21,188 18,821 62,227 61,674 3,980 439 Last Updated: 3/10/2016 1:16 PM Schedule 8.2 Page 5 of 5 Prepared By EES Consulting, Inc.City of Palo Alto kWh @ Input Voltage Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 84,221,494 12,197,250 6,346,606 29,437,301 33,651,339 2,425,491 163,508 Aug‐16 85,275,915 12,006,683 6,391,143 30,179,165 33,987,895 2,547,522 163,508 Sep‐16 88,810,020 12,019,229 6,586,023 31,151,306 36,018,110 2,871,844 163,508 Oct‐16 83,104,909 12,662,793 6,150,810 28,768,341 33,622,134 1,737,323 163,508 Nov‐16 85,407,717 11,869,049 5,998,093 28,598,155 35,525,930 3,252,982 163,508 Dec‐16 85,862,734 15,766,037 5,886,299 26,568,301 34,953,981 2,524,609 163,508 Jan‐17 83,331,554 17,760,868 6,097,855 26,270,091 30,746,994 2,292,238 163,508 Feb‐17 78,615,685 14,620,157 5,818,910 25,381,836 30,460,118 2,171,155 163,508 Mar‐17 78,520,925 13,666,341 5,626,301 24,642,717 32,355,777 2,066,281 163,508 Apr‐17 80,393,131 12,482,777 5,964,575 26,455,756 31,963,956 3,362,561 163,508 May‐17 79,419,811 11,641,645 6,027,025 26,890,151 32,207,966 2,489,517 163,508 Jun‐17 83,628,605 11,559,822 5,961,077 27,606,074 35,851,168 2,486,956 163,508 Total Purchases ‐ bottom up 996,592,500 158,252,650 72,854,715 331,949,194 401,345,367 30,228,479 1,962,095 growth in Purchases against Recorded (bottom‐up) 1% 0% 6%‐1% 0% On‐Peak Energy Use by Percentage Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 66%66% 66% 66% 66% 66% 66% Aug‐16 66%66% 66% 66% 66% 66% 66% Sep‐16 66%66% 66% 66% 66% 66% 66% Oct‐16 66%66% 66% 66% 66% 66% 66% Nov‐16 66%66% 66% 66% 66% 66% 66% Dec‐16 66%66% 66% 66% 66% 66% 66% Jan‐17 66%66% 66% 66% 66% 66% 66% Feb‐17 66%66% 66% 66% 66% 66% 66% Mar‐17 66%66% 66% 66% 66% 66% 66% Apr‐17 66%66% 66% 66% 66% 66% 66% May‐17 66%66% 66% 66% 66% 66% 66% Jun‐17 66%66% 66% 66% 66% 66% 66% Total 66% 66% 66% 66% 66% 66% 66% On‐Peak kWh @ Input Voltage Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 55,586,186 8,050,185 4,188,760 19,428,619 22,209,884 1,600,824 107,915 Aug‐16 56,282,104 7,924,411 4,218,154 19,918,249 22,432,011 1,681,364 107,915 Sep‐16 58,614,613 7,932,691 4,346,775 20,559,862 23,771,953 1,895,417 107,915 Oct‐16 54,849,240 8,357,443 4,059,535 18,987,105 22,190,609 1,146,633 107,915 Nov‐16 56,369,093 7,833,572 3,958,741 18,874,782 23,447,114 2,146,968 107,915 Dec‐16 56,669,405 10,405,585 3,884,957 17,535,079 23,069,627 1,666,242 107,915 Jan‐17 54,998,825 11,722,173 4,024,584 17,338,260 20,293,016 1,512,877 107,915 Feb‐17 51,886,352 9,649,304 3,840,480 16,752,012 20,103,678 1,432,963 107,915 Mar‐17 51,823,811 9,019,785 3,713,359 16,264,193 21,354,813 1,363,746 107,915 Apr‐17 53,059,467 8,238,633 3,936,619 17,460,799 21,096,211 2,219,290 107,915 May‐17 52,417,075 7,683,486 3,977,836 17,747,499 21,257,257 1,643,081 107,915 Jun‐17 55,194,879 7,629,482 3,934,311 18,220,009 23,661,771 1,641,391 107,915 Total 657,751,050 104,446,749 48,084,112 219,086,468 264,887,943 19,950,796 1,294,983 FORECAST kWh AT INPUT Schedule 8.3 Last Updated: 3/10/2016 1:16 PM Schedule 8.3 Page 1 of 3 Prepared By EES Consulting, Inc.City of Palo Alto FORECAST kWh AT INPUT Schedule 8.3 Off‐Peak Energy Use by Percentage Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 34% 34% 34% 34% 34% 34% 34% Aug‐16 34% 34% 34% 34% 34% 34% 34% Sep‐16 34% 34% 34% 34% 34% 34% 34% Oct‐16 34% 34% 34% 34% 34% 34% 34% Nov‐16 34% 34% 34% 34% 34% 34% 34% Dec‐16 34% 34% 34% 34% 34% 34% 34% Jan‐17 34% 34% 34% 34% 34% 34% 34% Feb‐17 34% 34% 34% 34% 34% 34% 34% Mar‐17 34% 34% 34% 34% 34% 34% 34% Apr‐17 34% 34% 34% 34% 34% 34% 34% May‐17 34% 34% 34% 34% 34% 34% 34% Jun‐17 34% 34% 34% 34% 34% 34% 34% Total 34% 34% 34% 34% 34% 34% 34% Off‐Peak kWh @ Input Voltage Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 28,635,308 4,147,065 2,157,846 10,008,682 11,441,455 824,667 55,593 Aug‐16 28,993,811 4,082,272 2,172,989 10,260,916 11,555,884 866,157 55,593 Sep‐16 30,195,407 4,086,538 2,239,248 10,591,444 12,246,157 976,427 55,593 Oct‐16 28,255,669 4,305,350 2,091,275 9,781,236 11,431,526 590,690 55,593 Nov‐16 29,038,624 4,035,477 2,039,352 9,723,373 12,078,816 1,106,014 55,593 Dec‐16 29,193,330 5,360,453 2,001,342 9,033,222 11,884,353 858,367 55,593 Jan‐17 28,332,728 6,038,695 2,073,271 8,931,831 10,453,978 779,361 55,593 Feb‐17 26,729,333 4,970,853 1,978,429 8,629,824 10,356,440 738,193 55,593 Mar‐17 26,697,115 4,646,556 1,912,942 8,378,524 11,000,964 702,536 55,593 Apr‐17 27,333,665 4,244,144 2,027,955 8,994,957 10,867,745 1,143,271 55,593 May‐17 27,002,736 3,958,159 2,049,188 9,142,651 10,950,708 846,436 55,593 Jun‐17 28,433,726 3,930,339 2,026,766 9,386,065 12,189,397 845,565 55,593 Total Off‐Peak Energy 338,841,450 53,805,901 24,770,603 112,862,726 136,457,425 10,277,683 667,112 Summary of Future Test Period Seasonal Load Data Power Supply ‐ System kWh @ Input Voltage‐ Winter Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 84,221,494 12,197,250 6,346,606 29,437,301 33,651,339 2,425,491 163,508 Aug‐16 85,275,915 12,006,683 6,391,143 30,179,165 33,987,895 2,547,522 163,508 Sep‐16 88,810,020 12,019,229 6,586,023 31,151,306 36,018,110 2,871,844 163,508 Oct‐16 Nov‐16 Dec‐16 Jan‐17 Feb‐17 Mar‐17 Apr‐17 80,393,131 12,482,777 5,964,575 26,455,756 31,963,956 3,362,561 163,508 May‐17 79,419,811 11,641,645 6,027,025 26,890,151 32,207,966 2,489,517 163,508 Jun‐17 83,628,605 11,559,822 5,961,077 27,606,074 35,851,168 2,486,956 163,508 Total Winter 501,748,976 71,907,405 37,276,447 171,719,752 203,680,433 16,183,890 981,048 Last Updated: 3/10/2016 1:16 PM Schedule 8.3 Page 2 of 3 Prepared By EES Consulting, Inc.City of Palo Alto FORECAST kWh AT INPUT Schedule 8.3 ‐System kWh @ Input Voltage‐ Summer Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 Aug‐16 Sep‐16 Oct‐16 83,104,909 12,662,793 6,150,810 28,768,341 33,622,134 1,737,323 163,508 Nov‐16 85,407,717 11,869,049 5,998,093 28,598,155 35,525,930 3,252,982 163,508 Dec‐16 85,862,734 15,766,037 5,886,299 26,568,301 34,953,981 2,524,609 163,508 Jan‐17 83,331,554 17,760,868 6,097,855 26,270,091 30,746,994 2,292,238 163,508 Feb‐17 78,615,685 14,620,157 5,818,910 25,381,836 30,460,118 2,171,155 163,508 Mar‐17 78,520,925 13,666,341 5,626,301 24,642,717 32,355,777 2,066,281 163,508 Apr‐17 May‐17 Jun‐17 Total Summer 494,843,524 86,345,245 35,578,267 160,229,442 197,664,934 14,044,589 981,048 CP @ Input Voltage‐ Winter Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 156,901 13,524 13,091 62,054 62,492 5,741 Aug‐16 153,892 11,875 12,988 63,783 60,625 4,620 Sep‐16 148,481 11,516 15,901 61,945 53,024 6,095 Oct‐16 Nov‐16 Dec‐16 Jan‐17 Feb‐17 Mar‐17 Apr‐17 149,181 24,308 16,058 54,804 44,154 9,857 May‐17 151,443 17,377 15,388 56,087 57,255 5,336 Jun‐17 164,328 23,721 16,383 59,552 57,381 7,290 Total Winter 924,225 102,322 89,809 358,225 334,930 38,939 CP @ Input Voltage‐ Summer Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐16 Aug‐16 Sep‐16 Oct‐16 168,329 21,188 18,821 62,227 61,674 3,980 439 Nov‐16 149,625 10,870 17,187 60,641 53,269 7,246 413 Dec‐16 140,252 16,301 12,550 52,061 54,094 4,880 366 Jan‐17 138,921 25,125 10,716 50,289 48,184 4,269 338 Feb‐17 136,396 23,543 14,654 48,829 44,112 4,852 405 Mar‐17 137,145 13,032 11,191 52,693 55,865 3,963 399 Apr‐17 May‐17 Jun‐17 Total Summer 870,669 110,059 85,120 326,740 317,198 29,190 2,361 Last Updated: 3/10/2016 1:16 PM Schedule 8.3 Page 3 of 3 Prepared By EES Consulting, Inc.City of Palo Alto Number of Customers / Services Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 29,547 25,565 3,057 742 60 122 1 Aug‐14 29,529 25,535 3,060 743 67 123 1 Sep‐14 28,949 24,968 3,049 741 68 122 1 Oct‐14 29,679 25,666 3,083 741 67 121 1 Nov‐14 28,235 24,269 3,043 733 67 122 1 Dec‐14 29,346 25,359 3,060 741 67 118 1 Jan‐15 29,667 25,656 3,077 742 67 124 1 Feb‐15 29,562 25,555 3,074 740 67 125 1 Mar‐15 29,628 25,625 3,077 738 63 124 1 Apr‐15 29,575 25,562 3,097 724 67 124 1 May‐15 29,109 25,109 3,088 726 64 121 1 Jun‐15 29,245 25,223 3,110 720 67 124 1 Total Average 29,339 25,341 3,073 736 66 123 1 Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Input Recorded Data Energy Sales (kWh) 952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346 Total Billing Capacity (kVa) 1,521,344 773,606 747,738 Avg. Monthly Billing Capacity (kVa) 126,779 64,467 62,312 Number of Customers 29,339 25,341 3,073 736 66 123 1 Ratio of NCP to Avg. Billing Capacity 11 Rate Classes NCP Demand at Meter 177,573 27,808 17,374 63,599 61,411 6,775 607 Estimated Based on Recorded Data Annual NCP Load Factor 61% 62% 46% 55% 74% 49% 36% Rate Classes CP Demand at Input Voltage 169,623 21,594 17,963 62,227 61,674 5,712 454 Annual CP Load Factor 64% 80% 45% 56% 73% 58% 48% Average On‐Peak kWh as a % of Total kWh 66% 66% 66% 66% 66% 66% Average Off‐Peak kWh as a % of Total kWh 34% 34% 34% 34% 34% 34% kWh Sales at the Meter Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 77,965,899 11,789,582 5,880,488 26,024,709 31,803,107 2,309,901 158,112 Aug‐14 82,987,201 11,330,498 5,895,458 27,361,945 35,773,165 2,468,023 158,112 Sep‐14 87,503,059 11,560,737 6,386,405 29,269,602 37,406,835 2,721,368 158,112 Oct‐14 78,632,817 12,077,193 5,493,428 25,803,870 32,767,071 2,333,143 158,112 Nov‐14 79,700,792 11,607,795 5,456,028 24,942,299 34,971,656 2,564,902 158,112 Dec‐14 80,199,169 15,092,762 5,446,408 24,598,609 32,572,571 2,330,707 158,112 Jan‐15 80,513,170 17,342,158 5,951,986 24,061,704 30,479,098 2,520,112 158,112 Feb‐15 81,389,444 14,606,393 5,799,412 24,244,688 34,041,901 2,538,938 158,112 Mar‐15 71,512,256 12,097,303 5,333,019 22,956,678 28,761,884 2,205,260 158,112 Apr‐15 77,355,465 11,477,709 5,894,120 23,923,508 33,608,313 2,293,703 158,112 May‐15 76,149,464 11,077,484 6,431,015 25,223,376 30,780,866 2,478,611 158,112 Jun‐15 78,772,748 10,806,575 6,516,748 25,521,556 33,382,123 2,387,634 158,112 Total Sales 952,681,486 150,866,189 70,484,515 303,932,544 396,348,590 29,152,302 1,897,346 Load Data And Customer Sales ‐‐ Recorded Year ‐‐ Historic Energy, Demand And Customer Count RECORDED CUSTOMERS AND ENERGY SALES Schedule 8.4 Historic Year By Rate Class Last Updated: 3/10/2016 1:16 PM Schedule 8.4 Page 1 of 1 Prepared By EES Consulting, Inc.City of Palo Alto Metered Demand ‐ kVA Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 137,681 70,573 67,108 Aug‐14 137,268 70,808 66,460 Sep‐14 127,754 68,874 58,881 Oct‐14 139,636 69,274 70,362 Nov‐14 127,926 66,391 61,535 Dec‐14 124,223 60,673 63,551 Jan‐15 111,508 58,366 53,142 Feb‐15 108,195 57,248 50,947 Mar‐15 127,061 58,641 68,420 Apr‐15 114,608 61,809 52,799 May‐15 131,158 64,005 67,154 Jun‐15 134,324 66,944 67,380 Total 1,521,344 773,606 747,738 Individual Load Factor Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 66.78% 55.70% 49.56% 63.70% 49.56% 35.00% Aug‐14 68.14% 50.59% 57.50% 80.10% 57.50% 40.00% Sep‐14 68.84% 53.00% 57.12% 85.39% 57.12% 45.00% Oct‐14 70.96% 41.72% 51.73% 64.68% 51.73% 50.00% Nov‐14 72.02% 41.43% 50.50% 76.39% 50.50% 55.00% Dec‐14 71.61% 53.89% 56.31% 71.19% 56.31% 60.00% Jan‐15 72.67% 65.00% 55.41% 77.09% 55.41% 65.00% Feb‐15 72.41% 55.00% 56.92% 89.81% 56.92% 60.00% Mar‐15 71.87% 51.68% 54.37% 58.38% 54.37% 55.00% Apr‐15 63.00% 49.00% 52.02% 85.55% 45.00% 50.00% May‐15 65.00% 50.00% 54.73% 63.66% 54.73% 45.00% Jun‐15 63.00% 48.00% 51.24% 66.59% 45.00% 40.00% Individual NCP (kW) Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Power Factor:100% 100% Jul‐14 182,471 23,729 14,190 70,573 67,108 6,264 607 Aug‐14 186,332 24,746 17,343 70,808 66,460 6,387 588 Sep‐14 173,397 22,571 16,196 68,874 58,881 6,404 472 Oct‐14 188,267 23,640 18,288 69,274 70,362 6,264 439 Nov‐14 174,503 21,664 17,699 66,391 61,535 6,827 386 Dec‐14 173,646 29,271 14,037 60,673 63,551 5,749 366 Jan‐15 162,332 32,076 12,308 58,366 53,142 6,113 327 Feb‐15 155,828 27,111 14,173 57,248 50,947 5,995 354 Mar‐15 170,804 23,378 14,332 58,641 68,420 5,633 399 Apr‐15 162,539 24,487 16,168 61,809 52,799 6,851 425 May‐15 179,469 23,670 17,864 64,005 67,154 6,289 488 Jun‐15 183,290 23,056 18,248 66,944 67,380 7,132 531 Maximum 188,267 32,076 18,288 70,808 70,362 7,132 607 RECORDED CUSTOMER DEMAND Schedule 8.5 Last Updated: 3/10/2016 1:16 PM Schedule 8.5 Page 1 of 3 Prepared By EES Consulting, Inc.City of Palo Alto RECORDED CUSTOMER DEMAND Schedule 8.5 Group Coincidence Factor Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 95.00% 95.00% 85.04% 91.50% 90.00% 100.00% Aug‐14 85.00% 85.00% 89.82% 92.40% 80.00% 100.00% Sep‐14 95.00% 95.00% 88.58% 90.20% 90.00% 100.00% Oct‐14 95.00% 95.00% 86.88% 86.12% 90.00% 100.00% Nov‐14 95.00% 95.00% 88.34% 85.06% 90.00% 100.00% Dec‐14 95.00% 95.00% 82.99% 83.64% 90.00% 100.00% Jan‐15 85.00% 85.00% 83.33% 89.09% 80.00% 100.00% Feb‐15 95.00% 95.00% 82.50% 85.08% 90.00% 100.00% Mar‐15 85.00% 85.00% 86.91% 80.23% 80.00% 100.00% Apr‐15 95.00% 95.00% 85.76% 82.17% 95.00% 100.00% May‐15 95.00% 95.00% 84.76% 83.77% 90.00% 100.00% Jun‐15 95.00% 95.00% 86.04% 83.68% 95.00% 100.00% Rate Class NCP @ Meter (kW)Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 163,688 22,542 13,480 60,018 61,403 5,638 607 Aug‐14 166,483 21,034 14,742 63,599 61,411 5,109 588 Sep‐14 157,185 21,443 15,386 61,012 53,109 5,763 472 Oct‐14 166,693 22,458 17,374 60,186 60,599 5,637 439 Nov‐14 154,918 20,581 16,814 58,652 52,341 6,145 386 Dec‐14 150,187 27,808 13,335 50,353 53,152 5,174 366 Jan‐15 138,927 27,264 10,462 48,640 47,344 4,890 327 Feb‐15 135,541 25,756 13,464 47,228 43,344 5,396 354 Mar‐15 142,816 19,872 12,182 50,965 54,892 4,507 399 Apr‐15 141,947 23,263 15,359 53,007 43,384 6,508 425 May‐15 156,110 22,486 16,971 54,247 56,257 5,661 488 Jun‐15 160,525 21,903 17,336 57,599 56,381 6,775 531 Maximum 166,693 27,808 17,374 63,599 61,411 6,775 607 Rate Class NCP @ Primary Voltage (kW)Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Line Losses:2.50% 2.50% 2.50% 0.95% 2.50% 2.50% Jul‐14 166,900 23,120 13,826 61,557 61,992 5,782 623 Aug‐14 169,766 21,573 15,119 65,230 62,000 5,240 603 Sep‐14 160,363 21,993 15,781 62,576 53,619 5,911 484 Oct‐14 169,994 23,034 17,819 61,729 61,180 5,782 450 Nov‐14 158,050 21,108 17,245 60,155 52,843 6,302 396 Dec‐14 153,185 28,521 13,677 51,644 53,662 5,307 375 Jan‐15 141,730 27,964 10,730 49,887 47,798 5,016 335 Feb‐15 138,321 26,416 13,809 48,439 43,760 5,534 363 Mar‐15 145,597 20,381 12,494 52,272 55,418 4,622 410 Apr‐15 144,890 23,859 15,753 54,366 43,800 6,675 436 May‐15 159,210 23,063 17,406 55,638 56,797 5,806 501 Jun‐15 163,736 22,464 17,780 59,076 56,922 6,949 545 Maximum 169,994 28,521 17,819 65,230 62,000 6,949 623 Last Updated: 3/10/2016 1:16 PM Schedule 8.5 Page 2 of 3 Prepared By EES Consulting, Inc.City of Palo Alto RECORDED CUSTOMER DEMAND Schedule 8.5 Rate Class NCP @ Input Voltage (kW)Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Line Losses:0.80% 0.80% 0.80% 0.80% 0.80% 0.80% Jul‐14 168,246 23,307 13,937 62,054 62,492 5,829 628 Aug‐14 171,135 21,747 15,241 65,756 62,500 5,283 608 Sep‐14 161,656 22,170 15,908 63,081 54,051 5,959 488 Oct‐14 171,365 23,220 17,963 62,227 61,674 5,828 454 Nov‐14 159,324 21,278 17,384 60,641 53,269 6,353 399 Dec‐14 154,421 28,751 13,787 52,061 54,094 5,349 378 Jan‐15 142,873 28,189 10,816 50,289 48,184 5,056 338 Feb‐15 139,436 26,629 13,921 48,829 44,112 5,579 366 Mar‐15 146,771 20,546 12,595 52,693 55,865 4,659 413 Apr‐15 146,058 24,052 15,880 54,804 44,154 6,729 439 May‐15 160,494 23,249 17,546 56,087 57,255 5,853 505 Jun‐15 165,056 22,645 17,924 59,552 57,381 7,005 549 Maximum 171,365 28,751 17,963 65,756 62,500 7,005 628 System Coincidence Factor Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 58.00% 90.00% 100.00% 100.00% 97.00% Aug‐14 59.00% 90.00% 97.00% 97.00% 97.00% Sep‐14 50.00% 97.00% 98.20% 98.10% 97.00% Oct‐14 93.00% 100.00% 100.00% 100.00% 98.00% 100.00% Nov‐14 50.00% 90.00% 100.00% 100.00% 90.00% 100.00% Dec‐14 58.00% 90.00% 100.00% 100.00% 90.00% 100.00% Jan‐15 90.00% 100.00% 100.00% 100.00% 96.00% 100.00% Feb‐15 82.50% 98.00% 100.00% 100.00% 95.00% 100.00% Mar‐15 60.00% 90.00% 100.00% 100.00% 97.00% 100.00% Apr‐15 93.00% 100.00% 100.00% 100.00% 100.00% May‐15 76.00% 100.00% 100.00% 100.00% 97.00% Jun‐15 98.00% 100.00% 100.00% 100.00% 100.00% Coincident Peak (CP) @ Input (kW) Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 156,261 13,518 12,544 62,054 62,492 5,654 Aug‐14 156,081 12,831 13,717 63,783 60,625 5,124 Sep‐14 147,265 11,085 15,431 61,945 53,024 5,780 Oct‐14 169,623 21,594 17,963 62,227 61,674 5,712 454 Nov‐14 146,311 10,639 15,646 60,641 53,269 5,718 399 Dec‐14 140,432 16,675 12,409 52,061 54,094 4,814 378 Jan‐15 139,851 25,370 10,816 50,289 48,184 4,854 338 Feb‐15 134,219 21,969 13,642 48,829 44,112 5,300 366 Mar‐15 137,154 12,327 11,336 52,693 55,865 4,520 413 Apr‐15 143,935 22,368 15,880 54,804 44,154 6,729 May‐15 154,234 17,669 17,546 56,087 57,255 5,677 Jun‐15 164,054 22,193 17,924 59,552 57,381 7,005 Total 1,789,420 208,239 174,853 684,965 652,128 66,886 2,349 Peak Month 169,623 21,594 17,963 62,227 61,674 5,712 454 Last Updated: 3/10/2016 1:16 PM Schedule 8.5 Page 3 of 3 Prepared By EES Consulting, Inc.City of Palo Alto kWh @ Input Voltage Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 80,107,726 12,191,915 6,081,166 26,912,832 32,369,575 2,388,729 163,508 Aug‐14 85,235,616 11,717,164 6,096,647 28,295,703 36,410,346 2,552,247 163,508 Sep‐14 89,878,931 11,955,261 6,604,349 30,268,461 38,073,115 2,814,238 163,508 Oct‐14 80,781,677 12,489,341 5,680,898 26,684,457 33,350,708 2,412,764 163,508 Nov‐14 81,850,131 12,003,925 5,642,221 25,793,484 35,594,561 2,652,432 163,508 Dec‐14 82,404,655 15,607,820 5,632,273 25,438,065 33,152,744 2,410,245 163,508 Jan‐15 82,763,526 17,933,979 6,155,104 24,882,838 31,021,983 2,606,114 163,508 Feb‐15 83,611,578 15,104,853 5,997,324 25,072,066 34,648,245 2,625,582 163,508 Mar‐15 73,483,461 12,510,138 5,515,014 23,740,101 29,274,182 2,280,517 163,508 Apr‐15 79,447,009 11,869,399 6,095,264 24,739,926 34,206,934 2,371,978 163,508 May‐15 78,245,980 11,455,516 6,650,481 26,084,153 31,329,126 2,563,196 163,508 Jun‐15 80,916,349 11,175,362 6,739,140 26,392,509 33,976,716 2,469,115 163,508 Total Purchases ‐ Bottom Up 978,726,637 156,014,673 72,889,881 314,304,596 403,408,234 30,147,158 1,962,095 Historic Load Reconciliation Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Secondary Line Losses 2.50% 2.50% 2.50% 0.95% 2.50% 2.50% Primary Line Losses 0.80% 0.80% 0.80% 0.80% 0.80% 0.80% Total Jul‐14 Aug‐14 Sep‐14 Oct‐14 Nov‐14 Dec‐14 Recorded Energy Purchases kWh 980,893,955 85,616,647 86,907,303 83,078,225 82,724,711 79,300,007 83,420,214 Bottom‐Up Energy Purchases kWh 978,726,637 80,107,726 85,235,616 89,878,931 80,781,677 81,850,131 82,404,655 % Difference 0.22% 7% 2%‐8% 2%‐3% 1% Measured System Demand kW 1,821,704 156,272 156,120 147,279 170,079 146,691 140,814 CP @ Input Demand kW 1,789,420 156,261 156,081 147,265 169,623 146,311 140,432 % Difference 1.8% 0.0% 0.0% 0.0% 0.3% 0.3% 0.3% On‐Peak Energy Use by Percentage Average Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 66% 66% 66% 66% 66% 66% 66% Aug‐14 66% 66% 66% 66% 66% 66% 66% Sep‐14 66% 66% 66% 66% 66% 66% 66% Oct‐14 66% 66% 66% 66% 66% 66% 66% Nov‐14 66% 66% 66% 66% 66% 66% 66% Dec‐14 66% 66% 66% 66% 66% 66% 66% Jan‐15 66% 66% 66% 66% 66% 66% 66% Feb‐15 66% 66% 66% 66% 66% 66% 66% Mar‐15 66% 66% 66% 66% 66% 66% 66% Apr‐15 66% 66% 66% 66% 66% 66% 66% May‐15 66% 66% 66% 66% 66% 66% 66% Jun‐15 66% 66% 66% 66% 66% 66% 66% Total (Derived)66%66% 66% 66% 66% 66% 66% RECORDED kWh AT INPUT Schedule 8.6 Last Updated: 3/10/2016 1:16 PM Schedule 8.6 Page 1 of 2 Prepared By EES Consulting, Inc.City of Palo Alto RECORDED kWh AT INPUT Schedule 8.6 On‐Peak kWh @ Input Voltage Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 52,871,099 8,046,664 4,013,570 17,762,469 21,363,919 1,576,561 107,915 Aug‐14 56,255,507 7,733,329 4,023,787 18,675,164 24,030,828 1,684,483 107,915 Sep‐14 59,320,094 7,890,472 4,358,870 19,977,184 25,128,256 1,857,397 107,915 Oct‐14 53,315,906 8,242,965 3,749,392 17,611,742 22,011,468 1,592,424 107,915 Nov‐14 54,021,086 7,922,590 3,723,866 17,023,699 23,492,410 1,750,605 107,915 Dec‐14 54,387,072 10,301,161 3,717,300 16,789,123 21,880,811 1,590,762 107,915 Jan‐15 54,623,927 11,836,426 4,062,369 16,422,673 20,474,509 1,720,035 107,915 Feb‐15 55,183,642 9,969,203 3,958,234 16,547,564 22,867,842 1,732,884 107,915 Mar‐15 48,499,084 8,256,691 3,639,910 15,668,467 19,320,960 1,505,141 107,915 Apr‐15 52,435,026 7,833,803 4,022,874 16,328,351 22,576,577 1,565,506 107,915 May‐15 51,642,347 7,560,641 4,389,317 17,215,541 20,677,223 1,691,710 107,915 Jun‐15 53,404,790 7,375,739 4,447,832 17,419,056 22,424,632 1,629,616 107,915 Total On‐Peak Energy ‐ Bottom‐Up 645,959,581 102,969,684 48,107,322 207,441,033 266,249,435 19,897,124 1,294,983 Off‐Peak Energy Use by Percentage Average Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 34% 34% 34% 34% 34% 34% 34% Aug‐14 34% 34% 34% 34% 34% 34% 34% Sep‐14 34% 34% 34% 34% 34% 34% 34% Oct‐14 34% 34% 34% 34% 34% 34% 34% Nov‐14 34% 34% 34% 34% 34% 34% 34% Dec‐14 34% 34% 34% 34% 34% 34% 34% Jan‐15 34% 34% 34% 34% 34% 34% 34% Feb‐15 34% 34% 34% 34% 34% 34% 34% Mar‐15 34% 34% 34% 34% 34% 34% 34% Apr‐15 34% 34% 34% 34% 34% 34% 34% May‐15 34% 34% 34% 34% 34% 34% 34% Jun‐15 34% 34% 34% 34% 34% 34% 34% Total (Derived) 34%34% 34% 34% 34% 34% 34% Off‐Peak kWh @ Input Voltage Total Residential E‐1 Small Non‐ residential E‐2 Medium Non‐ residential E‐4 Large Non‐ residential E‐7 City Accounts E‐ 18 Street/Traffic Lights Jul‐14 27,236,627 4,145,251 2,067,597 9,150,363 11,005,655 812,168 55,593 Aug‐14 28,980,109 3,983,836 2,072,860 9,620,539 12,379,518 867,764 55,593 Sep‐14 30,558,836 4,064,789 2,245,478 10,291,277 12,944,859 956,841 55,593 Oct‐14 27,465,770 4,246,376 1,931,505 9,072,715 11,339,241 820,340 55,593 Nov‐14 27,829,044 4,081,334 1,918,355 8,769,785 12,102,151 901,827 55,593 Dec‐14 28,017,583 5,306,659 1,914,973 8,648,942 11,271,933 819,483 55,593 Jan‐15 28,139,599 6,097,553 2,092,736 8,460,165 10,547,474 886,079 55,593 Feb‐15 28,427,937 5,135,650 2,039,090 8,524,503 11,780,403 892,698 55,593 Mar‐15 24,984,377 4,253,447 1,875,105 8,071,634 9,953,222 775,376 55,593 Apr‐15 27,011,983 4,035,596 2,072,390 8,411,575 11,630,358 806,473 55,593 May‐15 26,603,633 3,894,875 2,261,163 8,868,612 10,651,903 871,487 55,593 Jun‐15 27,511,559 3,799,623 2,291,307 8,973,453 11,552,083 839,499 55,593 Total Off‐Peak Energy ‐ Bottom‐Up 332,767,057 53,044,989 24,782,560 106,863,563 137,158,800 10,250,034 667,112 Last Updated: 3/10/2016 1:16 PM Schedule 8.6 Page 2 of 2 Attachment D NOT YET APPROVED 160330 jb 6053723 Resolution No. _________ Resolution of the Council of the City of Palo Alto Adopting an Electric Rate Increase and Amending Rate Schedules E-1 (Residential Electric Service), E-2 (Small Commercial Electric Service), E-2-G (Small Commercial Green Power Electric Service), E-4 (Medium Commercial Electric Service), E-4-G (Medium Commercial Green Power Electric Service), E-4 TOU (Medium Commercial Time of Use Electric Service), E 7 (Large Commercial Electric Service), E-7-G (Large Commercial Green Power Electric Service), E 7 TOU (Large Commercial Time of Use Electric Service), E-14 (Street Lights), and E-16 (Unmetered Electrical Service) and Repealing Rate Schedules E-18 (Municipal Electric Service) and E- 18-G (Municipal Green Power Electric Service) R E C I T A L S A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of the City of Palo Alto may by resolution adopt rules and regulations governing utility services, fees and charges. B. On ____, 2016, the City Council heard and approved the proposed rate increase at a noticed public hearing. The Council of the City of Palo Alto does hereby RESOLVE as follows: SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2016. SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-2 (Small Commercial Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-2, as amended, shall become effective July 1, 2016. SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-2-G (Small Commercial Green Power Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-2-G, as amended, shall become effective July 1, 2016. SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-4 (Medium Commercial Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July 1, 2016. Attachment D NOT YET APPROVED 160330 jb 6053723 SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-4-G (Medium Commercial Green Power Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall become effective July 1, 2016. SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-4 TOU (Medium Commercial Time of Use Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended, shall become effective July 1, 2016. SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-7 (Large Commercial Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective July 1, 2016. SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-7-G (Large Commercial Green Power Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective July 1, 2016. SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-7 TOU (Large Commercial Time of Use Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become effective July 1, 2016. SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-14, as amended, shall become effective July 1, 2016. SECTION 11. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-16 (Unmetered Electrical Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-16, as amended, shall become effective July 1, 2016. SECTION 12. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-18 (Municipal Electric Service) is hereby repealed effective July 1, 2016. SECTION 13. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-18-G (Municipal Green Power Electric Service) is hereby repealed effective July 1, 2016. SECTION 14. The City Council finds as follows: a. Revenue derived from the electric rates approved by this resolution does not exceed the funds required to provide electric service. Attachment D NOT YET APPROVED 160330 jb 6053723 b. Revenue derived from the adoption of this resolution shall be used only for the purpose set forth in Article VII, Section 2, of the Charter of the City of Palo Alto. c. The fees and charges adopted by this resolution are charges imposed for a specific government service or product provided directly to the payor that are not provided to those not charged, and do not exceed the reasonable costs to the City of providing the service or product. SECTION 15. The adoption of this resolution changing electric rates to meet operating expenses, purchase supplies and materials, meet financial reserve needs and obtain funds for capital improvements necessary to maintain service is not subject to the California Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec. 21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After reviewing the staff report and all attachments presented to Council, the Council incorporates these documents herein and finds that sufficient evidence has been presented setting forth with specificity the basis for this claim of CEQA exemption. INTRODUCED AND PASSED: AYES: NOES: ABSENT: ABSTENTIONS: ATTEST: ___________________________ ___________________________ City Clerk Mayor APPROVED AS TO FORM: APPROVED: ___________________________ ___________________________ Senior Deputy City Attorney City Manager ___________________________ Director of Utilities ___________________________ Director of Administrative Services RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-2009 Supersedes Sheet No E-1-1 dated 11-1-2008 Sheet No E-1-1 A. APPLICABILITY: This schedule applies to separately metered single-family residential dwellings receiving retail energy services from the City of Palo Alto Utilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides electric service. C. UNBUNDLED RATES: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total Tier 1 usage $0.05448 $0.05883 $0.03755 $0.04795 $0.00321 $0.00351 $0.09524 $0.11029 Tier 2 usage 100%-200% ofAny usage over Tier 1 0.07654 0.09728 0.05045 0.06822 0.00321 0.00351 0.13020 0.16901 Tier 3 usage Over 200% of Tier 1 0.10349 0.06729 0.00321 0.17399 Minimum Bill ($/day) 0.3067 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Calculation of Usage Tiers Tier 1 electricity usage shall be calculated and billed based upon a level of 10 11 kWh per day, prorated by meter reading days of service. As an example, for a 30-day bill, the Tier 1 level would be 300 kWh. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. {End} ATTACHMENT E SMALL COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2009 Supersedes Sheet No E-2-1 dated 7-1-200911-1-2008 Sheet No E-2-1 A. APPLICABILITY: This schedule applies to non-demand metered electric service for small commercial customers and master-metered multi-family facilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides electric service. C. UNBUNDLED RATES: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total Summer Period $0.08219 $0.09094 $0.05505 $0.07400 $0.00321 $0.00351 $0.14045 $0.16845 Winter Period 0.07406 0.06417 0.04934 0.04677 0.00321 0.00351 0.12661 0.11445 Minimum Bill ($/day) 0.7657 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use in both the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. SMALL COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2009 Supersedes Sheet No E-2-2 dated 7-1-200911-1-2008 Sheet No E-2-2 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum demand meter will be installed as promptly as is practicable and thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The maximum demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month provided that in case the load is intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A thermal-type demand meter which does not reset after a definite time interval may be used at the City's option. The billing demand to be used in computing charges under this schedule will be the actual maximum demand in kilowatts for the current month. An exception is that the billing demand for customers with Thermal Energy Storage (TES) will be based upon the actual maximum demand of such customers between the hours of noon and 6 pm on weekdays. {End} SMALL COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-2-G-1 dated 7-1-20149-1-2013 Sheet No E-2-G-1 A. APPLICABILITY: This schedule applies to the following Customers receiving Electric Service from the City of Palo Alto Utilities under the Palo Alto Green Program: 1. Small commercial Customers receiving Non-Demand Metered electric service; and 2. Customers with accounts at Master-metered multi-family facilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: 1. 100% Renewable Option: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Palo Alto Green Charge Total Summer Period $0.09094 $0.08219 $0.07400 $0.05505 $0.00351 $0.00321 $0.0020 $0.14245 $0.17045 Winter Period 0.06417 0.07406 0.04677 0.04934 0.00351 0.00321 0.0020 0.12861 $0.11645 Minimum Bill ($/day) 0.7657 2. 1000 kWh Block Purchase Option: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total Summer Period $0.09094 $0.08219 $0.07400 $0.05505 $0.00351 $0.00321 $0.16845 $0.14045 Winter Period 0.06417 0.07406 0.04677 0.04934 0.00351 0.00321 0.11445 0.12661 Minimum Bill ($/day) 0.7657 Palo Alto Green Charge (per 1000 kWh block) $2.00 SMALL COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-2-G-2 dated 7-1-20149-1-2013 Sheet No E-2-G-2 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use in both the Summer and Winter Periods, usage will be prorated based upon the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the production of renewable energy, increase the financial value of power from renewable sources, and create a transparent and sustainable market that encourages new development of wind and solar power. Customers choosing to participate shall fill out a Palo Alto Green Power Program application provided by the Customer Service Center. Customers may request at any time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program. 4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be SMALL COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-2-G-3 dated 7-1-20149-1-2013 Sheet No E-2-G-3 removed. The maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that in case the load is intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option. The billing Demand to be used in computing charges under this schedule will be the actual maximum Demand in kilowatts for the current month. An exception is that the billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual maximum Demand of such Customers between the hours of noon and 6 pm on weekdays. {End} MEDIUM COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-4-1 dated 2-5-20137-1-2009 Sheet No E-4-1 A. APPLICABILITY: This schedule applies to Demand metered secondary Electric Service for customers with a Maximum Demand below 1,000 kilowatts. This schedule applies to three-phase Electric Service and may include Service to master-metered multi-family facilities or other facilities requiring Demand-metered services, as determined by the City. B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh): Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $5.31 $2.53 $15.23 $17.14 $20.54 $19.68 Energy Charge (per kWh) 0.06083 0.08218 0.01767 0.01661 0.00321 0.00351 0.08171 0.10229 Winter Period Demand Charge (per kW) $4.80 $1.55 $9.04 $12.49 $13.84 $14.04 Energy Charge (per kWh) 0.05281 0.06037 0.01716 0.01661 0.00321 0.00351 0.07318 0.08049 Minimum Bill ($/day) 16.3216 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. MEDIUM COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-4-2 dated 2-5-20137-1-2009 Sheet No E-4-2 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a Maximum Demand meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that in case the load is intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A thermal-type Demand meter which does not reset after a definite time interval may be used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such customers between the hours of noon and 6 pm on weekdays. 4. Power Factor For new or existing customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable metering to calculate a Power Factor. The City may remove such metering from the Service of a customer whose Demand has been below 200 kilowatts for four consecutive months. When such metering is installed, the monthly Electric bill will include a “Power Factor Adjustment”, if applicable. The adjustment will be applied to a customer ’s bill prior to MEDIUM COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-4-3 dated 2-5-20137-1-2009 Sheet No E-4-3 the computation of any primary voltage discount. The Power Factor Adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent (0.25%) for each one percent (1%) that the monthly Power Factor of the customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt hours to kilovolt-ampere hours consumed during the month. Where time-of-day metering is installed, the monthly Power Factor shall be the Power Factor coincident with the customer's Maximum Demand. 5. Changing Rate Schedules Customers may request a rate schedule change at any time to any City of Palo Alto full - service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile. 6. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be allowed provided the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the customer's electrical requirements. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any customer receiving a discount hereunder and affected by such change. The customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non- utility generation source. MEDIUM COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-4-4 dated 2-5-20137-1-2009 Sheet No E-4-4 b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.69 $15.23 $15.92 Winter Period $0.63 $9.04 $9.67 c. Meters. A separate meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions. (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} MEDIUM COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-4-TOU-1 dated 2-5-20137-1-2009 Sheet No E-4-TOU-1 A. APPLICABILITY: This voluntary rate schedule applies to Demand metered secondary Electric Service for customers with Demand between 500 and 1,000 kilowatts per month and who have sustained this level of usage for at least three consecutive months during the most recent 12 month period. This schedule applies to three-phase Electric Service and may include Service to master- metered multi-family facilities or other facilities requiring Demand-metered services, as determined by the City. In addition, this rate schedule is applicable for customers who did not pay Power Factor Adjustments during the last 12 months. B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh): Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) Peak $1.52$3.12 $5.91$8.96 $7.42$12.08 Mid-Peak 0.541.99 5.915.65 6.447.64 Off-Peak 0.541.13 5.913.26 6.444.39 Energy Charge (per kWh) Peak $0.08819 $0.10963 $0.01661 $0.03242 $0.00351 $0.00321 $0.10830 $0.14526 Mid-Peak 0.08367 0.05617 0.01661 0.01623 0.00351 0.00321 0.10378 0.07561 Off-Peak 0.07332 0.04298 0.01661 0.01218 0.00351 0.00321 0.09344 0.05837 Winter Period Demand Charge (per kW) Peak $2.77$0.87 $5.10$6.96 $7.87$7.83 Off-Peak 1.490.87 2.946.96 4.437.83 MEDIUM COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-4-TOU-2 dated 2-5-20137-1-2009 Sheet No E-4-TOU-2 Commodity Distribution Public Benefits Total Energy Charge (per kWh) Peak $0.07003 $0.06566 $0.02296 $0.01661 $0.00321 $0.00351 $0.09620 $0.08577 Off-Peak 0.04088 0.06167 0.01313 0.01661 $0.00351 0.00321 0.05722 0.08178 Minimum Bill ($/day) 16.3216 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31): Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays) Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays) 6:00 p.m. to 9:00 p.m. Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays) All day Saturday, Sunday, and holidays WINTER PERIOD (Service from November 1 to April 30): Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays) Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except MEDIUM COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-4-TOU-3 dated 2-5-20137-1-2009 Sheet No E-4-TOU-3 holidays) All day Saturday, Sunday, and holidays HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Years Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays are legally observed. SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and the Winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein.. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Demand meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts taken during any 15 -minute interval in each of the designated Time periods as defined under Section D.2. 4. Power Factor Adjustment Time of Use customers must not have had a Power Factor Adjustment assessed on their Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt-ampere hours consumed during the month, and must not have fallen below 95% to avoid the Power Factor Adjustment. Should the City of Palo Alto Utilities Department find that the Customer’s Service should be subject to Power Factor Adjustments, the Customer will be removed from the E-4- TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 5. Changing Rate Schedules MEDIUM COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-4-TOU-4 dated 2-5-20137-1-2009 Sheet No E-4-TOU-4 Customers electing to be served under E-4 TOU must remain on said schedule for a minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a rate schedule change to any applicable City of Palo Alto full- service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 6. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be allowed provided the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving a discount hereunder and affected by such change. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non- utility generation source. b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.69 $15.23 $15.92 Winter Period $0.63 $9.04 $9.67 c. Meters. A separate meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. MEDIUM COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-4-TOU-5 dated 2-5-20137-1-2009 Sheet No E-4-TOU-5 (1) In the event the Customer’s Maximum Demand occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions. (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} MEDIUM COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-4-G-1 dated 7-1-20149-10-2013 Sheet No E-4-G-1 A. APPLICABILITY: This schedule applies to Demand Metered Secondary Electric Service for Customers with a Maximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green Program. This schedule applies to three-phase Electric Service and may include Service to Master-metered multi-family facilities or other facilities requiring Demand-Metered Services, as determined by the City. B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: 1. 100% Renewable Option: Commodity Distribution Public Benefits Palo Alto Green Charge Total Summer Period Demand Charge (per kW) $2.53 $5.31 $17.14 $15.23 $19.68 $20.54 Energy Charge (per kWh) 0.08218 0.06083 0.01661 0.01767 0.00351 0.00321 0.0020 0.10429 0.08371 Winter Period Demand Charge (per kW) $1.55 $4.80 $12.49 $9.04 $14.04 $13.84 Energy Charge (per kWh) 0.06037 0.05281 0.01661 0.01716 0.00351 0.00321 0.0020 0.08249 0.07518 Minimum Bill ($/day) 16.3216 MEDIUM COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-4-G-2 dated 7-1-20149-10-2013 Sheet No E-4-G-2 2. 1000 kWh Block Purchase Option: Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $2.53 $5.31 $17.14 $15.23 $19.68 $20.54 Energy Charge (per kWh) 0.08218 0.06083 0.01661 0.01767 0.00351 0.00321 0.10229 0.08371 Palo Alto Green Charge (per 1000 kWh block) $2.00 Winter Period Demand Charge (per kW) $1.55 $4.80 $12.49 $9.04 $14.04 $13.84 Energy Charge (per kWh) 0.06037 0.05281 0.01661 0.01716 0.00351 0.00321 0.08049 0.07518 Palo Alto Green Charge (per 1000 kWh block) $2.00 Minimum Bill ($/day) 16.3216 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter MEDIUM COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-4-G-3 dated 7-1-20149-10-2013 Sheet No E-4-G-3 Whenever the monthly use of energy has exceeded 8,000 kilowatt -hours for three consecutive months, a Maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that in case the load is intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A thermal-t ype Demand Meter, which does not reset after a definite time interval, may be used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays. 4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four consecutive months. When such Metering is installed, the monthly Electric bill will include a “Power Factor Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to the computation of any primary voltage discount. The Power Factor Adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt- hours to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 5. Changing Rate Schedules MEDIUM COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-4-G-4 dated 7-1-20149-10-2013 Sheet No E-4-G-4 Customers may request a rate schedule change at any time to any applicable full-service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile. 6. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every mont h, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the production of renewable energy, increase the financial value of power from renewal sources, and creates a transparent and sustainable market that encourages new development of wind and solar. Customers choosing to participate shall fill out a Palo Alto Green Power Program application provided by the Customer Service Center. Customers may request at any time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program. 7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be allowed provided the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving a discount hereunder and affected by such change. The Customer then has the option to change the system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non- utility generation source. MEDIUM COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-4-G-5 dated 7-1-20149-10-2013 Sheet No E-4-G-5 b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.69 $15.23 $15.92 Winter Period $0.63 $9.04 $9.67 c. Meters: A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit: (1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Cust omer shall not receive the Maximum Demand credit described in this Section. e. Exemptions: (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} LARGE COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-7-1 dated 2-5-20137-1-2009 Sheet No E-7-1 A. APPLICABILITY: This schedule applies to Demand metered secondary Service for commercial Customers with a Maximum Demand of at least 1,000KW per month per site, who have sustained this Demand level at least 3 consecutive months during the last twelve months. B. TERRITORY: This rate schedule applies anywhere the City of Palo Alto provides Electric Service. C. RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh): Commodity Distribution Public Benefits Total Summer Period Demand Charge (kW) $6.42 $2.50 $12.55 $15.85 $18.97 $18.34 Energy Charge (kWh) 0.05662 0.08311 0.01825 0.00087 0.00321 0.00351 0.07808 0.08749 Winter Period Demand Charge (kW) $5.50 $1.53 $6.04 $14.11 $11.54 $15.65 Energy Charge (kWh) 0.04990 0.05804 0.01898 0.00087 0.00321 0.00351 0.07209 0.06242 Minimum Bill ($/day) 48.5054 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. LARGE COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-7-2 dated 2-5-20137-1-2009 Sheet No E-7-2 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use both in the summer and in the winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Request for Service Qualifying Customers may request Service under this schedule for more than one account or one meter if the accounts are on one site. A site shall be defined as one or more utility accounts serving contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and have a common billing address. 4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt -hours for three consecutive months, a Maximum Demand meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month provided that in case the load is intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A thermal-type Demand meter which does not reset after a definite time interval may be used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that th e Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 pm on weekdays. 5. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option to install applicable LARGE COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-7-3 dated 2-5-20137-1-2009 Sheet No E-7-3 metering to calculate a Power Factor. The City may remove such metering from the Service of a Customer whose Demand has been below 200 kilowatts for four consecutive months. When such metering is installed, the monthly Electric bill shall include a “Power Factor Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to the computation of any primary voltage discount. The Power Factor Adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent (0.25%) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt hours to kilovolt-ampere hours consumed during the month. Where time-of-day metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile. 7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be allowed provided the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving a discount hereunder and affected by such change. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kVA size limitation. 8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the Cit y’s revenue meter and that occasionally require backup power from the City due to non-operation of the non- LARGE COMMERCIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-7-4 dated 2-5-20137-1-2009 Sheet No E-7-4 utility generation source. b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76 c. Meters. A separate meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand (as defined in Section D.4) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions. (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4) , as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-7-TOU-1 dated 2-5-20137-1-2009 Sheet No E-7-TOU-1 A. APPLICABILITY: This voluntary rate schedule applies to Demand metered secondary Service for commercial customers with a Maximum Demand of at least 1,000KW per month per site, who have sustained this Demand level at least 3 consecutive months during the last twelve months. In addition, this rate schedule is applicable for customers who did not pay Power Factor Adjustments during the last 12 months. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh): Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) Peak $4.24 $1.48 $8.25 $5.33 $12.49 $6.80 Mid-Peak 2.06 0.51 4.13 5.33 6.19 5.84 Off-Peak 1.17 0.51 2.06 5.33 3.23 5.84 Energy Charge (per kWh) Peak $0.07029 $0.09267 $0.02296 $0.00087 $0.00321 $0.00351 $0.09646 $0.09705 Mid-Peak 0.05867 0.08792 0.01901 0.00087 0.00321 0.00351 0.08089 0.09230 Off-Peak 0.04870 0.07705 0.01567 0.00087 0.00321 0.00351 0.06758 0.08143 Winter Period Demand Charge (per kW) Peak $3.04 $0.78 $3.38 $7.15 $6.42 $7.92 Off-Peak 1.59 0.78 1.68 7.15 3.27 7.92 LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-7-TOU-2 dated 2-5-20137-1-2009 Sheet No E-7-TOU-2 Energy Charge (per kWh) Peak $0.05617 $0.06009 $0.02142 $0.00087 $0.00321 $0.00351 $0.08080 $0.06447 Off-Peak 0.04663 0.05643 0.01767 0.00087 0.00321 0.00351 0.06751 0.06081 Minimum Bill ($/day) 48.5054 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31): Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays) Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays) 6:00 p.m. to 9:00 p.m. Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday All day Saturday, Sunday, and holidays WINTER PERIOD (Service from November 1 to April 30): Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays) Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-7-TOU-3 dated 2-5-20137-1-2009 Sheet No E-7-TOU-3 holidays) All day Saturday, Sunday, and holidays HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Years Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays are legally observed. SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and the Winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Request for Service Qualifying customers may request Service under this schedule for more than one account or one meter if the accounts are on one site. A site shall be defined as one or more utility accounts serving contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and have a common billing address. 4. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt -hours for three consecutive months, a Demand meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated Time periods as defined under Section D.2. 5. Power Factor Adjustment Time of Use customers must not have had a Power Factor Adjustment assessed on their Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt- ampere hours consumed during the month, and must not have fallen below 95% to avoid the Power Factor Adjustment. Should the City of Palo Alto Utilities Department find that the Customer’s Service should be LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-7-TOU-4 dated 2-5-20137-1-2009 Sheet No E-7-TOU-4 subject to Power Factor Adjustments, the Customer will be removed from the E -7-TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 6. Changing Rate Schedules Customers electing to be served under E-7 TOU must remain on said schedule for a minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a rate schedule change to any applicable City of Palo Alto full -service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be allowed provided the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving a discount hereunder and affected by such change. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non- utility generation source. b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 LARGE COMMERCIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20162-5-2013 Supersedes Sheet No E-7-TOU-5 dated 2-5-20137-1-2009 Sheet No E-7-TOU-5 Winter Period $0.72 $6.04 $6.76 c. Meters. A separate meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions. (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Cus tomer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4) , as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-7-G-1 dated 7-1-20149-10-2013 Sheet No E-7-G-1 A. APPLICABILITY: This schedule applies to Demand Metered Service for large commercial Customers who choose Service under the Palo Alto Green Program. A Customer may qualify for this rate schedule if the Customer’s Maximum Demand is at least 1,000KW per month per site, who have sustained this Demand level at least 3 consecutive months during the last twelve months B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: 1. 100% Renewable Option: Commodity Distribution Public Benefits Palo Alto Green Charge Total Summer Period Demand Charge ( per kW) $2.50 $6.42 $15.85 $12.55 $18.34 $18.97 Energy Charge (per kWh) 0.08311 0.05562 0.00087 0.01825 0.00351 0.00321 0.0020 0.08949 0.07908 Winter Period Demand Charge (per kW) $1.53 $5.50 $14.11 $6.04 $15.65 $11.54 Energy Charge (per kWh) 0.05804 0.04990 0.00087 0.01898 0.00351 0.00321 0.0020 0.06442 0.07409 Minimum Bill ($/day) 48.5054 LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-7-G-2 dated 7-1-20149-10-2013 Sheet No E-7-G-2 2. 1000 kWh Block Purchase Option: Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $2.50 $6.42 $15.85 $12.55 $18.34 $18.97 Energy Charge (per kWh) 0.08311 0.05562 0.00087 0.01825 0.00351 0.00321 0.08749 0.07708 Palo Alto Green Charge (per 1000 kWh block) $2.00 Winter Period Demand Charge (per kW) $1.53 $5.50 $14.11 $6.04 $15.65 $11.54 Energy Charge (per kWh) 0.05804 0.04990 0.00087 0.01898 0.00351 0.00321 0.06242 0.07209 Palo Alto Green Charge (per 1000 kWh block) $2.00 Minimum Bill ($/day) 48.5054 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-7-G-3 dated 7-1-20149-10-2013 Sheet No E-7-G-3 Whenever the monthly use of energy has exceeded 8,000 kilowatt -hours for three consecutive months, a Maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that in case the load is intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays. 4. Request for Service Qualifying Customers may request Service under this schedule for more than one Account or one Meter if the Accounts are at one site. A site shall be defined as one or more utility Accounts serving contiguous parcels of land with no intervening public right- of-ways (e.g. streets) and have a common billing address. 5. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four consecutive months. When such Metering is installed, the monthly Electric bill shall include a “Power Factor Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to the computation of any primary voltage discount. The Power Factor Adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-7-G-4 dated 7-1-20149-10-2013 Sheet No E-7-G-4 The monthly Power Factor is the average Power Factor based on the ratio of kilowatt- hours to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile 7. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to match 100% of the energy usage at the facility every mont h, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the production of renewable energy, increase the financial value of power from renewal sources, and creates a transparent and sustainable market that encourages new development of wind and solar. Customers choosing to participate shall fill out a Palo Alto Green Power Program application provided by the Customer Service Center. Customers may request at any time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program. 8. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be allowed; provided, however, the City is not required to supply Service at a qualified line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's Electrical requirements. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving a discount hereunder and affected by such change. The Customer then has the option to change the system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 9. Standby Charge LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-7-G-5 dated 7-1-20149-10-2013 Sheet No E-7-G-5 a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non- utility generation source. b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76 c. Meters: A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit: (1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions: (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. LARGE COMMERCIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2014 Supersedes Sheet No E-7-G-6 dated 7-1-20149-10-2013 Sheet No E-7-G-6 {End} STREET LIGHTS UTILITY RATE SCHEDULE E-14 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-01-2009 Supersedes Sheet No. E-14-1 dated 7-01-20097-01-2008 Sheet No. E-14-1 A. APPLICABILITY: This schedule applies to all street and highway lighting installations owned by any governmental agency other than the City of Palo Alto. B. TERRITORY: Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City. C. RATES: Per Lamp Per Month Class A: Utility supplies energy and switching service only. kWh's Per Month Burning Schedule: All Night/Midnight All Night Midnight Lamp Rating: Mercury-Vapor Lamps 100 watts 42/20 $ 12.08 $ 8.92 175 watts 68/35 14.41 11.23 400 watts 154/71 29.66 22.87 High Pressure Sodium Vapor Lamps 120 volts 70 watts 29/15 10.59 7.43 100 watts 41/20 14.19 10.36 150 watts 60/30 18.43 15.48 240 volts 70 watts 34/17 11.85 8.92 100 watts 49/25 15.488.59 11.23 150 watts 70/35 18.43 12.72 200 watts 90/45 20.5515.87 16.31 250 watts 110/55 23.3219.50 16.51 310 watts 134/167 27.3224.13 21.60 400 watts 167/84 33.4731.07 24.78 Fluorescent Lamps 40 watts 15/8 4.46 3.60 STREET LIGHTS UTILITY RATE SCHEDULE E-14 (Continued) CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-2016 Supersedes Sheet No. E-14-2 dated 7-1-2009 Sheet No. E-14-2 Per Lamp Per Month -– Class C: Utility supplies energy and switching service and maintains entire system, including lamps and glassware. kWh's Per Month Burning Schedule: All Night/Midnight All Night Midnight Lamp Rating: Mercury-Vapor Lamps 100 watts 42/20 $ 13.56 $ 10.36 175 watts 68/35 16.31 12.91 250 watts 97/49 20.32 15.70 400 watts 154/71 30.2932.58 23.32 Incandescent Lamps 189 watts (2,500 L) 65/32 14.41 11.46 295 watts (4,000 L) 101/5 18.43 14.41 405 watts (6,000 L) 139/70 23.32 19.27 620 watts (10,000 L) 212/106 32.42 26.88 Fluorescent Lamps 25 watts 12/6 5.30 4.04 40 watts 15/8 5.49 4.46 55 watts 18/9 6.36 4.68 High Pressure Sodium Vapor Lamps 120 volts 70 watts 29/15 11.02 7.84 100 watts 41/20 14.82 10.81 150 watts 60/30 19.06 15.91 240 volts 70 watts 34/17 12.2928.61 9.33 100 watts 49/25 16.0930.79 11.85 150 watts 70/35 19.0634.43 13.35 200 watts 90/45 21.18 16.94 250 watts 110/55 23.7441.70 17.38 STREET LIGHTS UTILITY RATE SCHEDULE E-14 (Continued) CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-2016 Supersedes Sheet No. E-14-2 dated 7-1-2009 Sheet No. E-14-2 Light Emitting Diode (LED) Lamps 70 watts-equivalent 23.79 100 watts-equivalent 25.44 150 watts-equivalent 26.96 250 watts 31.12 STREET LIGHTS UTILITY RATE SCHEDULE E-14 (Continued) CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-01-2009 Supersedes Sheet No. E-14-2 dated 7-1-20097-01-2008 Sheet No. E-14-2 STREET LIGHTS UTILITY RATE SCHEDULE E-14 (Continued) CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2009 Supersedes Sheet No. E-14-4 dated 7-1-20097-1-2008 Sheet No. E-14-4 D. SPECIAL CONDITIONS: 1. Type of Service: This schedule is applicable to series circuit and multiple street lighting systems to which the Utility will deliver current at secondary voltage. Unless otherwise agreed, multiple current will be delivered at 120/240 volts, three-wire, single-phase. In certain localities the Utility may supply service from 120/208 volt star-connected poly-phase lines in place of 240-volt service. Single phase service from 480-volt sources will be available in certain areas at the option of the Utility when this type of service is practical from the Utility's engineering standpoint. All currents and voltages stated herein are nominal, reasonable variations being permitted. New lights will normally be supplied as multiple systems. 2. Point of Delivery: Delivery will be made to the customer's system at a point or at points mutually agreed upon. The Utility will furnish the service connection to one point for each group of lamps, provided the customer has arranged his system for the least practicable number of points of delivery. All underground connections will be made by the customer or at the customer's expense. 3. Switching: Switching will be performed by the Utility (on the Utility's side of points of delivery) and no charge will be made for switching provided there are at least 10 kilowatts of lamp load on each circuit separately switched, including all lamps on the circuit whether served under this schedule or not; otherwise, an extra charge of $2.50 per month will be made for each circuit separately switched unless such switching installation is made for the Utility's convenience or the customer furnishes the switching facilities and, if installed on the Utility's equipment, reimburses the Utility for installing and maintaining them. 4. Annual Burning Schedule: The above rates apply to lamps which will be turned on and off once each night in accordance with a regular burning schedule agreeable to the customer but not exceeding 4,100 hours per year for all-night service and 2,050 hours per year for midnight service. 5. Maintenance: The rates under Class C include all labor necessary for replacement of glassware and for inspection and cleaning of the same. Maintenance of glassware by the Utility is limited to standard glassware such as is commonly used and manufactured in reasonabl y large quantities. A suitable charge will be made for maintenance of glassware of a type entailing unusual expense. Under Class C, the rates include maintenance of circuits between lamp posts and of circuits and equipment in and on the posts, provided these are all of good standard construction; otherwise, the Utility may decline to grant Class C rates. STREET LIGHTS UTILITY RATE SCHEDULE E-14 (Continued) CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-20167-1-2009 Supersedes Sheet No. E-14-4 dated 7-1-20097-1-2008 Sheet No. E-14-4 Class C rates applied to any agency other than the City of Palo Alto also include painting of posts with one coat of good ordinary paint as required to maintain good appearance but do not include replacement of posts broken by traffic accidents or otherwise. 6. Multilamp Electroliers: The above charges are made on per-lamp basis. For posts supporting one or more lamps, where the lamps are less than nine feet apart, the above charges for Class C will be reduced by 6 percent (6%) computed to the nearest whole cent, for all lamps other than the first one. 7. Operating Schedules Other Than All-Night and Midnight: Rates for regular operating schedules other than all-night and midnight will be the midnight rates plus or minus one-eleventh of the difference between the midnight and the all-night rate, computed to the nearest whole cent, for each half hour per night more or less than midnight service. This adjustment will apply only to lamps on regular operating schedules which do not exceed 4,500 hours per year. 8. Street Light Lamps, Standard and Nonstandard Ratings: The rates for incandescent lamps under Class A are applicable for service to regular street lamps only and must be increased by 6 percent, computed to the nearest whole cent, for service to group-replacement street lamps. The rates under Class C are applicable to both regular and group -replacement street lamps. 9. Continuous Operation: The rate for continuous 24-hour operation under Class A service will be twice the all-night rate. 10. . System Owned In-Part by Utility : Where, at customer's request, the Utility installs, owns, and maintains any portion of the lighting fixtures, supports, and/or interconnecting circuits, an extra monthly charge of one and one-fourth percent of the Utility's estimate of additional investment shall be made. 11. Rates For Lamps Not on Schedule: In the event a customer installs a lamp which is not presently represented on this schedule, the Utility will prepare an interim rate reflecting the Utility's estimated costs associated with the specific lamp size. This interim rate will serve as the effective rate for billing purposes until the new lamp rating is added to Schedule E-14. {End} UNMETERED ELECTRIC SERVICE UTILITY RATE SCHEDULE E-16 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-201610-16-2012 Supersedes Sheet No.E-16-3 dated 10-16-20127-26-2011 Sheet No. E-16- 1 A. APPLICABILITY: This rate schedule is applicable under the terms and conditions of the City of Palo Alto Utilities Department to Customers who contract with the City for unmetered electric service for billboards, unmetered telephone services, telephone booths, railroad signals, cathodic protection units, traffic cameras, wireless antenna and related equipment, community antenna television and video systems, cable TV power supplies, and automatic irrigation systems and also applies to other miscellaneous Electric Utility fees to various public agencies and private entities. B. TERRITORY: Within the incorporated limits of the City of Palo Alto and land owned or leased by the City. C. NET MONTHLY BILL: 1. Customer Charge: ............ $9.00 per month 2. Energy Charge: (for all kWh supplied) using Electric Rate Schedule E2 plus all applicable riders 3. Minimum Charge: Minimum monthly charge will be the Customer Charge. D. DETERMINATION OF ENERGY REQUIREMENTS: a. Initial Inventory Customer shall enter into a contract for service under this Schedule and provide a written inventory of all equipment at each of service requested, including the type and nameplate rating for each piece of equipment. The billing energy for each point of service will be determined by the Utilities Electric Engineering Division estimation of the kWh usage based on the type, rating and quantity of the equipment provided by the Customer. Monthly bill will be based on the following calculations: 1. Total Wattage. 2. Total Wattage times estimated annual operating hours as set in the contract equals annual watt hours. 3. Annual watt hours divided by 1000 hours equals annual kilowatt hours (kWh) UNMETERED ELECTRIC SERVICE UTILITY RATE SCHEDULE E-16 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-201610-16-2012 Supersedes Sheet No.E-16-3 dated 10-16-20127-26-2011 Sheet No. E-16- 2 4. Annual kWh divided by twelve (12) months equal monthly kWh. 5. Monthly kWh times current rate per kWh = monthly bill for each unmetered service location or equipment. b. Updating Inventory Customer will update its inventory by informing the Utilities Electric Engineering Division in writing of changes in type, rating and/or quantity of equipment as such changes occur, and billings will be adjusted accordingly. Upon Utilities Electric Engineering Division request, but no later than the one year anniversary of the date on which Customer first takes service, Customer shall provide an updated inventory of all equipment at each point of service. c. Test Metering The Utilities Electric Engineering Division may, at its discretion, test meter the load at various types and ratings of the Customer’s equipment to the extent necessary to verify the estimated kWh usage used for billing purpose and, where dictated by such test metering, Utilities Electric Engineering Division will make prospective adjustments in estimated usage for subsequent billing purposes; however, Utilities shall be under no obligation to test meter- the load of Customer’s equipment. Utilities’ decision not to test meter the load of Customer’s equipment shall not release Customer from the obligation to provide to Utilities Electric Engineering Division, and to update, annually as provided in section b, an accurate inventory of the types, rating and quantities of equipment upon which billing is based. d. Inspection The Utilities Electric Engineering Division shall endeavor to inspect the equipment at each point of service annually as close to the anniversary date of the contract as is practical, and make prospective adjustments in billing as indicated by such inspections; however, Utilities shall be under no obligation to conduct such inspections for the purpose of determining accuracy of billing or otherwise. Utilities decisions not to conduct such inspections shall not release Customer from the obligation to provide to Utilities Electric Engineering Division, and to update, an accurate inventory of the types, rating and quantities of equipment upon which billing is based. e. Billing for Service As the service described in this schedule is unmetered, Customer agrees to pay amounts billed in accordance with the current inventory, regardless of whether any of the installations of the Customer’s equipment were electrically operable during the period in UNMETERED ELECTRIC SERVICE UTILITY RATE SCHEDULE E-16 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-201610-16-2012 Supersedes Sheet No.E-16-3 dated 10-16-20127-26-2011 Sheet No. E-16- 3 question and regardless of the cause of such equipment failure to operate. E. MISCELLANEOUS RATES: Service Description Rate * 1. Traffic Signal maintenance and energy costs (A) Controller $522.26 ea (B) 8" Lamp (LED) $1.85 ea (C) 12" & PVH Lamp (LED) $2.16 ea (D) Pedestrian Head (LED) $5.58 ea (E) Vehicle, System and Bike Sensor Loop $43.22 ea 21. License Fee for Electric Conduit Usage (A) Exclusive use $1.94/ft/yr (B) Non-Exclusive use $0.97/ft/yr 32. Processing Fee for Electric Conduit Usage Actual Cost 43. License Fee for Utility Pole Attachments (A) 1 ft. of usable space $29.59/pole/yr (B) 2 ft. of usable space $32.39/pole/yr (C) 3 ft. of usable space $35.18/pole/yr (D) 4 ft. of usable space $37.98/pole/yr 54. Processing Fee for Utility Pole Attachments $55.00/pole 65. License Fee for mounting communication equipment including distributed antenna systems on utility poles $270.00/pole/yr * Rates are monthly unless otherwise indicated. F. NOTES: The fees set forth in Section E.1 through E.65, inclusive, are subject to adjustment annually in accordance with fluctuations in the Consumer Price Index (CPI), if any. The base for computing UNMETERED ELECTRIC SERVICE UTILITY RATE SCHEDULE E-16 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-201610-16-2012 Supersedes Sheet No.E-16-3 dated 10-16-20127-26-2011 Sheet No. E-16- 4 the adjustment is the Consumer Price Index for All Urban Consumers (CPI-U) for the San Francisco-Oakland-San Jose MSA, which is published by the U.S. Department of Labor, Bureau of Labor Statistics for the month of December of a base year, which falls within the year in which a master license agreement is signed by the City and the licensee. The adjustment shall be calculated, if there is an increase or decrease between December of a base year (when the rate(s) is/are first applicable) and December of any subsequent base year. {End} Page 1 of 15 2 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: April 12, 2016 SUBJECT: Staff Request that the Utilities Advisory Commission Recommend that City Council Approve the Proposed Net Energy Metering Successor Rate E-EEC-1 and Net Energy Metering Grandfathering Policy REQUEST Staff requests that the Utilities Advisory Commission (UAC) recommend that the City Council adopt: 1. The proposed net energy metering (NEM) successor rate structure E-EEC-1 (Attachment A); and 2. The following grandfathering provisions for eligible NEM customers: a. Establish a 20-year transition period from the time of system interconnection through which NEM customers will remain eligible for net metering and related terms and conditions described in California Public Utilities Code Section 2827, and b. Allow NEM customers to expand their systems by up to 10% of the original system size while still remaining eligible for net metering after the NEM cap has been reached. EXECUTIVE SUMMARY Net energy metering (NEM) is a billing mechanism designed to promote the installation of renewable distributed generation by allowing customers to be compensated at the full retail rate for electricity generated by their on-site systems, such as solar photovoltaic (solar PV) systems. Under the City’s current rates, NEM customers can reduce, or completely avoid, charges on their electric utility bill while still remaining interconnected with the electric grid and utilizing grid services. State law requires all electric utilities to offer NEM to customers with eligible renewable distributed generation up to a maximum cap, or “NEM cap”, which in Palo Alto is 9.5 megawatts (MW). The set of terms and conditions for on-site renewable generation installed after the NEM cap is reached is referred to as the “NEM successor rate” or “NEM successor program.” As of mid-February, the City of Palo Alto Utilities (CPAU) was approximately 79% toward meeting the NEM cap, and could exceed it by the end of 2016. Page 2 of 15 As Utilities across the state approach their respective NEM caps, NEM successor rates are a topic of much debate. To help guide staff efforts on the NEM successor rate development, City Council adopted NEM Successor Program Design Guidelines in January 2016. Under the proposed NEM successor rate, customers would receive a credit for all electricity sent to the grid (when instantaneous on-site generation is greater than instantaneous on-site consumption), and they would be billed at the prevailing retail rate for all electricity drawn from the grid (when instantaneous on-site consumption is greater than instantaneous on-site generation). The proposed value of the credit for energy sent to the grid is 7.485 cents per kilowatt-hour (kWh), which compensates the customer for the energy, avoided capacity charges, avoided transmission/ancillary service charges, avoided transmission and distribution system losses, and environmental attributes. The energy value takes into account that solar energy is often generated at times of the state’s peak system demand. If approved, the credit would take effect July 1, 2016, and would be updated annually along with the budget. Based on staff analysis, the proposal will support continued solar PV deployment while ensuring that the City’s electric rates are based on the cost of providing service, in compliance with state constitutional requirements amended by Proposition 26 . In addition to the proposed NEM successor rate, staff also recommends adopting a grandfathering policy for customers with systems installed within the NEM cap. Specifically, staff proposes adopting a 20-year transition period from the time of interconnection through which NEM customers remain eligible for net metering under the terms set forth in California Public Utilities Code 2827. In addition, staff proposes allowing grandfathered customers to expand their systems by up to 10% of the original system size while still remaining eligible for net metering after the NEM cap has been reached. BACKGROUND Net energy metering was established in California in 1996 as a mechanism to support distributed energy generation such as solar PV (sometimes referred to as “customer-sited” or “behind-the-meter” generation). In 1999, Palo Alto began a solar PV demonstration program, through which the first net metered systems were installed in the City. At the time, the total system price was over $10 per watt. Solar PV system costs have dropped by 70% compared to the late 1990s. Page 3 of 15 Figure 1: Summary of NEM Participation (1999 through mid-February 2016) The California Public Utilities Code section on NEM requires all electric utilities to offer NEM to eligible customers with renewable distributed generation, up to a cap. In October 2015 Council formally adopted a NEM cap for Palo Alto of 9.5 MW (Staff Report 6139). As of mid-February 2016, the City is approximately 79% toward meeting its NEM cap, as shown in Figure 1. To date, all local solar PV installations in Palo Alto utilize NEM, and all net energy metered systems are solar PV systems. All NEM customers are subject to terms and conditions outlined in the California Public Utilities Code Section 2827, including the ability to receive credit for eligible on-site customer generation at the retail rate, to have the credits roll over month-to-month over a 12-month period, and the option to cash-out any net surplus generation that exists at the end of the 12- month period. NEM customers remain subject to Council-approved changes to their otherwise applicable electric rate schedules, including rate design changes and potential minimum or fixed charges. Assembly Bill 327 (AB 327) directed the California Public Utilities Commission (CPUC) to develop a standard NEM successor tariff for the state’s investor-owned utilities (IOUs) no later than December 31, 20151. For the IOUs, the NEM successor tariff is to take effect either after an IOU has reached its NEM cap or July 1, 2017, whichever occurs first. On January 28, 2016, in a split 1 http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201320140AB327 Page 4 of 15 3-2 decision, the CPUC approved a NEM successor tariff for IOUs that leaves NEM largely intact. The primary differences from the original NEM structure are that customers under the NEM successor rate are required 1) to pay an interconnection fee estimated to be $75-$150, 2) to be subject to certain non-bypassable charges on all energy delivered to the customer by the utility estimated to be 2-3 cents per kWh, and 3) to take service under a time-of-use rate if interconnecting from January 1, 2018, onward. The CPUC decision also establishes a 2019 review of the NEM successor tariff. Publicly-owned utilities (POUs) in California, whose rates are not regulated by the CPUC, are working with their respective governing bodies and stakeholders to formulate their own NEM successor rates, to take effect after their respective NEM caps have been reached. To staff’s knowledge, only two California POUs have adopted NEM successor rates: the City of Lompoc and Turlock Irrigation District (TID). In contrast to the CPUC-adopted NEM successor tariff for the IOUs, the POU-adopted NEM successor rates significantly modify the existing NEM program . More detailed information of the adopted NEM successor rates at California POUs is included in the Discussion section below. Local Solar Plan On April 22, 2014, the City Council adopted the Local Solar Plan (Staff Report 4608, Resolution 9402), which set the overarching goal of meeting 4% of the City’s total energy needs from local solar by 2023, corresponding to achieving 23 MW of solar PV installed in the City. Included within the Local Solar Plan is a strategy to develop proper policies, incentives, price signals and rates to encourage solar installation, including the exploration of cost-based rate structures that encourage the development of new solar systems in Palo Alto. Electric Cost of Service Analysis (COSA) CPAU carried out an electric cost of service analysis (COSA) in Winter 2015/2016. The primary goal of the COSA was to review the allocation of costs to customer classes and the electric rate design to ensure customers are charged according to the cost to serve them. The COSA also included a review of the rate design issues created by increasing numbers of local solar installations and the impact of rate designs on the economics of local solar for current and future customers. The NEM successor rate development was carried out in close coordination with the electric COSA. The proposed electric rate adjustments to be effective July 1, 2016 are described in the FY 2017 Financial Plan which is presented in an April 2016 UAC report. NEM Successor Program Design Guidelines & Stakeholder Feedback In order to guide research and development efforts, staff developed a set of design guidelines for the NEM successor rate, called the “NEM Successor Program Design Guidelines”. After receiving recommendations from the UAC and the Finance Committee, City Council formally adopted the NEM Successor Program Design Guidelines in January 2016 (Staff Report 6437). Through the stakeholder review process of the design guidelines, CPAU also received extensive feedback from the solar industry and advocates. The Energy Freedom Coalition of America (EFCA), a SolarCity-funded national advocacy group promoting public awareness and the Page 5 of 15 benefits of solar and alternative energy, provided extensive feedback on NEM and the proposed design guidelines in letters to the UAC, Finance Committee, and City Council preceding each step of the review process. The letter EFCA submitted to City Council is included as Attachment D. DISCUSSION Energy Flows in a Typical Residential PV System When a customer installs a solar PV system, the energy produced by the system first serves the customer load and is netted on-site. When the customer’s energy demand is greater than what is being generated by the solar system at that point in time, then the customer draws additional power from the grid to meet their energy needs. When the customer is using less energy than the solar PV system is generating, the excess energy is exported to the grid. This energy is referred to by a variety of terms including “energy sent to the grid,” “energy exports,” “surplus energy,” and “excess energy.” Figure 2 is an illustration of a daily load of a residential customer with a solar PV system that specifies the energy sent to the grid and the energy delivered by the utility. Page 6 of 15 Figure 2: (Top) Illustration of a residential solar customer’s load, solar production, and net load (Bottom) Illustration of the energy that is delivered by the utility to the customer and the energy that is sent to the grid NEM Successor Proposal Staff carried out a thorough evaluation of a broad variety of NEM successor rate design options considering the NEM successor design guidelines as well as conceptual and practical considerations of each option. Under the proposed NEM successor rate, customers would receive a credit for all electricity sent to the grid (energy generated in excess of instantaneous usage), and they would be billed at the prevailing retail rate for all electricity they use from the grid (energy used in excess of instantaneous generation). Large commercial customers, or customers with small PV systems relative to their overall load, may rarely or potentially never export energy to the grid. Residential customers, or customers with systems sized to meet a Page 7 of 15 large fraction of their load, typically export energy on a daily basis during hours of peak solar production. Figure 3 shows all three categories of energy, including the solar energy netted on-site (solar generation used directly on-site). Figure 3: Illustration of three categories of energy: solar energy netted on-site, energy sent to the grid, and energy delivered by the utility to the customer Under the staff proposal, over the course of a billing period, the sum of all energy delivered by the utility to the customer would be charged at the prevailing retail rate. For example, if the solar customer is a residential customer, the energy delivered by the utility in the billing period would be subject to the E-1 rate. In addition to the utility charges, the customer would also be credited for all energy sent to the grid. The sum of all energy exports would be credited at th e credit rate of 7.485 cents per kWh. If in a given billing period, the total credits applied to the customer’s utility bill for exported energy exceed the total charges applied for the energy delivered to the customer, the surplus credit will automatically apply to the customer’s bill. Please see Attachment C for an illustration of an example bill for a residential customer who installs a solar system subject to the proposed NEM successor rate. Value of the Credit Rate The value of the credit for energy sent to the grid is 7.485 cents per kWh. As shown in Figure 4, this value compensates the customer for the energy, avoided capacity charges, avoided transmission and ancillary service (AS) charges, avoided transmission and distribution (T&D) system losses, and renewable energy credits (RECs), or environmental attributes. The energy Page 8 of 15 component to the overall credit rate is calculated by taking wholesale monthly round-the-clock market price indicatives for northern California, and weighting them based on the typical generation profile of rooftop solar PV systems in Palo Alto and the hourly profile of market prices in northern California. In this way, the valuation methodology accounts for the fact that solar energy is often generated at times of peak system demand. Avoided transmission and AS charges are calculated based on the actual charges that the City pays to the California Independent System Operator (CAISO) for these services. And, the value of the environmental benefits is based on market price indicatives for the value of a “Bucket 1” REC. The 7.485 cents per kWh credit would take effect July 1, 2016, and would be updated annually and approved along with the budget. Figure 4: Value of credit rate Metering The proposed NEM successor rate structure requires a bidirectional meter. A bidirectional meter is a meter with two registers to measure energy flowing in each direction: the first register measures all energy drawn from the grid, while the second register measures all energy sent to the grid. For example, if a customer has a solar system and that system is generating energy that exceeds the instantaneous needs of the customer, energy is sent to the grid and measured on the second register of the bidirectional meter. For all other times when the energy generated by the solar system is not sufficient to meet the customer’s needs, then 3.02 1.45 0.58 2.00 0.44 0 1 2 3 4 5 6 7 8 Ce n t s p e r k W h ( ¢ / k W h ) T&D Losses Transmission/AS Capacity REC Energy Page 9 of 15 energy is drawn from the grid and measured on the primary register . Under the proposed NEM successor rate structure, at the end of the billing period, the sum of the energy drawn from the grid measured on the primary register is billed at the applicable retail rate. The sum of the energy sent back to the grid measured on the second register is credited to the customer’s account according to the credit rate. The usage that is directly served with simultaneous solar generation, the “solar energy netted on-site” shown in Figure 3, is not measured by the meter and, therefore, effectively avoids the full bundled retail rate. At present, the default meter type is a single-register meter. Therefore, a bidirectional meter must be installed at a customer premise upon the installation of a sola r PV system to implement the proposed NEM successor rate. These meters would be provided at no cost to the customer as part of CPAU’s long-term meter replacement plan. Environmental Attributes As described above, the credit rate for energy sent to the grid is calculated based on the value of the energy, avoided capacity costs, avoided transmission and ancillary services costs, avoided transmission and distribution system losses, and environmental attributes, or RECs. Thus, all of the exported energy and its environmental benefits would be bought by CPAU as a bundled product. Under this proposal, the customer therefore could not claim the environmental benefits of any of the energy that is sent to the grid. However, the customer would nonetheless still be able to claim they are “going solar” for all of the energy that is netted on-site, as shown in Figure 3. An alternative is for CPAU to value the energy sent to the grid at a rate that does not include the environmental benefits—effectively stripping the REC from the energy—and paying the customer only for “brown” energy, so that customers can claim the environmental attributes for all energy produced from their systems. The staff proposal is to set the credit rate for exports to include the value of the environmental attributes because it improves the customer economics, and the customer would still be able to claim the RECs for all energy netted on-site. Interconnection Fees Public Utilities Code Section 2827 prohibits electric utilities from charging existing eligible customer generators for interconnection costs incurred by the utility. For systems installed after the NEM cap is reached, customers will be subject to an interconnection charge set at the level to recover the utility’s cost of connecting them to the local distribution system . Staff is currently updating Utility Rate Schedule E-15 “Electric Service Connection Fees”2, which contain charges for generation interconnection. The current estimate for the interconnection fee that would apply to a NEM successor customer is a one-time charge of between $100-200. Staff plans to take Schedule E-15 forward for Council review in Fall 2016. Addressing the NEM Successor Program Design Guidelines in Relation to the Staff Proposal The development of the proposed NEM successor rate and potential alternatives was the result of a comprehensive evaluation guided by the Council-adopted design guidelines and the 2 The current version can be found here: http://www.cityofpaloalto.org/civicax/filebank/documents/8083. Page 10 of 15 stakeholder feedback received through that process. Attachment B discusses each of the design guidelines in relation to the staff NEM successor program proposal. Comparison to NEM Successor Rates Adopted in California and Across the Country Table 1 provides a high-level summary of the NEM successor rates that have been adopted in California and other states across the country. The most relevant comparison agencies to CPAU are the listed California POUs. Table 1: High-level Summary of Adopted NEM Successor Rates Utility/Regulatory Body Description of Adopted NEM Successor Rate Decision Date CPAU*, Staff Proposal All energy delivered by the utility charged at applicable retail rate, and all energy sent to the grid credited at short-term avoided cost export rate. Under review Turlock Irrigation District* Mandatory time-of-use rate that incorporates time-dependent demand and energy charges and standard fixed customer charge. Dec. 2014 City of Lompoc* Reverted to self-generation rate developed in the 1990s, which charges customers for distribution system costs for all energy generated and consumed on-site. Energy delivered to the customer charged at the applicable retail rate. All energy sent to the grid credited to customer at a wholesale rate. June 2014 Hawaiian PUC All energy delivered by the utility to the customer charged at applicable retail rate with a minimum monthly bill of $25, and all energy sent to the grid credited at a fixed, island-dependent export rate. Customer forfeits any surplus credit at the end of a monthly billing cycle. HPUC also approved another rate option that is available exclusively to customers with solar plus storage systems that do not export to the grid. Oct. 2015 California PUC Continuation of full retail rate compensation. NEM successor customers subject to interconnection charges (est. $75-$150) and certain non-bypassable charges on all energy delivered to the customer (est. 2-3 ¢/kWh). Mandatory time-of-use rate in 2018. Planned NEM successor tariff review in 2019. Jan. 2016 Nevada PUC All energy delivered by the utility charged at applicable retail rate, and all energy sent to the grid credited at a fixed energy rate. Feb. 2016 Modesto Irrigation District* TBD Planned: March 2016 * Subject to Proposition 26 Page 11 of 15 Implications of Proposal on Solar Adoption in Palo Alto Staff’s analysis indicates that the proposed NEM successor rate will continue to promote solar adoption due to the following factors: the proposed NEM successor rate continues retail rate compensation for a significant fraction of the energy generated, solar PV system costs continue to decline year-over-year, the federal investment tax credit for 30% of the total system costs was extended until 2020, and customers can load-shift to enhance the economics of their on- site system if desired. Under this NEM successor proposal, staff expects to still achieve the Council-adopted Local Solar Plan goal of achieving 4% of the City’s energy needs from local solar by 2023. Customer Economics The customer economics of a solar PV system adopted under the proposed NEM successor rate are dependent on a number of factors including: 1) the fraction of energy exported to the grid versus used immediately on-site, 2) the total solar PV system costs, 3) available federal incentives, and 4) other tax implications. Each of these factors is discussed in greater detail below. 1. Fraction of energy exported to the grid vs. used on-site Customers that rarely export energy to the grid would have similar customer economics to systems installed within the NEM cap. On the other hand, if the fraction of energy sent to the grid is significant, it may impact the customer economics. Based on an analysis of CPAU’s NEM solar customers, existing large commercial customers with solar systems rarely export. Therefore, the staff proposal is effectively a continuation of NEM. Given CPAU lacks full advanced meter deployment, residential solar customer data is more limited. The 2013 CPUC- commissioned study of NEM in the IOU service territories indicated that on average 49% of energy from residential systems is exported to the grid from their NEM customers3. Given the higher export fraction for residential customers based on typical load patterns, other economic factors discussed below may become more significant. Furthermore, under the proposed NEM successor rate, customers may decide to load-shift to consume energy concurrently with the solar generation, for instance by installing a behind-the-meter storage system or utilizing programmable or controllable loads. Load-shifting could reduce the fraction of energy exported to the grid and therefore increase the economic return of their solar system. 2. Solar PV system costs As shown in Figure 5, the total solar PV system price has declined substantially in the past decades. As discussed in the report referenced in the figure caption, in the early years, the system price decline is attributed primarily to falling solar PV module costs. Since 2012, given the relatively constant price of solar modules, the recent declines are due to reductions in other total system cost components, including, system design, installation, permitting, interconnection, and marketing and customer acquisition. Industry experts indicate there is 3 Draft Net Energy Metering Cost-Effectiveness Evaluation, E3 (2013). (See https://ethree.com/documents/CSI/CPUC_NEM_Draft_Report_9-26-13.pdf accessed February 26, 2016) Page 12 of 15 opportunity for further cost reductions and forecast continued price declines in the coming three to five years. Figure 5: Installed prices for residential and non-residential solar systems in the U.S.4 3. Federal incentives for solar Significant federal incentives remain available for both commercial and residential projects. In mid-December 2015, the federal investment tax credit (ITC), which was set to drop from 30% to 10% for commercial systems and to 0% for residential systems at the end of 2016, was extended at the full 30% through the end of 2019, and will be phased downward year-by-year to 10% for commercial projects and 0% for household-owned residential projects in 2022. Commercially-owned projects also receive accelerated depreciation treatment, which, when combined with the 30% ITC, is estimated to make up over 40% of the total system costs5. 4. Other tax implications In addition to the ITC, the tax implications for customer-cited generation installed under the NEM successor rate structure may differ from a system installed within the NEM cap, and may therefore impact the customer economics. Any solar customer under the NEM successor rate who within a given calendar year receives over $600 in payments from CPAU for energy sent to the grid will receive a 1099 tax form. This is equivalent to how CPAU handles compensation paid to customers who elect to cash out their net surplus electricity after a 12-month period. Customers are encouraged to consult their tax advisor or legal counsel regarding tax implications for any distributed energy system, including those installed within the NEM cap or after the NEM cap has been reached. 4 Source of Figure 5 is Tracking the Sun, an annual solar PV cost tracking report produced by the Department of Energy’s Lawrence Berkeley National Laboratory. (See http://newscenter.lbl.gov/2015/08/12/solar-prices-fell- 2015/ accessed February 26, 2016) 5 Private Net Benefits of Residential Solar PV: The Role of Electricity Tariffs, Tax Incentives and Rebates, S. Borenstein (2015). (See https://ei.haas.berkeley.edu/research/papers/WP259.pdf accessed February 29, 2016) Page 13 of 15 Proposed Grandfathering Policy for Customers within the NEM Cap Transition Period In March 2014, the CPUC ruled that for the IOUs, existing NEM customers and all those who install eligible systems within each IOU’s respective NEM cap are eligible for full retail rate compensation through a 20-year transition period from the date of interconnection. The length of the transition period was determined in part based on an assessment of expected useful life, as indicated by module warranties, power purchase agreements, and third-party financing agreements. To staff’s knowledge, no California POU has adopted a specified time frame that NEM customers remain eligible for NEM. To help promote regulatory certainty and transparency for existing NEM customers who have invested in solar PV systems and for solar developers operating in Palo Alto, staff proposes that existing NEM customers and all eligible customers within the NEM cap in CPAU service territory remain eligible for NEM through a 20- year transition period from the date of system interconnection, matching the transition period adopted by the CPUC for the IOUs. System Expansions Some customers who install systems within the NEM cap may wish to expand their systems after the NEM cap has been reached. The circumstances under which the system could be expanded and remain eligible for NEM is covered by the NEM grandfathering policy. Staff proposes that if the existing NEM system is modified or repaired after the NEM cap is reached, the customer will remain eligible for NEM as long as the system does not increase by more than 10% of the original system size. If the system modification or expansion results in an increase of over 10% of the original system size, the customer would be required to transition to the NEM successor program for the entire system capacity. Allowing system expansion up to a given threshold is broadly in-line with system expansion policies established in the California IOU service territories and Turlock Irrigation District, as shown in Table 2. Adopting this policy would allow a customer to expand their system by a few panels or to replace panels that failed prematurely with higher efficiency panels while still remaining eligible for NEM under the original program terms. Table 2: Existing policies of California utilities for system expansions after the NEM cap has been reached. Utility Description of System Expansion Policy CPAU, Staff Proposal Customers remain eligible for NEM for system expansions within 10% of the original system size. Larger system expansions require the entire system capacity to be transitioned to the NEM successor rate. Turlock Irrigation District Residential customers whose original system size is less than 10 kW may increase their system up to 11 kW total. Residential customers with an original system size of 10 kW or greater and non-residential customers may increase their system by a maximum of 10%. For expansions beyond these thresholds, the customer must transition the entire system capacity to the NEM successor rate. City of Lompoc No existing policy for system expansions. Pacific Customers may increase the system size up to 10% of the original system size or 1 Page 14 of 15 Utility Description of System Expansion Policy Gas & Electric kW, whichever is greater, and remain eligible for NEM. Customers who wish to expand their systems more may either 1) Meter the added capacity separately under the NEM successor tariff, or 2) elect for the entire system to take service under the NEM successor tariff. San Diego Gas & Electric Customers may increase the system size up to 10% of the original system size and remain eligible for NEM. Customers who wish to expand their systems beyond 10% may either 1) meter the added capacity separately under the NEM successor tariff, or 2) elect for the entire system to take service under the NEM successor tariff. Southern California Edison Customers may increase the system size up to 10% of the original system size or 1 kW, whichever is greater, and remain eligible for NEM. Customers who wish to expand their systems more may either 1) Meter the added capacity separately under the NEM successor tariff, or 2) elect for the entire system to take service under the NEM successor tariff. NEXT STEPS The tentative timeline for the review and approval of NEM-related policies and rates is shown below. Tentative Timeline for Review and Approval of NEM-Related Policies and Rates Description UAC Finance Committee Council Proposed NEM Successor Rate and Grandfathering Policy April 2016 May 2016 June 2016 Update to Net Metering Net Surplus Electricity Compensation Rate (E-NSE-1) June 2016 -- July 2016 RESOURCE IMPACT Staff has developed an implementation plan to be executed upon adoption of the NEM successor rate to help ensure that CPAU will be ready for customers who install eligible renewable energy systems after the NEM cap has been reached. Implementation of the proposed NEM successor rate requires modifications to current business systems and processes including installing bidirectional electric meters, programming of meter reading devices, training meter reading staff, modifying the format of electric Utilities bills, and revising electric usage billing calculations. Furthermore, all staff must be trained in these new systems and processes. At present, all modifications to systems and processes are planned to utilize existing staff and budget resources. The proposed NEM successor rate is based on the cost to serve, and the credit value would be updated annually to reflect the market value of solar energy, value of the RECs, avoided capacity charges, avoided charges for transmission and ancillary services, and avoided transmission and distribution system losses. Therefore, there would be no direct financial resource impact for eligible systems installed under staff’s proposed NEM successor program. POLICY IMPACT Fulfilling Palo Alto's NEM legislati ve requirements and adopting the proposed NEM successo r program are consistent with the California Public Utilities Code and state constitutional requi rements regarding cost-based rates. Furthermore, adopting a NEM successor rate will add greater market certainty for those interested in installing rooftop solar PV after the NEM cap has been reached. The proposed policy directly supports Strategy #2 of the Local So lar Plan, to "develop proper policies, incentives, price signals and rates to encou r age solar installation". Furthermore, staff analyses indicates the proposed NEM successor rate will support continued uptake of distributed renewable energy technologies in Palo Alto, which further supports the Carbon Neutral Plan, the Local Solar Plan, and the City's broader environmental sustainability goals, including those set out in the 2011 Utilities Strategic Plan and the 2007 Climate Protection Plan. ENVIRONMENTAL IMPACT The UAC's review of staff's proposed NEM successor program and grandfathering pol icy does not meet the California Environmental Quality Act's (CEQA) definition of "project" under California Public Resources Code Sec . 21065, thus no environmental review is required. ATTACHMENTS A. Proposed Net Energy Metering Successor Rate Schedule E-EEC-1 B. Implementation of Council-Adopted Net Energy Metering (NEM) Successor Program Design Guidelines C. Bill Illustration for Residential Customer with Solar PV System under the Proposed NEM Successor Rate D. Energy Freedom Coalition of America Comments to Pa lo Alto City Council PREPARED BY: REVIEWED BY: APPROVED BY: AIMEE BAILEY, Resource Planner ~crt Director, Resource Management EDSHIKADA Assistant City Manager/Interim Director of Utilities Page 15of15 EXPORT ELECTRICITY COMPENSATION UTILITY RATE SCHEDULE E-EEC-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Effective 7-1-2016 Sheet No.E-EEC-1 A. APPLICABILITY: This schedule applies in conjunction with the otherwise applicable rate schedules for each customer class. This schedule may not apply in conjunction with any time-of-use rate schedule. This schedule applies to Customer-Generators as defined in Rule and Regulation 2 who are either not eligible for Net Energy Metering or who are eligible for Net Energy metering but elect to take service under this rate schedule. B. TERRITORY: Applies to locations within the service area of the City of Palo Alto. C. RATE: The following buyback rate shall apply to all energy exported to the grid. Per kWh Export electricity compensation rate $0.07485 D. SPECIAL CONDITIONS 1. Metering equipment: Electricity delivered by CPAU to the Customer-Generator or received by CPAU from the Customer-Generator shall be measured using a meter capable of registering the flow of electricity in two directions (aka “bidirectional meter”). The electrical power measurements will be used for billing the Customer-Generator. CPAU shall furnish, install and own the appropriate meter. 2. Billing: a.CPAU shall measure during the billing period, in kilowatt-hours, the energy delivered and received after the Customer-Generator serves its own instantaneous load. b. CPAU shall bill the Customer-Generator consumption charges for the energy delivered by CPAU to the Customer-Generator based on the Customer-Generator’s applicable rate schedule. c.In the event the energy generated exceeds the energy consumed and therefore is received by CPAU, the Customer will receive a credit for all energy received by CPAU at the buyback rate designated in section C above. 3. Generation facilities shall adhere to Rule and Regulation 27: Generating Facility Interconnections. {End} ATTACHMENT A Attachment B Page 1 of 3 Implementation of Council-Adopted Net Energy Metering (NEM) Successor Program Design Guidelines Guideline 1. Rates must be based on the cost to serve customers. This is the overriding principle for the NEM Successor Program development; all other design considerations are subsidiary to this basic premise. Based on the assessment completed by the City’s electric cost of service study consultant and staff, the proposed NEM successor rate is based on the cost to serve. Guideline 2. Consider and evaluate program options that compensate customers fairly and equitably for local renewable energy production. The combination of tiered, electric rate structures and NEM make solar installations on high- energy consuming households considerably more cost -effective compared to low- or average- energy consuming households. This combination hinders solar adoption by households that have average or low electricity consumption achieved through conservation and energy efficiency measures. The proposed NEM successor rate, which provides a flat rate based on the utility’s avoided cost for any energy exported to the grid, provides equitable and fair compensation to customers. Any energy generated that is used immediately on-site would effectively receive retail rate compensation for avoided energy purchases, similar to how a customer would be compensated for implementing an energy efficiency measure. Guideline 3. Consider and evaluate compensating solar participants at a rate equivalent to the value of solar to Palo Alto via “value of solar tariff”. A “value of solar tariff” is a rate design in which customers are compensated at a specified rate for all generation produced from their on-site systems. On-site consumption is metered separately and charged in full at the applicable retail rate for that customer class. It is often referred to as a “buy-all, sell-all” rate option, where no energy is netted on-site as is the case with the staff proposal. The compensation rate for the on-site generation would be based on the value of local solar energy generation calculated using avoided cost models that are utilized in all of the City’s resource acquisition and financial planning. An advantage of the value of solar tariff design is that it utilizes a standardized and transparent framework for valuing distribu ted generation that would be updated regularly. Staff ultimately did not propose a “value of solar tariff” option for two reasons. First, the customer may feel unsatisfied that generation from a solar PV system is not counted on a kilowatt-hour basis toward reducing on-site consumption, as is the case with an energy efficiency measure. Second, this option would require installing a second meter at the customer premise to measure all generation from the on-site system, adding cost and requiring significant changes to current processes and systems to implement. Attachment B Page 2 of 3 Guideline 4. Consider and evaluate the impact on the concurrent adoption of on-site generation and other demand-side technologies. Many of the same motivations that drive the adoption of solar PV may also drive customers to adopt other advanced energy technologies, such as electric vehicles (EVs), energy storage, smart thermostats, and building energy management systems. Staff evaluated the impact of the concurrent adoption of a solar PV system under the proposed NEM successor rate and other demand-side technologies. The NEM successor rate proposal provides an economic incentive for customers to load-shift to use energy from a solar PV system as it is being generated, prior to being exported to the grid. Customers could load-shift manually by changing behavior patterns, but more likely will utilize programmable and controllable loads, such as one or more of those listed above. Regarding energy storage in particular, currently the market for storage systems for residential customers in Palo Alto is extremely limited. CPAU has offered a pilot time-of-use rate1 to approximately 120 residential customers through the CustomerConnect advanced metering pilot program. However, the price differential between summer peak usage compared to summer off-peak usage is 7.64 cents per kWh, which is not sufficiently high to make behind- the-meter energy storage cost-effective based on current storage cost estimates, excluding any other potential benefits beyond energy arbitrage (charging the battery when the retail rate is lower and discharging to meet energy needs when the retail rate is higher). The proposed NEM successor rate would provide 9.416 cents per kWh differential that could be captured by energy arbitrage, which is the difference between the value of exported energy and the highest residential rate tier, thus increasing the value stream to prospective storage systems and expanding the storage market beyond the CustomerConnect pilot participants. Staff plans t o bring forward an updated energy storage assessment for review in 2017, which will evaluate a variety of use cases, including residential and non -residential applications. Furthermore, staff is currently evaluating responses to a competitive solicitation called “Solutions to Leverage the Value of Distributed Energy Resources within the City of Palo Alto”, some of which could utilize behind-the-meter storage, in addition to other advanced energy technologies discussed above. Guideline 5. Consider and evaluate the likely impact on the rate of solar adoption and implications for meeting the Local Solar Plan goal. The overarching Local Solar Plan goal is to meet 4% of the City’s load from local solar by 2023, which translates to achieving 23 MW of installed local solar PV capacity. As discussed in the 2015 update on the Local Solar Plan (Staff Report 6649), the Local Solar Plan goal could be achieved with current and planned programs, existing incentives, and realistic forecasts for falling solar system prices. The analysis supported that the City could meet the goal without expanding rebates or NEM incentives beyond the 9.5 MW cap. Since that time, the 30% federal ITC was extended through the end of 2019, which provides substantial unexpected support for solar deployment. Palo Alto’s progress toward meeting the Local Solar Plan goal will be reevaluated on an ongoing basis as new policies and programs come forward for review. 1 http://www.cityofpaloalto.org/civicax/filebank/documents/32678 Attachment B Page 3 of 3 Guideline 6. Consider the ease of marketing and communicating the program to customers. Utilities customers are increasingly seeking more detailed information regarding their energy usage and costs, which makes communications and marketing considerations a primary concern in the development of rates and programs. During the research and development of a NEM successor rate, staff evaluated all rate options based on a number of criteria, including specifically the ease of marketing and communication. Utilities communications and marketing staff have assessed the proposed NEM successor rate and did not identify any significant communications-related barriers for the proposed program. Furthermore, at this point in time, staff does not anticipate needing additional resources for NEM successor program marketing and outreach efforts. Guideline 7. Assess technology constraints of program implementation. The seventh design guideline was to assess all technology constraints for implementing the proposed NEM successor rates and alternatives, along with associated staff and budget resource impacts. Staff evaluated a broad variety of NEM successor rate options and identified compatibility of each to CPAU’s existing systems and processes, such as the customer information and billing system and metering infrastructure. A mandatory time-of-use rate is not recommended because of the substantial resource impact of manually implementing such a rate prior to having full advanced metering infrastructure (AMI) deployment and a billing system capable of automatically processing the bills. AMI is identified as a long-term rate design issue for the electric COSA, and evaluation of time-of-use and other rate structures that AMI enables will be evaluated during Phase Two of the Electric COSA work plan. The NEM successor program will be revisited at that time in coordination with the COSA. Guideline 8. Consider and evaluate the impact on non-solar customers. The proposed NEM successor rate is based on the cost to serve, and the credit value would be updated annually to reflect the market value of solar energy, value of the RECs, avoided capacity charges, avoided transmission and distribution system losses, and avoided charges for transmission and ancillary services. Therefore, there would be no direct financial resource impact for eligible systems installed under the NEM successor. Attachment C Page 1 of 2 Bill Illustration for Residential Customer with Solar PV System under the Proposed Net Energy Metering (NEM) Successor Rate Table 1 below estimates the potential electric utility bill of a residential customer installing a solar photovoltaic (solar PV) system under the proposed Net Energy Metering (NEM) successor rate with a solar system sized to meet 50% of the customer’s energy usage on site. Each column is labelled as follows. 1. Total Energy Consumption (kWh): This column shows the customer’s total energy consumption on a monthly basis. This customer uses 12,184 kWh over the entire year, which is approximately two times the average residential consumption. 2. Solar Energy Production (kWh): This column shows the total energy generated from the customer’s solar PV system. This simplified example assumes that the customer sized the solar PV system to meet 50% of the total annual energy consumption shown in column 1. 3. Solar Energy Netted On-site (kWh): Under the proposed NEM successor rate, a customer’s solar PV generation will first meet simultaneous on-site energy needs, and then any excess energy generation is sent to the grid. This column shows the amount of energy that is netted on-site to meet instantaneous customer needs, which was estimated from analyzing hourly load data from the CustomerConnect advanced metering pilot and hourly generation data from the National Renewable Energy Laboratory’s PVWatts Calculator1. 4. Solar Energy Sent to the Grid (kWh): This column shows the amount of energy sent to the grid, summed over hours of the day when solar PV production exceeds on-site load. 5. Energy Delivered to Customer (kWh): This column shows the amount of energy delivered by the utility to the customer. This includes energy delivered at night and during times of the day when the customer’s on-site energy needs exceed the on-site solar PV generation. 6. Bill Charges for Energy Delivered: This column shows monthly bill charges to the customer after applying the proposed residential retail rate in the accompanying UAC report to the energy quantity shown in column 5. 7. Bill Credit for Energy Sent to the Grid: This column shows the monthly bill credits to the customer after applying the credit rate (7.485 ¢/kWh) to the energy quantity in column 4. 8. Monthly Bill with Solar: This column shows the customer’s monthly utility bill with their solar PV system under the NEM successor rate, after taking column 6 and subtracting column 7. During summer months, for some customers the credit for exported energy may exceed charges applied to the energy delivered to the customer, resulting in net credit. 9. Monthly Bill without Solar: This column shows what the customer’s monthly utility bill would have been without a solar PV system. The calculation takes the consumption in column 1 and applies the proposed residential retail rate. 10. Monthly Bill with Solar under NEM: This column shows what the monthly utility bill would be for a solar PV system installed within the NEM cap. The calculation takes the difference between total consumption and generation and applies the proposed residential retail rate. 1 http://pvwatts.nrel.gov/ Attachment C Page 2 of 2 Table 1: Bill Illustration of a Residential Customer with a Solar PV System under the Proposed NEM Successor Rate Month 1. Total Energy Consumption (kWh) 2. Solar Energy Production (kWh) 3. Energy Netted On-site (kWh) 4. Solar Energy Sent to the Grid (kWh) 5. Energy Delivered to Customer (kWh) 6. Bill Charges for Energy Delivered 7. Bill Credit for Energy Sent to the Grid* 8. Monthly Bill with Solar 9. Monthly Bill Without Solar 10. Monthly Bill with Solar Under NEM Jan. 1,400 327 244 84 1,156 $175 ($6) $169 $217 $161 Feb. 1,204 314 250 64 954 $143 ($5) $138 $184 $132 Mar. 1,061 519 309 210 752 $107 ($16) $91 $160 $72 Apr. 918 610 311 299 607 $83 ($22) $61 $136 $34 May 885 704 341 363 543 $72 ($27) $45 $130 $20 June 882 659 352 307 530 $70 ($23) $47 $130 $25 July 929 711 377 334 552 $73 ($25) $48 $138 $24 Aug. 894 582 312 270 582 $78 ($20) $58 $132 $34 Sept. 930 551 301 250 629 $87 ($19) $68 $138 $45 Oct. 943 467 266 201 677 $94 ($15) $79 $140 $60 Nov. 954 348 191 157 764 $110 ($12) $98 $142 $83 Dec. 1,184 299 198 101 985 $147 ($8) $139 $180 $130 Total: 12,184 6,092 3,452 2,640 8,732 $1,240 ($198) $1,042 $1,825 $820 *All credits shown in parentheses. Table 2: Annual Bill Comparison of Residential Customer with a Solar PV System Annual Bill Comparison for Customer Illustration Annual Bill with Solar under Proposed NEM Successor Rate (column 8) $1,042 Annual Bill with Solar under NEM (column 10) $820 Annual Bill Difference Between NEM and NEM Successor $220 Annual Bill without Solar (column 9) $1,825 December 30, 2015 City of Palo Alto, City Council 250 Hamilton Ave. Palo Alto, CA 94301 Re: Item #5, Finance Committee Recommendation that the City Council Approve Design Guidelines for the Net Energy Metering Successor Program – OPPOSE UNLESS AMENDED Dear Members of the City Council, Energy Freedom Coalition of America ("EFCA") is a national advocacy group that seeks to promote both the public awareness of the benefits of solar and alternative energy, as well as the use of rooftop and other customer-owned and third-party owned distributed solar electrical generation, for residential and commercial applications. EFCA applauds the City of Palo Alto Utilities’ (CPAU) effort to undertake a thorough and thoughtful process in developing a solar program that will continue to promote rooftop solar adoption for Palo Alto’s residents. However, the guidelines as currently written are incomplete and should not be approved. Before the City Council approves the proposed guidelines, we recommend adding a new guideline and expanding several of the current guidelines. New Guideline We strongly recommend that a new guideline be added, for a total of 7 guidelines. New Guideline: Evaluate the benefits and costs of continuing the NEM program without modification after the cap has been reached. CPAU has the authority to continue its NEM program after the cap has been reached, and should strongly consider this option. NEM is a simple, effective, and reliable payment mechanism that fairly compensates solar customers for the value their systems provide to the grid. NEM has been crucial to the widespread adoption of solar in California, and now exists in 44 states. In California, NEM has leveraged more than $10 billion in private investment, reduced electricity demand, and helped support more than 54,000 in-state jobs. Rooftop solar is vital to continue growing the clean energy economy, both locally and across the state, and to meeting the state’s ambitious clean energy goals. Continuing NEM will provide market certainty and predictability, and will help local homeowners, schools, and businesses to save on their electric bills while reducing greenhouse gas emissions. Moreover, NEM requires only a single meter, provides a form of compensation that is not subject to federal income tax, and gives customers the satisfaction of offsetting their own usage with renewable power. If changes to the current NEM program are considered, CPAU should examine changes that “phase-in” gradually over time. One of the most successful programs in the country for promoting rooftop solar at a reasonable cost was the California Solar Initiative, which was structured as a 10-year program with ATTACHMENT D incentives that stepped down gradually and predictably as the solar market grew in size. This program design worked well because the long-term nature of the program sent a signal to investors that the incentive regime would not change abruptly, while the gradual step-down of incentives aligned the incentive structure with the long-term solar cost trajectory. When designing any successor NEM tariff, CPAU should consider one that creates long-term stability and predictability for the market, rather than one that could be reviewed and changed on an ad hoc basis. Modifications to Existing Guidelines In addition to the new guideline listed above, we recommend several modifications to the existing guidelines. Current Guideline 1: Evaluate program options that compensate customers fairly and equitably for local renewable energy production. Proposed Guideline 1: Evaluate program options that compensate customers fairly and equitably for local renewable energy production. Consider environmental benefits, short-term and long-term system cost savings from behind-the-meter, and consistency with the objectives of AB 327. Behind-the-meter solar provides several benefits to the grid which results in reduced costs for all ratepayers. In the short-term, when a generation resource is located behind a customer’s meter, it is avoiding line losses when compared to more remote generation that is delivered across transmission and distribution facilities. In the long-term, distributed generation may enable a utility to avoid or defer large-scale capital transmission and distribution projects and associated maintenance and upgrades. CPAU’s NEM successor program should adequately take into account these avoided costs when assessing any perceived “cost-shift” between solar and non-solar customers. Should CPAU choose not to continue its current NEM program after the cap has been reached, the successor program should be aligned with the goals and requirements outlined in Assembly Bill 327 (AB 327). While AB 327 has directed the CPUC to adopt a successor program to NEM by 2016, the new program must ensure that (1) the total benefits of the new tariff must be equal to the total costs; and (2) customer-sited renewable distributed generation continues to grow sustainably. All NEM successor programs considered by CPAU should be consistent with these requirements. There are a number of changes that could be made to the existing NEM program, such as minimum bills for NEM customers that could address ratepayer equity issues while maintaining a viable NEM program that continues progress toward CPAU’s energy and climate goals. Current Guideline 2: Consider compensating solar participants at a rate equivalent to the value of solar to Palo Alto via “value of solar tariff.” Proposed Guideline 2: Consider compensating solar participants at a rate equivalent to the value of solar to Palo Alto via “value of solar tariff”. Thoroughly review both the positive and negative attributes of a “value of solar tariff”. A “value of solar tariff” (VOST) is a rate design in which customers are compensated at a specified rate based on the value of local solar energy generation for all generation produced from their on-site systems. Unlike NEM, a VOST does not allow a customer to consume their on-site generation before selling to the utility. While a VOST appears to be straight forward and transparent, it has many negative attributes. One primary issue is that a VOST creates a hidden tax for ratepayers, as the income paid to the solar customer by the utility for solar electricity may be subject to income tax, and in some cases may even make customers ineligible for the federal investment tax credit on their solar systems. The fact that VOSTs may be regularly updated also poses an issue, as this wavering rate guarantees regular market uncertainty that can be harmful to solar customers. Customers in states like Texas and Minnesota where VOSTs have been introduced have quickly seen the value compensated to them for their solar decline. While a VOST may appear to provide a fair market value to distributed generation, its many negative attributes make it a confusing and potentially harmful alternative to NEM. CPAU should carefully examine these issues before considering a VOST as a fair alternative to NEM. Current Guideline 5: Consider the ease of marketing and communicating the program to customers. Proposed Guideline 5: Consider the ease of marketing and communicating the program to new and existing customers. Prioritize a program design that is easy to understand, and does not harm existing NEM customers. NEM is a simple, easy to understand, and trusted program that has been in effect in California for almost two decades, making it the most established state incentive for solar and other distributed generation technologies. CPAU should carefully consider the significant customer outreach and education that will be necessary to minimize confusion and harm to behind-the-meter solar adoption should the NEM successor program differ significantly from the current NEM program. CPAU should ensure that any NEM successor tariff does not harm existing NEM customers. When customers make the substantial investment to buy a rooftop solar system, they typically assume that their electric rate and NEM compensation mechanism will not change for the life of the solar system. Requiring existing NEM customers to transition onto a new tariff will change the return on investment for those customers in a way most likely did not expect. The CPUC has approved a NEM transition period that allows current NEM customers to continue on their current NEM tariff for 20 years after their install date. The CPAU should carefully consider the impact on existing NEM customers when developing a successor tariff and should provide guidance on a transition plan. Palo Alto has long been a leader in innovative rate and program designs, and we hope this post-NEM program continues that trend. Thank you for taking comments on this important issue. We look forward to working with you as this process continues. Regards, Julia Jazynka Associate Energy Freedom Coalition of America, LLC Page 1 of 7 3 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: April 12, 2016 SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend that the City Council Adopt: (1) a Resolution Approving the Fiscal Year 2017 Gas Utility Financial Plan; and (2) a Resolution Increasing Gas Rates by Amending Rate Schedules G-1 (Residential Gas Service), G-1-G (Residential Green Gas Service), G-2 (Residential Master-Metered and Commercial Gas Service), G-2-G (Residential Master-Metered and Commercial Green Gas Service), G-3 (Large Commercial Gas Service), G-3-G (Large Commercial Green Gas Service). G-10 (Compressed Natural Gas Service) and G-10-G (Compressed Natural Green Gas Service) RECOMMENDATION Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council: 1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2017 Gas Utility Financial Plan (Attachment B); and 2. Adopt a resolution (Attachment C) increasing gas rates by amending Rate Schedules G-1 (Residential Gas Service), G-1-G (Residential Green Gas Service), G-2 (Residential Master-Metered and Commercial Gas Service), G-2-G (Residential Master-Metered and Commercial Green Gas Service), G-3 (Large Commercial Gas Service), G-3-G (Large Commercial Green Gas Service). G-10 (Compressed Natural Gas Service Service) and G- 10-G (Compressed Natural Green Gas Service) EXECUTIVE SUMMARY The FY 2017 Gas Utility Financial Plan includes projections of the utility’s costs and revenues for FY 2017 through FY 2026. Costs have risen over the past several years and revenues have not kept pace. Gas rates have not been adjusted since July 2012. A rate increase of 24% is required to increase revenues to cover projected FY 2017 costs, but staff proposes utilization of reserves and a series of rate increases over the next three years to minimize the impact to customers. The proposed FY 2017 Gas Utility Financial Plan includes an 8% gas rate increase on July 1, 2016 followed by rate increases of 9% and 7% in FY 2018 and FY 2019, respectively, so that revenues cover costs by FY 2019. In addition, the plan includes proposed transfers to the Operations Page 2 of 7 Reserve of $1.5 million and $5.3 million from the Rate Stabilization Reserve in FY 2016 and FY 2017, respectively, to ensure that there are appropriate financial reserves for contingencies . These actions will reduce the Rate Stabilization Reserve to zero by the end of FY 2017. Gas Utility expenses are projected to increase by roughly 4.4% annually from FY 2016 to FY 2026 due primarily to higher operations and maintenance expenses and increasing gas supply costs. In the short term, some of these costs are related to the cross-bore inspection program, as well as cap-and-trade allowance purchase costs. In addition, capital improvement program (CIP) costs have increased as the economy has improved. Gas supply costs are currently very low and can vary significantly, but are projected to rise steadily over the forecast horizon; however, those costs are passed on to customers with the monthly -varying, market-based commodity rate. Besides costs increases, the gas rate increase projections are also negatively affected by the downward trend in gas usage over the last several years. BACKGROUND Every year staff presents the UAC with Financial Plans for its Electric, Water, Gas, and Wastewater Collection Utilities and recommends any rate adjustments required to maintain their financial health. These Financial Plans include a comprehensive overview of the utility’s operations, both retrospective and prospective, and are intended to be a reference for UAC and Council members as they review the budget and staff’s rate recommendations. Each Financial Plan also contains a set of Reserves Management Practices describing the reserves for each utility and the management practices for those reserves. The UAC reviewed preliminary financial forecasts at its February 3, 2016 meeting. Staff has revised the preliminary projections presented at that meeting. DISCUSSION Staff’s annual assessment of the financial position of the City’s gas utility is completed to ensure adequate revenue to fund operations. This includes making long-term projections of market conditions, the physical condition of the system, and other factors that could affect utility costs, and setting rates adequate to recover these costs. The current rate proposals are also based on the cost of service methodology described in the 2012 Gas Utility Cost of Service Study completed by Utility Financial Solutions. Proposed Actions for FY 2016 This year’s Gas Utility Financial Plan includes the following proposed actions for FY 2016: 1. Reduce the $3.4 million transfer from the Rate Stabilization Reserve to the Operations Reserve proposed in the FY 2016 Gas Financial Plan to $1.5 million. Proposed Actions for FY 2017 This year’s Gas Utility Financial Plan also includes the following proposed actions for FY 2017: 1. Transfer $5.3 million from the Rate Stabilization Reserve to the Operations Reserve; and 2. Amend gas rate schedules (see Attachment D) to increase rates by approximately 8%. Page 3 of 7 The reserve transfers will enable staff to maintain sufficient funds in the Gas Operations Reserve levels while spreading the required rate increases for the gas utility over several years. These proposed actions are described in more detail in the FY 2017 Gas Financial Plan (Attachment B). Staff proposes to adjust gas rates as shown in Table 1 and Table 2, below, effective July 1, 2016. These changes are projected to increase the system average gas rate by roughly 8%. These rate changes are included in the proposed amended rate schedules in Attachment D. Table 1: Gas Consumption Charges in $/CCF (Current and Proposed) Current (7/1/12) Proposed (7/1/16) Change $/Therm % G-1 (Residential) Tier 1 Rates 0.4392 0.5021 0.0629 14.3% Tier 2 Rates 0.9546 1.0407 0.0861 9.0% G-2 (Residential Master-Metered and Small Commercial) Uniform Rate 0.6147 0.6855 0.0708 11.5% G-3 (Large Commercial) Uniform Rate 0.6071 0.6775 0.0704 11.5% G-10 (Compressed Natural Gas) Uniform Rate 0.0509 0.0963 0.0454 89.2% Table 2: Current and Proposed Monthly Service Charge Rate Schedule Monthly Service Charge ($/month) Change Current (7/1/12) Proposed (7/1/16) $/mo % G-1 (Residential) $9.88 $10.32 $0.44 4.5% G-2 (Res. Master-Metered and Small Commercial) $74.86 $78.23 $3.37 4.5% G-3 (Large Commercial) $361.18 $377.43 $16.25 4.5% G-10 (CNG) $50.65 $52.93 $2.28 4.5% Bill Impact of Proposed Rate Changes Table 3 shows the impact of the proposed July 1, 2016 rate changes on the median residential bill. The average increase is roughly 8% based on commodity prices in March 2016, but some customers may see slightly higher or lower increases due to slight changes in the composition of the utility’s costs, as well as prevailing market prices. Page 4 of 7 Table 3: Impact of Proposed Gas Rate Changes on Residential Bills Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change $/mo. % Winter (Using March 2016 commodity prices) 30 $ 29.67 $ 32.00 $ 2.33 8% 54 (median) 45.40 49.34 3.84 8% 80 72.96 78.89 5.94 8% 150 155.21 167.17 11.96 8% Summer (Using July 2015 commodity prices) 10 $ 17.70 $ 18.77 $ 1.07 6% 18 (median) 23.95 25.52 1.57 7% 30 38.49 41.05 2.56 7% 45 57.95 61.80 3.85 7% Table 4 shows the impact of the proposed July 1, 2016 rate changes on various representative commercial customer bills. Table 4: Impact of Proposed Gas Rate Changes on Commercial Bills (Using March 2016 commodity prices) Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change % G-2 (Residential Master-Metered and Small Commercial) 500 492 531 8% 5,000 4,250 4,608 8% 10,000 8,426 9,137 8% G-3 (Large Commercial) 25,000 21,049 22,825 8% 50,000 41,736 45,272 8% FY 2017 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years Table 5 shows the projected rate adjustments over the next five years and their impact on the annual median residential gas bill. Table 5: Projected Rate Adjustments, FY 2017 to FY 2021 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 Gas Utility 8% 9% 7% 4% 1% Estimated Bill Impact ($/mo)* $2.52 $3.19 $2.70 $1.65 $0.43 * estimated impact on median residential gas bill, which is currently $32.93. Changes from Prior Financial Forecasts After presenting the preliminary financial forecast to the UAC on February 3, 2016, continuing warmer winter weather has caused staff to lower its projections for FY 2016 sales and Page 5 of 7 revenues, and thus increase its FY 2017 rate projection from 7% to 8% as shown in Table 6 below. Staff has projected future gas rate increases for several years. Table 6 compares current rate projections to those projected in the last two year’s Financial Plans. As shown, the FY 2017 rate projections are somewhat higher than projected last year. In the FY 2015 Financial Plan, the reduction in gas usage due to warm weather and drought had not occurred and the additional costs for cross-bore investigations beyond FY 2017 had not been planned. Table 6: Projected Gas Rate Trajectory for FY 2017 to FY 2026 Projection FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Preliminary Financial Forecast (presented to the UAC in Feb. 2016) 7% 5% 5% 5% 3% N/A N/A N/A N/A N/A Current (FY 2017 Financial Plan) 8% 9% 7% 4% 1% 1% 1% 1% 1% 1% Last year (FY 2016 Financial Plan) 7% 4% 4% 4% 3% 3% N/A N/A N/A N/A Two years ago (FY 2015 Financial Plan) 0% 3% 3% 4% 3% N/A N/A N/A N/A N/A Gas Bill Comparison with Surrounding Cities Table 7 presents winter and summer residential bills for Palo Alto and PG&E at several usage levels for commodity rates in effect as of July 2015 (to illustrate a summer month bill) and March 2016 (to illustrate a winter month bill). The annual gas bill for the median residential customer for calendar year 2015 was $420.86, about 15% lower than the annual bill for a PG&E customer with the same consumption. PG&E’s distribution rates for gas have increased substantially to collect for needed system improvements for pipeline safety and maintenance. The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which includes the surrounding communities Table 7: Residential Monthly Gas Bill Comparison Season Usage (therms) Palo Alto PG&E Zone X % Difference Winter (March 2016) 30 31.25 40.23 -22% (Median) 54 48.34 72.42 -33% 80 77.16 117.37 -34% 150 163.10 245.51 -34% Summer (Jul 2015) 10 17.75 12.47 42% (Median) 18 24.04 22.60 6% 30 38.64 43.44 -11% 45 58.18 69.50 -16% Page 6 of 7 Monthly gas bills for commercial customers for various usage levels for rates in effect as of March 1, 2016 are shown in Table 8. Bills for CPAU customers at the usage levels shown are around 9% lower for smaller commercial customers and 4 to 17% higher for larger commercial customers than for PG&E customers. This is a substantial improvement over the calendar year 2013 bill comparison, when commercial gas bills for CPAU customers were 27-44% higher than for PG&E customers. This is primarily attributable to PG&E’s increased distribution rates as the commodity rates for CPAU and PG&E are very similar, both being based on spot market gas prices. Table 8: Commercial Monthly Average Gas Bill Comparison (for Rates in Effect Mar. 1, 2016) Usage (therms/mo) Gas Bill ($/month) % Difference Palo Alto PG&E 500 518 572 -9% 5,000 4,510 4,953 -9% 10,000 9,231 8,859 4% 50,000 44,711 38,104 17% NEXT STEPS The Finance Committee is scheduled to review the FY 2017 Gas Financial Plan on May 17, 2016. The City Council will consider adopting the Financial Plan and amending the rate schedules as part of the FY 2017 budget review and adoption process. RESOURCE IMPACT Normal year sales revenues for the Gas Utility are projected to increase by roughly 8% ($2.2 million) as a result of the proposed rate increases, not including fluctuations in commodity revenue/cost. See the attached FY 2017 Gas Financial Plan for a more comprehensive overview of projected cost and revenue changes for the next ten years. POLICY IMPLICATIONS The proposed gas rate adjustments are consistent with Council-adopted Reserve Management Practices that are part of the Financial Plan , and were developed using a cost of service study and methodology consistent with industry accepted cost of service principles. ENVIRONMENTAL REVIEW The UAC’s review and recommendation to Council on the FY 2017 Gas Financial Plans and rate adjustments does not meet the California Environmental Quality Act’s definition of a project, pursuant to Public Resources Code Section 21065, thus no environmental review is required. PREPARED BY: REVIEWED BY: A ACHIVIENTS Resolution of Financial Plan Proposed FY 2017 Gas Utility Financial Plan Resolution of the Council of the City of Palo Alto Adopting a Gas Rate Increase and Amending Rate Schedules G-1, G -1.-G, -2, G -2-G, G-3, G -3-G, G-10 and G -1 0-G Amended Rate Schedules G-1, G -1-G, G-2 G -2-G, G-3, G -3-G, G-10 and G40 -G (proposed changes shown in in redline/strikeout) APPROVED BY: he Counc the City Palo AltoApproving he FY 2017 Gas Uti RIC KE ISTO , Acting Rates Manager ANE RATCHYE, Assistant Director, Resource Management ED ;IKADA; Interim Dircto Page 7 cif 7 Attachment A * NOT YET APPROVED * 6053681 Resolution No. _________ Resolution of the Council of the City of Palo Alto Approving the FY 2017 Gas Utility Financial Plan R E C I T A L S A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of its utilities with the goal of ensuring adequate revenue to fund operations. This includes making long-term projections of market conditions, the physical condition of the system, and other factors that could affect utility costs, and setting rates adequate to recover these costs. It does this with the goal of providing safe, reliable, and sustainable utility services at competitive rates. The City adopts Financial Plans to summarize these projections. B. The City uses reserves to protect against contingencies and to manage other aspects of its operations, and regularly assesses the adequacy of these reserves and the management practices governing their operation. The status of utility reserves and their management practices are included in Reserves Management Practices attached to and made part of the Financial Plans. The Council of the City of Palo Alto does hereby RESOLVE as follows: SECTION 1. The Council hereby adopts the FY 2017 Gas Utility Financial Plan. SECTION 2. The Council hereby approves the transfer of $1.5 million in FY 2016 from the Rate Stabilization Reserve to the Operations Reserve, as described in the FY 2017 Gas Utility Financial Plan approved via this resolution. SECTION 3. The Council finds that the adoption of this resolution does not meet the California Environmental Quality Act’s (CEQA) definition of a project under Public Resources Code Section 21065, and therefore, no environmental assessment is required. INTRODUCED AND PASSED: AYES: NOES: ABSENT: ABSTENTIONS: ATTEST: ___________________________ ___________________________ Attachment A * NOT YET APPROVED * 6053681 City Clerk Mayor APPROVED AS TO FORM: APPROVED: ___________________________ ___________________________ Senior Deputy City Attorney City Manager ___________________________ Director of Utilities ___________________________ Director of Administrative Services FY 2017 GAS UTILITY FINANCIAL PLAN FY 2017 TO FY 2026 ATTACHMENT B GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 2 | P a g e GAS UTILITY FINANCIA L PLAN FY 201 7 TO FY 202 6 TABLE OF CONTENTS Section 1: Definitions and Abbreviations................................................................................ 4 Section 2: Executive Summary and Recommendations ........................................................... 5 Section 2A: Overview of Financial Position .................................................................................. 5 Section 2B: Summary of Proposed Actions .................................................................................. 6 Section 3: Detail of FY 2017 Rate and Reserve Proposals ........................................................ 6 Section 3A: Rate Design ............................................................................................................... 6 Section 3B: Current and Proposed Rates ..................................................................................... 6 Section 3C: Bill impact of Proposed Rate Changes ...................................................................... 8 Section 3D: Proposed Reserve Transfers ..................................................................................... 8 Section 4: Utility Overview .................................................................................................... 9 Section 4A: Gas Utility History ..................................................................................................... 9 Section 4B: Customer Base ........................................................................................................ 10 Section 4C: Distribution System ................................................................................................. 11 Section 4D: Cost Structure and Revenue Sources ...................................................................... 12 Section 4E: Reserves Structure ................................................................................................... 12 Section 4F: Competitiveness ...................................................................................................... 13 Section 4G: Gas Supply Rates .................................................................................................... 14 Section 5: Utility Financial Projections ................................................................................. 15 Section 5A: Load Forecast .......................................................................................................... 15 Section 5A: FY 2011 to FY 2015 Cost and Revenue Trends ........................................................ 16 Section 5B: FY 2015 Results ....................................................................................................... 17 Section 5C: FY 2016 Projections ................................................................................................. 18 Section 5D: FY 2017-FY 2026 Projections .................................................................................. 18 Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 19 GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 3 | P a g e Section 5F: Alternate Scenarios ................................................................................................. 21 Section 5G: Long-Term Outlook ................................................................................................. 22 Section 6: Details and Assumptions ..................................................................................... 24 Section 6A: Gas Purchase Costs ................................................................................................. 24 Section 6B: Operations .............................................................................................................. 25 Section 6C: Capital Improvement Program (CIP) ....................................................................... 26 Section 6D: Debt Service ............................................................................................................ 28 Section 6E: Equity Transfer ........................................................................................................ 29 Section 6F: Revenues ................................................................................................................. 29 Section 6G: Communications Plan ............................................................................................. 30 Appendices ......................................................................................................................... 32 Appendix A: Gas Financial Forecast Detail ................................................................................ 33 Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 34 Appendix C: Gas Utility Reserves Management Practices ......................................................... 36 Appendix D: Description of Gas Utility Cost Categories ............................................................ 40 Appendix E: Gas Utility Communications Samples .................................................................... 41 GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 4 | P a g e SECTION 1: DEFINITIONS AND ABBR EVIATIONS ABS: Acrylonitirile butydene styrene, a plastic gas main material CARB: California Air Resources Board CIP: Capital Improvement Program CNG: Compressed Natural Gas CPAU: City of Palo Alto Utilities Department CPUC: California Public Utilities Commission Cross-bore: A cross-bore exists when one utility line has been drilled or “bored” through a portion of another line. Gas cross-bores can occur in sewer lines as a result of “horizontal boring” construction practices. Distribution: transportation of gas to customers. GMR Program: Gas Main Replacement Program Local Transportation: transportation of gas to Palo Alto across PG&E’s distribution system from PG&E City Gate. Malin: a delivery hub referred to in gas purchase contracts and located in Malin, Oregon, where the northern end of PG&E’s Redwood Transmission Pipeline is located. MMBtu: Millions of British thermal units, a unit of gas measurement equal to ten therms. Commonly used for high volume gas measurement. Wholesale purchases of gas from suppliers are typically measured in MMBtu. O&M: Operations and Maintenance PE or HDPE: Polyethylene, a gas main material (more specifically, High-Density Polyethylene) PG&E: Pacific Gas and Electric PG&E Citygate, or Citygate: a delivery hub referred to in gas purchase contracts. Any gas delivered to PG&E’s distribution system (such as gas delivered at the southern end of PG&E’s Redwood Transmission Pipeline) is said to have been delivered at PG&E Citygate. PVC: Polyvinyl chloride, a plastic gas main material Summer: April 1 to October 31 Therms: The standard unit of measurement for natural gas sales to customers, equal to 100,000 British thermal units. Therms measure the heating value of the gas, rather than its volume . Transmission: transportation of gas between major gas delivery hubs via a gas transmission pipeline, such as PG&E’s Redwood pipeline. UAC: Utilities Advisory Commission, an appointed body that advises the City Council on CPAU issues. Winter: November 1 to March 31 GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 5 | P a g e SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS This document presents a Financial Plan for the City’s Gas Utility for the next ten years. This Financial Plan provides revenues to cover the costs of operating the utility safely over that time while adequately investing for the future. It also addresses the financial risks facing the utility over the short term and long term, and includes measures to mitigate and manage those risks. SECTION 2 A : OVERVIEW OF F INANCIAL P OSITION From FY 2017 through FY 2026, non-commodity costs are projected to increase at roughly 3.5% per year. In the short term, some of these costs are related to the cross-bore inspection program, as well as cap-and-trade allowance purchase costs. In addition, capital improvement program (CIP) costs have increased as the economy has improved, and CPAU is also planning new gas main replacement projects after completing a large multi-year gas main replacement project. The Gas Utility expenses over the period of this financial plan are shown in Table 1 below. Table 1: Gas Utility Expenses for FY 2015 to FY 2026 (Thousand $’s) Expenses ($000) FY 2015 (act.) FY 2016 (est.) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Commodity costs 10,519 9,258 12,337 13,293 13,770 14,338 14,834 15,380 16,013 16,600 17,178 17,613 Operations 18,529 19,738 21,792 22,443 23,541 23,548 24,535 25,553 26,631 27,755 28,929 30,257 Capital Projects 1,832 6,889 6,305 5,985 6,115 6,301 6,488 6,680 6,879 7,083 7,293 7,509 TOTAL 30,881 35,886 40,434 41,721 43,426 44,188 45,857 47,613 49,522 51,438 53,400 55,380 To ensure that revenues cover these rising costs, the financial plan includes the rate trajectory shown in Table 2. There was no rate increase in FY 2016 since new gas main replacement projects were not added in FY 2014 and FY 2015 in order to complete a multi-year project to replace the last of the ABS plastic mains in Palo Alto. An 8% increase is projected for FY 2017, followed by 9% and 7% increases for FY 2018 and FY 2019. An 8% increase in FY 2017 is equivalent to $2.52 per month for the median residential customer’s monthly gas bill, based on commodity prices as of February 2016. Table 2: Projected Gas Rate Trajectory for FY 2017 to FY 2026 Projection FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Current Financial Plan 8% 9% 7% 4% 1% 1% 1% 1% 1% 1% FY 2016 Financial Plan 7% 4% 4% 4% 3% 3% N/A N/A N/A N/A The Gas Rate Stabilization Reserve is used to smooth rate increases over several years. This Financial Plan projects that these reserves will be exhausted by the end of FY 2017. The Gas CIP Reserve can be used to offset one-time unanticipated capital costs. Table 3 shows the projected reserve transfers over the forecast period. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 6 | P a g e Table 3: Transfers To/(From) Reserves for FY 2016 to FY 2026 ($000) Reserve FY 2016 FY 2017 FY 2018 to FY 2026 Rate Stabilization (1,531) (5,275) - Operations 1,531 5,275 - SECTION 2 B : SUMMARY OF PROPOSE D ACTIONS Staff proposes the following actions for the Gas Utility in FY 2016: 1.Amend the $3.4 million transfer proposed in the FY 2016 Gas Financial Plan to $1.5 million, based on ending Operations Reserve levels. Staff proposes the following actions for the Gas Utility in FY 2017: 2.Increase rates as shown in Section 3B: Current and Proposed Rates. These changes are projected to increase rates by 8%, assuming monthly commodity prices are constant. However, should commodity prices rise, relative bill increases will be higher, and conversely lower if commodity prices should fall. 3.Transfer $5.3 million from the Rate Stabilization Reserve to the Operations Reserve. See Section 3B: Current and Proposed Rates for more details. SECTION 3: DETAIL OF FY 2017 RATE AND RESERVE PRO POSALS SECTION 3 A : RATE DESIGN The Gas Utility’s rates are evaluated and implemented in compliance with cost of service requirements. The Gas Utility’s current rates are based on the methodology from the April 2012 Gas Utility Cost of Service Study completed by Utility Financial Solutions1. Staff tentatively plans to review this cost of service study in the next year or two unless any major changes occur to the utility’s operations or customer base that would necessitate an earlier study. Before any such update, staff will review current rates and the scope of the study with the UAC and Council to determine UAC and Council policy priorities. SECTION 3 B : CURRENT AND PROPOS ED RATES On July 1, 2012 CPAU restructured its rates so that the commodity component varied monthly to match changes in gas market prices2. In addition, monthly service charges were increased to recover the cost of providing gas service to customers. In January 2015, the Council adopted a new rate component to collect the costs of purchasing allowances for the purpose of compliance with the State’s cap-and-trade program3. This component will change depending on the cost of allowances and gas demand. At the same time, two bill components (Local 1 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395 2 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395 3 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537 GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 7 | P a g e transportation and Administration) were collapsed into the Distribution rate to streamline bill presentation. CPAU has four rate schedules: one for separately metered residential customers (G-1), one for small commercial and master-metered multi-family residential customers (G-2), one for customers using over 250,000 therms per year (G-3) and a specific schedules for the Compressed Natural Gas station (G-10). All customers pay a monthly service charge, which represents meter reading, billing, and other customer service costs, as well as a portion of operations and maintenance cost. All customers are also charged for each therm of gas used. Separately metered residential customers are charged on a tiered basis, differentiated by season. During the Winter months, the first 2 therms per day (60 therms for a 30 day billing period) are charged a base price per CCF, and all additional units charged a higher price per therm. During the Summer months, the first tier level is 0.667 therms per day, or 20 therms for a 30 day billing period. Commercial customers pay a uniform price for each therm used. Table 4 shows the current and proposed monthly service charges for all rate schedules. Table 9 shows the consumption charges related to distribution charges. As mentioned earlier, commodity charges change monthly. Some recent commodity price history is discussed in Section 6A: Gas Purchase Costs. Table 4: Current and Proposed Monthly Service Charges Rate Schedule Monthly Service Charge ($/month) Change Current (7/1/12) Proposed (7/1/16) $/mo % G-1 (Residential) $9.88 $10.32 $0.44 4.5% G-2 (Small Commercial) $74.86 $78.23 $3.37 4.5% G-3 (Large Commercial) $361.18 $377.43 $16.25 4.5% G-10 (CNG) $50.65 $52.93 $2.28 4.5% Table 5: Current and Proposed Gas Distribution Charges Current (7/1/12) Proposed (7/1/16) Change $/Therm % G-1 (Residential) Tier 1 Rates 0.4392 0.5021 0.0629 14.3% Tier 2 Rates 0.9546 1.0407 0.0861 9.0% G-2 (Residential Master-Metered and Small Commercial) Uniform Rate 0.6147 0.6855 0.0708 11.5% G-3 (Large Commercial) Uniform Rate 0.6071 0.6775 0.0704 11.5% G-10 (Compressed Natural Gas) Uniform Rate 0.0509 0.0963 0.0454 89.2% GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 8 | P a g e SECTION 3 C : BILL IMPACT OF PROPO SED RATE C HANGES Table 6 shows the impact of the proposed July 1, 2016 rate changes on the median residential bill. The average increase is roughly 8% based on March 2016 commodity rates, but some customers may see slightly higher or lower increases due to slight changes in the composition of the utility’s costs, as well as prevailing market prices. Table 6: Impact of Proposed Gas Rate Changes on Residential Bills Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change $/mo. % Winter (Using March 2016 commodity prices) 30 $ 29.67 $ 32.00 $ 2.33 8% 54 (median) 45.40 49.34 3.84 8% 80 72.96 78.89 5.94 8% 150 155.21 167.17 11.96 8% Summer (Using July 2015 commodity prices) 10 $ 17.70 $ 18.77 $ 1.07 6% 18 (median) 23.95 25.52 1.57 7% 30 38.49 41.05 2.56 7% 45 57.95 61.80 3.85 7% Table 7 shows the impact of the proposed July 1, 2016 rate changes on various representative commercial customer bills. Table 7: Impact of Proposed Gas Rate Changes on Commercial Bills (Using March 2016 commodity prices) Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change % G-2 (Residential Master-Metered and Small Commercial) 500 492 531 8% 5,000 4,250 4,608 8% 10,000 8,426 9,137 8% G-3 (Large Commercial) 25,000 21,049 22,825 8% 50,000 41,736 45,272 8% SECTION 3 D : PROPOSED RESERVE TRANSFERS In the FY 2016 Financial Plan, several transfers between reserves were discussed for FY 2016. CIP related funds were transferred out of the Reappropriations Replacement into the CIP Reserve, and $3.4 million was proposed to be transferred from the Rate Stabilization Reserve into the Operations Reserve. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 9 | P a g e As lower expenses in FY 2015 resulted in higher ending reserve balances than initially projected, staff recommends reducing the $3.4 million transfer from the Rate Stabilization Reserve in FY 2016 to $1.5 million, and proposes transferring $5.3 million in FY 2017. For FY 2016, staff proposes a $3.4 million transfer from the Rate Stabilization Reserve. This transfer will exhaust the Rate Stabilization Reserve, as planned for and discussed in Section 5E: FY 2017-FY 2026 ProjectionsSection 4E: Reserves Structure, and is included in the financial projections in this Financial Plan. It will enable CPAU to maintain adequate Operations Reserve levels while moderating the pace of increase in gas rates. The impact of these transfers on reserves levels can be seen in Appendix A: Gas Utility Financial Forecast Detail. SECTION 4: UTILITY O VERVIEW This section provides an overview of the utility and its operations. It is intended as general background information and to help readers better understand the forecasts in Section 5: Utility Financial Projections and Section 6: Details and Assumptions. SECTION 4 A : GAS UTILITY HISTORY On September 22, 1917, the City of Palo Alto issued a bond to purchase the property of Palo Alto Gas Company and continue it as a municipal enterprise. At the time, the system comprised 21 miles of mains, 1,900 meters, and was valued at $65,500. PG&E supplied the gas, which was synthesized from coal at its Potrero facility. Almost immediately the City faced challenges. Losses were at nearly 25% according to PG&E’s master meter, and PG&E had filed with the Railroad Commission (the forerunner to today’s Public Utilities Commission) to increase rates by nearly 72.5%. Despite these initial hurdles, Palo Alto’s system grew tremendously, and by 1924 revenues had exceeded those of the electric utility. Sales were such that the annual reports of the time noted gas usage “appears to be greater than that of any other city in the state, showing that gas is a very popular form of fuel in Palo Alto.” Just prior to the acquisition of the neighboring town of Mayfield’s gas system (centered around today’s California Avenue) in 1929, the miles of main in service and customers connections had doubled . Notable changes to the gas supply itself came in 1930, when PG&E ceased supplying purely manufactured (or coal) gas from its Potrero Hill facility in San Francisco and instead switched to natural gas. In 1935, a supplementary butane injection system (later retired) was purchased from Standard Oil to mitigate large wintertime peaks. Gas sales were at 248,658 million cubic feet (MCF) with 4,849 active services. Early gas mains in Palo Alto were made of steel, but in the 1950s, like many other utilities, CPAU switched to ABS plastic. CPAU switched to PVC plastic in the early 1970s, but around 100 miles of ABS mains had already been installed. A 1990 evaluation of the system found a steadily increasing rate of gas leaks associated with those mains, something that other gas utilities had also been experiencing. To reduce leaks, CPAU accelerated its main replacement program from 7,000 feet (1.3 miles) of replacements per year to 20,000 feet (3.8 miles) per year . This would enable the utility to replace all of its ABS and its most vulnerable steel and PVC mains with GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 10 | P a g e polyethylene (PE) mains over the course of the following 36 y ears.4 As of 2015 the Gas Utility had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic protection was not effective. Current main replacement projects will target the last ~800 feet of remaining ABS main as well as tackling PVC replacement. A PVC risk analysis to determine the appropriate footage of annual PVC replacement for future CIP projects is currently being conducted. This is an example of how local control of its Gas Utility has provided Palo Alto residents with substantial benefits. During the 1990s and 2000s, while CPAU was increasing its main replacement rate to ensure a robust gas distribution system, PG&E was underspending on safety-related infrastructure, according to a past audit.5 In the 1990s, while grappling with the issues surrounding its distribution system, CPAU was also participating in major changes to the structure of the gas industry in California . Until 1988 CPAU had a formal policy of setting its rates equal to PG &E’s rates and successfully did so with the exception of one year in the mid-1970s. At times this led to inadequate revenue (1974 to 1981) as PG&E, the City’s only gas supplier, regularly filed requests with the CPUC to increase the wholesale gas supply rates charged to the Gas Utility. In the 1990s, as the CPUC began deregulating the natural gas industry in California, the Gas Utility began purchasing gas from suppliers other than PG&E. In 1997 the CPUC adopted the “Gas Accord,”6 which enabled the Gas Utility (along with other local transportation-only customers) to obtain transmission rights on PG&E’s Redwood transmission pipeline running from Malin, Oregon into California. In 2000/2001 the California energy crisis occurred, causing major disruptions to the Gas Utility’s supply costs. Wholesale gas prices rose over 500% between January 2000 and January 2001. The Council approved drawing down reserves to provide ratepayer relief and, for two years following the crisis, CPAU rates were above PG&E’s as reserves were replenished. In April 2001 the Council approved a hedging practice of buying fixed price gas one to three years into the future. After reaching a low point in October 2001, prices continued to rise, and as a result the CPAU hedging strategy frequently resulted in a wholesale supply cost advantage compared to PG&E until prices began to decline steeply in mid-2008. At that point the Gas Utility’s wholesale supply costs became higher than market gas prices due to fixed price contracts entered into prior to 2008. As a result the Gas Utility’s wholesale supply costs were higher than PG&E’s for several years. In 2012 Council approved a plan to formally cease the hedging strategy and purchase all gas on the short-term (“spot”) markets. As of July 1, 2012, the commodity portion of the gas rates changes every month based on the spot market gas price. SECTION 4 B : CUSTOMER BASE CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas customers in Palo Alto. Close to 23,400 customers are connected to the natural gas system, approximately 21,700 (93%) of which are residential and 1,700 (7%) of which are non- residential. Residential customers consume about 10 to 12 million therms of gas per year, 4 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990 5 Focused Financial Audit of The Pacific Gas & Electric Company’s Gas Distribution Operations, Overland Consulting, made available through a CPUC Administrative Law Judge’s ruling on A12-11-009/I13-03-007 on 5/31/2013 6 CPUC decision 97-08-055. Since then, the Gas Accord has been amended four times, with the most recent being Gas Accord V, application A.09-09-013 GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 11 | P a g e roughly 45% of the gas sold, while non-residential customers consume 55% (about 14 to 15 million therms). Residential customers use gas primarily for space heating (46% of gas consumed) and water heating (42%), with the remainder consumed for other purposes such as cooking, clothes drying, and heating pools and spas7. Non-residential customers use gas for space and water heating (73% of gas consumed), cooking (20%), and industrial processes (6%).8 The Gas Utility receives gas at the four receiving stations within Palo Alto where CPAU’s distribution system connects with Pacific Gas and Electric’s (PG&E’s) system. These receiving stations are jointly operated by CPAU and PG&E. CPAU purchases gas from a various natural gas marketers, with PG&E providing only local transportation service (transportation from the PG&E City Gate gas delivery hub to Palo Alto). CPAU also has transmission rights on PG&E’s transmission pipeline from Malin, Oregon to PG&E City Gate, allowing it to purchase lower priced gas at that location. CPAU does not produce or store any natural gas, and purchases gas in the monthly and daily spot markets. The cost of the purchased gas is passed through directly to customers through a rate adjuster that varies monthly with market prices . The cost of purchased gas and PG&E local transportation service accounts for roughly one third of the utility’s expenditures. SECTION 4 C : DISTRIBUTION SYSTE M To deliver gas from the receiving stations to its customers, the utility owns 210 miles of gas mains (which transport the gas to various parts of the city) and 2 3,400 gas services (which connect the gas mains to the customers’ gas lines). These mains and services, along with their associated valves, regulators, and meters, represent the vast majority of the infrastructure used to deliver gas in Palo Alto. CPAU has an ongoing CIP to repair and replace its infrastructure over time, the expense of which accounts for around 15 to 20% of the utility’s expenditures. Costs for main replacements have been going up in recent years. In addition to the CIP, the Gas Utility performs a variety of maintenance activities related to the system, such as monitoring the system for leaks, testing and replacing meters, monitoring the condition of steel pipe, and building and replacing gas services for buildings being built or redeveloped throughout the city. The utility also shares the costs of other system-wide operational activities (such as customer service, billing, meter reading, supply planning, energy efficiency, equipment maintenance, and street restoration) with the City’s other utilities . These maintenance and operations expenses, as well as associated administration, debt service, rent, and other costs, make up roughly half of the utility’s expenses. In addition to these ongoing activities, CPAU has conducted a program to find and replace cross-bores over the last several years. Currently, $3 million is budgeted for the cross-bore program over the next three years. However, the ongoing cross-bore investigation may require additional funding, or extend for longer into the future, as the remaining sewer lines are more difficult to examine than the majority of the wastewater collection system that has been examined to date. 7 http://energyalmanac.ca.gov/naturalgas/overview.html 8 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Statistics shown are for end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 12 | P a g e Figure 2: Cost Structure (FY 2015) 60% 34% 6% Operations Gas Purchases Capital Figure 1: Revenue Structure (FY 2015) 95% 5% Sales of Gas Other Revenue SECTION 4 D : C OST S TRUCTURE AND R EVENUE S OURCES As shown in Figure 1, the Gas Utility receives 95% of its revenue from sales of gas and the remainder from capacity and connection fees, interest on reserves, and other sources. Appendix A: Gas Utility Financial Forecast Detail shows more detail on the utility’s cost and revenue structures. As shown in Figure 2, in FY 2015, gas purchase costs accounted for roughly 34% of the Gas Utility’s costs. This percentage can vary widely from year to year, as this cost is based upon market purchases. Operational costs represented roughly 60%, and capital investment was responsible for the remaining 6%. The percentages for FY 2015 are skewed by the fact that CIP, which is normally about 20% of expenses, was reduced in FY 2014 and FY 2015 to allow for a backlog of projects to be completed. SECTION 4 E : RESERVES STRUCTURE CPAU maintains six reserves for its Gas Utility to manage various types of contingencies. These are summarized below, but see Appendix C: Gas Utility Reserves Management Practices for more detailed definitions and guidelines for reserve management: Reserve for Commitments: A reserve equal to the utility’s outstanding contract liabilities for the current fiscal year. Most City funds, including the General Fund, have a Commitments Reserve. Reserve for Reappropriations: A reserve for funds dedicated to projects reappropriated by the City Council, nearly all of which are capital projects. Most City funds, including the General Fund, have a Reappropriations Reserve. Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to accumulate funds for future expenditure on CIP projects and is anticipated to be empty unless a major one-time CIP expenditure is expected in future years. This CIP can also GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 13 | P a g e act as a contingency reserve for the CIP. This type of reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as well. Rate Stabilization Reserve: This reserve is intended to be empty unless one or more large rate increases are anticipated in the forecast period. In that case, funds can be accumulated to spread the impact of those future rate increases across multiple years. This type of reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as well. Operations Reserve: This is the primary contingency reserve for the Gas Utility, and is used to manage yearly variances from budget for operational gas costs. This type of reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as well. Unassigned Reserve: This reserve is for any funds not assigned to the other reserves and is normally empty. SECTION 4 F : COMPE TITIVENESS Table 8 presents winter and summer residential bills for Palo Alto and PG&E at several usage levels for commodity rates in effect as of July 2015 (to illustrate a summer month bill) and March 2016 (to illustrate a winter month bill). The annual gas bill for the median residential customer for calendar year 2015 was $420.86, about 15% lower than the annual bill for a PG&E customer with the same consumption. PG&E’s distribution rates for gas have increased substantially to collect for needed system improvements for pipeline safety and maintenance. The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which includes the surrounding communities. Table 8: Residential Monthly Natural Gas Bill Comparison ($/month) Season Usage (therms) Palo Alto PG&E Zone X % Difference Winter (March 2016) 30 31.25 40.23 -22% (Median) 54 48.34 72.42 -33% 80 77.16 117.37 -34% 150 163.10 245.51 -34% Summer (Jul 2015) 10 17.75 12.47 42% (Median) 18 24.04 22.60 6% 30 38.64 43.44 -11% 45 58.18 69.50 -16% Table 9 shows the monthly gas bills for commercial customers for various usage levels for rates in effect as of March 1, 2016. Bills for CPAU customers at the usage levels shown are around 9% lower for smaller commercial customers and 4 to 17% higher for larger commercial customers than for PG&E customers. This is a substantial improvement over the calendar year 2013 bill comparison, when commercial gas bills for CPAU customers were 27% to 44% higher than for PG&E customers. This is primarily attributable to PG&E’s increased distribution rates as the GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 14 | P a g e commodity rates for CPAU and PG&E are very similar, both being based on spot market gas prices. Table 9: Commercial Monthly Average Gas Bill Comparison (for Rates in Effect Feb. 1, 2016) Usage (therms/mo) Gas Bill ($/month) % Difference Palo Alto PG&E 500 518 572 -9% 5,000 4,510 4,953 -9% 10,000 9,231 8,859 4% 50,000 44,711 38,104 17% SECTION 4 G : GAS SUPPLY RATES Starting in July 2012, CPAU replaced a “laddering” hedging strategy for purchasing gas supplies with a strategy to buy gas on the short-term, or “spot” markets and pass the commodity cost to customers on a monthly basis. The actual commodity prices are shown in Figure 3. As shown, commodity prices have steadily fallen for the last two years. Figure 3: Gas Commodity Rates from July 2012 through March 2016 GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 15 | P a g e SECTION 5 : UTILITY F INANCIAL PROJECTIONS SECTION 5 A : LOAD F O RECAST Gas usage in Palo Alto is volatile, varying with both economic and weather conditions . As shown in Figure 4, in the early 1970’s, gas purchases reached over 45 million therms per year . Usage dropped dramatically in the 1976/1977 drought when customers saved signifi cant amounts of (hot) water by upgrading to efficient showerheads. During the 1980s and 90s average gas usage was around 36 million therms per year. Usage dropped again in the early 2000’s. In FY 2001, gas prices escalated during the California energy crisis and Palo Alto’s rates increased by nearly 200%. From 2003 to 2011, usage decreased by 2.3% mainly as a result of continued customer investments in energy efficiency. In FY 2015 an unusually warm winter, as well as ongoing drought, have again caused gas usage to tumble to historic lows. Gas usage was 25.6 million therms in FY 2015. Figure 4: Historic Gas Consumption 20 25 30 35 40 45 50 19 7 1 19 7 3 19 7 5 19 7 7 19 7 9 19 8 1 19 8 3 19 8 5 19 8 7 19 8 9 19 9 1 19 9 3 19 9 5 19 9 7 19 9 9 20 0 1 20 0 3 20 0 5 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 Th e r m s ( M i l l i o n s ) GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 16 | P a g e Gas consumption, as denoted by the dotted line in Figure 5, is projected to recover somewhat and stay stable over the forecast period, although changes such as replacement of gas appliances with electric appliances or customer behavior may result in lower long run usage. Figure 5: Forecast Gas Consumption SECTION 5 A : FY 2011 TO FY 2015 COST AND REVENUE TRENDS Figure 6 and Appendix A: Gas Utility Financial Forecast Detail how costs have changed during the last five years as well as how they are projected to change over the next decade. The annual expenses for the gas utility decreased substantially between 2011 and 2015 due to lower gas sales. Market prices for gas supplies are shown in Figure 3 above. FY 2014 and 2015 were notable for a temporary hiatus in most CIP bud geting, to permit the completion of a backlog of projects which had previously been budgeted for. This budgetary hol d allowed for backlogged gas main replacement projects to be started, which consumed capital reserves. Starting in FY 2012, additional funding for gas cross-bore inspections increased Operations costs. Revenues are below expenses, and the projected rate trajectory will bring revenues in line with costs by FY 2019. As shown in Figure 6 below, revenues were below cost in FY 2011 and FY 2013 and are projected to be below cost in FY 2016. Reduced budgeting for new CIP in FY 2014 and FY 2015, as well as the availability of relatively large reserves, forestalled the need for rate increases until now. However, since Rate Stabilization Reserves are projected to be depleted by FY 2017, the Gas Utility must increase rates to cover costs. As shown in Figure 6, the last gas rate adjustment was in July 2012 when rates were increased by 12%. However, this was at the same time that the commodity rates were changed to a market-based, monthly pass-through cost—and commodity rates (and usage) fell, so revenues actually declined in FY 2013 after the rate increase. 20 22 24 26 28 30 32 34 36 20 0 3 20 0 4 20 0 5 20 0 6 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 Th e r m s ( M i l l i o n s ) GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 17 | P a g e Figure 6: Gas Utility Expenses, Revenues, and Rate Changes: Actual Costs through FY 2015 and Projections through FY 2026 SECTION 5 B : FY 2015 RESULTS Sources of funds for FY 2015 were lower than projected by $4.8 million, but expenses related to Purchases and Operations and Maintenance activities came in well below expected budget. Total FY 2015 expenses were $30.9 million compared to projections of $34.9 million in the FY 2015 Financial Plan. Table 10 summarizes the variances from forecast. Table 10: FY 2015, Actual Results vs. Financial Plan Forecast Net Cost/(Benefit) Type of change Sales revenues lower than forecast 5,427,000 Revenue decrease Other revenues and interest were higher than forecasted (628,000) Revenue increase Purchase costs lower than forecast (3,212,000) Cost savings Operations & maintenance, Customer service and other savings (760,000) Cost savings Net Cost / (Benefit) of Variances $827,000 GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 18 | P a g e SECTION 5 C : FY 2016 PROJECTION S Current projections indicate that sales revenues continue to be lower than forecast, at this time projected to be $4.7 million. However, Purchase cost reductions of $4.2 million offset most of this. Table 11 summarizes the current projected variances from FY 2016 Financial Plan. Table 11: FY 2016, Projected Results vs. Financial Plan Forecast Net Cost/ (Benefit) Type of change Sales revenues lower than forecast 4,719,000 Revenue decrease Purchase costs lower than forecast (4,171,000) Cost savings Operations & maintenance, Customer service and other savings (1,843,000) Cost savings Capital improvement budgets higher 1,216,000 Cost increase Other revenues and interest lower than forecasted 611,000 Revenue decrease Net Cost / (Benefit) of Variances $531,000 SECTION 5 D : FY 2017 -FY 2026 PROJECTIONS As can be seen in Figure 6 above, costs for the Gas Utility are projected to rise in FY 2017, then are projected to increase at a bit less than 3.5% per year through FY 2026. In Operations, this is due to an additional $1 million for cross-bore inspections (this expense is projected to continue for at least three years), as well as general inflationary increases of around 2.6% per year. Salaries and benefits expenses are projected to rise at nearly 4% per year, per the City’s Long Range Financial Plan. CIP programs are projected to increase, then stabilize at around $6 million per year in FY 2018, then grow at around 2% per year thereafter. Gas commodity costs are the most variable component. At the time the budget was developed in December 2015, gas supply prices were projected to increase by around 3 to 4% per year, but recently gas prices have hit near record lows. Since this is a pass-through cost to customers, the risk of these costs being higher or lower than expected has a minimal impact on reserves. As shown in Figure 7, the Rate Stabilization Reserves are projected to be depleted by FY 2017. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 19 | P a g e Figure 7: Gas Utility Reserves Actual Reserve Levels for FY 2011 and Projections through FY 2026 SECTION 5 E : RISK ASSESSMENT AND RESERVES ADEQUAC Y The Gas Utility’s primary contingency reserve, the Operations Reserve, is projected to be right at the approved minimum guideline level in FY 2018 and FY 2019, barring either short-run budget savings and/or larger future increases. Figure 8 shows the Operations Reserve recovering to the target level by FY 2021 with the projected rate trajectory. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 20 | P a g e Figure 8: Operations Reserve Adequacy Forecast Operations Reserve levels also exceed the short-term risk assessment for the Utility. Table 12 summarizes the risk assessment calculation for the Gas Utility through FY 2021. The same methodology is used for FY 2022 through FY 2026 as well . The risk assessment includes the revenue shortfall that could accrue due to: 1. Lower than forecasted distribution sales revenue; and 2. An increase of 10% of planned system improvement CIP expenditures for the budget year. Table 12: Gas Risk Assessment ($000) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 Total non-commodity revenue $21,587 $24,256 $26,956 $28,370 $28,781 Max. revenue variance, previous ten years 16% 16% 16% 16% 16% Risk of revenue loss $3,462 $3,890 $4,323 $4,549 $4,615 CIP Budget $5,076 $4,720 $4,811 $4,958 $5,105 CIP Contingency @10% $508 $472 $481 $496 $511 Total Risk Assessment value $3,969 $4,362 $4,804 $5,045 $5,126 Finally, the CIP Reserve was created at the end of FY 2015 to act as a contingency reserve for capital improvement projects. Current guidelines state that the balance of this reserve should fall between 12 and 24 months of budgeted CIP expense. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 21 | P a g e At the end of FY 2016, the sum of the CIP Reserve and existing Commitments was a bit below $5 million, as shown in Figure 7. However, based upon FY 2016’s CIP budget, the minimum reserve level is $6.9 million. As such, this reserve is technically below the minimum level , but the Risk assessment reserve level for the Operations Reserve is also set to handle a 10% increase to CIP costs should that arise. As such, staff does not recommend an additional increase to rates to fund this reserve at this time. If any CIP funds budgeted in FY 2016 are not used or committed by the end of the fiscal year, those funds flow to the Operations Reser ve and those funds could be used to fund the CIP reserve, so increasing rates for this contingency is premature. Staff is in the process of reviewing this reserve and the appropriateness of the current minimum and maximum guideline levels. SECTION 5 F : ALTERNATE SCENAR IOS At the UAC’s February 2016 meeting, it was suggested that staff prepare two alternate scenarios for rate increases. The first (“Target”) scenario keeps the Operations Reserve at or near the Target level throughout the forecast period as shown in Figure 9 below. The second (“Minimum”) has no rate change in FY 2017 and lets the Operations Reserve stay at minimum for five years as shown in Figure 10 below. Both options as well as the proposed rate adjustments are shown in Table 13. Table 13: Projected Gas Rate Trajectory for FY 2017 to FY 2026 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Proposed 8% 9% 7% 4% 1% 1% 1% 1% 1% 1% Target 8% 16% 2% 1% 1% 2% 2% 2% 2% 1% Minimum 0% 24% 1% 1% 1% 4% 3% 1% 1% 1% The Target scenario does not change the FY 2017 proposed rate increase, but a 16% rate increase in FY 2018 would be needed to bring reserves to target levels. Figure 9 shows that the Operations Reserve levels for the Target scenario. The Minimum scenario avoids a rate increase in FY 2017, but requires a significant increase in FY 2018 (24%). If sales are lower than expected or costs rise, then this rate increase would be even higher. Figure 10 shows that the Operations Reserve levels for the Minimum scenario. Staff recommends an 8% gas rate increase in FY 2017 to moderate the rate increases that are projected in FY 2018 while keeping the Gas Operations Reserve at healthy levels. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 22 | P a g e Figure 9: Operations Reserve at Target Figure 10: Operations Reserve at Minimum SECTION 5 G : LONG -TERM OUTLOOK In the longer term (5 to 35 years out) it is very difficult to predict the Gas Utility’s commodity costs. A variety of long-term trends could affect commodity costs either positively or negatively. Continuing improvement in gas extraction technology, such as fracking, could continue to create generous supplies of gas, but these technologies are also under greater scrutiny with respect to their environmental impacts. On the demand side, a continued shift from coal to natural gas for electricity generation or an increase in manufacturing in the U.S. might drive up GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 23 | P a g e natural gas prices, but other factors, such as generally more mild winters, might drive gas demand lower. It is also difficult to predict the magnitude of the additional cost impacts associated with the State’s cap-and-trade program over the long term. In the face of this uncertainty, CPAU is able to protect the financial position o f the Gas Utility by continuing its current strategy of passing these costs directly to its customers via month-varying rate adjustment mechanisms. Future CIP investment needs for the Gas Utility may be lower than in the past, although costs per foot for main replacement may increase substantially. The Gas Utility has replaced nearly all of its ABS gas mains and its most problematic steel and PVC mains as well . The PE pipe being used now is expected to have at least a fifty-year lifetime, and there is growing evidence that it may last much longer than that. This would result in lower CIP investment over the long term . CPAU is considering performing a study in the near future to develop its future main replacements priorities and strategy. Long-term state or local climate goals could also have a major impact on the Gas Utility. The Global Warming Solutions Act, Assembly Bill 32 (AB32), set a goal of reducing greenhouse gas (GHG) emissions to 1990 levels by 2020 and then maintaining those reductions. In its December 2007 Climate Protection Plan, the City set a goal of lowering emissions to 15% below 2005 levels by 2020. As a community Palo Alto achieved these goals in 2012 even with continued use of natural gas for heating, cooking, and industrial processes. If stricter goals are enacted at the state or local level, however, it could lead to “electrification”, or consumer switching from gas - using appliances to electric-using appliances for heating, cooking and processes. If significant amounts of electrification occurred, stranded investment and higher rates could be required as the costs of the distribution system are recovered over a lower sales base. One example of a stricter standard has been stated by the Governor—reducing GHG emissions to 80% below 1990 levels by 2050.9 This goal, or less ambitious interim state goals, would require legislation to implement. But it is instructional that, in the recent discussion draft of its scoping plan update, CARB says, to meet those goals, natural gas use would have to be “mostly phased out.”10 Legislation has been recently passed addressing the Governor’s 2030 climate goals of 50% renewable generation, 50% reduction in transportation fuels, and a doubling of energy efficiency. A few bills have already been introduced on post-2020 GHG emission reduction goals and the GHG cap-and-trade market. As stewards of the Gas Utility, the City should continue to stay aware of developments in state climate planning, participate as a stakeholder, and consider these types of impacts and ways to mitigate them when developing its own sustainability goals. 9 Executive Orders S-3-05 and B-16-2012. 10 Climate Change Scoping Plan, First Update, Discussion Draft for Public Review and Comment, California Air Resources Board, October 2013, pg 88. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 24 | P a g e SECTION 6 : D ETAILS AND A SSUMPTIONS SECTION 6 A : GAS PURCHASE COSTS The Gas Utility purchases much of its gas for delivery at Malin, Oregon which is almost always cheaper than delivery at PG&E City Gate, even including the costs of transmission from Malin to City Gate. Gas is purchased on a month-ahead and day-ahead basis in the spot market. The last few years have seen gas prices in a relatively narrow but low band, and prices for the last year in particular have been lower than most projections. High levels of natural gas in storage, along with warmer than normal weather on the West coast has kept prices low, as shown in Figure 11. Figure 11: Gas Market Prices at PG&E Citygate Future gas commodity costs are expected to increase steadily over the next several years. Figure 12 shows the projected gas prices used to generate this forecast. Projections for transmission costs associated with transporting gas over PG&E’s Redwood transmission pipeline (from Malin, Oregon to the PG&E Citygate) are based on rates adopted in the most recent update to the Gas Accord. Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary adder to PG&E’s local transportation rate,11 but in December 2014 PG&E applied to the CPUC to more than double local transportation costs. Staff is tracking PG&E’s application and, based on 11 California Public Utilities Commission Advice Letter 3430-G, effective January 1, 2014. Also see CPUC Decision 12-12-30 regarding the Pipeline Safety Enhancement Plan Adder. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 25 | P a g e discussions to date, expects that nearly all of the proposed increase in local transportation costs will be approved. Staff projects these costs to escalate at 3% per year in subsequent years. As these charges are dictated by PG&E and are outside of Palo Alto’s control, staff may propose making these costs a pass-through charge, similar to the commodity charge, in FY 2018. Figure 12: Wholesale Gas Price Projections SECTION 6 B : OPERATIONS Operations costs include the Customer Service, Demand Side Management, Operations and Maintenance (including Engineering), Resource Management, and Administration categories in Figure 13, below. Debt service, rent, and transfers are also included in Operations costs (excluding the General Fund equity transfer). Appendix D: Description of Gas Utility Cost Categories includes detailed descriptions of the activities associated with these cost categories . Operations costs are projected to increase by 2 to 4% per year. Salary and benefits, inflation, and other assumptions match those used in the City’s long-range financial forecast. Operations costs for FY 2017 to FY 2019 include funding for the cross-bore program. In the 1970s CPAU, like many other utilities, adopted horizontal drilling as an alternative to trenching when installing new gas services. This created the possibility of cross-bores, which can happen when a gas service is bored through a sewer lateral. Though cross-bores are very rare, they can create a dangerous situation when a contractor attempts to clear a blocked sewer line, because if the cross-bored gas service is damaged during the line clearing it can result in a gas leak. CPAU has been inspecting new gas services since 2001, and in 2011 began video inspections of the sewer laterals at the location of horizontally-drilled gas services installed before 2001. This inspection program has cost roughly $1 million per year since FY 2012. While a majority of sewer laterals have been inspected, staff has come across several services which are not able to be scoped, either due to infiltration by roots or broken/collapsed pipe segments. Staff has GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 26 | P a g e included $3 million in additional funding between FY 2017 and FY 2019 for this program, but the program will likely require additional funding in futu re years to complete. Figure 13: Historical and Projected Operational Costs SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP) The Gas Utility’s CIP program consists of the following programs and budgets: The Gas Main Replacement Program, under which the Gas Utility replaces aging gas mains Customer Connections, which covers the cost when the Gas Utility installs new services or upgrades existing services at a customer’s request in response to development or redevelopment. The Gas Utility charges a fee to these customers to cover the cost of these projects. Ongoing Projects, which covers the cost of routine meter, regulator, and service replacement, minor projects to improve reliability or increase capacity, and other general improvements. Tools and Equipment, which covers the cost of capitalized equipment, such as directional boring equipment. One-time Projects, which represents occasional large projects that do not fall into any other category. Table 14 shows the current status of these project categories and future projected spending. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 27 | P a g e Table 14: Budgeted Gas CIP Spending The Gas Main Replacement (GMR) Program is in the process of reaching a major milestone, the replacement of the last gas mains made from ABS plastic. The program to replace ABS and other low-performing materials in the system started in the 1990s (see Section 4A: Gas Utility History for more detail). CPAU temporarily slowed down its new CIP appropriations in this category in FY 2014 and 2015 in order to finish the last major ABS main replacement project and to catch up on a backlog of projects that has accumulated due to staffing issues. With the replacement of all ABS mains with PE plastic, the material most at risk for failure is removed leaving only PVC plastic, steel (wrapped, with cathodic protection), and PE mains . The next focus of the GMR program will be PVC mains. CPAU is considering updating the Gas System Master Plan to determine which areas of the system to prioritize . The plan will help CPAU determine whether the pace of main replacement (approximately three miles of main each year, or 1.5% of the system) needs to be increased, decreased, or whether it needs to remain the same. The current budget for gas main replacement assumes the current pace of main replacement, but does not take into account the recent rise in costs for main replacement, which have increased from the levels seen during the recent recession . Several factors may be contributing to this. Economic recovery in the Bay Area, as well as a greater focus on infrastructure improvement by many municipal agencies and utilities could be creating high demand for contractors in these fields. Newer, more leak resistant pipe materials may have ongoing greater costs. CPAU has seen the replacement cost per linear foot increase by 25 to 50% over the last couple of years. Currently CPAU plans to complete as much main replacement as possible within its current budget, provided there are no safety concerns. However, if this trend of higher cost continues, the Gas Utility may require larger CIP budgets, and as a result, larger rate increases. Ongoing Projects, Tools and Equipment, and Customer Connections are projected to cost approximately $0.8 million in FY 2017 and increase by 3% per year through the end of the forecast period. In practice, these projects can fluctuate dramatically depending on system conditions and the pace of development and redevelopment in the city . It is worth noting that the Customer Connections program is paid for through fee revenue, so when costs go up, so does fee revenue. Aside from customer connections and some transfers from other funds, the CIP plan for FY 2017 to FY 2021 is funded by utility rates. The details of the plan are shown in Appendix B: Gas Utility Capital Improvement Program (CIP) Detail. Project Category Current Budget* Spending, Curr. Yr Remain. Budget**Committed FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 One Time Projects 150 (9) 141 125 - - - - - Gas Main Replacement 8,097 (367) 7,730 3,580 4,191 3,811 3,878 4,000 4,121 Tools And Equipment 291 (76) 214 - 100 100 100 100 100 Ongoing Projects 918 (193) 726 76 785 809 833 858 884 Customer Connections 953 (576) 377 38 1,229 1,265 1,303 1,342 1,383 TOTAL 10,409 (1,222) 9,187 3,818 6,305 5,985 6,115 6,301 6,488 *Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year **Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments). GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 28 | P a g e SECTION 6 D : DEBT SERVICE The Gas Utility currently makes debt service payments on one bond issuance, the 2011 Series A Utility Revenue Refunding Bonds. This bond issuance was to refinance the $18 million principal remaining on the Utility Revenue Bonds, 2002 Series A issued for the Gas and Water Utilities to finance various improvements to the distribution systems . $9.4 million of this issuance was secured by the net revenues of the Gas Utility. Debt service for this bond for the financial forecast period is shown in Table 15. Debt service on this bond will continue through 2026. Table 15: Gas Utility Debt Service FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 2011 Utility Revenue Refunding Bonds, Series A 803 802 800 800 802 804 805 803 800 803 The 2011 bonds include two covenants stating that 1) the Gas Utility will maintain a debt coverage ratio of 125% of debt service, and 2) that the City will maintain “Available Reserves”12 equal to five times the annual debt service. The current financial plan complies with these covenants throughout the forecast period, as shown in Table 16 and Table 17. Table 16: Debt Service Coverage Ratio ($000) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Revenues 35,938 39,825 43,628 46,051 47,336 48,323 49,891 51,465 53,429 54,696 Expenses (Excluding CIP and Debt Service) -33,310 -34,933 -36,511 -37,086 -38,566 -40,128 -41,838 -43,552 -45,307 -47,068 Net Revenues 2628 4892 7117 8965 8770 8195 8053 7913 8,122 7,628 Debt Service 803 802 800 800 802 804 805 803 800 803 Coverage Ratio 327% 610% 890% 1121% 1094% 1019% 1000% 985% 985% 985% Table 17: Debt Service Minimum Reserves ($000) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Gas Utilitya 9,543 7,647 7,849 9,712 11,191 11,901 12,270 12,298 12,327 12,742 Debt Serviceb 803 804 803 802 801 801 802 803 800 803 Reserves Ratioc 12x 10x 10x 12x 14x 15x 15x 15x 15x 15x a) CIP, Rate Stabilization, Operations, and Unassigned Reserves b) Gas Utility’s share of the debt service on the 2011 bonds. c) Calculated using only Gas Utility reserves. The actual reserves ratio for the 2011 bonds is calculated based on the combined Electric, Gas, and Water Utility reserves and debt service and is higher than shown here. 12 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 29 | P a g e The Gas Utility’s reserves and net revenue are also pledged as security for the bond issuances listed in Table 18, even though the Gas Utility is not responsible for the debt service payments . The Gas Utility’s reserves or net revenues would only be called upon if the responsible utilities are unable to make their debt service payments. Staff does not currently foresee this occurring. Table 18: Other Issuances Secured by Gas Utility’s Revenues or Reserves Bond Issuance Responsible Utilities Annual Debt Service ($000) Secured by Gas Utility’s: Net Revenues Reserves 1995 Series A Utility Revenue Bonds Storm Drain $680 Yes No 1999 Utility Revenue Bonds, Series A Wastewater Collection Wastewater Treatment Storm Drain $1,207 No Yes 2009 Water Revenue Bonds (Build America Bonds) Water $1,977* No Yes *Net of Federal interest subsidy SECTION 6 E : E QUITY T RANSFER The City calculates the equity transfer from its Gas Utility based on methodology adopted by Council in 2009 that has remained unchanged since13. Each year it is calculated according to the 2009 Council-adopted methodology, and does not require additional Council action. SECTION 6 F : REVENUE S The Gas Fund receives most of its revenues from sales of gas, but about 5% comes from other sources. The largest of these comes from service connection and capacity fees, followed closely by sales of allowances related to California’s cap-and-trade program. Another revenue item related to the cap-and-trade program is collected in customer’s bills. While the State provides CPAU with a certain number of free allowances each year, the Gas Utility is required to sell a portion of those in accordance with the regulations. In order to have enough allowances to cover customer’s natural gas emissions, CPAU must buy allowances at market, and subsequently passes through the cost of those allowances to customers. The regulations do not allow the revenue derived from the sale of the free allowances to offset allowance purchases, thus the pass-through rate component. Sales revenue projections are based on the load forecast in Section 5A: Load Forecast. Except where stated otherwise, these load forecasts are based on normal weather. Weather can vary substantially, however, and this can affect revenues substantially. Also, changes in custome r behavior, as well as changes to more efficient gas appliances, or switching to electric 13 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed changes to equity transfer methodology. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 30 | P a g e appliances, will modify these forecasts. Forecasts are continually evaluated to see when new trends emerge. SECTION 6 G : COMMUNICATIONS PLAN The FY 2017 communications strategy covers four primary areas: operations, infrastructure, safety, efficiency, renewables and rates. Since moving to market pricing for commodity rates, changes to the commodity rates are posted monthly on the City’s website. Gas use efficiency incentives are promoted year-round, but most heavily during winter months to impact heating activities. Promotional methods include community outreach events, print ads in local publications, utility bill inserts, messaging on the bills and envelopes, website pages, email blasts, videos for the web and local Comcast channels, Home Energy Reports and the use of social media. To keep customers apprised of the status and accomplishments of capital improvement projects, a network of project web pages are maintained. Traffic is driven to the website via print and digital ads, social media and email blasts. Safety topics are emphasized year-round. CPAU is engaging in several campaigns and programs in FY 2017 to promote gas utility efficiency and renewable energy. The Georgetown University Energy Prize competition is a friendly, national campaign to encourage communities to reduce energy use. Energy savings from reduced gas and electric consumption qualify to help Palo Alto compete for a $5 million prize at the end of a two-year campaign. Since adoption of a carbon neutral electric supply portfolio, CPAU launched a new voluntary renewable natural gas carbon offsets program, PaloAltoGreen Gas. Much of our programmatic promotional activity will center around customer education and encouragement to sign up for participation in PaloAltoGreen Gas. Other new programs include home efficiency services and online tools to help customers manage their energy use. Stepping up efforts to promote gas safety education, staff is focusing outreach around youth, the importance of calling USA (811) before digging for anyone who may excavate in and around Palo Alto, such as plumbers and contractors, potential sewer and gas line crossbores, keeping fats, oils and greases out of drains, and ensuring clear access to meters. For younger “customers-to-be,” CPAU created a Home Safety Detective campaign that includes special tool kits to help them identify home safety problem s. Staff provides safety kits to youth and adults at school presentations, neighborhood safety and emergency preparedness fairs and other community outreach events. Meter access awareness is highlighted through use of materials featuring photos of some unusual ways people obstruct access to their meters, including using them as bike racks and building storage sheds around them. CPAU will continue to promote safety, infrastructure, operations, efficiency and rate adjustment messages through a variety of marketing and media channels. Every year, CPAU publishes an updated gas safety awareness brochure which is mailed to all customers in Palo Alto, as well as plumbers, contractors and excavators that may work in and around the area. Staff talks with business customers at special facilities meetings, attends neighborhood safet y and emergency preparedness fairs and offers presentations to school and community groups. While print materials and website pages still feature prominently, CPAU is turning the outreach GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 31 | P a g e emphasis to direct mail, newspaper inserts, social media, online videos and cable TV. Copies of all outreach materials and logs of activities are saved in the Gas Safety Public Awareness Plan that is reviewed at least once per year by the Department of Transportation. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 32 | P a g e APPENDICES Appendix A: Gas Financial Forecast Detail Appendix B: Gas Utility Capital Improvement Program (CIP) Detail Appendix C: Gas Utility Reserves Management Practices Appendix D: Description of Gas Utility Cost Categories Appendix E: Gas Utility Communications Samples GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 33 | P a g e APPENDIX A : GAS FINANCIAL FORECA ST D ETAIL ($'000) Actual Actual Actual Actual Actual 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 1 RATE CHANGE (%)*0%0%12%0%0%0%8%9%7%4%1%1%1%1%1%1% 2 SALES IN THOUSAND THERMS 30,914 30,447 28,901 28,117 28,881 27,261 28,653 28,680 28,711 28,743 28,511 28,412 28,461 28,522 28,590 28,658 3 4 Utilities Retail Sales 42,855 41,034 33,759 34,843 29,515 28,608 33,259 37,038 40,365 42,408 43,293 43,965 45,170 46,396 47,584 48,622 5 Service Connection & Capacity Fees 516 592 731 654 602 655 1,017 1,048 1,079 1,110 1,145 1,145 1,145 1,145 1,145 1,145 6 Other Revenues & Transfers In 203 103 830 313 666 1,026 1,373 1,517 1,975 2,328 2,635 2,920 3,221 3,529 4,313 4,834 7 Interest plus Gain or Loss on Investment 821 1,119 (239)706 450 376 288 223 210 205 264 293 355 396 387 368 8 Total Sources of Funds 44,396 42,847 35,081 36,517 31,233 30,665 35,938 39,825 43,628 46,051 47,336 48,323 49,891 51,465 53,429 54,969 9 10 Purchases of Utilities: 11 Supply Commodity 20,732 15,356 12,461 12,992 9,537 6,693 9,393 10,141 10,598 11,131 11,621 12,145 12,741 13,288 13,825 14,219 12 Supply Transportation 706 879 994 1,333 982 2,566 2,944 3,152 3,172 3,207 3,213 3,234 3,272 3,312 3,353 3,394 13 Total Purchases 21,438 16,235 13,455 14,325 10,519 9,258 12,337 13,293 13,770 14,338 14,834 15,380 16,013 16,600 17,178 17,613 14 15 Administration (CIP + Operating)2,895 3,473 4,273 3,988 4,007 4,114 4,243 4,370 4,497 4,629 4,764 4,902 5,045 5,192 5,343 5,499 16 Customer Service 1,230 1,270 1,358 1,338 1,195 1,232 1,286 1,335 1,384 1,435 1,486 1,539 1,594 1,651 1,711 1,772 17 Demand Side Management 563 614 630 438 632 648 665 683 701 720 739 759 779 799 821 842 18 Engineering (Operating)280 333 340 352 369 380 396 411 425 440 455 471 487 504 522 540 19 Operations and Maintenance 3,297 5,032 4,940 4,119 4,403 4,534 5,720 5,918 6,116 5,320 5,502 5,690 5,885 6,087 6,295 6,512 20 Resource Management 1,039 729 506 516 808 1,302 1,327 1,350 1,751 2,006 2,223 2,434 2,665 2,904 3,149 3,498 21 Debt Service Payments 488 406 296 805 804 804 803 802 801 801 803 804 805 803 800 803 22 Rent 230 230 219 419 431 443 455 467 480 492 505 519 532 546 561 574 23 Transfers to General Fund 5,304 6,006 5,971 5,811 5,730 6,126 6,722 6,945 7,220 7,535 7,883 8,255 8,653 9,078 9,533 10,019 24 Other Transfers Out 614 170 207 606 151 154 158 163 167 171 176 180 185 190 195 200 25 Capital Improvement Programs 8,325 7,821 7,620 1,026 1,832 6,889 6,305 5,985 6,115 6,301 6,488 6,680 6,879 7,083 7,293 7,509 26 Total Uses of Funds 45,704 42,320 39,814 33,743 30,881 35,886 40,418 41,721 43,426 44,188 45,857 47,613 49,522 51,438 53,400 55,380 27 28 Into/ (Out of) Reserves (1,308)528 (4,733)2,773 352 (5,221)(4,480)(1,896)202 1,864 1,479 710 369 28 29 (410) 29 30 Reappropriations + Commitments 17,174 19,211 19,363 11,305 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 31 Plant Replacement 1,000 1,000 1,000 0 0 0 0 0 0 0 0 0 0 0 0 0 32 CIP Reserve 0 0 0 0 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 33 Rate Stabilization 16,188 15,992 11,318 15,981 6,806 5,275 0 0 0 0 0 0 0 0 0 0 34 Operations Reserve 0 0 0 0 10,847 7,158 7,952 6,056 6,258 8,121 9,600 10,310 10,679 10,707 10,736 11,151 35 Unassigned 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 36 Total Reserves 34,362 36,203 31,681 27,286 25,735 20,514 16,034 14,138 14,340 16,203 17,682 18,392 18,761 18,789 18,818 19,233 37 (1,551)(5,221)(4,480)(1,896)202 1,864 1,479 710 369 28 29 415 38 Short Term Risk Assessment Value 1,226 3,789 3,969 4,362 4,766 5,005 5,085 5,134 5,247 5,365 5,487 5,612 39 40 Operations Reserve Guidelines 41 Min (60 Days Commodity + O&M) 5,620 4,772 5,618 5,889 6,090 6,151 6,368 6,599 6,851 7,103 7,361 7,603 42 Target (90 Days Commodity + O&M) 8,429 7,158 8,426 8,833 9,135 9,227 9,552 9,898 10,277 10,654 11,041 11,405 43 Max (120 Days Commodity + O&M) 11,239 9,543 11,235 11,778 12,180 12,302 12,736 13,198 13,703 14,206 14,721 15,207 44 City of Palo Alto Gas Utility Fiscal Year GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 34 | P a g e APPENDIX B : GAS UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL Project #Project Name Reappropriated / Carried Forward from Previous Years Current Year Funding Budget Amendments Spending, Current Year Remaining in CIP Reserve Fund Commitments FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 ONE TIME PROJECTS GS-09000 Gas Station 1 Rebuild - - - - - - - - - - GS-08000 Gas Station 2 Rebuild - - - - - - - - - - GS-10000 Gas Station 3 Rebuild 4 - - - 4 - - - - - - GS-11001 Gas Station 4 Rebuild - - - - - - - - - - GS-13003 COBUG emissions equipment - - - - - - - - - - GS-15001 Security at Receiving Stations 150,000 150,000 (150,000) (9,459) 140,541 125,000 - - - - Subtotal, One-time Projects 150,004 150,000 (150,000) (9,459) 140,545 125,000 - - - - - GAS MAIN REPLACEMENT (GMR) PROGRAM GS-08011 GMR - Project 18 - - - - - - - - - - - GS-09002 GMR - Project 19 526,621 - (30,410) (68,899) 427,312 427,312 - - - - - GS-10001 GMR - Project 20 2,311,602 - (13,981) (23,297) 2,274,324 2,274,325 - - - - - GS-11000 GMR - Project 21 867,159 - (20,512) (100,049) 746,598 832,416 - - - - - GS-12001 GMR - Project 22 295,985 4,033,001 (493,001) (175,008) 3,660,977 3,000 - - - - - GS-13001 GMR - Project 23 - 620,650 - - 620,650 42,500 3,550,650 - - - - GS-14003 GMR - Project 24 - - - - - - 640,000 3,100,000 - - - GS-15000 GMR - Project 25 - - - - - - - 711,000 3,200,000 - - GS-16000 GMR - Project 26 - - - - - - - - 678,200 3,300,000 - GS-20000 GMR - Project 27 - - - - - - - - - 700,000 3,400,000 GS-20001 GMR - Project 28 - - - - - - - - - - 721,000 Subtotal, Gas Main Replacement Program 4,001,367 4,653,651 (557,904) (367,253) 7,729,861 3,579,553 4,190,650 3,811,000 3,878,200 4,000,000 4,121,000 TOOLS AND EQUIPMENT GS-13002 General Shop Equipment/Tools 130,931 100,000 (113,062) (46,069) 71,800 - 100,000 100,000 100,000 100,000 100,000 GS-01019 Global Positioning System 73,578 - (70,768) (641) 2,169 - - - - - GS-02013 Directional Boring Machine - - - - - - - - - - - GS-03007 Directional Boring Equipment - - - - - - - - - - - GS-03008 Polyethylene Fusion Equip.29,168 - - - 29,168 - - - - - GS-14004 Gas Distribution System Model 140,742 87,690 (87,690) (29,544) 111,198 - - - - - - Subtotal, Tools and Equipment 374,419 187,690 (271,520) (76,254) 214,335 - 100,000 100,000 100,000 100,000 100,000 GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 35 | P a g e Gas Utility Capital Improvement Program (CIP) Detail (continued) Project #Project Name Reappropriated / Carried Forward from Previous Years Current Year Funding Budget Amendments Spending, Current Year Remaining in CIP Reserve Fund Commitments FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 ONGOING PROJECTS GS-11002 Gas System Improvements 151,021 292,669 (66,397) (114,635) 262,658 76,036 231,913 238,870 246,036 253,417 261,020 GS-03009 System Ext. - Unreimbursed 284,821 192,675 (284,095) (35,809) 157,592 - 198,500 204,455 210,590 216,908 223,415 GS-80019 Gas Meters and Regulators 736,596 344,690 (733,487) (42,523) 305,276 - 355,030 365,681 376,652 387,952 399,591 Subtotal, Ongoing Projects 1,172,438 830,034 (1,083,979) (192,967) 725,526 76,036 785,443 809,006 833,278 858,277 884,025 CUSTOMER CONNECTIONS (FEE FUNDED) GS-80017 Gas System Extensions (252,428) 950,000 255,428 (575,893) 377,107 37,880 1,228,500 1,265,355 1,303,315 1,342,415 1,382,688 Subtotal, Customer Connections (252,428) 950,000 255,428 (575,893) 377,107 37,880 1,228,500 1,265,355 1,303,315 1,342,415 1,382,688 GRAND TOTAL 5,445,800 6,771,375 (1,807,975) (1,221,826) 9,187,374 3,818,469 6,304,593 5,985,361 6,114,793 6,300,692 6,487,713 Funding Sources Connection Fees 639,600 255,428 1,017,000 1,047,510 1,078,935 1,111,303 1,144,642 Utility Rates 6,131,775 (2,063,403) 5,287,593 4,937,851 5,035,857 5,189,389 5,343,070 CIP-RELATED RESERVES DETAIL 6/30/2015 (Actual)9/30/2015 Reappropriations 2,100,800 5,368,905 5,076,093 4,720,006 4,811,478 4,958,277 5,105,025 Commitments 3,345,000 3,818,469 GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 36 | P a g e APPENDIX C : GAS UTILITY RESERVES MANAGEMENT PRACTICES The following reserves management practices shall be used when developing the Gas Utility Financial Plan: Section 1. Definitions a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal years covered by the Financial Plan. For example, if the Financial Plan delivered in conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015 to FY 2019 would be the Financial Planning Period . b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers to the Utility’s Unrestricted Net Assets. c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets as the difference between its assets and liabilities . d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital assets (net of related debt) or restricted for debt service or other restricted purposes. Section 2. Supply Fund Reserves The Gas Utility’s Supply Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserve for Commitments) b) For operating and capital budgets re-appropriated from previous years, as described in Section 5 (Reserve for Re-appropriations) Section 3. Distribution Fund Reserves a) For existing contracts, as described in Section 4 (Reserve for Commitments) b) For operating and capital budgets re-appropriated from previous years, as described in Section 5 (Reserve for Re-appropriations) c) For cash flow management and contingencies related to the Gas Utility’s Capital Improvement Program (CIP), as described in Section 6 (CIP Reserve) d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve) e) For operating contingencies, as described in Section 8 (Operations Reserve) f) Any funds not included in the other reserves will be considered Unassigned Reserves and shall be returned to ratepayers or assigned a specific purpose as described in Section 9 (Unassigned Reserves) Section 4. Reserve for Commitments At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for Commitments will be set to an amount equal to the total remaining spending authority for all contracts in force for the Wastewater Collection Utility at that time. Section 5. Reserve for Reappropriations At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for Reappropriations will be set to an amount equal to the amount of all remaining capital and GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 37 | P a g e non-capital budgets, if any, that will be re-appropriated to the following fiscal year for each fund in accordance with Palo Alto Municipal Code Section 2.28.090. Section 6. CIP Reserve The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for capital contingencies. Staff will manage the CIP Reserve according to the following practices: a) The following guideline levels are set forth for the CIP Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period based on the levels of CIP expense budgeted for that year. Minimum Level 12 months of budgeted CIP expense Maximum Level 24 months of budgeted CIP expense b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and the Reserve for Commitments when funds are added to or removed from the Reserve for Commitments as a result of a change in contractual commitments related to CIP projects. Any other additions to or withdrawals from the CIP reserve require Council action. c) Minimum Level: i) Funds held in the Reserve for Commitments may be counted as part of the CIP Reserve for the purpose of determining compliance with the CIP Reserve minimum guideline level. ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present a plan to the City Council to replenish the reserve. The plan shall be delivered by the end of the following fiscal year, and shall, at a minimum, result in the reserve reaching its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is below its minimum level at the end of FY 2017, staff must present a plan by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff may present, and the Council may adopt, an alternative plan that takes longer than one year to replenish the reserve, or that does so in a shorter period of time. d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds may be added to this reserve. If there are funds in this reserve in excess of the maximum level staff must propose to transfer these funds to another reserve or return them to ratepayers in the next Financial Plan. Staff may also seek Council approval to hold funds in this reserve in excess of the maximum level, if they are held for a specific future purpose related to the CIP. Section 7. Rate Stabilization Reserve Funds may be added to the Rate Stabilization Reserve by action of the City Council and held to manage the trajectory of future year rate increases . Withdrawal of funds from the Rate Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization Reserve at the end of any fiscal year, any subsequent Gas Utility Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the Financial Planning Period . GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 38 | P a g e Section 8. Operations Reserve The Operations Reserve is used to manage normal variations in costs and as a reserve for contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves described in Section 4-Section 7 above will be included in the Operations Reserve unless this reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage the Operations Reserve according to the following practices: a) The following guideline levels are set forth for the Operations Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period based on the levels of Operations and Maintenance (O&M) and commodity expense forecasted for that year in the Financial Plan. Minimum Level 60 days of O&M and commodity expense Target Level 90 days of O&M and commodity expense Maximum Level 120 days of O&M and commodity expense b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations Reserve are lower than the minimum level set forth above, staff shall present a plan to the City Council to replenish the reserve. The plan shall be delivered within six months of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its minimum level by the end of the following fiscal year. For example, if the Operations Reserve is below its minimum level at the end of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its minimum level by June 30, 2015 . In addition, staff may present, and the Council may adopt, an alternative plan that takes longer than one year to replenish the reserve. c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower than the target level, any Financial Plan created for the Gas Utility shall be designed to return the Operations Reserve to its target level by the end of the forecast period. d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no funds may be added to this reserve. Any further increase in the Gas Utility’s Fund Balance shall be automatically included in the Unassigned Reserve described in Section 9, below. Section 9. Unassigned Reserve If the Operations Reserve reaches its maximum level, any further additions to the Gas Utility’s Fund Balance will be held in the Unassigned Reserve. If there are any funds in the Unassigned Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council must include a plan to assign them to a specific purpose or return them to the Gas Utility ratepayers by the end of the first fiscal year of the next Financial Planning Period. For example, if there were funds in the Unassigned Reserves at the end of FY 2015, and the next Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a plan to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff may present an alternative plan that retains these funds or returns them over a longer period of time. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 39 | P a g e Section 10. Intra-Utility Transfers Between Supply and Distribution Funds The Gas Utility records costs in two separate f unds: the Gas Supply Fund and the Gas Distribution Fund. At the end of each fiscal year staff is authorized to transfer an amount equal to the difference between Gas Supply Fund costs and Gas Supply Fund Revenues from the Gas Distribution Fund Operations Reserve to the Gas Supply Fund, or vice versa. Such transfers shall be included in the ordinance closing the budget for the fiscal year. GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 40 | P a g e APPENDIX D : DESCRIPTION OF GAS UTILITY COST CATEGORIES This appendix describes the activities associated with the various cost categories referred to in this Financial Plan. Customer Service: This category includes the Gas Utility’s share of the call center, meter reading, collections, and billing support functions. Billing support encompasses staff time associated with bill investigations and quality control on certain aspects of the billing process . It does not include maintenance of the billing system itself, which is included in Administration . This category also includes CPAU’s key account representatives, who wor k with large commercial customers who have more complex requirements for their gas services. Resource Management: This category includes gas procurement, contract management, rate setting, and tracking of legislation and regulation related to the gas indu stry. Operations and Maintenance: This category includes the costs of a variety of distribution system maintenance activities, including: surveying the gas system (50% of the system each year) and repairing any leaks found; investigating reports of damaged mains or services and perform emergency repairs; building and replacing gas services for new or redeveloped buildings; and testing and replacing meters to ensure accurate sales metering. This category also includes a variety of functions the utility shares with other City utilities, including: the Field Services team (which does field research of various customer service issues); the Cathodic Protection team (which monitors and maintains the systems that prevent corrosion in metal pipes and reservoirs); and the General Services team (which manages and maintains equipment, paves and restores streets after gas, water, or sewer main replacements, and provides welding services, including certified gas line welding services) Administration: Accounting, purchasing, legal, and other administrative functions provided by the City’s General Fund staff, as well as shared communications services and Utilities Department administrative overhead and billing system maintenance costs. Demand Side Management: Includes the cost of administering gas efficiency programs and the direct cost of rebates paid. Engineering (Operating): The Gas Utility’s engineers focus primarily on the CIP, but a small portion of their time is spent assisting with distribution system maintenance. APPENDIX E : GAS UTILITY COMMUNIC ATIONS SAMPLES Attachment C * NOT YET APPROVED * 6053683 Resolution No. _________ Resolution of the Council of the City of Palo Alto Increasing Gas Rates by Amending Rate Schedules G-1 (Residential Gas Service), G-1-G (Residential Green Gas Service), G-2 (Residential Master- Metered and Commercial Gas Service), G-2-G (Residential Master- Metered and Commercial Green Gas Service), G-3 (Large Commercial Gas Service), G-3-G (Large Commercial Green Gas Service). G-10 (Compressed Natural Gas Service Service) and G-10-G (Compressed Natural Green Gas Service) R E C I T A L S A. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of the City of Palo Alto may by resolution adopt rules and regulations governing utility services, fees and charges. B. On ____, 2016, the City Council heard and approved the proposed rate increase. The Council of the City of Palo Alto does hereby RESOLVE as follows: SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule G-1 (Residential Gas Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule G-1, as amended, shall become effective July 1, 2016. SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule G-1-G (Residential Green Gas Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule G-1-G, as amended, shall become effective July 1, 2016. SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule G-2 (Residential Master-Metered and Commercial Gas Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule G-2, as amended, shall become effective July 1, 2016. SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule G-2-G (Residential Master-Metered and Commercial Green Gas Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule G-2-G, as amended, shall become effective July 1, 2016. SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule G-3 (Large Commercial Gas Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule G-3, as amended, shall become effective July 1, 2016. SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule G-3-G (Large Commercial Green Gas Service) is hereby amended to read as Attachment C * NOT YET APPROVED * 6053683 attached and incorporated. Utility Rate Schedule G-3-G, as amended, shall become effective July 1, 2016. SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule G-10 (Compressed Natural Gas Service Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule G-10, as amended, shall become effective July 1, 2016. SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule G-10-G (Compressed Natural Green Gas Service Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule G-10-G, as amended, shall become effective July 1, 2016. SECTION 9. The City Council finds as follows: a. Revenues derived from the gas rates approved by this resolution do not exceed the funds required to provide water service. b. Revenues derived from the gas rates approved by this resolution shall not be used for any purpose other than providing gas service, and the purposes set forth in Article VII, Section 2, of the Charter of the City of Palo Alto. SECTION 10. The Council finds that the fees and charges adopted by this resolution are charges imposed for a specific government service or product provided directly to the payor that are not provided to those not charged, and do not exceed the reasonable costs to the City of providing the service or product. SECTION 11. The Council finds that the adoption of this resolution changing gas rates to meet operating expenses, purchase supplies and materials, meet financial reserve needs and obtain funds for capital improvements necessary to maintain service is not subject to the California Environmental Quality Act (CEQA), pursuant to Californ ia Public Resources Code Sec. 21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After reviewing the staff report and all attachments presented to Council, the Council incorporates these documents herein and finds that sufficient evidence has been presented setting forth with specificity the basis for this claim of CEQA exemption. Attachment C * NOT YET APPROVED * 6053683 INTRODUCED AND PASSED: AYES: NOES: ABSENT: ABSTENTIONS: ATTEST: ___________________________ ___________________________ City Clerk Mayor APPROVED AS TO FORM: APPROVED: ___________________________ ___________________________ Senior Deputy City Attorney City Manager ___________________________ Director of Utilities ___________________________ Director of Administrative Services RESIDENTIAL GAS SERVICE UTILITY RATE SCHEDULE G-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-1-1 Effective 72-1-20156 dated 12-1-20135 Sheet No G-1-1 A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from City of Palo Alto Utilities: 1. Separately-metered single-family residential Customers. 2. Separately-metered multi-family residential Customers in multi-family residential facilities. B. TERRITORY: This schedule applies anywhere the City of Palo Alto provides Gas Service. C. UNBUNDLED RATES: Per Service Monthly Service Charge: ..................................................................................................$910.3288 Tier 1 Rates: Per Therm Supply Charges: 1. Commodity (Monthly Market Based) .......................................... $0.10-$2.00 2. Cap and Trade Compliance Charge ..................................................$0.00-$0.25 Distribution Charge: .............................................................................................$0.50214392 Tier 2 Rates: (All usage over 100% of Tier 1) Supply Charges: 1. Commodity (Monthly Market Based) .......................................... $0.10-2.00 2. Cap and Trade Compliance Charge ...................................................$0.00-$0.25 Distribution Charge: ............................................................................................. .........................................................................................................$01.0407954 6 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and ATTACHMENT D RESIDENTIAL GAS SERVICE UTILITY RATE SCHEDULE G-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-1-2 Effective 72-1-20156 dated 12-1-20135 Sheet No G-1-2 adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter. The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will change in response to changing market conditions, retail sales volumes and the quantity of allowances required. The Commodity and Cap and Trade Compliance Charges will fall within the minimum/maximum ranges set forth in Section C. 2. Seasonal Rate Changes: The Summer period is effective April 1 to October 31 and the Winter period is effective from November 1 to March 31. When the billing period includes use in both the Summer and the Winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates for each period. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Calculation of Usage Tiers Tier 1 natural gas usage shall be calculated and billed based upon a level of 0.667 therms per day during the Summer period and 2.0 therms per day during the Winter period, rounded to the nearest whole therm, based on meter reading days of service. As an example, for a 30 day bill, the Tier 1 level would be 20 therms during the Summer period and 60 therms during the Winter period months. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. {End} RESIDENTIAL GREEN GAS SERVICE UTILITY RATE SCHEDULE G-1-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-1-G-1 Effective 27-1-20156 dated 72-1-20145 Sheet No G-1-G-1 A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto Utilities under the PaloAltoGreen Gas Program: 1. Separately-metered single-family residential Customers. 2. Separately-metered multi-family residential Customers in multi-family residential facilities. B. TERRITORY: This schedule applies anywhere the City of Palo Alto provides Gas Service. C. UNBUNDLED RATES: Per Service Monthly Service Charge: ..................................................................................................$910.3288 Tier 1 Rates: Per Therm Supply Charges: 1. Commodity (Monthly Market Based) .......................................... $0.10-$2.00 2. Cap and Trade Compliance Charges .................................................$0.00-$0.25 Distribution Charge:.............................................................................................$0.50214392 PaloAltoGreen Gas Charge .................................................................................. $0.1200 Tier 2 Rates: (All usage over 100% of Tier 1) Supply Charges: 1. Commodity (Monthly Market Based) .......................................... $0.10-2.00 2. Cap and Trade Compliance Charges ..................................................$0.00-$0.25 Distribution Charge:.............................................................................................$01.04079546 PaloAltoGreen Gas Charge .................................................................................. $0.1200 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and RESIDENTIAL GREEN GAS SERVICE UTILITY RATE SCHEDULE G-1-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-1-G-2 Effective 27-1-20156 dated 72-1-20145 Sheet No G-1-G-2 adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter. The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will change in response to changing market conditions, retail sales volumes and the quantity of allowances required. The Commodity and Cap and Trade Compliance Charges will fall within the minimum/maximum ranges set forth in Section C. 2. Seasonal Rate Changes: The Summer period is effective April 1 to October 31 and the Winter period is effective from November 1 to March 31. When the billing period includes use in both the Summer and the Winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates for each period. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Calculation of Usage Tiers Tier 1 natural gas usage shall be calculated and billed based upon a level of 0.667 therms per day during the Summer period and 2.0 therms per day during the Winter period, rounded to the nearest whole therm, based on meter reading days of service. As an example, for a 30 day bill, the Tier 1 level would be 20 therms during the Summer period and 60 therms during the Winter period months. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 4. PaloAltoGreen Gas Program Description and Participation PaloAltoGreen Gas provides for the reduction of green-house gas (GHG) emissions associated with a Customer’s Gas usage, through the purchase of certified environmental offsets, with a preference to projects located in California. Purchases are made to match 100% of the therm usage at the Customer’s premises every month. Customers choosing to participate shall fill out a PaloAltoGreen Gas Program application provided by the Customer Service Center. {End} RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE UTILITY RATE SCHEDULE G-2 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-2-1 Effective 27-1-20156 dated 72-1-20125 Sheet No G-2-1 A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto Utilities: 1. Commercial Customers who use less than 250,000 therms per year at one site. 2. Master-metered residential Customers in multi-family residential facilities. B. TERRITORY: This schedule applies anywhere the City of Palo Alto provides Gas Service. C. UNBUNDLED RATES: Per Service Monthly Service Charge: ..................................................................................................$784.2386 Per Therm Supply Charges: 1. Commodity (Monthly Market Based) .................................... $0.10-$2.00 2. Cap and Trade Compliance Charges ................................................. $0.00-0.25 Distribution Charge: ........................................................................................................$0.6855147 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter. The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will change in response to changing market conditions, retail sales volumes and the quantity of allowances required. The Commodity and Cap and Trade Compliance Charges will fall within the minimum/maximum ranges set forth in Section C. {End} RESIDENTIAL MASTER-METERED AND COMMERCIAL GREEN GAS SERVICE UTILITY RATE SCHEDULE G-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-2-G-1 Effective 27-1-20156 dated 72-1-20145 Sheet No G-2-G-1 A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto Utilities under the PaloAltoGreen Gas Program: 1. Master-metered residential Customers in multi-family residential facilities. 2. Commercial Customers who use less than 250,000 therms per year at one site. B. TERRITORY: This schedule applies anywhere the City of Palo Alto provides Gas Service. C. UNBUNDLED RATES: 1. 100% Renewable/Full Green option:Per Service Monthly Service Charge: ......................................................................................$784.2386 Per Therm Supply Charges: 1. Commodity (Monthly Market Based) .......................................... $0.10-$2.00 2. Cap and Trade Compliance Charges ....................................................... $0.00-0.25 Distribution Charge: ............................................................................................$0.6855147 PaloAltoGreen Gas Charge .................................................................................. $0.1200 2. 100 Therm block option:Per Service Monthly Service Charge: ......................................................................................$784.2386 Per Therm Supply Charges: 1. Commodity (Monthly Market Based) .......................................... $0.10-$2.00 2. Cap and Trade Compliance Charges ....................................................... $0.00-0.25 Distribution Charge: ............................................................................................$0.6855147 PaloAltoGreen Gas Charge (per 100 therm block) .............................................. $12.00 RESIDENTIAL MASTER-METERED AND COMMERCIAL GREEN GAS SERVICE UTILITY RATE SCHEDULE G-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-2-G-2 Effective 27-1-20156 dated 72-1-20145 Sheet No G-2-G-2 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter. The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will change in response to changing market conditions, retail sales volumes and the quantity of allowances required. The Commodity and Cap and Trade Compliance Charges will fall within the minimum/maximum ranges set forth in Section C. 2. Request for Service A qualifying Customer may request service under this schedule for more than one account or meter if the accounts are located on one. A site consists of one or more contiguous parcels of land with no intervening public right-of-ways (e.g. streets). 3. PaloAltoGreen Gas Program Description and Participation PaloAltoGreen Gas provides for the reduction of green-house gas (GHG) emissions associated with a Customer’s gas usage, through the purchase of certified environmental offsets, with a preference to projects located in California. Purchases are made to match 100% of the therm usage at the Customer’s facility every month (the 100% Renewable/Full Green option), or in 100 therm blocks. Customers choosing to participate shall fill out a PaloAltoGreen Gas Program application provided by the Customer Service Center. {End} LARGE COMMERCIAL GAS SERVICE UTILITY RATE SCHEDULE G-3 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-3-1 Effective 27-1-20156 dated 72-1-20125 Sheet No G-3-1 A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto Utilities: 1. Commercial Customers who use at least 250,000 therms per year at one site. 2. Customers at City-owned generation facilities. B. TERRITORY: This schedule applies anywhere the City of Palo Alto provides natural gas service. C. UNBUNDLED RATES: Per Service Monthly Service Charge: $37761.4318 Per Therm Supply Charges: 1. Commodity (Monthly Market Based) .................................................... $0.10-$2.00 2. Cap and Trade Compliance Charges ...................................................... $0.00-0.25 Distribution Charge: .......................................................................................................$0.6775071 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter. The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will change in response to changing market conditions, retail sales volumes and the quantity of allowances required. The Commodity and Cap LARGE COMMERCIAL GAS SERVICE UTILITY RATE SCHEDULE G-3 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-3-2 Effective 27-1-20156 dated 72-1-20125 Sheet No G-3-2 and Trade Compliance Charges will fall within the minimum/maximum ranges set forth in Section C. 2. Request for Service A qualifying Customer may request service under this schedule for more than one account or meter if the accounts are located on one site. A site consists of one or more contiguous parcels of land with no intervening public right-of- ways (e.g. streets). 3. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable City of Palo Alto full-service rate schedule. Customers served under this rate schedule may elect Gas Direct Access at any time. {End} LARGE COMMERCIAL GREEN GAS SERVICE UTILITY RATE SCHEDULE G-3-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-3-G-1 Effective 27-1-20156 dated 72-1-20145 Sheet No G-3-G-1 A. APPLICABILITY: This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto Utilities under the PaloAltoGreen Gas Program: 1. Commercial Customers who use at least 250,000 therms per year at one site. 2. Customers at City-owned generation facilities. B. TERRITORY: This schedule applies anywhere the City of Palo Alto provides Gas Service. C. UNBUNDLED RATES: 1. 100% Renewable/Full Green option:Per Service Monthly Service Charge:$37761.4318 Per Therm Supply Charges: 1. Commodity (Monthly Market Based) .......................................................... $0.10-$2.00 2. Cap and Trade Compliance Charges .......................................................... $0.00-0.25 Distribution Charge: ...........................................................................................$0.6775071 PaloAltoGreen Gas Charge: ......................................................................................$0.1200 2. 100 Therm block option: Per Service Monthly Service Charge:$37761.4318 Per Therm Supply Charges: 1. Commodity (Monthly Market Based) .......................................................... $0.10-$2.00 2. Cap and Trade Compliance Charges .......................................................... $0.00-0.25 Distribution Charge: ...........................................................................................$0.6775071 PaloAltoGreen Gas Charge (per 100 therm block): ....................................................$12.00 D. SPECIAL NOTES: LARGE COMMERCIAL GREEN GAS SERVICE UTILITY RATE SCHEDULE G-3-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-3-G-2 Effective 27-1-20156 dated 72-1-20145 Sheet No G-3-G-2 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. The Commodity Charge is based on the monthly natural gas Bidweek Price Index for delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter. The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will change in response to changing market conditions, retail sales volumes and the quantity of allowances required. The Commodity and Cap and Trade Compliance Charges will fall within the minimum/maximum ranges set forth in Section C. 2. Request for Service A qualifying Customer may request service under this schedule for more than one account or meter if the accounts are located on one site. A site consists of one or more contiguous parcels of land with no intervening public right-of-ways (e.g. streets). 3. PaloAltoGreen Gas Program Description and Participation PaloAltoGreen Gas provides for the reduction of green-house gas (GHG) emissions associated with a Customer’s gas usage, through the purchase of certified environmental offsets, with a preference to projects located in California. Purchases are made to match 100% of the therm usage at the Customer’s facility every month, (the 100% Renewable/Full Green option), or in 100 therm blocks. Customers choosing to participate shall fill out a PaloAltoGreen Gas Program application provided by the Customer Service Center. {End} COMPRESSED NATURAL GAS SERVICE UTILITY RATE SCHEDULE G-10 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-10-1 Effective 47-201-20156 dated 14-201-20135 Sheet No.G-10-1 A. APPLICABILITY: This schedule applies to the sale of natural gas to the City-owned compressed natural gas (CNG) fueling station at the Municipal Service Center in Palo Alto B. TERRITORY: Applies to location at the Municipal Service Center in City of Palo Alto. C. UNBUNDLED RATES: Per Service Monthly Service Charge: ..................................................................................................$520.9365 Per Therm Supply Charges: Commodity (Monthly Market Based) ................................................................ $0.10-$2.00 Cap and Trade Compliance Charges .............................................................. $0.00 to $0.25 Distribution Charge .........................................................................................................$0.0963509 D. SPECIAL CONDITIONS 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. The Commodity charge is based on the monthly natural gas Bidweek Price Index for delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter. The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will change in response to changing market conditions, retail sales volumes and the quantity of allowances required. The Commodity and Cap and Trade Compliance Charges will fall within the minimum/maximum range set forth in Section C. {End} COMPRESSED NATURAL GREEN GAS SERVICE UTILITY RATE SCHEDULE G-10-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-10-G--1 Effective 47-120-20156 dated 4-20-2015 Sheet No.G-10-G-1 A. APPLICABILITY: This schedule applies to the wholesale sale of natural gas to the City-owned compressed natural gas (CNG) fueling station at the Municipal Service Center in Palo Alto under the PaloAltoGreen Gas Program: B. TERRITORY: The City-owned compressed natural gas (CNG) fueling station located at the Municipal Service Center in City of Palo Alto. C. UNBUNDLED RATES: Per Service Monthly Service Charge: ..................................................................................................$520.9365 Per Therm Supply Charges: Commodity (Monthly Market Based) .................................................... $0.10-$2.00 Cap and Trade Compliance Charges .................................................. $0.00 to $0.25 Distribution Charge .........................................................................................................$0.0963509 PaloAltoGreen Gas Charge ...................................................................................................$0.1200 D. SPECIAL CONDITIONS 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. The Commodity charge is based on the monthly natural gas Bidweek Price Index for delivery at PG&E Citygate, accounting for delivery losses to the Customer’s Meter. The Cap and Trade Compliance Charge reflects the City’s cost of regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The Cap and Trade Compliance Charge will change in response to COMPRESSED NATURAL GREEN GAS SERVICE UTILITY RATE SCHEDULE G-10-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-10-G--2 Effective 47-120-20156 dated 4-20-2015 Sheet No.G-10-G-2 changing market conditions, retail sales volumes and the quantity of allowances required. The Commodity and Cap and Trade Compliance Charges will fall within the minimum/maximum range set forth in Section C. 2. PaloAltoGreen Gas Program Description and Participation PaloAltoGreen Gas provides for the reduction of green-house gas (GHG) emissions associated with a Customer’s Gas usage, through the purchase of certified environmental offsets, with a preference to projects located in California. Purchases are made to match 100% of the therm usage at the Customer’s premises every month. Customers choosing to participate shall fill out a PaloAltoGreen Gas Program application provided by the Customer Service Center. {End} Page 1 of 9 4 MEMORANDUM TO: UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT DATE: APRIL 12, 2016 SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend that the City Council Adopt a Resolution Approving the 2015 Urban Water Management Plan and Adopt an Ordinance Amending Municipal Code Sections 12.32.010 (Water Use Restrictions) and 12.32.020 (Enforcement) ______________________________________________________________________________ REQUEST Staff requests the Utilities Advisory Commission (UAC) recommend the City Council adopt: 1.A resolution (Attachment B) approving the 2015 Urban Water Management Plan (Attachment A) and a revised Water Shortage Contingency Plan (WSCP); and 2.An ordinance (Attachment C) amending Municipal Code Sections 12.32.010, Water Use Restrictions, and 12.32.020, Enforcement. BACKGROUND The California Urban Water Management Planning Act (Act) requires every California water agency supplying more than 3,000 acre-feet (AF) of water per year or providing service to more than 3,000 connections to prepare an Urban Water Management Plan (UWMP). The UWMP is prepared every five years by urban water suppliers to assess the reliability of water sources over a 20-year planning horizon under both normal and dry hydrologic conditions and to ensure adequate water supplies are available to meet existing and future water demands. Senate Bill x7-7 (SBx7-7), adopted in November 2009, mandates a statewide per capita potable water use reduction of 20% by the year 2020. Urban water suppliers are required to identify a baseline usage (expressed in gallons per capita per day, or GPCD) for their service area, calculate a target to meet the 20% reduction, and include a plan for compliance in the 2015 UWMP. The City’s 2015 UWMP addresses these items. The City must adopt the 2015 UWMP by July 1, 2016 and submit it to the California Department of Water Resources within 30 days of adoption. DISCUSSION For the 2015 UWMP, the City has updated the 2010 UWMP and addressed any changes as required by the Act and related legislation. In terms of water supply sources, the 2015 UWMP policy and direction is the same as in the 2010 UWMP. Apart from state requirements for Page 2 of 9 reporting, the City already implements water resource planning on an ongoing basis. The main approach the City uses is to prepare a Water Integrated Resource Plan (WIRP), in which all water resource options are evaluated, as well as a Demand Side Management Implementation Plan, which includes projections and plans for implementing water efficiency measures. The 2015 UWMP provides background on the WIRP and other supply planning efforts as well as an updated analysis of current and planned Demand Management Measures (DMMs) developed to meet new State requirements for potable water use reductions . A detailed description of these measures is included in the DMM1 section of this report and in the UWMP. The 2015 UWMP contains the following highlights: Public involvement and coordination with other agencies; Description of current and potential water sources, including the potential for expanded use of recycled water in the City; The City's water demand projections; Plans to implement water efficiency (conservation) programs; Discussion of (non-drought) emergency plans; The sufficiency of supplies from San Francisco, particularly in droughts; and Drought response plans for droughts of varying severity. Each of these sections, including new developments since the 2010 UWMP was adopted, is summarized below. Public Involvement and Coordination with Other Agencies The City has actively encouraged community participation in its urban water management planning efforts. The City also coordinates its planning activities with neighboring communities and water agencies. Various stakeholders were notified of the City’s plan to review and update the UWMP in December 2015. Letters explaining how to access the City’s draft 2015 UWMP were also sent to the San Francisco Public Utilities Commission (SFPUC), the Bay Area Water Supply and Conservation Agency (BAWSCA), the Santa Clara Valley Water District (SCVWD), the County of Santa Clara, the Cities of Mountain View, East Palo Alto, Menlo Park, and Redwood City, the Purissima Hills Water District, Stanford University and the Palo Alto Regional Water Quality Control Plant (RWQCP) for review and comments. The City maintains a web site with background information and links to related resources to educate the public and encourage participation in the process (http://www.cityofpaloalto.org/uwmp). Consideration of the 2015 UWMP by the Utilities Advisory Commission affords the public an opportunity to participate in the process prior to the meeting when the City Council considers adoption of the Plan. In addition, notices will be placed in the local daily and weekly newspapers informing the public of the opportuniti es to comment on the City’s 2015 UWMP 1 Although commonly referred to as Demand Side Management (DSM) measures, the California Water Code specifically requires an urban water supplier to report on Demand Management Measures (DMM), therefore this terminology is used throughout the 2015 UWMP and related reports. Page 3 of 9 update. The draft 2015 UWMP is available on the City’s web site, and hard copies are available at City Hall for public review. Current and Potential Water Sources San Francisco Public Utilities Commission The City’s potable water is supplied by the SFPUC from the Regional Water (Hetch Hetchy) System. In June 2009, the City signed a Water Supply Agreement (WSA) with the City and County of San Francisco (CMR:269:09). The WSA expires in 2034, and the City anticipates maintaining the current level of reliance on SFPUC supplies for the foreseeable future . In order to enhance the ability of the SFPUC water supply system to meet service goals for water quality, seismic reliability, delivery reliability and water supply, the SFPUC undertook the Water System Improvement Program (WSIP), which was approved on October 31, 2008. The WSIP is aimed at enhancing the SFPUC’s ability to meet its water service mission of providing high quality water to customers in a reliable, affordable and environmentally sustainable manner. Many of the water supply and reliability projects evaluated in the WSIP were originally put forth in the SFPUC’s 2000 Water Supply Master Plan. The WSIP is 90% complete with the largest outstanding project, the Calaveras Dam replacement, scheduled to be completed by November 2018. Groundwater As of 2015, the City has implemented the Emergency Water Supply and Storage Project (Emergency Project) including five refurbished wells, three new wells and a new 2.5 million gallon storage tank. The primary purpose of the Emergency Project was to provide water supply and fire suppression in the event of a catastrophic disruption of supply . However, the Emergency Project also enables the use of groundwater for supplemental supplies in droughts, as was done on several occasions during previous water shortages . There are no current plans to use groundwater in normal (non-drought) years for water supply although the City is partnering with the SCVWD to analyze the shallow and deep aquifers in the Northwestern portion of the county, including the potential for groundwater recharge and indirect potable reuse. Recycled Water The City currently uses recycled water for certain non-potable uses. The largest current uses are irrigation of the Palo Alto Municipal Golf Course and Greer Park and processes at the Palo Alto RWQCP. In September 2015, the City Council certified the project Environmental Impact Report to expand the current recycled water system to serve customers in the Stanford Research Park. Recycled water use for the project expansion is not included in the 2015 UWMP water production forecast, as no decision has been made to proceed with the p roject. Staff is preparing a financial plan for the project and evaluating alternatives such as purifying the recycled water to use for potable water supplies or to recharge groundwater aquifers. Page 4 of 9 Other Water Supply Options Other supply options include executing water transfer agreements with other agencies and constructing a desalination plant. The City has no current plans for either of these options, but is coordinating with BAWSCA and the SCVWD on efforts to identify and evaluate new supply sources. In addition, and as mentioned above, the City is partnering with the SCVWD to study and explore groundwater and indirect potable reuse as a potential water supply source. Water Demand Incorporating the profound effects of the current drought and state-imposed mandatory potable water use reductions presented an additional challenge when developing the water demand projections for this 2015 UWMP. A model developed in-house was used to forecast SFPUC purchases assuming the continuation of the City’s existing DMMs. Water savings from future DMMs were developed using the same end use model that was used to develop the projections in the 2010 UWMP. The City developed baseline projections for the purchased SFPUC water using an econometric model built in-house. The model uses historical water usage data as well as assumptions regarding population, economic growth, and development. Current DMMs are implicitly accounted for in the model. Breaking down demand at the end -use level was accomplished by applying the 2015 water use percentages for each type of water service account (single‐family, multi‐ family, commercial, irrigation, etc.) to the total projected demand. The end use model was used to forecast the impact of future DMMs. For 2015 and future population and employment projections, staff relied upon projections prepared in 2013 by the Association of Bay Area Governments (ABAG). Using the 2013 ABAG projections does not indicate that the City agrees with these projections . In fact, staff is aware that many believe these projections are too high . However, for purposes of planning water supply needs, using the 2013 ABAG projections is a conservative assumption. It is prudent to ensure that the City accounts for unexpected growth and other unforeseen factors for future water demand projections. The population and employment projections used for the 2015 UWMP are shown in Table 1 below. Table 1: Population – Current and Projected The City has a contractual entitlement (Individual Supply Guarantee, or “ISG”) from the SFPUC regional water system of 17.07 million gallons per day (mgd), or 19,118 acre -feet per year (AFY). Current and projected water demands are considerably lower than the ISG and staff does not anticipate water usage will exceed the contractual entitlement in the foreseeable future. 2015 2020 2025 2030 2035 2040 Service Area Population 67,400 70,500 73,700 77,100 80,800 84,600 Five Year Precent Increase 4.6%4.5%4.6%4.8%4.7% Total Employment 96,900 104,820 107,870 110,940 115,110 119,470 Five Year Precent Increase 8.2%2.9%2.8%3.8%3.8% Page 5 of 9 The City purchased 10,724 AF of water from the SFPUC in 2015. In 1985, the City’s water purchases were 18,700 AF and in 1976, the City purchased over 20,000 AF. The observed water use reduction can be attributed to many factors, including the 1976-77 drought, the 1987-92 drought, the 2015 SWRCB-mandated water use reductions and early adoption of efficiency measures and conservation. Table 2 provides the projection for SFPUC purchases for the 2015 UWMP planning horizon. Table 2: Palo Alto Supply/Demand Balance (AF/Y) The 2015 UWMP addresses the City’s requirements under the Water Conservation Bill of 2009 (SBx7-7). The statute requires water suppliers to reduce average per capita daily water consumption by 20% by December 31, 2020. Water suppliers can choose one of four different methods to calculate the baseline from which the 20% reduction is calculated . Staff has evaluated the four methods based on several criteria and has determined that the method th at is most suitable for the City is Method 1, which allows water suppliers to select a baseline of the average use over a 10-year period ending no earlier than 2004 and no later than 2010 . For the City, the optimal 10-year period is from 1994 to 2004. Using future water usage and population projections, staff has determined that the planned water efficiency measures will result in enough savings to meet the SBx7-7 target as shown in Figure 1 below. Figure 1: SB 7 Compliance Projection (in gallons per capita per day, or GPCD) 2015 2020 2025 2030 2035 Palo Alto Demand for SFPUC Water 10,724 11,883 11,411 11,132 10,879 Individual Supply Guarantee 19,118 19,118 19,118 19,118 19,118 Difference 8,394 7,235 7,707 7,986 8,239 Page 6 of 9 Demand Management Measures (DMM) The City is committed to implement Best Management Practices (BMPs) related to water conservation programs. Since 2002, the City has partnered with SCVWD to promote and cost- share water efficiency programs for Palo Alto customers. Through this cost-sharing agreement, the City pays roughly half of the cost of the programs, with SCVWD administering many of these programs including onsite water audits, and rebates for landscape conversion as well as water efficient fixtures and appliances. The City also administers other water conservation programs in-house or through separate contracts with outside vendors, such as the Home Water Report program. The City continues to evaluate opportunities for program partnership opportunities with BAWSCA and other regional alliances. The 2015 UWMP addresses the following seven areas of water demand management that have been implemented over the past five years and/or will be implemented to achieve the City’s SBx7-7 target: 1. Water waste prevention ordinance 2. Metering 3. Conservation pricing 4. Public education and outreach 5. Programs to assess and manage distribution system real loss 6. Water conservation program coordination and staff support 7. Other demand management measures that have a significant impact on water use as measured in GPCD, including innovative measures, if implemented Descriptions and implementation details of each of the above DMMs are provided in the 2015 UWMP. Reliability and Emergency Planning The reliability of the City’s water system depends upon two basic factors: (1) the reliability of the local distribution system under the City’s control, and (2) the reliability of the Regional Water System under the control of the SFPUC. The Regional Water System’s reliability deficiencies are being addressed as part of the WSIP. The WSIP is 90% complete with the largest outstanding project, the Calaveras Dam replacement project, scheduled to be completed by November 2018. Since the SFPUC’s Regional Water System still has some vulnerability, local distribution system reliability is important. In addition, the SFPUC’s Regional Water System is subject to temporary outages due to such factors as water quality events that could mean that service from SFPUC could be cut off for short periods. In 1999, a study of Palo Alto’s distribution system revealed that it needed additional storage and the capability of reliably using groundwater to endure such an emergency.2 The study also identified capital improvements to allow the City to provide eight-hour emergency water supplies. Subsequent studies showed that the capital improvements recommended by the study could assist in shortages such as a multi -year 2 Carollo Engineers, Water Wells, Regional Storage, and Distribution Study, December 1999. Page 7 of 9 drought and 30 to 60 day outages as well as the eight-hour outage they were designed to handle.3 To address the deficiency, City Council completed the Emergency Water Supply and Storage Project. The City’s wells and storage system are now capable of providing fire suppression and serving the community’s water needs for up to eight hours during peak usage times . Drought-time Availability of SFPUC Supplies In July 2009, as part of the WSA, the wholesale customers 4 and San Francisco adopted a Water Shortage Allocation Plan (WSAP) to allocate water from the regional water system to retail and wholesale customers during system-wide shortages of 20% or less (the “Tier 1 Plan”)5. The Tier 1 Plan allows for voluntary transfers of shortage allocations between the SFPUC and any wholesale customer and between wholesale customers themselves. In addition, water “banked” by a wholesale customer through reductions in usage greater than required, may also be transferred. The Tier 1 Plan will expire at the end of the term of the WSA on June 30, 2034, unless extended by San Francisco and the wholesale customers. The wholesale customers adopted the “Tier 2 Plan”, which allocates the collective wholesale customer share among each of the 26 wholesale customers . The City of Palo Alto approved the Tier 2 plan in February 2011 (Staff Report 1308). The Tier 2 allocation plan is based on a formula that takes into account multiple factors for each wholesale customer . The Tier 2 Plan requires that the water allocation factors for each agency be calculated each year in preparation for a potential water shortage emergency. The Tier 2 Plan will expire in 2018 unless extended by the wholesale customers. As the wholesale customers change their water use characteristics (e.g., increases or decreases in SFPUC purchases and use of other water sources, changes in monthly water use patterns or changes in residential per capita water use), the final drought allocation for each wholesale customer will also change. It is difficult to predict what that allocation may be in the future . For illustration purposes, staff is providing one possible outcome using the example provided in the Tier 2 Plan adopted by the City Council, as calculated for FY 2013. Table 3 below illustrates how much water would be available to the City from the regional system under di fferent reduction scenarios using actual water purchases from FY 2013. 3 Carollo Engineers, Long-Term Water Supply Study, May 2000. Carollo Engineers, Groundwater Supply Feasibility Study, April 2003. 4 The wholesale customers are the entities that purchase water from the SFPUC regional system and are members of BAWSCA 5 The previous water shortage allocation plan expired in 2009 with the termination of the previous Water Supply Agreement with the SFPUC. Details of the previous allocation plan are provided in the 2005 UWMP. Page 8 of 9 Table 3: Palo Alto Share of Available Water (AF/Y) Drought Contingency Plan Palo Alto has experience with both severe droughts resulting in the SFPUC rationing Regional Water System supplies and with the current SWRCB-mandated potable water use reductions. In both cases, residents and businesses reduced water consumption to meet the reduction targets. The City’s actions included the implementation and enforcement of emergency water restrictions and focused public outreach campaigns to provide information on ways to efficiently use available water. As shown in Table 4, the 2015 UWMP outlines actions that the City could take to achieve varying degree of water use reduction. Voluntary water use reduction are estimated to cost the City $30,000-$50,000 in outreach costs and, based on the experience in 2015, implementation and enforcement of mandatory reductions are estimated to cost $400,000-$600,000. Table 4: Drought Response Strategy Stage I Stage II Stage III Stage IV Target Water Savings 5% - 10% 10% -20% 20%- 35% 35% - 50% Information Outreach and Audit Program Continuation of existing programs plus a low level media campaign Increased advertising, availability of kits with low-cost devices Escalated outreach efforts and media campaign. High water users targeted. Further escalated outreach efforts. Focus on survival strategies and prioritization of water use. Demand-Side Management Programs Continuation of existing programs, evaluation of new programs Augmented programs as necessary to achieve reduction targets Programs continued with monitoring of reductions to determine whether to increase program incentive levels Additional program efforts targeted to indoor water use, if that area shows potential. Rate Structures Standard rates already encourage conservation Implementation of rates with consumption tiers for non single-family residential customers Rates as in Stage II with steeper prices for higher usage tiers Allocation method introduced for first time. Year 1 Year 2 Year 3 System-wide Shortage 0%10%10%22%22% BAWSCA 163,429 170,934 170,934 144,722 144,722 City of Palo Alto 12,692 12,692 12,692 11,425 11,425 Availability of Water for Palo Alto 100%100%100%90%90% Allocations During Multiple Dry Years Demand (FY 2013) One Critical Dry Year Allocation ·Stage I Stage II Stage Ill Stage·1v Water Use Only More vigilant Additional Severe emergency Restrictions permanent enforcement of water emergency water water use restrictions. water use use restrictions and use restrictions Rigorous enforcement ordinance -no addition of new added. new restrictions restrictions. Commence Enforcement efforts apply. is suance of warning increased. citations. Recycled Advertise availability of Advertise Advertise availability of Water Use recycled water for availability of recycled water for trucked delivery recycled water for trucked delivery trucked delivery Water Use Restrictions Four water uses are permanently restricted in the Palo Alto Municipal Code. The proposed and attached ordinance will cause to be permanent four additional common sense water use restrictions. ENVIRONMENTAL IMPACT Adoption of the resolution approving the 2015 Urban Water Management Plan and ordinance amending Municipal Code Sections 12.32.010 (Water Use Restrictions) and 12.32.020 (Enforcement) does not meet the California Environmental Quality Act's (CEQA) definition of "project" under California Public Resources Code Sec. 21065, thus no environmental review is required. ATIACHMENTS A. Draft 2015 Urban Water Management Plan B. Resolution Adopting the Urban Water Management Plan Ordinance Modifying Water Use Restrictions C. Ordinance Amending Section 12.32.010, Water Use Restrictions and Section 12.32.020, Enforcement PREPARED BY: REVIEWED BY: APPROVED BY : Karla Dailey, Sen ior Resource Planner {~hristine Tam, Senior Resource Planner 'a ~·Director of Utilities, Resource Management Ed Shikada Assistant City Manager/Interim Utilities Director Page 9of9 2015 Draft URBAN WATER MANAGEMENT PLAN JUNE 2016 ATTACHMENT A Cover photo courtesy of Catherine Elvert – Rancheria Falls above the Hetch Hetchy Reservoir City of Palo Alto Utilities 2015 Draft Urban Water Management Plan June 2016 i Table of Contents List of Tables ........................................................................................................................ iv List of Figures ....................................................................................................................... iv List of Acronyms .................................................................................................................... v Contact Sheet ........................................................................................................................ 1 Section 1 – Plan Development and Adoption ......................................................................... 2 Plan Structure ........................................................................................................................... 2 Plan Adoption............................................................................................................................ 2 Public Participation ................................................................................................................... 2 Agency Coordination ................................................................................................................. 4 Internal City Coordination .................................................................................................. 4 Interagency Coordination ................................................................................................... 5 Section 2 – Service Area ....................................................................................................... 10 Demographics ......................................................................................................................... 10 Climate Characteristics ........................................................................................................... 11 Section 3 – System Supplies ................................................................................................. 12 Historical Background ............................................................................................................. 12 SFPUC Supply .......................................................................................................................... 16 Description of SFPUC Regional Water System .................................................................. 16 Water Supply Agreement ................................................................................................. 16 BAWSCA and Its Role .............................................................................................................. 20 Regional Water Demand and Conservation Projections .................................................. 20 Long Term Reliable Water Supply Strategy ...................................................................... 21 Alternative Water Supply Analysis .......................................................................................... 22 Transfer or Exchange Opportunities ....................................................................................... 22 Groundwater ........................................................................................................................... 23 Deep Aquifer Groundwater .............................................................................................. 23 Shallow Aquifer Groundwater .......................................................................................... 27 Water Recycling ...................................................................................................................... 28 Recycled Water Market Survey ........................................................................................ 28 Participation in Regional Recycled Water Planning .......................................................... 29 Wastewater Collection and Treatment in Palo Alto ......................................................... 30 Wastewater Generation, Collection & Treatment ........................................................... 31 Palo Alto Regional Water Quality Control Plant (RWQCP) ............................................... 31 Wastewater Disposal and Recycled Water Uses .............................................................. 31 Disposal of Wastewater .................................................................................................... 32 Recycled Water Currently Used ........................................................................................ 32 ii Potential Uses of Recycled Water ..................................................................................... 33 Recycled Water Facility Plan ............................................................................................. 33 Encouraging Recycled Water Use ..................................................................................... 35 Current and Proposed Actions to Encourage Use of Recycled Water .............................. 35 Recycled Water Optimization Plan ................................................................................... 36 RWQCP Long Range Facilities Plan ................................................................................... 37 BAWSCA Long Term Reliable Water Supply Strategy ....................................................... 37 Indirect Potable Reuse ...................................................................................................... 37 Desalinated Water .................................................................................................................. 37 Section 4 – Water Demand .................................................................................................. 39 Water Usage ........................................................................................................................... 39 Demand Projections .......................................................................................................... 39 Water Sales ....................................................................................................................... 41 Share of Total Consumption by Customer Type ............................................................... 42 Sales to Other Agencies .................................................................................................... 43 Additional Water Uses ‐ Recycled Water Use ................................................................... 43 Non‐Revenue Water/Water Loss ...................................................................................... 44 Total Water Use ................................................................................................................ 44 Projected Low to Moderate Income Water Use ............................................................... 44 Water Conservation Bill of 2009 ............................................................................................. 46 Measures, Programs and Policies to Achieve SBx7‐7 Water Targets ............................... 48 Economic Impacts of SBx7‐7 Compliance ......................................................................... 49 Section 5 – Demand Management Measures ....................................................................... 50 Water Waste Prevention Ordinance ....................................................................................... 51 Metering ................................................................................................................................. 51 Conservation Pricing ............................................................................................................... 52 Public Education and Outreach .............................................................................................. 52 Programs to Assess and Manage Distribution Systems Real Loss .......................................... 53 Water Conservation Program Coordination and Staffing Support ......................................... 53 Water Conservation Program Partnership with SCVWD .................................................. 53 Home Water Report Program ........................................................................................... 54 Water Conservation Coordinator ..................................................................................... 54 Water Waste Coordinator................................................................................................. 54 Other Demand Management Measures ................................................................................. 55 Landscape Survey and Water Budget Program ................................................................ 55 Real-time Water Use Monitoring Pilot for Commercial Customers ................................. 55 Business Water Reports Pilot Program ............................................................................. 55 Section 6 – Water Supply Reliability ..................................................................................... 56 Water Supply Reliability .......................................................................................................... 56 Frequency and Magnitude of Supply Deficiencies ................................................................. 57 iii Reliability of the Regional Water System ......................................................................... 58 Climate Change ................................................................................................................. 61 Plans to Assure a Reliable Water Supply ................................................................................ 66 Section 7 – Water Shortage Contingency Plan ...................................................................... 67 Background ............................................................................................................................. 67 Catastrophic Interruption of Supply ....................................................................................... 67 Regional System Reliability ............................................................................................... 67 Local Distribution System Reliability ................................................................................. 69 Emergency Response Plan ................................................................................................ 69 Water Shortage Contingency Analysis .................................................................................... 71 Palo Alto’s Experience with Drought Management ......................................................... 71 Regional Interim Water Shortage Allocation Plan ............................................................ 72 Palo Alto’s Water Shortage Contingency Planning ........................................................... 74 Water Shortage Mitigation Options ....................................................................................... 74 Supply Side Options .......................................................................................................... 74 Demand Side Options ....................................................................................................... 75 Stages of Action ...................................................................................................................... 80 STAGE I: Minimum Water Shortage – 5% to 10% target water savings ........................... 81 STAGE II: Moderate Water Shortage – 10% to 20% target water savings........................ 81 STAGE III: Severe Water Shortage – 20% to 35% target water savings ............................ 82 STAGE IV: Critical Water Shortage – 35% to 50% target water savings ........................... 83 Alternative Water Supplies During a Water Shortage ............................................................ 84 Revenue and Expenditure Impacts and Measures to Overcome Impacts ............................. 84 Impact on Expenditures .................................................................................................... 85 Reduction Measuring Mechanism .......................................................................................... 85 Water Shortage Contingency Ordinance/Resolution ............................................................. 86 Section 8 – Supply and Demand Comparison Provisions ....................................................... 87 Supply and Demand Comparison ........................................................................................... 87 APPENDIX A ‐ Resolution Adopting UWMP .......................................................................... 91 APPENDIX B ‐ Public Participation Notices............................................................................ 94 APPENDIX C ‐ Water Loss Report.......................................................................................... 95 APPENDIX D – DWR Standardized Tables ............................................................................. 97 APPENDIX E – City of Palo Alto Resolution Approving Water Shortage Allocation Plan (w/attachments) ............................................................................................................... 118 APPENDIX F ‐ Water Shortage Contingency Plan Draft Ordinance ....................................... 125 APPENDIX G ‐ Water Shortage Contingency Plan Evaluation Criteria .................................. 127 APPENDIX H ‐ Water Shortage Contingency Plan Use Restrictions ...................................... 130 APPENDIX I – Single and Multi Year Delivery Shortages ...................................................... 134 iv List of Tables Table 1: Calendar for Adoption...................................................................................................... 3 Table 2: Coordination with Appropriate Agencies ......................................................................... 9 Table 3: Population – Current and Projected ............................................................................... 11 Table 4: Climate ............................................................................................................................ 11 Table 5: Current and Planned Water Supply Sources ................................................................... 16 Table 6: Tier One Drought Allocations .......................................................................................... 17 Table 7: Wastewater Treatment ................................................................................................... 31 Table 8: Wastewater Collected and Treated – AF ........................................................................ 31 Table 9: Disposal of Wastewater (non‐recycled) – AF .................................................................. 32 Table 10: Potential Future Use of Recycled Water in Palo Alto‐ AFY ........................................... 33 Table 11: Historical and Projected Water Sales – by Customer Type .......................................... 42 Table 12: Historical and Projected Water Accounts – by Customer Type .................................... 42 Table 13: Historical and Project Water Sales per Account ........................................................... 42 Table 14: Recycled Water Use (AF/Y) ........................................................................................... 44 Table 15: Non-Revenue Water (AF/Y) .......................................................................................... 44 Table 16: Total Water Use (AF/Y) ................................................................................................. 44 Table 17: Projected Low Income Water Demands (AF) ................................................................ 45 Table 18: Baseline Daily Per Capita Water Use for 10 -year period (1995 through 2004) ............ 47 Table 19: 2015 UWMP SBx7-7 Performance Metrics (gallons per capita per day) ...................... 48 Table 20: Water Deliveries in San Francisco Regional Water System Service Area ..................... 61 Table 21: Summary of BAIRWMP Climate Change Vulnerability Assessment ............................. 63 Table 22: Interties with other Agencies ....................................................................................... 69 Table 23: SFPUC and Wholesale Customer Share of Available Water ......................................... 72 Table 24: Palo Alto Share of Available SFPUC Water (AF/Y) ......................................................... 74 Table 25: SFPUC System Supply (MGD) ....................................................................................... 87 Table 26: City of Palo Alto Supply/Demand Balance (AF) ............................................................. 88 Table 27: SFPUC Water Supply Assumptions (AF/Y) .................................................................... 88 List of Figures Figure 1: Potential Groundwater Use Area .................................................................................. 25 Figure 2: Phase 3 Recycled Water Project .................................................................................... 34 Figure 3: Water Supply Purchases – Actual and Forecast ............................................................ 41 Figure 4: 2010 Water Sales by Customer Class ............................................................................. 43 Figure 5: 2015 Water Sales by Customer Class ............................................................................. 43 v List of Acronyms AF Acre Feet ABAG Association of Bay Area Governments AF/Y Acre Feet per Year BAWAC Bay Area Water Agencies Coalition BAWSCA Bay Area Water Supply and Conservation Agency BCA Baseline Consumption Allowance BMP Best Management Practices CAFR City Audited Financial Report CALTRANS California Department of Transportation ccf Centi Cubic Feet (hundred cubic feet) CCSF City and County of San Francisco CEE Consortium for Energy Efficiency CEQA California Environmental Quality Act CIMIS California Irrigation Management Information System COM Commercial CPAU City of Palo Alto Utilities CUWCC California Urban Water Conservation Council DHS Department of Health Services DSM Demand Side Management DMM Demand Management Measures DSS Demand Side Management Least Cost Planning Decision Support System EIR Environmental Impact Report EPA Environmental Protection Agency ET Evapotranspiration ETO Reference Evapotranspiration FEMA Federal Emergency Management Agency FY Fiscal Year gpm Gallons per minute HET High Efficiency Toilets ICI Industrial Commercial and Institutional WIRP Integrated Resource Plan IRWMP Integrated Regional Water Management Plan IT Information Technology IWSAP Interim Water Shortage Allocation Plan MF Multi‐family mg/L Milligrams per liter MGD Million Gallons per Day MOU Memorandum of Understanding O&M Operations and Maintenance vi OES Office of Emergency Services RWQCP Palo Alto Regional Water Quality Control Plant PEIR Program Environmental Impact Report RWS Regional Water System SCVWD Santa Clara Valley Water District SF Single‐family SFPUC San Francisco Public Utilities Commission SFWD San Francisco Water Department TAC Technical Advisory Committee TDS Total Dissolved Solids TRC Total Resource Cost UAC Utilities Advisory Commission UER Utilities Emergency Response ULF Ultra Low Flow ULFT Ultra Low Flow Toilet URS United Research Services, Consultant Firm UWMP Urban Water Management Plan WIRP Water Integrated Resource Plan WPL West Pipeline WSA Water Supply Agreement WSAP Water Shortage Allocation Plan WSIP Water System Improvement Program WSMP Water Supply Master Plan 1 City of Palo Alto Utilities 2015 Urban Water Management Plan Contact Sheet Date plan submitted to the Department of Water Resources: June X, 2016 Name of persons preparing this plan: Karla Dailey, Senior Resource Planner Christine Tam, Senior Resource Planner Phone: (650) 329‐2523 (650) 329‐2289 Fax: (650) 326‐1507 E‐mail address: karla.dailey@CityofPaloAlto.org christine.tam@CityofPaloAlto.org Utility services provided by the City include: electric, natural gas, commercial fiber, refuse, recycled water, storm drain, wastewater collection, treatment and disposal. Is This Agency a Bureau of Reclamation Contractor? No Is This Agency a State Water Project Contractor? No 2 Section 1 – Plan Development and Adoption Plan Structure The City of Palo Alto (City) has not experienced significant changes in the water supply distribution system and reliability since the preparation of the 2010 Urban Water Management Plan (UWMP), and has determined the 2010 UWMP provided sufficient guidance to meet the City’s needs during the 2010 UWMP cycle. For the 2015 UWMP report, the City has updated the 2010 UWMP and addressed any changes to the UWMP Act since 2010 as outlined in Appendix C of the Department of Water Resources (DWR) UWMP Guidebook. Plan Adoption The City began preparing this update of its Urban Water Management Plan in winter 2015. The updated plan will be considered by City Council before June 30, 2016 and submitted to the California Department of Water Resources within 30 days of Council adoption. This plan includes all information necessary to meet the requirements of California Water Code Division 6, Part 2.6 (Urban Water Management Planning) as well as requirements of the California Water Code Division 6, Part 2.55 (Water Conservation Bill of 2009). Public Participation The City actively encourages community participation in its urban water management planning efforts. The City held public hearings before the Utilities Advisory Commission (UAC) and City Council prior to adoption. An UWMP webpage (www.cityofpaloalto.org/UWMP) was created to educate the public about the UWMP process, provide outreach for public meetings and opportunities to participate, as well as to make available background materials on the City’s urban water management planning activities. Table 2 lists the notified agencies, and Appendix B includes samples of public participation notices. 3 Table 1: Calendar for Adoption Date Meeting/Activity Topic April 12 2016 Utilities Advisory Commission (UAC) Review and Recommendation on UWMP April X, 2016 Published Notice of Public Hearing Newspaper (Council meeting) on UWMP Newspaper (Council meeting) on SBx7‐7 Reductions May 16, 2016 City Council Review and Discussion on SBx7‐7 Reduction Targets Review and Adoption of UWMP June X, 2016 Final UWMP and Council Resolution Copy to DWR and Stakeholder Agencies June X, 2016 Final UWMP and Council Resolution Available to the Public Appendix B contains samples of the public participation notices the City sent in compliance with Water Code 10621(b), 10620(d)(2), and 10642. A sample notice of the City Council meeting will be added to the Final Draft UWMP that will be presented to Council for approval. The City’s Utilities Advisory Commission (UAC) provides advice to the City Council on : the acquisition and development of electric, gas and water resources; joint action projects with other public or private entities which involve electric, gas or water resources; wastewater collection and fiber optic issues; environmental implications of electric, gas or water utility projects, as well as conservation and demand management. The UAC meets monthly and reviews the activities of the various utility services. One of the primary tasks of the UAC is to assist with the review and development of long‐term plans for the City’s utilities. The UAC meetings are open to the public and agendas are posted for public review prior to each meeting. The draft schedule for approval of the 2015 UWMP provides the opportunity for the UAC to review and comment on the Draft UWMP prior to submittal to the City Council for final approval. In addition to the review of the UWMP, the UAC has been very active in the review of several other water supply and water management documents. Since the adoption of the 2010 UWMP, this review during public meetings has included discussion and presentations on the following: Preliminary Assessment of Water Resource Alternatives (February 2013) Update on Emergency Water Supply and Storage Project and its Role in the City’s Overall Emergency Response Capabilities (March 2013) Discussion of Potential Transfer of a Portion of the City’s Individual Supply Guarantee (October 2013) Water utility Cost and Consumption Benchmarking Report ( January 2014) Drought Rate Design Guidelines (September 2014) Demand Side Management Annual Report (May 2015) 4 Activation of Drought Rates in Response to Mandatory Water Restrictions (June 2015) Certification of the Recycled Water System Expansion Environment Impact Report (September 2015) Monthly Drought Updates (May 2014 to present) Agency Coordination Law California Water Code section 106201 (a) Every urban water supplier shall prepare and adopt an urban water management plan in the manner set forth in Article 3 (commencing with Section 10640). (d) (1) An urban water supplier may satisfy the requirement of this part by participation in area wide regional, watershed, or basis wide urban water management planning where those plans will reduce preparation costs and contribute to the achievement of conservation and efficient water use. (2) Each urban water supplier shall coordinate the preparation of its plan with other appropriate agencies in the area, including other water suppliers that share a common source, water management agencies, and relevant public agencies, to the extent practicable. Internal City Coordination Many members of City staff were involved to coordinate development of this plan, including representatives from all divisions of the City of Palo Alto Utilities Department (CPAU) and other City departments including Planning and Community Environment; the City Manager’s Office; the City Attorney’s Office; and Public Works (Palo Alto Regional Water Quality Control Plant). The UWMP is coordinated with other City planning and policy level documents to ensure the water policy direction in the UWMP informs future decisions within the City of Palo Alto, including the Urban Forest Master Plan and the Comprehensive Plan Update. Since completion of the 2010 UWMP, CPAU has completed several important water supply and planning milestones, including: Recycled Water Expansion Project Environmental Impact Report (EIR) Certification (September 2015) – Palo Alto City Council certification of the EIR was a major step in the effort to expand the use of recycled water in the city. City of Palo Alto Emergency Water Supply and Storage Project Completion (December 2013) – The City constructed a 2.5 million gallon underground water reservoir and pump station in Palo Alto to meet emergency water supply and storage needs. In addition to this water reservoir, the three new emergency wells were completed and the five existing wells and the existing Mayfield Pump Station were upgraded. The Water Shortage Implementation Plan (June 2015) – In Response to the SWRCB Emergency Water Use Regulation, the Palo Alto City Council passed a resolution that 1 Unless noted, all statutory references herein are to the California Water Code. 5 included a new Water Shortage Implementation Plan and put into place restrictions for a Stage II water shortage. Drought Rate Design and Implementation: In response to the water utility revenue reduction resulting from water conservation, the City Council approved drought rate design guidelines (December 2014) and the approved implementation of drought surcharges as part of the water rates (August 2015). The completion of the plans and agreements listed above required the cooperation of all divisions within the CPAU and several other departments within the City. Data and information from these reports was used in this document. Interagency Coordination The City is an active member of the California water community and coordinated with a number of agencies in preparation of its UWMP. The City is particularly active in the following organizations: The City is a very active member of the Bay Area Water Supply and Conservation Agency (BAWSCA). The BAWSCA members, including the City, receive water from the City and County of San Francisco through a contract that is administered by the SFPUC. The City is represented on the Santa Clara Valley Water District (SCVWD) Commission, the SCVWD Water Retailers Group, the SCVWD Recycled Water Subcommittee, and the SCVWD Water Conservation Subcommittee group. The City has actively participated on several initiatives in relation to the SFPUC, including: •Preparation of the SFPUC’s Program EIR for its Water System Improvement Program (WSIP) •The Interim Supply Limitation imposed by the SFPUC during adoption of the WSIP to limit deliveries from the regional system until 2018. Through BAWSCA, the City is represented in the Bay Area Water Agencies Coalition (BAWAC), a group of the seven largest water agencies in the Bay Area. BAWAC was established to develop regional water planning objectives, coordinate projects and programs that would meet the regional objectives to improve water supply reliability and water quality, and document, coordinate and communicate existing and planned programs and activities being implemented in the Bay Area region in the areas of water use efficiency and water treatment. The City has been a signatory to the Memorandum of Understanding Regarding Urban Water Conservation with the California Urban Water Conservation Council since 1992. The City is a member of the Bay Area Water Conservation Coordinators group, a consortium of water conservation professionals formed to discuss and share policy and program implementation strategies and research. The City is a member of the WateReuse Association, an organization of governmental, non‐profit and private sector entities working together to encourage increased recycled water use in California. 6 The City is a member of the Consortium for Energy Efficiency (CEE), through which water and power agencies strive to evaluate and promote water and energy efficient appliances and technologies. The City is a member of the Alliance for Water Efficiency. The City is a Partner in the Environmental Protection Agency’s (EPA) WaterSense program, which promotes water efficient products and assists utilities in marketing its programs for water use efficiency. The City Council adopted the Ahwahnee Water Principles for Resource Efficient Land Use on October 17, 2005.2 These principles were developed by the Local Government Commission, a nonprofit, nonpartisan organization working to create healthy, walkable, and resource‐efficient communities. The City is a member of the Bay Area Clean Water Agencies (BACWA). BACWA members work together to carry out mutually beneficial projects, and to share scientific, economic and other information about the San Francisco Bay environment. The City is a member of the Western Recycled Water Coalition (WRWC), an organization that pursues highly leveraged, locally managed projects that will help ensure the security of water supplies. The City is a participant in the Bay Area Integrated Regional Water Management Plan (IRWMP) working to coordinate and improve water supply reliability, protect water quality, manage flood protection, maintain public health standards, protect habitat and watershed resources, and enhance the overall health of the Bay. The City continually coordinates water‐planning activities that support and inform the City’s creation of this UWMP with neighboring communities and water agencies. The Water Supply Master Plan ‐ One early example of interagency coordination and planning was the development of the Water Supply Master Plan (WSMP). From 1996 through 1999, the BAWSCA agencies, the SFPUC, and the SCVWD worked cooperatively to develop a WSMP. A Palo Alto representative was on the steering committee for this project. The WSMP is intended to address the future water supply needs of the water agencies and 2.3 million people, who are served via the SFPUC water system. On April 25, 2000 the SFPUC formally adopted the WSMP including the implementation schedule for identified, selected projects. Water Integrated Resource Plan (WIRP) ‐ The City has evaluated all its water supply alternatives in an effort to determine what long‐term direction the City should take for water resource planning. In 2000, this effort resulted in the City’s publication of a document3 describing in detail all the identified alternatives. Besides BAWSCA, the agencies that have received this document include: the City of Mountain View, Alameda County Water District, Stanford University, the City of San Jose, California Water Company, the City of Redwood City, 2 Staff Report CMR:367:05: http://www.cityofpaloalto.org/civicax/filebank/documents/5859 3 Preliminary Assessment of Water Resources: http://www.cityofpaloalto.org/civicax/filebank/documents/25619 7 the City of Daly City, the Purissima Hills Water District, the City of Santa Clara, the City of Milpitas and the City of Sunnyvale. In addition, the City continuously interacts with the 26 other BAWSCA agencies in the development of water efficiency programs to be implemented regionally, as well as the regional evaluation of water supply alternatives. In 2013, the City initiated development of a new WIRP by producing a water supply Preliminary Assessment4. This report will provide the basis for an updated WIRP planned for 2016. Integrated Regional Water Management Plan – The Association of Bay Area Government (ABAG) convened a broad‐based group of stakeholders to develop an Integrated Regional Water Management Plan (IRWMP) for the Bay Area. The Bay Area IRWMP will facilitate regional cooperation on issues of water supply, quality and reliability, water recycling and conservation, storm water and flood water management, wetlands and habitat restoration and creation, recreation and access. The plan was finalized in November 2006. The City was involved in the development of the Bay Area IRWMP on the water supply and reliability areas through BAWSCA’s representation in BAWAC. In addition, the City also coordinates water recycling and wastewater for the IRWMP implementation through the City’s membership in the Bay Area Clean Water Agencies (BACWA). BAWSCA Long Term Water Reliable Water Supply Strategy ‐ The BAWSCA agencies identified a need for dry year supplies to meet future demands. The study, completed in February 2015 identified cost‐effective regional and local projects that will meet individual BAWSCA member needs. One of the projects included in the strategy is the City’s Phase 3 recycled water project to serve the Stanford Research Park. Palo Alto Regional Water Quality Control Plant Long Range Facilities Plan ‐ Palo Alto’s Regional Water Quality Control Plant (RWQCP) has been in operation since 1934 and now serves the six communities of Palo Alto, East Palo Alto, Mountain View, Stanford, Los Altos and Los Altos Hills. Aging equipment, new regulatory requirements, and the movement to full sustainability will require rehabilitation, replacement and new processes. The Long Range Facilities Plan was completed in October 2012. Major recommendations in the plan were modeling influent sewer flows, continuing source control and flow reduction efforts, rehabilitating and replacing critical infrastructure, and preparing for regulatory action. In addition, it was recommended the plant be positioned for a possible increase in recycled water demand by reserving space on site for reverse osmosis facilities and being prepared to implement additional storage and pumping capabilities. Santa Clara Valley Water District Water Supply and Infrastructure Master Plan ‐ The City participated with other stakeholders in the preparation of a 2012 Master Plan to address long range water supply and reliability needs in Santa Clara County. The Water Master Plan includes 4 Report to the UAC, February 2013: http://www.cityofpaloalto.org/civicax/filebank/documents/33029 8 an implementation program that schedules projects based on finances, risk, and water supply and infrastructure needs. 9 The City coordinated the 2015 update of the Urban Water Management Plan with the following agencies: Table 2: Coordination with Appropriate Agencies AGENCIES Participated in Plan development Sent notice of Plan preparation Commented on the draft Attended public meetings Contacted for assistance Received copy of draft Sent notice of public hearing Not involved / No information SFPUC X X X X BAWSCA X X X X SCVWD X X X City of East Palo Alto X X City of Mountain View X X City of Menlo Park X X Purissima Hills Water District X X City of Redwood City X X Stanford University X X All other BAWSCA agencies X X County of Santa Clara X X 10 Section 2 – Service Area Law 10631. A plan shall be adopted in accordance with this chapter and shall do all of the following: (a) Describe the service area of the supplier, including current and projected population, climate, and other demographic factors affecting the supplier's water management planning. The projected population estimates shall be based upon data from the state, regional, or local service agency population projections within the service area of the urban water supplier and shall be in five‐year increments to 20 years or as far as data is available…. Demographics Palo Alto is located in northern Santa Clara County approximately 35 miles south of the City of San Francisco. The City’s population in 2015 was approximately 67,4005. The City is roughly 26 square miles in area and is a part of the San Francisco Bay metropolitan area. The City is one of the area's most desirable residential communities with approximately 28,5006 housing units. The City’s desirability is partly due to the excellent public schools, comprehensive municipal services, shopping, restaurants and the community's aesthetics. The City is considered the birthplace of the high technology industry and the Silicon Valley. Located directly adjacent to the City is Stanford University, which attracts major corporations from around the world. The City's 630‐acre Stanford Research Park includes among its tenants such prestigious and innovative high‐tech leaders as Hewlett‐Packard, Varian, Tesla Motors, and VMware. The City has approximately 27 million square feet of non-residential floor‐space, 36 parks and preserves (comprising 157 acres of urban parks and 3,752 acres of open space), tennis courts (51), community centers (4), theaters (3), swimming pools (1), nature centers (3), athletic centers (4), a golf course, an art center, and a junior museum and zoo 7. Table 3 shows the population and employment projections for the City from 2015 to 2040 based on Association of Bay Area Governments (ABAG) 2013 projections. The City relied on ABAG population and employment projections for the 2005 and 2010 UWMPs and several recent water supply and demand forecasts and continues to primarily rely on ABAG projections in this plan8. According to these projections, total expected 2015-2040 population growth is about 26%, or about 0.9% per year on average. Total expected growth in employment from 2015 to 2040 is 23%, or 0.8% per year on average. 5 Association of Bay Area Governments – Projections 2013 6 City of Palo Alto 2015-2023 Housing Element 7 City of Palo Alto 2014-2015 Comprehensive Annual Financial Report (CAFR) 8 The City is in the process of updating its Comprehensive Plan which will include updated population projections. 11 Table 3: Population – Current and Projected Climate Characteristics The City enjoys a mild climate surrounded by the San Francisco Bay on the east, and coastal mountains on the west. The monthly average temperature, rainfall and ETO (Reference Evapotranspiration) for the area are presented in Table 4 below. Table 4: Climate Climate Standard Monthly Average ETO9 Average Rainfall (inches)10 Average Max Temperature (degrees F)11 Average Min Temperature (degrees F) Jan 1.4 3.2 57.4 38.5 Feb 1.9 2.9 61.1 41.3 Mar 3.4 2.3 64.2 43.1 Apr 4.4 1.0 68.4 44.7 May 5.5 0.4 72.9 48.5 Jun 6.0 0.1 77.4 52.5 Jul 6.2 0.0 78.4 54.9 Aug 5.5 0.1 78.4 54.8 Sep 4.4 0.2 78.3 52.6 Oct 3.1 0.7 73.0 48.0 Nov 1.7 1.7 64.3 42.6 Dec 1.3 2.7 57.8 38.2 9 Average ETO data for closest active station (Hayward) reported by CIMIS website http://www.cimis.water.ca.gov/ 10 Average rainfall data for Palo Alto reported by NOAA website http://www.wrcc.dri.edu/ 11 Average temperature data for Palo Alto reported by NOAA website http://www.wrcc.dri.edu/ 2015 2020 2025 2030 2035 2040 Service Area Population 67,400 70,500 73,700 77,100 80,800 84,600 Five Year Precent Increase 4.6% 4.5% 4.6% 4.8% 4.7% Total Employment 96,900 104,820 107,870 110,940 115,110 119,470 Five Year Precent Increase 8.2% 2.9% 2.8% 3.8% 3.8% 12 Section 3 – System Supplies Law 10631 (b) Identify and quantify, to the extent practicable, the existing and planned sources of water available to the supplier over the same five year increments described in subdivision (a)….. Historical Background The water utility was established on May 9, 1896, two years after the City was incorporated. Local water companies were bought out at that time with a $40,000 bond approved by the voters of the 750‐person community. These private water companies operated one or more shallow wells to serve the nearby residents. The City grew and the well system expanded until nine wells were in operation in 1932. In December 1937, the City signed a 20‐year contract with the City and County of San Francisco, administered by the San Francisco Water Department (SFWD), for water deliveries from the newly constructed pipeline bringing Hetch Hetchy water from Yosemite to the Bay Area. Water deliveries from San Francisco commenced in 1938 and well production declined to less than half of the total citywide water demand. A 1950 engineering report noted, "the capricious alternation of well waters and the SFWD water . . . has made satisfactory service to the average consumer practically impossible." However, groundwater production increased in the 1950s, leading to lower groundwater tables and water quality concerns. In 1962, a survey of water softening costs to City customers determined that the City should purchase 100% of its water supply needs from the SFWD. A 20‐ year contract was signed with San Francisco, and the City’s wells were placed in a standby condition. The SFWD later became known as the SFPUC. Since 1962 (except for some very short periods) the City’s entire supply of potable water has come from the SFPUC. BAWSCA is comprised of SFPUC’s 26 wholesale customers. The City largely works through BAWSCA to manage its SFPUC contract and to interact with the SFPUC. In 1993, the City completed a Water Integrated Resources Plan (WIRP). This IRP was completed because the City was facing a decision regarding participation in a recycled water project. In the 1993 IRP, the City calculated the value of recycled water for water supply. At that time, the City decided not to participate in the recycled water project because the costs exceeded the benefits of the project. In 1999, the City began to prepare a new Water Integrated Resources Plan (WIRP). As a first step, staff completed a high level overview of each of the City’s water resource options and helped identify the most promising alternatives to be further analyzed in subsequent phases. The second phase in the WIRP process was the development and evaluation of water supply 13 portfolios so policy makers can determine the proper balance between cost, quality, reliability, and environmental factors. At the conclusion of the second phase of the WIRP in 2003, several pieces of missing information were identified that needed to be further developed in order to further analyze the City’s water resource options and alternatives. The WIRP work has been coordinated with infrastructure work by the City to increase the distribution system reliability. Under a contract with the City, Carollo Engineers completed several studies of the water distribution system. These studies are discussed in Section 3, “System Supplies,” under the heading “Groundwater.” The City and other Santa Clara County water retailers coordinated with the SCVWD to examine extending the SCVWD West Pipeline (WPL) that currently ends at Miramonte Road and Foothills Expressway to a point in Palo Alto to serve the City and other neighboring water agencies. In addition, the study examined creating an intertie between the WPL and the SFPUC’s Bay Division Pipelines at Page Mill Road. The SCVWD West Pipeline Conceptual Evaluation, completed in March 2003, concluded that the conceptual projects were constructible, but that no decisions could be made until SCVWD concluded additional studies. These ongoing studies include the SCVWD project to evaluate its system reliability, asset management program, and Water Treatment Plant Master Plan Project. These studies, completed in the fall of 2004, concluded that extending the WPL to serve the City could not be justified from a county‐wide reliability aspect when evaluated against more cost‐effective alternatives. The information obtained from the studies completed on the groundwater and SCVWD’s conceptual study on the WPL Extension was used to characterize the supply options examined in the WIRP. In mid‐2003, the WIRP concluded, based on available information, that supplies from the SFPUC are adequate in normal years, but additional supplies are needed in drought years to avoid shortages. Additionally, the WIRP contained a recommendation not to seek additional supplies for use on a continuous basis unless there is another benefit that can be identified. As a result, the City did not pursue a connection to the SCVWD’s treated water line for ongoing water needs nor evaluate further the use the wells on a continuous basis. The WIRP noted that expanded use of water efficiency programs and recycled water might be worthwhile for the environmental benefits and to reduce the drought‐time deficit. Based on the WIRP analysis, the City Council adopted a set of WIRP guidelines in December 200312. The WIRP guidelines include: 1.Preserve and enhance SFPUC supplies With respect to the City’s primary water supply source, the SFPUC, continue to actively participate in the BAWSCA to assist in achieving BAWSCA’s stated goal: “A reliable supply of water, with high quality, and at a fair price.” 12 See City Manager Report 547:03: http://www.cityofpaloalto.org/cityagenda/publish/cmrs/2732.pdf 14 2.Advocate for an interconnection between SFPUC and the SCVWD Work with SCVWD and the SFPUC to pursue the extension of the SCVWD’s West Pipeline to an interconnection with the SFPUC Bay Division Pipelines 3&4. Continue to reevaluate the attractiveness of a connection to an extension of the SCVWD’s West Pipeline. 3.Actively participate in development of cost‐effective regional recycled water plans Re‐initiate discussions with the owners of the Palo Alto RWQCP on recycled water development. In concert with the RWQCP owners, conduct a new feasibility study for recycled water development. Since the feasibility of a recycled water system depends upon sufficient end‐user interest, determine how much water Stanford University and the Stanford Research Park would take. 4.Focus on water DSM programs to comply with BMPs Continue implementation of water efficiency programs with the primary focus to achieve compliance with the Best Management Practices (BMPs) promoted by the California Urban Water Conservation Council. 5.Maintain emergency water conservation measures to be activated in case of droughts Review, retain, and prioritize CPAU’s emergency water conservation measure s that would be put into place in a drought emergency. 6.Retain groundwater supply options in case of changed future conditions Using groundwater on a continuous basis does not appear to be attractive at this time due to the availability of adequate, high quality supplies from the SFPUC in normal years. However, SFPUC supplies are not adequate in drought years and circumstances could change in the future such that groundwater supplies could become an attractive, cost‐ effective option. Examples of changing circumstances could be that the amount of water available from the SFPUC system is reduced due to regulatory or other actions. CPAU should retain the option of using groundwater in amounts that would not result in land surface subsidence, saltwater intrusion, or migration of contaminated plumes. 7.Survey community to determine its preferences regarding the best water resource portfolio Seek feedback from all classes of water customers on the question of whether to use groundwater during drought to improve drought year supply reliability. At the same time, seek feedback on the appropriate level of water treatment for groundwater if it is to be used during drought. Survey all classes of water customers to determine their preferences as to the appropriate balance between cost, quality, reliability, and environmental impact. Since the major WIRP conclusion was that SFPUC supplies are adequate except in drought years, the focus turned to the options to reduce the supply deficit during droughts. These options include using groundwater, connecting to the SCVWD’s treated water pipeline, developing recycled water, and expanding water efficiency programs. The goal was to find the proper balance between the key factors of cost, availability in a drought, water quality, and environmental impacts in determining the best portfolio for the community. 15 Following Council’s adoption of the WIRP Guidelines, and to gain insight into the question of whether to use groundwater as supplemental supply in droughts, the City surveyed its residential customers. Respondents were asked to rank three options for water supply in a drought: A. Blend Groundwater – Blend the groundwater with water from SFPUC in droughts. Water customers would still need to cut back water usage by 10% in droughts. B. No Groundwater – Use no groundwater during droughts. Instead, community is subjected to larger water usage cutbacks in droughts (20% cutback). C. Treat Groundwater – Highly treat the groundwater (reverse osmosis treatment) before introducing it into distribution system. Water customers would still need to cut back water usage by 10% in droughts. Survey respondents generally preferred Options B (no groundwater) and C (treat groundwater), but Option A (blend groundwater) was not soundly rejected. Based on the survey, any of the three options would probably be accepted by the City’s water customers under drought conditions. Based on the WIRP and the results of the community survey, staff made the following conclusions and recommendations in June 2004: 1.Do not install advanced treatment systems for the groundwater at this time. This option is simply too expensive, both in capital and in operating costs. 2.Blending at an SFPUC turnout is the best way to use groundwater as a supplemental drought time supply while maintaining good water quality. 3.Staff should await the conclusion of the environmental review process for selecting any new emergency well sites before developing a recommendation on whether to use groundwater in droughts. In the selection process for new well sites, the costs for blending with SFPUC water in droughts should be considered. The least expensive location is a well at El Camino Park due to its proximity to an SFPUC turnout. 4.Actively participate in the development of long‐term drought supply plans with SFPUC and BAWSCA. 5.Continue in the efforts identified in the Council‐approved WIRP Guidelines: a.Evaluate a range of demand‐side management (DSM) options for their ability to reduce long‐term water demands; b.Evaluate feasibility of expanding the use of recycled water; and c.Maintain emergency water conservation measures to be activated in case of droughts. While groundwater is a potential supply source for the City, at this time it is not considered to be an existing nor planned water supply source. The City has now completed the Emergency Water Supply and Storage project, which provides the City the flexibility to rely on groundwater during a drought if necessary. At this point the City Council has not directed staff to begin using groundwater as a supplemental drought supply. 16 Table 5 below shows the current and planned water supply sources for the City for normal years. As required by 10631(j), this information has been provided to the SFPUC, the City’s wholesale supplier. Table 5: Current and Planned Water Supply Sources Water Supply Sources in AFY 2015 (actual) 2020 2025 2030 2035 SFPUC13 10,732 11,892 11,428 11,148 10,895 Local Groundwater 0 0 0 0 0 Local Surface Water 0 0 0 0 0 Recycled Water 845 850 850 850 850 Transfers in or out 0 0 0 0 0 Exchanges in or out 0 0 0 0 0 Desalination 0 0 0 0 0 Other Sources 0 0 0 0 0 Total 11,577 12,742 12,278 11,998 11,745 SFPUC Supply Description of SFPUC Regional Water System Palo Alto receives water from the City and County of San Francisco’s Regional Water System (RWS), operated by the SFPUC. This supply is predominantly from the Sierra Nevada, delivered through the Hetch Hetchy aqueducts, but also includes treated water produced by the SFPUC from its local watersheds and facilities in Alameda and San Mateo Counties. The amount of imported water available to the SFPUC’s retail and wholesale customers is constrained by hydrology, physical facilities and the institutional limitations that allocate the water supply of the Tuolumne River. Due to these constraints, the SFPUC is very dependent on reservoir storage to ensure water supply availability in dry years. The SFPUC serves its retail and wholesale water demands with an integrated operation of local Bay Area water production and imported water from the Hetch Hetchy Reservoir. In practice, the local watershed facilities are operated to capture local runoff. Water Supply Agreement In July 2009, the wholesale customers and San Francisco adopted the Water Supply Agreement14 (WSA), which includes a Water Shortage Allocation Plan (WSAP) to allocate water from the Regional Water System (RWS) to retail and wholesale customers during system-wide shortages of 20 percent or less. The WSAP has two components: 13 Data from internal forecasting model except for 2015 actual usage data 14 Palo Alto City Council approved the WSA in June 2009 – See City Manager Report 269:09: http://www.cityofpaloalto.org/civicax/filebank/documents/15985 17 1.The Tier One Plan, which allocates water between San Francisco and the wholesale customers collectively; and 2.The Tier Two Plan, which allocates the collective wholesale customer share among the wholesale customers. Tier One Drought Allocations The Tier One Plan allocates water between San Francisco and the wholesale customers collectively based on the level of shortage: Table 6: Tier One Drought Allocations Level of System-Wide Reduction in Water Use Required Share of Available Water SFPUC Share Wholesale Customers Share 5% or less 6% through 10% 11% through 15% 16% through 20% 35.5% 36.0% 37.0% 37.5% 64.5% 64.0% 63.0% 62.5% The Tier One Plan allows for voluntary transfers of shortage allocations between the SFPUC and any wholesale customer and between wholesale customers themselves. In addition, water “banked” by a wholesale customer, through reductions in usage greater than required, may also be transferred. The Tier One Plan will expire at the end of the term of the WSA in 2034, unless mutually extended by San Francisco and the wholesale customers. The Tier One Plan applies only when the SFPUC determines that a system-wide water shortage exists and issues a declaration of a water shortage emergency under California Water Code Section 350. Separate from a declaration of a water shortage emergency, the SFPUC may opt to request voluntary cutbacks from San Francisco and the wholesale customers to achieve necessary water use reductions during drought periods. During the current drought to date, the SFPUC has requested, but has not mandated, a 10 percent system-wide reduction since January 2014. The SFPUC has not yet been compelled to declare a water shortage emergency and implement the Tier One Plan because its customers have exceeded the 10 percent voluntary system-wide reduction in conjunction with the state-wide mandatory reductions assigned by the State Water Resources Control Board. Tier Two Drought Allocations The wholesale customers have negotiated and adopted the Tier Two Plan15, the second component of the WSAP, which allocates the collective wholesale customer share among each 15 Palo Alto’s City Council adopted the Tier Two Water Shortage Allocation Plan in February 2011. See Staff Report 1308: http://www.cityofpaloalto.org/civicax/filebank/documents/40970 18 of the 26 wholesale customers. This Tier Two allocation is based on a formula that takes into account multiple factors for each wholesale customer including: Individual Supply Guarantee (ISG); Seasonal use of all available water supplies; and Residential per capita use. The water made available to the wholesale customers collectively will be allocated among them in proportion to each wholesale customer’s Allocation Basis, expressed in millions of gallons per day (MGD), which in turn is the weighted average of two components. The first component is the wholesale customer’s ISG, as stated in the WSA, and is fixed. The second component, the Base/Seasonal Component, is variable and is calculated using the monthly water use for three consecutive years prior to the onset of the drought for each of the wholesale customers for all available water supplies. The second component is accorded twice the weight of the first, fixed component in calculating the Allocation Basis. Minor adjustments to the Allocation Basis are then made to ensure a minimum cutback level, a maximum cutback level, and a sufficient supply for certain wholesale customers. The Allocation Basis is used in a fraction, as numerator, over the sum of all wholesale customers’ Allocation Bases to determine each wholesale customer’s Allocation Factor. The final shortage allocation for each wholesale customer is determined by multiplying the amount of water available to the wholesale customers’ collectively under the Tier One Plan, by the wholesale customer’s Allocation Factor. The Tier Two Plan requires that the Allocation Factors be calculated by BAWSCA each year in preparation for a potential water shortage emergency. As the wholesale customers change their water use characteristics (e.g., increases or decreases in SFPUC purchases and use of other water sources, changes in monthly water use patterns, or changes in residential per capita water use), the Allocation Factor for each wholesale customer will also change. However, for long-term planning purposes, each wholesale customer shall use as its Allocation Factor, the value identified in the Tier Two Plan when adopted. The current Tier Two Plan will expire in 2018 unless extended by the wholesale customers. Individual Supply Guarantee San Francisco has a perpetual commitment (Supply Assurance) to deliver 184 MGD to the 24 permanent wholesale customers collectively. San Jose and Santa Clara are not included in the Supply Assurance commitment and each has temporary and interruptible water supply contracts with San Francisco. The Supply Assurance is allocated among the 24 permanent wholesale customers through ISGs, which represent each wholesale customer’s allocation of the 184 MGD Supply Assurance. Palo Alto’s ISG is 17.07 MGD, or approximately 19,118 acre feet per year. 19 2018 Interim Supply Limitation As part of its adoption of the Water System Improvement Program (WSIP) in October 2008, discussed separately herein, the SFPUC adopted a water supply limitation, the Interim Supply Limitation (ISL), which limits sales from San Francisco’s RWS watersheds to an average annual delivery of 265 MGD through 2018. All 26 wholesale customers and San Francisco are subject to the ISL. The wholesale customers’ collective allocation under the ISL is 184 MGD and San Francisco’s is 81 MGD. Although the wholesale customers did not agree to the ISL, as further discussed below, the WSA provides a framework for administering the ISL. Interim Supply Allocations The ISAs refer to San Francisco’s and each individual wholesale customer’s share of the ISL. On December 14, 2010, the SFPUC established each agency’s ISA through 201816. In general, the SFPUC based the wholesale customer allocations on the lesser of the projected fiscal year 2018 purchase projections or Individual Supply Guarantees. The ISAs are effective only until December 31, 2018 and do not affect the Supply Assurance or the ISGs, both discussed separately herein. San Francisco’s ISA is 81 MGD. Palo Alto’s ISA is 14.70 MGD or approximately 16,464 acre feet per year. Palo Alto does not anticipate exceeding the ISA before the ISL period ends in 2018. As stated in the WSA, the wholesale customers do not concede the legality of the SFPUC’s establishment of the ISAs and Environmental Enhancement Surcharge, discussed below, and expressly retain the right to challenge either or both, if and when imposed, in a court of competent jurisdiction. Environmental Enhancement Surcharge As an incentive to keep RWS deliveries below the ISL of 265 MGD, the SFPUC adopted an Environmental Enhancement Surcharge for collective deliveries in excess of the ISL effective at the beginning of fiscal year 2012. This volume-based surcharge would be unilaterally imposed by the SFPUC on individual wholesale customers and San Francisco retail customers, when an agency’s use exceeds its ISA and when sales of water to the wholesale customers and San Francisco retail customers, collectively, exceeds the ISL of 265 MGD. Actual charges would be determined based on each agency's respective amount(s) of excess use over their ISA. As of the end of 2015, no Environmental Enhancement Surcharges have been levied. 2018 SFPUC Decisions In the WSA, there are three decisions the SFPUC committed to making before 2018 that will affect water supply development: Whether or not to make the cities of San Jose and Santa Clara permanent customers, 16 An informational report on the Interim Supply Limitation was provided to the City Council in February 2011. See Staff Report 1321: https://www.cityofpaloalto.org/civicax/filebank/documents/26211 20 Whether or not to supply the additional unmet supply needs of the whole sale customers beyond 2018, and Whether or not to increase the wholesale customer Supply Assurance above 184 MGD. Additionally, there have been recent changes to instream flow requirements and customer demand projections that will affect water supply planning beyond 2018. As a result, the SFPUC has developed a Water Management Action Plan (Water MAP) to provide ne cessary information to address the 2018 decisions and to begin developing a water supply program for the 2019 to 2035 planning horizon. The water supply program will enable the SFPUC to continue to meet its commitments and responsibilities to wholesale and retail customers, consistent with the priorities of the SFPUC. The SFPUC plans to take the water MAP to its Commission in May 2016. The discussion resulting from the questions described in the Water MAP will help guide the water supply planning objectives through 2035. While the Water MAP is not a water supply program, it presents pertinent information that will help develop the SFPUC’s future water supply planning program. At this time, and for purposes of long-term planning, it is assumed that deliveries from the RWS to San Francisco’s wholesale customers will not exceed 184 MGD. BAWSCA and Its Role BAWSCA provides regional water reliability planning and conservation programming for the benefit of its 26 member agencies that purchase wholesale water supplies from the San Francisco Public Utilities Commission. Collectively, the BAWSCA member agencies deliver water to over 1.74 million residents and nearly 40,000 commercial, industrial and institutional accounts in Alameda, San Mateo and Santa Clara Counties. BAWSCA also represents the collective interests of these wholesale water customers on all significant technical, financial and policy matters related to the operation and improvement of the SFPUC’s Regional Water System (RWS). BAWSCA’s role in the development of the 2015 UWMP updates is to work with its member agencies and the SFPUC to seek consistency among the multiple documents being developed. As a member of BAWSCA, the City is formally represented on the BAWSCA Board of Directors on matters involving decision‐making, policy setting and issues of interest to the BAWSCA members. On the staff level, the City participates on several advisory and policy committees, including the Water Quality Committee and the Technical Advisory Committee. St aff also represents the City with the other BAWSCA members on other issues that may arise from time to time. Regional Water Demand and Conservation Projections In September 2014, BAWSCA completed the Regional Water Demand and Conservation Projections Report (Demand Study). The goal of the Demand Study was to d evelop transparent, 21 defensible, and uniform demand and conservation savings projections for each wholesale customer using a common methodology to support both regional and individual agency planning efforts. The Demand Study projections were incorporated into BAWSCA’s Long -Term Reliable Water Supply Strategy (Strategy) discussed below. Through the Demand Study process, BAWSCA and the wholesale customers (1) quantified the total average-year water demand for each BAWSCA member agency through 2030, (2) quantified passive and active conservation water savings potential for each individual wholesale customer through 2040, and (3) identified conservation programs for further consideration for regional implementation by BAWSCA. The Demand Study projected that by 2040 the collective active conservation efforts of the wholesale customer’s would yield an additional 16 MGD in savings beyond what has already been achieved for the BAWSCA service area. Based on the revised water demand projections, the identified water conservation savings, and other actions, the collective purchases of the BAWSCA member agencies from the SFPUC are projected to stay below 184 MGD (206,080 AF/Y) through 2018. As part of the Demand Study, each wholesale customer was provided with a demand model that can be used to support ongoing demand and conservation planning efforts, including UWMP preparation. The City utilized that model to estimate water use reduction from future demand-side programs. Long Term Reliable Water Supply Strategy BAWSCA’s Strategy was developed to quantify the water supply reliability needs of the BAWSCA member agencies through 2040, identify the water supply management projects and/or programs (projects) that could be developed to meet those needs, and prepare an implementation plan for the Strategy’s recommendations. Successful implementation of the Strategy is critical to ensuring that there will be sufficient and reliable water supplies for the BAWSCA member agencies and their customers in the future. Phase II of the Strategy was completed in February 2015 with release of the Strategy Phase II Final Report. The water demand analysis done during Phase II of the Strategy resulted in the following key findings: There is no longer a regional normal year supply shortfall. There is a regional drought year supply shortfall of up to 43 MGD. In addition, the project evaluation analysis done during Phase II of the Strategy resulted in the following key findings: Water transfers score consistently high across the various performance measures and within various portfolio constructs and thus represent a high priority element of the Strategy. Desalination also potentially provides substantial yield, but its high effective costs and intensive permitting requirements make it a less attractive drought year supply alternative. However, given the limited options for generating significant yield for the 22 region, desalination warrants further investment in information as a hedge against the loss of local or other imported supplies. The other potential regional projects provide tangible, though limited, benefit in reducing dry year shortfalls given the small average yields in drought years17. BAWSCA is now implementing the Strategy recommendations in coordination with BAWSCA member agencies. Strategy implementation will be adaptively managed to account for changing conditions and to ensure that the goals of the Strategy are met efficiently and cost - effectively. Due to the size of the supply and reliability need, and the uncert ainty around yield of some Strategy projects, BAWSCA will need to pursue multiple actions and projects in order to provide some level of increased water supply reliability for its member agencies. On an annual basis, BAWSCA will reevaluate Strategy recommendations and results in conjunction with development of the work plan for the following year. In this way, actions can be modified to accommodate changing conditions and new developments. Alternative Water Supply Analysis In anticipation of extended periods of drought and mandatory potable water reduction imposed by the State, the City is evaluating a wide range of alternative water supplies. Recycled water and groundwater are two such resources that are interrelated in their development and potential. Therefore, the City is taking an integrated approach to evaluating n on-potable recycled water, shallow aquifer groundwater, deep aquifer groundwater, Direct Potable Reuse (DPR) and Indirect Potable Reuse (IPR). The end product will be a recycled water strategic plan for the most flexible and robust use of these resources. In addition, the City, through BAWSCA, has been working on a water transfer opportunity. Each is discussed in more detail below. Transfer or Exchange Opportunities Law 10631 (d) Describe the opportunities for exchanges or transfers of water on a short‐term or long‐ term basis. 17 While specific projects were not developed or evaluated for the Strategy, regional discussions on indirect/direct potable reuse have accelerated dramatically in the last year, making this a water supply management project BAWSCA is tracking closely. 23 Because the existing San Francisco regional water system does not have sufficient supplies in dry years, dry‐year water transfers are potentially an important part of future water supplies. As a result, in February 2011, the Palo Alto City Council approved a new Water Shortage Implementation Plan to allocate water between the BAWSCA members. This plan includes th e ability to transfer water allocated to the BAWSCA agencies between BAWSCA members during drought periods. All the BAWSCA agencies adopted the Plan by April 2011. In addition, BAWSCA is investigating water transfer opportunities as part of the Long Term Reliable Water Supply Strategy discussed above. Groundwater Deep Aquifer Groundwater The City is located in Santa Clara County. SCVWD is the groundwater management agency in Santa Clara County as authorized by the California legislature under the SCVWD Act , California Water Code Appendix, Chapter 60. The 2012 Groundwater Management Plan, which was adopted by the District Board of Directors in July 2012, describes the district's groundwater basin management objectives and the strategies, programs, and activities that support those objectives. In September 2014, Governor Brown signed the Sustainable Groundwater Management Act (SGMA) to promote the local, sustainable management of groundwater supplies. SGMA requires sustainable groundwater management for all medium and high priority basins in California. SGMA identifies the District as the exclusive groundwater management agency for Santa Clara County. The District actively manages the Santa Clara sub-basin, designated as medium priority by the California Department of Water Resources. The groundwater basins in Santa Clara County are not adjudicated nor have the basins been identified by the Department of Water Resources as being in overdraft. Although groundwater resources, particularly in South Santa Clara County, have been heavily relied upon during the last four years of drought, groundwater levels throughout the county are generally good, as potable water demand has been reduced and as SCVWD efforts to prevent groundwater basin overdraft, curb land surface subsidence, and protect water quality have been largely successful. The groundwater quality of the City’s wells is considered fair to good quality, though significantly less desirable in comparison to SFPUC’s supplies. The groundwater is approximately six times higher in total dissolved solids (TDS) and hardness than SFPUC’s supplies. The City has not pumped groundwater since 1991, and, although not a planned future water supply source, groundwater is an available alternative that is evaluated and reviewed on a regular basis. Five wells were constructed in Palo Alto in the mid‐1950s and were operated continuously until 1962. In 1988, the wells were operated to provide supplemental supplies while SFPUC 24 implemented mandatory rationing. Two of the wells we re operated for about a month and a half in 1991 when it appeared that the City was facing a severe (45%) cutback requirement. Besides normal annual operational testing, the wells have not been used since 1991. From 1999 to 2003, the City completed numerous studies that provided significant analysis of City‐owned wells and the local distribution system. The analysis is discussed in detail in the 2005 UWMP. The results of the studies provided a significant amount of information regarding the costs and operational issues of wells for emergency use, drought‐only supply and full‐time operation. Since the publication of the 2010 UWMP, the City completed the Emergency Water Supply and Storage Project. The project consisted of the repair and rehabilitation of the five existing wells, construction of three new wells, and construction of a 2.5 million gallon storage reservoir and associated pump station, and other upgrades to the water distribution system. The Emergency Water Supply and Storage Project’s primary goal was to correct the deficiency in the City’s emergency water supply. The well system can now support a minimum of eight hours of normal water use at the maximum day demand level and four hours of fire suppression at the design fire duration level. The groundwater system may also be used to a limited extent for water supply during drought conditions (up to 1,500 acre feet per year), and is capable of providing normal wintertime supply needs during extended shutdowns of the SFPUC system. Up to 11,000 gpm of reliable well capacity is available for emergency use as well as 13 million gallons (MG) of storage. Figure 1 shows the potential groundwater use area in the City’s service territory. 25 Figure 1: Potential Groundwater Use Area 26 In April 2010, the California Department of Public Health18 (CDPH) approved a permit amendment to add the new Library/Community Center Well and the Eleanor Pardee Park Wells to the City’s existing water supply permit. CDPH permitted the new El Camino Park well in 2014. As part of the permit process, all three wells were tested for primary and secondary drinking water quality standards. The results of the test indicate the wells currently meet primary and secondary water quality standards, but the potential remains for exceedance of secondary standards for manganese, iron and TDS. The wells are planned to remain as standby sources, and no additional treatment to ensure compliance with secondary standards is required at this point. In an emergency situation, the City can provide emergency chlorination treatment at several of the well sites, including the Library/Community, Eleanor Pardee, Hale, Peers, and Rinconada wells. The City has identified the wells as a potential supply source for use during a prolonged drought. As specified in the EIR for the Emergency Water Supply and Storage Project, concern about prolonged groundwater pumping in the area resulted in a maximum production limitation of 1,500 AFY during a drought19. If the wells were to be used as a dry year supply option, coordination with CDPH would be needed to ensure necessary treatment is in place to meet regulatory standards. In addition, several other issues need to be addressed prior to the use of the wells during a drought, including the capital costs of any treatment or blending upgrades, water quality compared to the City’s SFPUC source and customer acceptance, SCVWD groundwater production costs, and the exact mechanism for how groundwater would form a part of any drought response portfolio. Groundwater may hold some advantages in the long term for the City and may be useful during water supply shortage events. However, a water supply portfolio that includes potable groundwater not benefit under the type of potable water reductions mandated by the State Water Resources Control Board (SWRC) in 2015. Under those regulations, the City was required to reduce potable water consumption by 24% re gardless of the supply source. As the City considers groundwater to supplement potable water supplies during water supply shortages or as a long-term water supply source, a better understanding of the hydrology in north Santa Clara County is imperative. To that end, the City is working with the SCVWD to gather data regarding private well use within the City and to develop a model of the shallow and deep aquifers, particularly focusing on potential recharge zones and the connectivity between the aquifers. Results of this effort will be used to inform the both the evaluation of groundwater as a long-term supply source and the overall recycled water supply strategy with respect to the potential for IPR. 18 CDPH issues and has the authority to revise domestic water supply permits pursuant to Health and Safety Code section 116525 (City of Palo Alto permit #4210009 and # 4310009) 19 Final EIR, City of Palo Alto Emergency Water Supply and Storage Project, SCH #2 006022038 27 Shallow Aquifer Groundwater The drought and resulting water use restriction have increased public concern over basement construction groundwater pumping in Palo Alto. Concerns range from the apparent wasting of water by discharging to storm drains, potential impacts on groundwater elevation and flow volume, as well as potential impacts on neighboring properties, such as subsidence and cracks, and impacts on trees and other landscaping. Basement construction is often required for non -residential, mixed use and multifamily residential buildings, particularly if underground parking is involved. Additionally, the high value of land and housing in the City has resulted in more residential property owners seeking to increase the size of their single family homes by constructing basements. Basement construction groundwater pumping occurs when a basement is constructed in areas of shallow groundwater, typically in the neighborhoods closer to the bay or near current or former creek beds. Dewatering continues until enough of the house has been constructed to keep the basement in place. While the City has long regulated several aspects of basement groundwater pumping for both residential and commercial sites, recent public concern over the appearance of wasted water resulted in Council’s adoption of several new requirements for builders. Where groundwater pumping is needed, builders must install a fill station and submit a Groundwater Use Plan describing how use of the pumped groundwater will be maximized. On February 1, 201620, Council approved the following additional requirements and actions: Public outreach to encourage greater fill station use; Increased outreach on the water cycle and value of fresh water flows to storm drains, creeks and bay; Additional requirements for Groundwater Use Plans such as maximizing on-site water reuse (e.g. watering on-site and nearby vegetation), providing water truck hauling service for neighbor and City landscaping, and piping to nearby parks or major users where feasible; Expansion of fill station specifications to address water pressure issues from multiple concurrent users, including separate pumps for neighbors where needed and sidewalk bridges for hoses to reduce tripping hazards; and Submission of a determination of the effects of groundwater pumping on nearby buildings, infrastructure, trees, or landscaping. The shallow and deep aquifer research described in the section above and to be undertaken by the City in coordination with the SCVWD will provide valuable insight to the relationship between the aquifers in the north part of Santa Clara County. 20 See Staff Report 6478: http://www.cityofpaloalto.org/civicax/filebank/documents/50690 28 Water Recycling Law 10633. The plan shall provide, to the extent available, information on recycled water and its potential for use as a water source in the service area of the urban water supplier. To the extent practicable, the preparation of the plan shall be coordinated with local water, wastewater, groundwater, and planning agencies and shall include all of the following: (a) A description of the wastewater collection and treatment systems in the supplier's service area… The City operates the Regional Water Quality Control Plant (RWQCP), a wastewater treatment plant, for the East Palo Alto Sanitary District, Los Altos, Los Altos Hills, Mountain View, Palo Alto, and Stanford University. Wastewater from these communities is treated by the RWQCP prior to discharge to the Bay. Approximately 220,000 people live in the RWQCP service area. Of the wastewater flow to the RWQCP, about 60 percent is estimated to come from residences, 10 percent from industries, and 30 percent from commercial businesses and institutions. The RWQCP uses physical, biological, and chemical treatment to remove about 99 percent of the solids and organic materials from influent wastewater. In 1992, the City and the other RWQCP partners completed a Water Reclamation Master Plan (Master Plan). This Master Plan identified a five‐year, three‐stage implementation for recycled water development in the service area of the RWQCP. In 1995, City Council certified the final PEIR for the Master Plan projects. At the same time, the City decided not to pursue any of the recommended expansion stages of a water recycling system as the cost of the projects could not be justified. In addition, Council adopted a Water Recycling Policy, which includes continuation of the existing recycled water program and monitoring of the conditions that would trigger an evaluation of the Master Plan projects studied in the Program EIR. The Water Recycling Policy described five conditions that would trigger evaluation of the Master Plan projects: 1. Changes in the RWQCP discharge requirements; 2. Increased mass loading to the RWQCP; 3. Requests from partner agencies or other local agencies; 4. Availability of federal or other funds; and 5. Water supply issues – Issues which may lead to an increase in the value of recycled water from a water supply perspective include: a. Water supply shortages; b. Regulatory or legislative initiatives; or c. Advanced treatment for potable reuse. Recycled Water Market Survey Since the Council adopted the Water Recycling Policy in 1995, several factors have altered the feasibility of recycled water use in the City, including the following: 29 The SFPUC has nearly finished implementing the WSIP to repair and improve the regional water system’s infrastructure. This $4.8 billion program has resulted in steadily increasing wholesale water rates. Wholesale water rates are projected to double from the current (FY 2016) rates of $1,800/AF to nearly $2,500/AF in FY 2020. In addition, the current drought and state-mandated potable water use reductions have negatively impacted water sales that will result in additional upward pressure on supply costs. At these prices, and considering the local benefits of a recycled water supply source, recycled water is increasingly competitive with the cost of SFPUC water; The RWQCP completed a project to replace an existing deteriorating pipeline to Shoreline Golf Course in Mountain View and to extend the pipeline to the Mountain View‐Moffett area. The pipeline replacement restored the golf course connection and provides recycled water services to the Shoreline community. CPAU paid $1 million of the cost for this pipeline to ensure the pipeline will be sized to meet possible future needs in the City. In addition, CPAU has committed to pay another $1 million if and when it taps into the new pipeline; and There are potential partners for expanding the use of recycled water in the City. Since there is a regional benefit to maximizing local sources, neighboring communities and the Bay Area at large may wish to participate financially in an expansion of recycled water use in the City, especially if there are no feasible sites in their own communities. In 2005, the City engaged a consultant to complete a Recycled Water Market Survey (Market Survey). Completed in 200621, the objectives of the study were to review and update the list of potential recycled water users identified in the 1992 Master Plan and to update the estimated recycled water use potential and the cost estimates for the delivery of recycled water. The Market Survey included site investigations, market analysis, conceptual project design, and preparation of a preliminary financing and revenue plan. In December 2008, the City completed the Recycled Water Facility Plan investigating the expansion of the regional recycled water system to serve areas in Palo Alto22. As described in the narrative regarding potential future uses for recycled water, in September 2015, City Council certified the project EIR for the expansion of the City’s recycled water system to serve the Stanford Research Park. Participation in Regional Recycled Water Planning The City has participated in various regional recycled water planning initiatives. 21 The report was provided to the UAC in October 2006 and the Council in Novemb er 2006: http://www.cityofpaloalto.org/cityagenda/publish/uac- meetings/documents/Item1AttachmentARecycledWaterMarketSurveyfinalreport.pdf 22 Report provided to the UAC in March 2009: http://www.cityofpaloalto.org/civicax/filebank/documents/14932. The executive summary of the report provided to Council in April 2009 in informational Staff Report 203:09: http://www.cityofpaloalto.org/civicax/filebank/documents/15501 30 The City is a stakeholder in the ABAG‐led effort to secure grant funding for a Bay Area Integrated Regional Water Management Plan (IRWMP) and for projects identified in that IRWMP. CPAU and the partners of the RWQCP assisted in the funding of a project to build a new recycled water pipeline from the RWQCP to Mountain View. The project was completed in summer 2009. This project does not have new connections to end uses in the City, but the pipeline is sized to accommodate future expansion of recycled water use in the City. The City is a member of the California WateReuse Association, which helps promote and implement water recycling in California. The City is a member of the Bay Area Recycled Water Coalition, a group of regional recycled water project proponents that advocate for and seek funding from the Federal Bureau of Reclamation under Title 16. The City is a member of Bay Area Clean Water Agencies, a group of wastewater treatment plants that advocate and seek funding from State propositions and State Revolving Fund loans. The City actively participates on the SCVWD recycled Water Sub committee. The Committee is a group of recycled water retailers and wholesalers that meets bimonthly to discuss issues and challenges surrounding the use and promotion of recycled water. The City is working with the SCVWD to explore possible funding mechanisms to expand the City’s recycled water system in Palo Alto and to East Palo Alto. The City of Palo Alto is currently a member of the Joint Recycled Water Task Force with the Santa Clara Valley Water District which seeks future recycled water expansion projects. Wastewater Collection and Treatment in Palo Alto The City’s wastewater flows to the RWQCP. The RWQCP is an EPA award winning Class V tertiary treatment facility featuring primary treatment (bar screening and primary sedimentation), secondary treatment (fixed film reactors, conventional activated sludge, clarification and filtration), and tertiary treatment (filtration through a sand and coal filter and UV disinfection). Through these treatments, 99% of ammonia, organic pollutants, and solid pollutants are removed. While the plant was not designed to remove metals, the treatment process through optimization has reduced the quantity of mercury, silver, and lead by 90%. The removal rates for other heavy metals range from 20 to 85%. The plant's discharge meets very high standards that are among the most stringent discharge standards in the nation. The quality of the water leaving the plant approaches the standards for drinking water. Table 7 provides some data on the RWQCP. A full description of the treatment facility is included in the 1992 Water Reclamation Master Plan and is not reproduced here. 31 Table 7: Wastewater Treatment Treatment Plant Name Location (City) Average Daily Flow (2015) Maximum Daily Flow (2015) Year of Planned Build‐out Planned Maximum Daily Volume RWQCP City of Palo Alto 21,616 AF 55,000 AF Plant built out 90,000 AF = Maximum Design Daily Flow 44,000 AF = Average Design Daily Flow (Dry weather capacity) Wastewater Generation, Collection & Treatment Law 10633. The plan shall provide, to the extent available, information on recycled water and its potential for use as a water source in the service area of the urban water supplier. To the extent practicable, the preparation of the plan shall be coordinated with local water, wastewater, groundwater, and planning agencies and shall include all of the following: (a) A […] quantification of the amount of wastewater collected and treated… (b) A description of the quantity of treated wastewater that meets recycled water standards, is being discharged, and is otherwise available for use in a recycled water project. Palo Alto Regional Water Quality Control Plant (RWQCP) The RWQCP has an average dry weather flow design capacity of 39 MGD (43,680 AF/Y) with full tertiary treatment, and a peak wet weather flow capacity of 80 MGD (89,600 AF/Y) with full secondary treatment. Current average flows are approximately 19 MGD (21,280 AF/Y). The plant capacity is sufficient for current dry and wet weather loads and for future load projections. There are no plans for expansion of the plant or to “build ‐out” the plant. All of the wastewater treated at the RWQCP can be recycled. As shown in Table 8, the plant already has some capability to produce recycled water that meets the Title 22 unrestricted use standard (approximately 4.5 MGD of capacity). Current production is about 25% of capacity. Table 8: Wastewater Collected and Treated – AF Wastewater Disposal and Recycled Water Uses Law 10633. The plan shall provide, to the extent available, information on recycled water and its potential for use as a water source in the service area of the urban water supplier. To the extent practicable, the preparation of the plan shall be coordinated with local w ater, wastewater, groundwater, and planning agencies and shall include all of the following: 2015 2020 2025 2030 2035 2040 Waste Water Collected and Treated 21,616 21,280 21,280 21,280 21,280 21,280 Recycled Water Available if Full Capacity is Used 5,040 5,040 5,040 5,040 5,040 5,040 32 (c) A description of the recycled water currently being used in the supplier's service area, including but not limited to, the type, place and quantity of use. (d) A description and quantification of the potential uses of recycled water, including, but not limited to, agricultural irrigation, landscape irrigation, wildlife habitat enhancement, wetlands, industrial reuse, groundwater recharge, and other appropriate uses, and a determination with regard to the technical and economic feasibility of serving those uses. (e) The projected use of recycled water within the supplier's service area at the end of 5, 10, 15, and 20 years and a description of the actual use of recycled water in comparison to uses previously projected pursuant to this subdivision. Disposal of Wastewater Current and future City of Palo RWQCP discharges of treated wastewater to the San Francisco Bay are shown in Table 9. Table 9: Disposal of Wastewater (non‐recycled) – AF Recycled Water Currently Used The recycled water produced by the RWQCP in FY 2015 was used for the following: Trucked water mostly for irrigation with some construction dust control (25 AF) Irrigation water for Palo Alto Parks (28 AF) Irrigation water for the Palo Alto Municipal Golf Course (166 AF) Water for the Duck Pond (29 AF) Irrigation water for CalTrans freeway landscape medians (11 AF) The pipeline serving Shoreline Park and other customers in Mountain View (410 AF) Water for irrigation in and around the RWQCP and in processes at the plant itself. The amount of recycled water that replaces potable water for this use (560 AF). That usage is about 112 AF/Y for landscape irrigation and about 448 AF/Y for industrial use. Total industrial water use for the plant is about 1,960 AF/Y. Because the water is recirculated through the plant, it was assumed approximately 20% of the total water use is newly recycled water, the amount of fresh water that would need to be continuous ly added if recycled water was not available. Due to the drought, actual recycled water use in Palo Alto in 2015 was slightly lower than the projection in the 2010 UWMP (818 AF versus 850 AF). Method of Disposal 2015 2020 2025 2030 2035 2040 Discharged to San Francisco Bay 19,759 18,676 18,676 18,676 18,676 18,676 Discharged to Bay by way of Emily Renzel Marsh 629 1,344 1,344 1,344 1,344 1,344 33 Potential Uses of Recycled Water On September 28, 2015 the Palo Alto City Council adopted a resolution certifying the EIR for an expansion of the existing recycled water distribution system23. The primary objectives of extending the recycled water pipeline would be: 1. To allow the City to maximize recycled water as a supplemental water source, thereby improving potable water supply reliability by conserving drinking water, which is currently used for irrigation and other non -potable uses; 2. To provide a dependable, drought-proof locally controlled non-potable water source; 3. To increase recycled water use from the RWQCP and reduce discharge to San Francisco Bay; and 4. To reduce reliance on imported water. The potential uses in Palo Alto for recycled water are shown in Table 10 below. The table shows current use continuing for 2015 and the most recently-assessed potential for expansion is shown in the totals for 2020 and beyond. A business plan for the recycled water distribution system expansion project, the Phase 3 expansion (discussed in more detail below), will include an updated analysis of potential uses for the water as well as a determination with regard to the technical and economic feasibility of serving those uses. The potential landscape use increase starting in 2020 in Table 10 reflects the possibility of the Phase 3 recycled water system expansion. As noted in the groundwater discussion above but not included in Table 10, recycled water is also being considered for indirect potable reuse. Table 10: Potential Future Use of Recycled Water in Palo Alto‐ AFY Recycled Water Facility Plan Following completion of the recycled Water Market Survey, the City applied for and secured grant funding for the project planning from the SWRCB through the Regional W ater Recycling Facilities Planning Grant Program. The grant provided a 50% cost share with the City for up to $75,000 to fund the preparation of a Facilities Plan for the recycled water project. The purpose of the Facility Plan was fourfold: 1. Define recycled water alternatives (i.e. reuse sites and demands, distribution alignment, sizing, construction alternatives, etc) and identify a recommended project; 23 See Staff Report 6071: http://www.cityofpaloalto.org/civicax/filebank/documents/49059 Treatment 2015 (Actual) Agriculture 0 0 0 0 0 Landscape (no golf courses)175 1,072 1,072 1,072 1,072 Golf Course 166 196 196 196 196 Industrial 448 448 448 448 448 Groundwater Recharge 0 0 0 0 0 Palo Alto Duck Pond 29 34 34 34 34 Total 818 1,750 1,750 1,750 1,750 Type of Use 2020 2025 2030 2035 Tertiary treatment plus additional disinfection (Title 22 unrestricted use standard) 34 2. Develop a realistic funding strategy for the recommended project; 3. Develop an implementation strategy for the recommended project; and 4. Provide the basis for any future State and Federal grant requests for the recommended project. The City engaged a consultant in April 2007 to assist in preparing the Facility Plan. Based on the analysis in the Facility Plan, the report identified a recommended project to serve customers in the Stanford Research Park area and potentially offset the need to import approximately 900 AFY of potable water. Figure 2: below illustrates the areas currently being provided recycled water (Phases 1 and 2) and the future potential Phase 3 project to serve the Stanford Research Park. Figure 2: Phase 3 Recycled Water Project 35 The Facility Plan provided a comprehensive analysis of the Stanford Research Park project, including detailed costs estimates. The Facility Plan identified a gross project cost of approximately $2700/AF (2007 dollars), as compared to a current SFPUC projection in 2020 of approximately $2,500/AF. Potential grant and low cost financing opportunities may decrease the project cost to Palo Alto. In December 2008, the Facility Plan was deemed complete by the State Water Resources Control BoardThe City is in the process of developing a Recycled Water Strategic Plan that will include an assessment of all possible scenarios for recycled water in Palo Alto. Encouraging Recycled Water Use Law 10633. The plan shall provide, to the extent available, information on recycled water and its potential for use as a water source in the service area of the urban water supplier. To the extent practicable, the preparation of the plan shall be coordinated with local water, wastewater, groundwater, and planning agencies and shall include all of the following: (f) A description of actions, including financial incentives, which may be taken to encourage the use of recycled water, and the projected results of these actions in terms of acre‐feet of recycled water used per year. The City encourages Recycled Water usage in the following ways: Participating in the Integrated Regional Water Management Plan process Encouraging businesses and City departments to utilize the existing recycled water capability within the City Participating as an active member of the WateReuse Association, including hosting meetings of the Northern California Chapter of the Association Offering recycled water for free to users willing to pick it up at the RWQCP by truck Adoption of the Recycled water Mandatory Use Ordinance Adoption of the Salinity Reduction Policy Current and Proposed Actions to Encourage Use of Recycled Water Since completion of the 2010 UWMP, the City has continued to pursue several approaches to encourage recycled water use. If the Phase 3 recycled water expansion project is approved by City Council, the actions taken by the City to encourage the use of recycled wa ter are estimated to increase recycled water use by approximately 900 AF/Y, more than twice the volume used today. In May 2008, the City approved a Mandatory Use Ordinance to require customers to prepare for recycled water delivery in the future24. For most new construction and some renovations that meet certain criteria, the applicant must install dual‐plumbing and prepare the site for irrigation with recycled water. Compliance with the ordinance is administered through the 24 City of Palo Alto Municipal Code, Title 16, Chapter 16.12. The Ordinance applies to non‐residential customers. The City has no plans to provide recycled water to residential customers. 36 permit process with the Building Department. CPAU provides plan review services of landscape and irrigation design plans, in order to ensure compliance with outdoor water efficiency and recycled water requirements. The City Council approved a Salinity Reduction Policy25 in January 2010 to address the elevated salinity levels in the recycled water. The policy identified inflow and infiltration as a likely contributor to the elevated salinity levels, and provided a target salinity level based on minimum inflow and infiltration into the wastewater collection system. As a result, several steps were implemented to lower the TDS levels in the recycled water: The RWQCP continues to monitor potential saltwater intrusion "hotspots" and communicate the results to the RWQCP partners; The RWQCP tracks salinity data and perform other investigative work to support the effort; CPAU coordinated implementation of the Sanitary Sewer Management Plan to manage the Palo Alto wastewater collection system and identify inflow and infiltration reduction actions; and The RWQCP developed a plan to coordinate salinity reduction activities with the RWQCP partners and prepare for expanded recycled water application. This plan26 was coordinated with the SCVWD, which has jurisdiction over the groundwater basins in Santa Clara County. Nevertheless, customer concerns regarding potential negative effects of recycled water on redwood trees and other sensitive plants led the City to identify several mitigation measures in the EIR if the City is unable to meet the goal for a TDS of 650 mg/l by project start-up: The City may utilize its existing Recycled Water Ordinance exemption process to exempt redwood trees and/or other salt sensitive species from the use of recycled water; The City may blend recycled water and other lower salinity water prior to application; and/or The City may treat recycled water to reduce TDS prior to application, or shortly thereafter. Additionally, the City is initiating a feasibility analysis to treat and blend recycled water prior to delivery. The feasibility analysis is also supported by the City of Mountain View, a RWQCP partner agency, since it already uses the recycled water and has an interest in improving the water quality of the recycled water it delivers. Recycled Water Optimization Plan Law 25 City Council Resolution 9035: http://www.cityofpaloalto.org/civicax/filebank/documents/21246 26 The SCVWD updated its groundwater management plan in 2012 37 10633. The plan shall provide, to the extent available, information on recycled water and its potential for use as a water source in the service area of the urban water supplier. To the extent practicable, the preparation of the plan shall be coordinated with local water, wastewater, groundwater, and planning agencies and shall include all of the following: (g) A plan for optimizing the use of recycled water in the supplier's service area, including actions to facilitate the installation of dual distribution systems and to promote recirculating uses. The City continues to create a plan for optimizing the use of recycled water. Completion of the Recycled Water Market Survey, the Facility Plan, and the EIR are steps in that direction. The City expects that the costs of implementing expanded recycled water use can be reduced through a combination of regional coordination and state and federal matching funds. RWQCP Long Range Facilities Plan The City of Palo Alto Public Works Department completed a Long Range Facilities Plan for the Palo Alto RWQCP. Aging equipment, new regulatory requirements, and the movement to full sustainability will require rehabilitation, replacement and new processes. The Long Range Facilities Plan maps out these changes and focuses on biosolids treatment and disposal, waste ‐ to‐energy technologies, energy use, major pipeline repairs, recycled water treatment, carbon footprint impacts, and the best alternatives for rehabilitation, replacement or improvement. BAWSCA Long Term Reliable Water Supply Strategy Palo Alto was a participating agency on the BAWSCA Long Term Reliable Water Supply Stra tegy. The Long Term Reliable Water Supply Strategy evaluated potential new supply sources to meet normal and dry year BAWSCA member needs. The City’s Phase 3 recycled water expansion project was included in the plan. Indirect Potable Reuse The City is working with the SCVWD, the principle agency responsible for the groundwater in Santa Clara County, to gather data and study the potential for IPR in the North County. The City also anticipates that the SCVWD’s Water Supply and Infrastructure Master Plan will evaluate IPR as part of any future supply portfolio. The recycled water expansion project is an asset that could potentially benefit aquifer recharge activities. Desalinated Water Law 10631 A plan shall be adopted . . . that shall do all of the following: (h) Describe the opportunities for development of desalinated water, including, but not limited to, ocean water, brackish water, and groundwater, as a long-term supply. Development of desalinated water is not feasible at this time. In its Long Term Reliable Water Supply Strategy, BAWSCA considered a wide range of desalination projects, ranging in size from 1 MGD to 20 MGD, and ranging in type from brackish groundwater to an ocean water open 38 intake. Two types of projects were included in the final report: 1) a project that produces 15 MGD of water sourced from an open intake in San Francisco Bay; and 2) a project that produces up to 6.5 MGD from brackish water sourced from either shallow vertical brackish groundwater wells or horizontal directionally drilled (HDD) wells extracting higher salinity brackish groundwater from under the Bay. BAWSCA is committed to facilitating desalination partnerships and pursuing outside funding for related studies . The City is currently aware of one regional collaborative effort between different water agencies to evaluate a large scale Bay Area desalination project, The Bay Area Regional Desalination Project. The Bay Area Regional Desalination Project is a collaboration between the East Bay Municipal Utility District, SCVWD, the SFPUC, Contra Costa Water District, and Zone 7 Water Agency to jointly explore developing the feasibility of a regional desalination facility that could directly or indirectly benefit 5.4 million San Francisco Bay Area residents and bu sinesses served by these agencies. 39 Section 4 – Water Demand Law 10631 (e) (1) Quantify, to the extent records are available, past and current water use, over the same five‐ year increments described in subdivision (a), and projected water use, identifying the uses among water use sectors including, but not necessarily limited to, all of the following uses: (A) Single‐family residential; (B) Multifamily; (C) Commercial; (D) Industrial; (E) Institutional and governmental; (F) Landscape; (G) Sales to other agencies; (H) Saline water intrusion barriers, groundwater recharge, or conjunctive use, or any combination thereof; (I) Agricultural; and (J) Distribution system water loss. (2) The water use projections shall be in the same 5‐year increments to 20 years or as far as data is available. (3) (A) For the 2015 urban water management plan update, the distribution system water loss shall be quantified for the most recent 12-month period available. For all subsequent updates, the distribution system water loss shall be quantified for each of the fi ve years preceding the plan update. (B) The distribution system water loss quantification shall be reported in accordance with a worksheet approved or developed by the department through a public process. The water loss quantification worksheet shall be based on the water system balance methodology developed by the American Water Works Association. 10631.1 (a) include projected water use for single‐family and multi‐family residential housing for lower income households, as identified in the housing element of any City, County, or City and County in the service area of the supplier. 10608.2 Provide baseline daily per capita water use target, interim urban water use target, and compliance daily per capita water use, along with the basis for determining th ose estimates. Water Usage Although the City has experienced several drought periods since 1975, the current drought has had a particularly profound effect on City and customer attitudes regarding water. The current state-mandated water use reductions resulted in large numbers of landscape conversion projects as well as a dramatic shift in customer behavior regarding water use. In addition, n ew construction in every sector is subject to increasingly stringent regulations regarding water ‐ using appliances and fixtures. Demand Projections Incorporating the profound effects of the current drought and state-imposed mandatory potable water use reductions presented an additional challenge when developing the water 40 demand projections for this 2015 UWMP. A model developed in-house was used to forecast SFPUC purchases assuming the continuation of the City’s existing Demand Management Measures (DMMs). Water savings from future DMMs were developed using the same end use model that was used to develop the projections in the 2010 UWMP. The City developed baseline projections for the purchased SFPUC water using an econometric model built in-house. The model uses historical water usage data as well as assumptions regarding population, economic growth, and development. Current DMMs are implicitly considered in the model. Breaking down demand at the end-use level was accomplished by applying the 2015 water use percentages for each type of water service account (single ‐family, multi‐ family, commercial, irrigation, etc.) to the total projected demand. The end use model (also known as the Demand Side Management Least Cost Planning Decision Support System, or DSS model) was used to forecast the impact of future DMMs discussed in detail in Section 5 of this report. Figure 3: below shows the City’s potable water use since 1988 and a projection of water supplies through 2040. Present water consumption at its lowest level in the more than 25-year history. The reduction in current water consumption is the result of state mandated water reductions and permanent water conservation measures implemented during the past 25 years. Under the current drought to date, the SFPUC has called for, but has not mandated, a 10% system-wide reduction since January 2014. SFPUC has not yet been compelled to impose mandatory system-wide rationing because its customers have exceeded the 10 percent voluntary system-wide reduction as a result of the state-wide mandatory reductions imposed by the State Water Resources Control Board. The SWRCB required the City to reduce potable water use by 24% for the period June 2015 through October 2016 compared to usage in 2013. As of the end of calendar year 2015, the City is on track to meet or exceed that reduction target. Because many permanent water use changes including landscape conversion has occurred as a result of rebate programs and public outreach, and because the City detects a shift in the community’s attitude regarding water use, the City’s water consumption is forecast to remain relatively stable in the future, with slight increases due to a post-drought rebound and continued increases in economic development and population. By 2025, it is predicted that the overall trend of decreasing pe r capita water use will resume. 41 Figure 3: Water Supply Purchases – Actual and Forecast Water Sales Total water sales decreased by 11%, from 11,375 AF/Y to 10,177 AF/Y between 2010 and 2015. Table 11 shows historical and projected sales by customer type before and after incorporating the impact of planned DMMs discussed in Section 5 – Demand Management Measures. Table 12 shows the number of accounts in each category, and Table 13 shows the sales per account for each customer type. The City does not have sales to other agencies, agricultural use, or saline water intrusion barriers, groundwater recharge, or conjunctive use, or any combination thereof. 42 Table 11: Historical and Projected Water Sales – by Customer Type Table 12: Historical and Projected Water Accounts – by Customer Type Table 13: Historical and Project Water Sales per Account Use per account decreased for every customer type from 2010 to 2015. Overall water use per account decreased by 14%. During this period, water use per account decreased by 17% for single family residences, 3% for multifamily, 18% for commercial, 14% for in dustrial, 18% for public facilities, 10% for irrigation customers and 34% for City facilities. Share of Total Consumption by Customer Type In 2015 residential and multi-family water sales were responsible for 60% of total water consumption in the City. The business sectors including commercial and industrial customers consume 23%, while irrigation customers consumed 11%. Public and City facilities consume the AF/Y 2010 2015 2020 2025 2030 2035 2040 Single Family 5,372 4,554 4,972 4,829 4,712 4,605 4,523 Multifamily 1,685 1,530 1,670 1,622 1,583 1,547 1,519 Commercial 1,942 1,911 2,086 2,026 1,977 1,932 1,898 Industrial 705 397 434 421 411 402 394 Institutional 368 357 390 379 370 361 355 Other 4 3 3 3 3 3 3 Landscape 1,012 1,163 1,269 1,233 1,203 1,176 1,155 Government 288 263 287 279 272 266 261 Total Water Sales 11,375 10,177 11,111 10,793 10,530 10,292 10,108 Future DMM 123 121 120 119 Net Water Sales 11,375 10,177 11,111 10,669 10,409 10,172 9,989 2010 2015 2020 2025 2030 2035 2040 Single Family 14,659 15,029 15,179 15,210 15,240 15,271 15,301 Multifamily 2,058 1,923 1,923 1,923 1,923 1,923 1,923 Commercial 1,245 1,494 1,494 1,494 1,494 1,494 1,494 Industrial 139 91 91 91 91 91 91 Institutional 42 50 50 50 50 50 50 Other 535 669 669 669 669 669 669 Landscape 289 371 371 371 371 371 371 Government 171 236 236 236 236 236 236 Total Water Acounts 19,139 19,863 20,014 20,044 20,075 20,105 20,136 2010 2015 2020 2025 2030 2035 2040 Single Family 0.366 0.303 0.328 0.318 0.309 0.302 0.296 Multifamily 0.819 0.795 0.868 0.843 0.823 0.804 0.790 Commercial 1.560 1.279 1.396 1.356 1.323 1.293 1.270 Industrial 5.065 4.348 4.747 4.611 4.499 4.397 4.319 Institutional 8.673 7.148 7.804 7.580 7.396 7.228 7.099 Other 0.007 0.004 0.004 0.004 0.004 0.004 0.004 Landscape 3.497 3.132 3.419 3.321 3.240 3.167 3.111 Government 1.686 1.115 1.217 1.183 1.154 1.128 1.108 Total Use per Account 0.594 0.512 0.555 0.538 0.525 0.512 0.502 43 remaining 6%. The relative share of water consumed has not changed significantly between customer types since 2010. Figure 4 and Figure 5 below show the breakdown of consumption by customer type for 2010 and 2015. Figure 4: 2010 Water Sales by Customer Class Figure 5: 2015 Water Sales by Customer Class Sales to Other Agencies The City has not, and does not plan to, sell water supplies to other agencies. Additional Water Uses ‐ Recycled Water Use Recycled water use is discussed in Section 3, “System Supp lies,” under the heading “Water Recycling.” Past use and future recycled water use projections are presented in Table 14 below. Although the City is exploring an expansion of its recycled water system, the Co uncil has not made a commitment to expand the use of recycled water in the City and, therefore, the table reflects no increase in the use of recycled water in the future. The 2010 UWMP projected 44 future recycled water use to be 850 AF/Y. Actual use in 2015 was slightly lower (818 AF) resulting from drought-related water use reductions. Table 14: Recycled Water Use (AF/Y) Non‐Revenue Water/Water Loss Non‐Revenue water, or unaccounted‐for water, is the difference between the amount of water purchased and the amount sold to customers. Non‐revenue water typically amounts to about 7% of total purchases. From CY 2005 to 2008, the City’s non‐revenue water volumes significantly increased, with a peak in CY 2006 of 12.45%. In response, the City initiated a comprehensive leak detection, meter locating and meter calibration program. As of 2009, the non‐revenue water volumes have returned to expected levels. Appendix C contains the water loss audit report for the most recent year of date, FY 2014. Real losses in that year, as per the audit, were 563 AF. Table 15 presents the historical and projected non‐revenue volumes for the City’s water system. Table 15: Non-Revenue Water (AF/Y) Total Water Use Table 16 shows total water use in the City. Table 16: Total Water Use (AF/Y) Projected Low to Moderate Income Water Use Palo Alto was one of the first jurisdictions in California to establish an official low to moderate income housing requirement in 1974. The Below Market Rate (BMR)27 program now requires 27 City of Palo Alto Comprehensive Plan, Chapter 4 – Housing Element 2010 2015 2020 2025 2030 2035 2040 Water Trucks 7 25 29 29 29 29 29 Palo Alto Parks 20 39 31 31 31 31 31 Golf Course 167 166 196 196 196 196 196 Duck Pond 56 29 34 34 34 34 34 RWQCP 560 560 560 560 560 560 560 Total 810 818 850 850 850 850 850 2010 2015 2020 2025 2030 2035 2040 Non-Revenue Water 936 547 772 742 724 707 694 2010 2015 2020 2025 2030 2035 2040 Retail Sales 11,375 10,177 11,111 10,669 10,409 10,172 9,989 Non-Revenue Water 936 547 772 742 724 707 694 Recycled Water 810 818 850 850 850 850 850 Total 13,121 11,542 12,733 12,261 11,982 11,729 11,534 45 developers of projects with five or more units to comply with the City’s BMR requirements. The BMR program objective is to obtain actual housing units or buildable parcels within each development rather than off‐site units or in‐lieu payments. At least 15% of the housing units developed in a project involving fewer than five acres of land must be provided as BMR units. Projects involving the development of five or more acres must provide at least 20% of all units developed as BMR units. (Projects that cause the loss of existing rental housing may need to provide a 25 percent BMR component). The BMR units must be comparable to other units in the development. Due to the BMR requirements and the cost of housing in Palo Alto, the City has few single ‐ family BMR units and does not anticipate this will change in the future. Approximately 2058 units in the City meet lower income levels as defined in Section 50079.5 of the California Health and Safety code28. Of these, 456 rental and ownership units, or 1.5% of the total housing units meet the BMR requirements. The remaining 1,602 units, or 5.4% of total housing units, are subsidized housing.29 For purposes of the current lower income projections, the 2015 UWMP assumes: 2,058 units out of the total housing stock in 2015 are considered affordable housing as determined by the classification of very low to moderate incomes. Affordable housing units in Palo Alto are categorized as multi‐family. An average of 2.4330 individuals per multi‐family unit. This is approximately 5,000 individuals or 7% of the total population in 2015. Multi‐family usage in Palo Alto averages 75 GPCD (from the end use model). An additional of 527 units will be added for each 5 -year increment in the planning horizon.31 Table 17: Projected Low Income Water Demands (AF) The City anticipates the current low income BMR program will remain in effect in its current form for the foreseeable future. Future housing and population projections inherently assume that increases in housing stock will include growth in lower income households through the 28 The difference between the total BMR units and the units that meet the requirements in the UWMP Act is due to the inclusion of additional units that meet 81% to 120% of the Average Median Income in Santa Clara County. The City provides these additional units in recognition of high cost of housing in Palo Alto. 29 Current figures provided by the City of Palo Alto Planning Department. 30 U.S. Census Bureau, 2010, assumes an average of 2.43 persons per multi‐family dwelling unit. 31 Affordable Housing Forecast estimates includes “Very Low”, “Low”, and “Moderate” based on State Housing & Community Development (HCD) Regional Housing Needs Allocation (RHNA ) income definitions. Forecast estimates are derived from average of “need” for the City of Palo Alto per income category for the last three RHNA cycles (1998-2006, 2007-2014, & 2015-2023). Average “Very Low” – 26%, Average “Low” – 16%, & Average “Moderate” – 20%. 2015 2020 2025 2030 2035 Single-family Residential 0 0 0 0 0 Munti-family Residential 420 528 635 743 850 Total 420 528 635 743 850 46 BMR program. Based on future projected demand forecasts shown in Table 11, the City expects to have ample water supplies to meet all customers’ demands during a normal year. During a drought, the City will follow the steps outlined in Section 8 (Water Shortage Contingency Plan). The Water Shortage Contingency Plan addresses the City’s response depending on the severity of the drought. The City will implement measures to maximize potential savings while at the same time minimizing the impact to the wellbeing of the citizens and businesses in Palo Alto. As part of this process, the City Council will have an opportunity to balance the needs of different customer classes with the need to achieve meaningful reductions32. Water Conservation Bill of 2009 The Water Conservation Bill of 2009 (SBx7‐7) was enacted in November 2009. It requires water suppliers to reduce the statewide average per capita daily water consumption by 20% by December 31, 2020. To monitor the progress towards achieving the 20% by 2020 target, the bill also requires urban retail water providers to reduce per capita water consumption 10% by 2015. Water agencies that are not in compliance with the provisions of the bill could be ineligible for State grants and/or a low cost financing program. Water suppliers have some flexibility in setting and revising water use targets leading up to the 2020 compliance period, including: A water supplier may set its water use target and comply individually, or as part of a regional33 alliance. The City is in discussions with BAWSCA and SCVWD regarding a potential future alliance with other water agencies. A water supplier may revise its water use target in its 2015 or 2020 urban water management plan or in an amended plan. A water supplier may change the method it uses to set its water use target and report through an amendment to the 2010 plan or in its 2015 urban water management plan. Urban water suppliers are not permitted to change target methods after they have submitted their 2015 urban water management plan. SBx7‐7 provided four potential compliance methods that are summarized below: 1. 80% of the urban water user’s baseline gallons per capita per day (GPCD) water use; 2. The per capita daily water use that is estimated using several performance measures, subdivided between different customer classes; 32 Water Utilities typically do not possess income information for their customers and are limited in their ability to offer differential rate treatment for low income customers due to Proposition 218 restrictions. During a drought, it is more common for water utilities to differentiate between customers in a Class based on water usage patterns and relative efficiency. For example, accounts with extremely low water use could be exempted from penalty rate treatment. 33 SBx7‐7 allows entities to comply individually or as a group. The intent of this provision is to ensure there is equity among small agencies and large water agencies or districts that serve large areas that may span different socioeconomic and evapotranspiration zones. 47 3. Ninety‐five percent of the applicable state hydrologic region target, as set forth in the state’s draft 20x2020 Water Conservation Plan (dated April 30, 2009); or 4. A method that was identified and developed by the department, through a public process, and released on December 31, 2010. The fourth method uses a combination of metered sales data and achieved water use reductions across the different customer classes. The City Council, by Resolution 9174, adopted a compliance methodology based on the first option, or 80% of an urban water user’s baseline GPCD. Under this methodology, the City is required to prepare the following calculations for compliance purposes: Baseline daily per capita water use — The City must determine for baseline purposes how much water is used within an urban water supplier’s distribution system area on a per capita basis. It is determined using water use and population estimates from a defined range of years. For the City, the range selected is from fiscal year 1995 to 2004 (Table 18). Urban water use target — The value is equal to 80% of the baseline daily per capita water use value. Interim urban water use target — The planned daily per capita water use in 2015 is halfway between the baseline daily per capita water use and the urban water use target. Compliance daily per capita water use – The gross water use during the final year of the reporting period, reported in gallons per capita per day. This value will be adjusted during the 2015 and 2020 compliance period based on actual usage data. Table 18 illustrates the methodology to calculate the 10‐year average baseline per capita34 water use. Table 18: Baseline Daily Per Capita Water Use for 10-year period (1995 through 2004) 34 US Census Fiscal Year Distribution System Population Daily System Gross Water Use (MG) 1995 56,647 203.8 1996 56,885 220.8 1997 57,420 203.8 1998 57,868 203.8 1999 58,136 198.2 2000 58,467 203.7 2001 59,334 199.6 2002 60,028 209.1 2003 59,930 202.5 2004 59,894 251.1 225.3Baseline Daily Per Capita Water Use 48 Based on future water use and population growth projections, Table 19 summarizes Palo Alto’s 2010 UWMP SBx7‐7 target and compliance goals. Table 19: 2015 UWMP SBx7-7 Performance Metrics (gallons per capita per day) The City met the interim 2015 SBx7‐7 target and is projected to meet the 2020 target. As stated previously in this section, an urban water retailer has the flexibility to adjust the compliance target and to adjust the methodology in 2015. The City is continuing to apply the baseline per capita daily water use methodology. After 2015, the urban water supplier may not adjust the methodology, but there is the potential to adjust the compliance target as more current water use data becomes available. In addition, an agency that is at risk of non‐ compliance may, under limited circumstances35, seek to adjust its compliance daily per capita water use. Eligible circumstances include: Differences in evapotranspiration and rainfall in the baseline period compared to the compliance reporting period; Substantial changes to commercial or industrial water use resulting from increased business output and economic development that have occurred during the reporting period; and Substantial changes to institutional water use resulting from fire suppression services or other extraordinary events, or from new or expanded operations, that have occurred during the reporting period. Measures, Programs and Policies to Achieve SBx7‐7 Water Targets Table 19 provides a preliminary analysis of the City’s SBx7‐7 metrics, and the data shows the City will far surpass the water use reduction goal. The City will continue to monitor progress, however, and make program adjustments if needed. Potential adjustment to meet any shortfall could include the following: The City is currently evaluating an extension of the current recycled water system to serve customers in the Stanford Research Park area. This project was discussed in Section 3, but has not been included in the long‐term water use projection identified in the 2015 UWMP, largely due to the uncertainties surrounding project feasibility. Full build‐out of the project would result in an anticipated yield of approximately 900 AFY36 The City is committed to promoting all cost‐effective conservation programs that meet both the City’s water reduction goals and community interest. Palo Alto shifts emphasis between different conservation programs depending on various factors, including community acceptance. Over time, the program mixture may change, though the overall savings goals will remain constant. 35 CA Water Code; Section 10608.24 36 City of Palo Alto Recycled Water Facility Plan, June 2008 2015 2020 Baseline GPCD 225.3 225.3 Target GPCD 202.8 180.3 Actual/Projected GPCD 152.7 161.2 49 Economic Impacts of SBx7‐7 Compliance There are no incremental economic impacts associated with SBx7‐7 compliance at this time because it is anticipated the City will meet the target. The decision to implement additional conservation measures in the future will not necessarily depend on the need to comply with SBx7‐7; Palo Alto typically evaluates all measures that are cost effective compared to the incremental cost of purchasing additional water supplies from the SFPUC system 37. 37 DMMs discussed in Section 5 50 Section 5 – Demand Management Measures Law 10631 (f) Provide a description of the supplier’s water demand management measures. This description shall include all of the following: (1) (A) For an urban retail water supplier, as defined in Section 10608.12, a narrative description that addresses the nature and extent of each water demand management measure implemented over the past five years. The narrative shall describe the water demand management measures that the supplier plans to implement to achieve its water use targets pursuant to Section 10608.20. (B) The narrative pursuant to this paragraph shall include descriptions of the following water demand management measures: (i) Water waste prevention ordinances. (ii) Metering. (iii) Conservation pricing. (iv) Public education and outreach. (v) Programs to assess and manage distribution system real loss. (vi) Water conservation program coordination and staffing support. (vii) Other demand management measures that have a significant impact on water use as measured in gallons per capita per day, including innovative measures, if implemented. 10620 (f) An urban water supplier shall describe in the plan water management tools and options used by that entity that will maximize resources and minimize the need to import water from other regions. The City is committed to support conservation and efficient use of its water supply. It is the goal of the City to continue to look for opportunities, innovative technologies, and cost -effective programs that best utilize the City’s water conservation budget. The City has been working with other Bay Area Water Supply and Conservation Agency (BAWSCA) members, the Santa Clara Valley Water District (SCVWD), and other water agencies in the Bay Area to implement Best Management Practices (BMPs) related to water conservation programs. The California Water Code Section 10631 (f) requires that an urban retail water supplier provide descriptions that addresses the nature and extent of the following DMMs that have been implemented over the past five years and/or will be implemented to achieve its water use target pursuant to SBx7-7: A. Water waste prevention ordinance. B. Metering. C. Conservation pricing. D. Public education and outreach. E. Programs to asses and manage distribution system real loss. F. Water conservation program coordination and staff support. G. Other demand management measures that have a significant impact on water use as measured in gallons per capita per day, including innovative measures, if implemented. In addition, the DMMs described below are water management tools and options used by the City that maximize resources and minimize the need to import water from other regions. 51 Water Waste Prevention Ordinance The City has enforced water waste prevention as part of the City’s Municipal Code since 1989 (Palo Alto Municipal Code Chapter 12.32). Enforcement includes written warning notices to violators and may result in fines and installation of a flow restrictor on the service connection of the customer or purchaser of water whose service connection was used in the violations observed or established, and billing the costs of such installation to said customer or purchaser. In 2015, Palo Alto City Council approved an updated Green Building Ordinance (Palo Alto Municipal Code Chapter 16.14) that incorporates the state’s 2013 Green Building Standards Code (CALGreen), which sets permit requirements for water efficiency design, including irrigation systems, in new development. In addition to the CALGreen standards, the City requires the installation of a “laundry to landscape ready” irrigation system for all residential new construction projects. Also, the City’s Green Building Ordinance has a lower square footage trigger for irrigation efficiency than the state’s Model Water Efficient Landscape Ordinance (MWELO). For non-residential projects, MWELO requires compliance for landscapes of any size associated with new construction and landscapes of 1,000 square feet for renovation projects. Under the City’s current Green Building Ordinance, compliance with MWELO is required for landscapes of any size on all non-residential construction projects, as well as for landscaped areas of 1,000 square feet or more for residential projects. Palo Alto adopted the State Water Efficient Landscape Ordinance per Governor Brown’s Drought Executive Order EO-29-15. The new ordinance went into effect February 1, 2016. Metering The City has approximately 20,000 water service connections in its service territory. In 2015, irrigation meters accounted for 2% of the total installed meters, whereas water consumption from irrigation meters accounted for 10% of the City’s total metered water consumption. Non - revenue water (NRW) usage currently accounts for less than 7% of the City’s water consumption (by comparison, the 2015 national average of NRW was 16%.) The City is currently implementing an Advanced Metering Infrastructure (AMI) pilot installing advanced electric, gas and water meters at around 300 single-family homes. Customers with these advanced meters can monitor their hourly electric, gas and water usage from a secured website. Customers are alerted via email or text message when a potential water leak is detected and can act immediately to investigate and remedy the problem. So far, the AMI pilot has been very well-received by participating customers, and more than 200 leaks have been fixed by customers alerted to the leak by the program. The City currently plans to deploy advanced water meters to all customers by 2022. Since 2012, the City has begun replacing aging water meters with digital water meters that register water usage down to increments of 0.01 CCF (or hundred cubic feet). Traditional water 52 meters can only register water usage in increments of 1 CCF. The smaller incremental water usage readings help to facilitate water leak detection. Conservation Pricing Since 1976, the City has implemented conservation-based pricing for water usage, within an overall cost-based rate structure. For residential customers, water usage is billed as a two- tiered volumetric charge that increases as monthly water consumption exceeds a thresho ld level. For non-residential customers, water usage is billed on a uniform volumetric charge. All customers are also billed a monthly service charge that varies depending on the meter size. The City conducted a water cost of service and rate study in 2012 with the assistance of an independent consultant, to ensure continued compliance with the California Constitution’s cost of service requirements for water rates. The 2012 study and water rate structure were evaluated and updated in 2015, in light of new judicial guidance on constitutionally compliant water rates. On an annual basis, City staff reviews and updates the City’s water rates for both residential and nonresidential water customers. Public Education and Outreach Since 2006, the City has partnered with BAWSCA to offer free workshops on water efficient landscaping, irrigation and water conservation. Workshop topics include Creating a Water - Efficient Sustainable Garden, Laundry to Landscape Graywater Systems, Irrigation Basics for Homeowners, Water Conservation 101, Rainwater Harvesting, etc. In addition to public workshops, City of Palo Alto Utilities (CPAU) staff attends community, corporate and school events to promote water conservation programs and practices, in addition to energy efficiency , waste reduction and other sustainability practices. The City carries out various seasonal and general water conservation campaigns via the use of television, online, social media and print advertisements. Palo Alto also regularly updates the City’s website on water conservation programs and public workshops. The City utilizes utility bill inserts, brochures and email newsletters to customers as part of its outreach efforts. In the fall of 2014, due to the drought, the City implemented a web and mobile application known as PaloAlto311 to allow residents and businesses to report incidents of leaks or other water waste issues. In response to prolonged drought conditions, on January 31, 2014 the SFPUC asked its retail and wholesale customers to voluntarily reduce system-wide water consumption by 10 percent. That summer, BAWSCA, in partnership with the SFPUC, launched a regional drought education campaign to heighten awareness and encourage water conservation. The regional campaign drew upon the SFPUC’s “Water Conservation is Smart and Sexy” citywide campaign. The 53 regional campaign appeared in the form of billboards, BART station ads, movie theater ads, and online video advertisements. Following Governor Brown’s Drought Executive Order on April 1, 2015 an d conservation regulations mandating a statewide 25 percent reduction in potable urban water use, the SFPUC continued its call for a system-wide 10 percent reduction in water use. The SFPUC and BAWSCA partnered again to launch a new drought campaign for the summer of 2015 to remind customers to keep up their water conservation efforts, focusing in particular on outdoor water savings. Regional messaging was included in the form of billboards, BART station ads, television ads, newspaper ads, and a video campaign. Programs to Assess and Manage Distribution Systems Real Loss For over two decades, the City has pursued an aggressive Water Main Replacement Capital Improvement Program. This program identifies structurally deficient water mains and appurtenances that are undersized, corroded, and/or subject to breaks and leaks, and replaces them with jointless high-density polyethylene (HDPE) NSF 61 piping material using trenchless construction methods. Through this program, approximately 15,000 linear feet of water mains are replaced each year, which has significantly reduced water leaks throughout the system. The City maintains a 24-hour response program to fix water leaks. In addition, the City also maintains a Water Meter Replacement Program that replaces 500 to 1,000 meters per year in accordance with American Water Works Association (AWWA) standards. In 2012 through 2014, a “Large Water Meter Testing, Calibration, Repair & Replacement” Program was undertaken that involved a total of 257 large water meters. Of these meters, 136 meters have been tested, repaired, removed, or rep laced, thereby improving the accuracy and reliability of these meters. Coupled with the aforementioned current AMI pilot, these capital improvement programs further enhance the City’s ability to track volume of water entering and leaving the distribution system, reducing NRW and aligning the Utility's ten -year meter testing and replacement cycle in accordance with industry-standard best management practices. Water Conservation Program Coordination and Staffing Support Water Conservation Program Partnership with SCVWD Since 2002, the City has partnered with SCVWD to promote and cost -share a wide range of water conservation programs to encourage residents and businesses to improve water use efficiency. These programs include free indoor and outdoor water aud its, as well as rebates for upgrading a wide range of water-using fixtures to high efficiency models, including toilets, urinals, clothes washers, laundry to landscape graywater systems, high water-using landscapes, irrigation hardware, commercial food service and other process equipment. 54 Through SCVWD, the City has been offering the “Water Wise House Call” program that provides free site surveys to customers in both single‐family and multi‐family dwellings. The survey includes a review of customer water use history, water meter check for leak detection assistance, and thorough evaluation of indoor and outdoor water use. A technician provides each customer with free low‐flow showerheads, faucet aerators, toilet dye tablets, and/or toilet flappers when needed. The landscape survey includes an evaluation of the entire irrigation system, catch‐can test for irrigation distribution uniformity, and site‐specific recommendations including changes to the irrigation schedule. The Landscape Rebate Program (LRP) provides rebates for various irrigation hardware upgrades, including rain sensors, high efficiency nozzles, dedicated landscape meters, and weather-based irrigation controllers, as well as for converting high water-using landscapes (turf grass, pools) to a low water-using landscape. In response to the severe drought conditions, in 2014 the City and SCVWD doubled the rebate amounts customers could receive for a limited time period. This resulted in a significant increase in the number of LRP applications during FY 2015. The total square feet of turf grass removed through the LRP program in FY 2015 was more than ten times the area of grass replaced during the previous year. Home Water Report Program Beginning late 2013, the City began delivering quarterly Home Water Reports to single family households in Palo Alto. Approximately 13,000 residential customers received the reports. The Home Water Report compares a household’s water usage to neighbors with similar lot sizes, landscape area, and family demographics. The reports rank a household for how water efficient it is compared to homes with similar demographics, in an attempt to encourage more water efficient behaviors and participation in conservation programs. Annual water savings from this program are estimated at approximately 1.9% for households receiving the reports. The Home Water Report program ended in 2015. However, Palo Alto plans to re-launch a similar program in 2016. Water Conservation Coordinator The City has maintained a full-time Water Conservation Coordinator position for more than 20 years and expects to maintain the position indefinitely. Duties of the Water Conservation Coordinator includes water conservation program planning, implementation and management, reporting on California Urban Water Conservation Council’s Best Management Practices (BMP) implementation, and representing Palo Alto at various water conservation committees and meetings. Water Waste Coordinator In response to the drought in late 2014, the City created a part -time Water Waste Coordinator position. The Water Waste Coordinator performs a wide range of functions associated with the City’s drought response program, including investigating incidents of water waste, enforcing the City’s water use restrictions, and responding to customer inquiries about drought regulations and water conservation programs. 55 Other Demand Management Measures Landscape Survey and Water Budget Program Through SCVWD, the City offers a program that provides landscape irrigation surveys, water budgets and customized water usage reports for customers with large landscape sites. The water budget for each landscape site is calculated based on the area of irrigated landscape, type of plants, irrigation system and real-time weather monitoring. Monthly reports documenting a site’s irrigation performance are distributed to site managers, landscapers, homeowners association board members and other relevant parties, as approved by utility account holders. Through a web portal, customers can access site -specific recommendations, view trends in water use, verify water budget assumptions and request a free landscape field survey from an irrigation expert. This program has been in place since 2012 and to date, there are 132 large landscape sites covered under this program. Real-time Water Use Monitoring Pilot for Commercial Customers In 2012, the City implemented a real-time water use monitoring pilot with selected large commercial customers to actively engage them in reducing water usage and water losses. The pilot deploys a simple, relatively low cost technology that enables standard water meters to track real-time consumption, similar to an advanced water meter. A wireless device attached to the water meter transmits real-time data to a cloud-based software platform. Customers securely log into a web portal to view water usage on a minute by minute interval, identify water leaks or other anomalies in water use, and address these issues before they become maintenance or billing problems. Over a two-year period, the total water use among pilot participants was reduced by approximately 8%. Through grant funding from SCVWD, the City will launch a larger real-time water use monitoring pilot covering 100 city facility meters and 24 business customer sites. Pilot customers will be able to access real-time water consumption data through wireless sensors installed on the water meters. The pilot is expected to launch in early 2016 and will run for two years. Business Water Reports Pilot Program Through grant funding from SCVWD, the City will launch a Business Water Reports pilot to engage small to medium sized businesses in the hospitality and food service industries to actively manage their water use. The format and content of the report may vary slightly for customers in the hospitality versus food service sectors. The key objectives of the Business Water Reports are to communicate water use and potential ways to reduce water consumption, and to motivate behavior change for improved water use efficiency. The pilot is expected to launch in early 2016 and will run for two years. 56 Section 6 – Water Supply Reliability Law 10631 (c) (1) Describe the reliability of the water supply and vulnerability to seasonal or climatic shortage, to the extent practicable. Provide data for each of the following: (A) An average water year, (B) A single dry water year, (C) Multiple dry water years. (2) For any water source that may not be available at a consistent level of use, given specific legal, environmental, water quality, or climatic factors, describe plans to replace that source with alternative sources or water demand management measures, to the extent practicable. 10632. (a) The plan shall provide an urban water shortage contingency analysis that includes each of the following elements that are within the authority of the urban water supplier: (2) An estimate of the minimum water supply available during each of the next three water years based on the driest three‐year historic sequence for the agency's water supply. 10631 (g) Include a description of all water supply projects and water supply programs that may be undertaken by the urban water supplier to meet the total projected water use , as established pursuant to subdivision (a) of Section 10635. The urban water supplier shall include a detailed description of expected future projects and programs that the urban water supplier may implement to increase the amount of the water supply available to the urban water supplier in average, single-dry, and multiple-dry water years. The description shall identify specific projects and include a description of the increase in water supply that is expected to be available from each project. The description shall include an estimate with regard to the implementation timeline for each project or program. Water Supply Reliability The weather‐related reliability of the City’s water supply is very dependent upon the reliability of SFPUC’s regional water supply system. The SFPUC defines reliability by the amount and frequency of water delivery reductions (deficiencies) required to balance customer demands with available supplies in droughts. The SFPUC plans its water deliveries anticipating that a drought worse than the worst drought yet experienced may occur. This section discusses these potential system‐wide deficiencies. The SFPUC’s Hetch Hetchy supply is vulnerable to periodic, short‐term outages. Due to the fact that Hetch Hetchy water is not filtered, it is subject to strict water quality standards set by the State Water Board. As a result of weather events, turbidity levels can exceed standards requiring the Hetch Hetchy supply to be shut off until levels drop to within standards. Hetch Hetchy supply outages can last a week or longer. During these periods, the entire SFPUC supply comes from the Sunol Valley Water Treatment Plant and the Harry Tracy Water Treatment Plant, both of which are supplied by local reservoirs. 57 The City, working in cooperation with SFPUC and BAWSCA, completed several studies and reports analyzing weather‐ and climate‐related reliability of the water supply. Several of these are described in previous sections of this UWMP, including the following: Water Wells, Regional Storage and Distribution System Study (1999) – This study examined the ability of the City’s water system to supply water during an 8‐hour disruption of SFPUC supply. The study concluded the City should invest in certain capital projects. These projects became part of the City’s Emergency Water Supply and Storage Project, which is currently under construction. The Water Supply Master Plan (2000) – The WSMP was a joint study by BAWSCA and the SFPUC to address the future water supply needs of the 30 agencies and 2.3 million people who are served via the SFPUC water system. The City was actively involved in the development of this plan, participating on the WSMP Steering Committee. This plan is further described below. Alternative Emergency Water Supply Options Study (2001) – This study examined the ability of the City’s distribution system to supply water during various lengths of supply disruption (e.g., 1 day, 3‐days, 30 days) and included an analysis of the vulnerability of the City’s water distribution system. The study concluded that the capital projects in the Emergency Water Supply and Storage Project, specif ically related to groundwater wells, would result in the ability to supply sufficient water in disruptions of SFPUC supply. City of Palo Alto Emergency Water Supply and Storage Project Final Environmental Impact Report (2007) – The City completed construction of a 2.5 million gallon underground water reservoir and pump station in Palo Alto to meet emergency water supply and storage needs. In addition three new emergency supply wells were competed and five existing wells and the existing Mayfield Pump Station were upgraded. Frequency and Magnitude of Supply Deficiencies The City experienced severe droughts during 1976‐77 and 1987‐93. In response to these droughts the City adopted a number of water conservation strategies. In 2015, although the SFPUC system supply conditions only warranted a 10% voluntary reduction request by the SFPUC, the state-mandated 24% reduction in potable water use spurred an aggressive water conservation public outreach campaign. Full descriptions of the City’s water conservation programs are included in Section 5, “Demand Management Measures”. The magnitude of future supply deficiencies is difficult to estimate. The total amount of water the SFPUC has available to deliver during a defined period of time is dependent on several factors which generally include a comparison of: 1) the amount of water that is available to the SFPUC system from natural runoff and reservoir storage; and 2) the amount of that water that 58 must be released from the SFPUC’s system for commitments to purposes other than customer deliveries (e.g., releases below Hetch Hetchy reservoirs to meet Raker Act and fishery purposes). The 1987‐93 drought profoundly highlighted the deficit between SFPUC’s water supplies and the demands on the SFPUC system. Based on the 1987‐93 drought experience, the SFPUC assumes its “firm” capability to be the amount the system can be expected to deliver during historically experienced drought periods. In estimating this firm capability, the SFPUC assumes the potential recurrence of a drought such as occurred during 1987‐93, plus an additional 18 months of limited water availability. The SFPUC used this “design drought” to develop the level of service goals for the Water System Improvement Program (WSIP) of meeting at least 80% of customer demands during periods of water shortage. Reliability of the Regional Water System The SFPUC’s WSIP provides goals and objectives to improve the delivery reliability of the RWS, including water supply reliability. The goals and objectives of the WSIP related to water supply are: Program Goal System Performance Objective Water Supply – meet customer water needs in non- drought and drought periods Meet average annual water demand of 265 MGD from the SFPUC watersheds for retail and wholesale customers during non-drought years for system demands through 2018. Meet dry-year delivery needs through 2018 while limiting rationing to a maximum 20 percent system-wide reduction in water service during extended droughts. Diversify water supply options during non-drought and drought periods. Improve use of new water sources and drought management, including groundwater, recycled water, conservation, and transfers. The adopted WSIP had several water supply elements to address the WSIP water supply goals and objectives. The following provides the water supply elements for all year types and the dry-year projects of the adopted WSIP to augment all year type water supplies during drought. Water Supply – All Year Types The SFPUC historically has met demand in its service area in all year types from its watersheds, which consist of: Tuolumne River watershed Alameda Creek watershed San Mateo County watersheds In general, 85% of the supply comes from the Tuolumne River through Hetch Hetchy Reservoir and the remaining 15% comes from the local watersheds through the San Antonio, Calaveras, 59 Crystal Springs, Pilarcitos and San Andreas Reservoirs. The adopted WSIP retains this mix of water supply for all year types. Water Supply – Dry-Year Types The adopted WSIP includes the following water supply projects to meet dry -year demands with no greater than 20% system-wide rationing in any one year: Calaveras Dam Replacement Project: Calaveras Dam is located near a seismically active fault zone and was determined to be seismically vulnerable. To address this vulnerability, the SFPUC is constructing a new dam of equal height downstream of the existing dam. The project EIR was certified by the San Francisco City Planning Commission in 2011, and construction is now ongoing. Construction of the new dam is slated for completion in 2018; the entire project should be completed in 2019. Alameda Creek Recapture Project: The Alameda Creek Recapture Project will recapture the water system yield lost due to instream flow releases at Calaveras Reservoir or bypassed around the Alameda Creek Diversion Dam and return this yield to the RWS through facilities in the Sunol Valley. Water that naturally infiltrates from Alameda Creek will be recaptured into an existing quarry pond known as SMP (Surface Mining Permit)-24 Pond F2. The project will be designed to allow the recaptured water to be pumped to the Sunol Valley Water Treatment Plant or to San Anton io Reservoir. The project’s Draft EIR will be released in the spring of 2016, and construction will occur from spring 2017 to fall 2018. Lower Crystal Springs Dam Improvements: The Lower Crystal Springs Dam Improvements were substantially completed in November 2011. While the project has been completed, permitting issues for reservoir operation have become significant. While the reservoir elevation was lowered due to Division of Safety of Dams restrictions, the habitat for the Fountain Thistle, an endangered plant, followed the lowered reservoir elevation. Raising the reservoir elevation now requires that new plant populations be restored incrementally before the reservoir elevation is raised. The result is that it may be several years before the original reservoir elevation can be restored. Regional Groundwater Storage and Recovery Project: The Groundwater Storage and Recovery Project is a strategic partnership between SFPUC and three San Mateo County agencies: the California Water Service Company (serving South San Francisco and Colma), the City of Daly City, and the City of San Bruno. The project seeks to balance the management of groundwater and surface water resources in a way that safeguards supplies during times of drought. During years of normal or heavy rainfall, the project would provide additional surface water to the partner agencies in San Mateo County, allowing them to reduce the amount of groundwater that they pump from the South Westside Groundwater Basin. Over time, the reduced pumping wou ld allow the aquifer to recharge and result in increased groundwater storage of up to 20 billion gallons. The project’s Final EIR was certified in August 2014, and the project also received Commission approval that month. The well station construction contract Notice to 60 Proceed was issued in April 2015, and construction is expected to be completed in spring 2018. 2 MGD Dry-year Water Transfer In 2012, the dry-year transfer was proposed between the Modesto Irrigation District and the SFPUC. Negotiations were terminated because an agreement could not be reached. Subsequently, the SFPUC is having ongoing discussions with the Oakdale Irrigation District for a one-year transfer agreement with the SFPUC for 2 MGD (2,240 acre-feet). In order to achieve its target of meeting at least 80% of its customer demand during droughts at 265 MGD, the SFPUC must successfully implement the dry-year water supply projects included in the WSIP. Furthermore, the permitting obligations for the Calaveras Dam Replacement Project and the Lower Crystal Springs Dam Improvements include a combined commitment of 12.8 MGD for instream flows on average. When this is reduced for an assumed Alameda Creek Recapture Project recovery of 9.3 MGD, the net loss of water supply is 3.5 MGD. The SFPUC’s participation in regional water supply reliability efforts, such as the Bay Area Regional Desalination Project, additional water transfers, and other projects may help to make up for this shortfall. Projected SFPUC Regional Water System Supply Reliability The SFPUC has provided the data in the table in Appendix I presenting the projected RWS supply reliability. This table assumes that the wholesale customers purchase 184 MGD from the RWS through 2040 and the implementation of the dry-year water supply projects included in the WSIP. The numbers represent the wholesale share of available supply during historical year types per the Tier One Water Shortage Allocation Plan. This table does not reflect any potential impact to RWS yield from the additional fishery flows required as part of Calaveras Dam Replacement Project and the Lower Crystal Springs Dam Improvements Project. Impact of Recent SFPUC Actions on Dry-Year Reliability As noted earlier, in adopting the Calaveras Dam Replacement Project and the Lower Crystal Springs Dam Improvements Project, the SFPUC committed to providing fishery flows below Calaveras Dam and Lower Crystal Springs Dam, as well as bypass flows below Alameda Creek Diversion Dam. The fishery flow schedules for Alameda Creek and San Mateo Creek represent a potential decrease in available water supply of an average annual 9.3 MGD and 3.5 MGD, respectively with a total of 12.8 MGD average annually. The Alameda Creek Recapture Project, described above, will replace the 9.3 MGD of supply lost to Alameda Creek fishery flows. Therefore, the remaining 3.5 MGD of fishery flows for San Mateo Creek will potentially create a shortfall in meeting the SFPUC demands of 265 MGD and slightly increase the SFPUC’s dry-year water supply needs. The adopted WSIP water supply objectives include (1) meeting a target delivery of 265 MGD through 2018 and (2) rationing at no greater than 20% system-wide in any one year of a 61 drought. As a result of the fishery flows, the SFPUC may not be able to meet these objectives between 2015 and 2018. Participation in the Bay Area Regional Desalination Project and additional water transfers, as described earlier, may help manage the water supply loss associated with the fishery flows. As a result of the Individual Supply Guarantees described above, the SFPUC has a responsibility to provide 184 MGD to its wholesale customers in perpetuity, regardless of demand. Therefore, the current projections for purchase requests through 2018 remain at 265 MGD, which includes wholesale and retail demand. However, in the last decade including the current drought, SFPUC deliveries have been below this level, as illustrated in the Table 20 below. Table 20: Water Deliveries in San Francisco Regional Water System Service Area 38 Fiscal Year Total Deliveries (MGD) 2005-06 247.5 2006-07 257.0 2007-08 254.1 2008-09 243.4 2009-10 225.2 2010-11 219.9 2011-12 220.5 2012-13 223.9 2013-14 222.3 2014-15 196.0 Under the current drought and as of January 31, 2016 , the SFPUC has called for, but has not mandated, a 10% system-wide reduction since January 2014. The SFPUC has not yet been compelled to declare a water shortage emergency and impose mandatory system-wide rationing because its customers have exceeded the 10% voluntary system-wide reduction in conjunction with the state-wide mandatory reductions assigned by the State Water Resources Control Board. If current drought conditions worsen between 2015 and 2018, and the SFPUC determines that system-wide rationing would need to be imposed, then the SFPUC would issue a declaration of a water shortage emergency in accordance with Water Code Section 350 and implement rationing in accordance with the WSA and WSAP as described above. Climate Change The issue of climate change has become an important factor in water resources planning in the State, and is frequently considered in urban water management planning purposes, though the extent and precise effects of climate change remain uncertain. There is convincing evidence that increasing concentrations of greenhouse gasses have caused , and will continue to cause, a rise in temperatures around the world, which will result in a wide range of changes in climate 38 Reference: SFPUC FY 9-10 and FY 2014-15 J-Tables Line 9 “Total System Usage” plus 0.7 MGD for Lawrence Livermore National Laboratory use and 0.4 MGD for Groveland. No groundwater use is included in this number. Non-revenue water is included. 62 patterns. Moreover, observational data show that a warming trend occurred during the latter part of the 20th century and virtually all projections indicate this will continue through the 21st century. These changes will have a direct effect on water resources in California, and numerous studies have been conducted to determine the potential impacts to water resources. Based on these studies, climate change could result in the following types of water resource impacts, including impacts on the watersheds in the Bay Area: Reductions in the average annual snowpack due to a rise in the snowline and a shallower snowpack in the low and medium elevation zones, such as in the Tuolumne River basin, and a shift in snowmelt runoff to earlier in the year; Changes in the timing, intensity and variability of precipitation, and an increased amount of precipitation falling as rain instead of as snow; Long-term changes in watershed vegetation and increased incidence of wildfires that could affect water quality and quantity; Sea level rise and an increase in saltwater intrusion; Increased water temperatures with accompanying potential adverse effects on some fisheries and water quality; Increases in evaporation and concomitant increased irrigation need; and Changes in urban and agricultural water demand. Both the SFPUC and BAWSCA participated in the 2013 update of the Bay Area Integrated Regional Water Management Plan (BAIRWMP), which includes an assessment of the potential climate change vulnerabilities of the region’s water resources and identifies climate change adaptation strategies. In addition, the SFPUC continues to study the effect of climate change on the Regional Water System (RWS). These works are summarized below. Bay Area Integrated Regional Water Management Plan Climate change adaptation was established as an overarching theme for the 2013 BAIRWMP update. As stated in the BAIRWMP, identification of watershed characteristics that could potentially be vulnerable to future climate change is the first step in assessing vulnerabilities of water resources in the Bay Area Region (Region). Vulnerability is defined as the degree to which a system is exposed to, susceptible to, and able to cope with or adjust to, the adverse effects of climate change. A vulnerability assessment was conducted in accordance with the Department of Water Resources’ (DWR’s) Climate Change Handbook for Regional Water Planning and using the most current science available for the Region. The vulnerability assessment, summarized in Table 21 below, provides the main water planning categories applicable to the Region and a general overview of the qualitative assessment of each category with respect to anticipated climate change impacts. 63 Table 21: Summary of BAIRWMP Climate Change Vulnerability Assessment Vulnerability Areas General Overview of Vulnerabilities Water Demand Urban and Agricultural Water Demand – Changes to hydrology in the Region as a result of climate change could lead to changes in total water demand and use patterns. Increased irrigation (outdoor landscape or agricultural) is anticipated to occur with temperature rise, increased evaporative losses due to warmer temperature, and a longer growing season. Water treatment and distribution systems are most vulnerable to increases in maximum day demand. Water Supply Imported Water – Imported water derived from the Sierra Nevada sources and Delta diversions provide 66 percent of the water resources available to the Region. Potential impacts on the availability of these sources resulting from climate change directly affect the amount of imported water supply delivered to the Region. Regional Surface Water – Although future projections suggest that small changes in total annual precipitation over the Region will not change much, there may be changes to when precipitation occurs with re ductions in the spring and more intense rainfall in the winter. Regional Groundwater – Changes in local hydrology could affect natural recharge to the local groundwater aquifers and the quantity of groundwater that could be pumped sustainably over the long-term in some areas. Decreased inflow from more flashy or more intense runoff, incre ased evaporative losses and warmer and shorter winter seasons can alter natural recharge of groundwater. Salinity intrusion into coastal groundwater aquifers due to sea - level rise could interfere with local groundwater uses. Furthermore, additional reductions in imported water supplies would lead to less imported water available for managed recharge of local groundwater basins and potentially more groundwater pumping in lieu of imported water availability. 64 Vulnerability Areas General Overview of Vulnerabilities Water Quality Imported Water – For sources derived from the Delta, sea-level rise could result in increases in chloride and bromide (a disinfection by-product (DBP) precursor that is also a component of sea water), potentially requiring changes in treatment for drinking water. Increased temperature could result in an increase in algal blooms, taste and odor events, and a general increase in DBP formation Regional Surface Water – Increased temperature could result in lower dissolved oxygen in streams and prolong thermocline stratification in lakes and reservoirs forming anoxic bottom conditions and algal blooms. Decrease in annual precipitation could result in higher concentrations of contaminants in streams during droughts or in association with flushing rain events. Increased wildfire risk and flashier or more intense storms could increase turbidity loads for water treatment. Regional Groundwater – Sea-level rise could result in increases in chlorides and bromide for some coastal groundwater basins in the Region. Water quality changes in imported water used for recharge could also impact groundwater quality. Sea-Level Rise Sea-level rise is additive to tidal range, storm surges, stream flows, and wind waves, which together will increase the potential for higher total water levels, overtopping, and erosion. Much of the bay shoreline is comprised of low-lying diked baylands which are already vulnerable to flooding. In addition to rising mean sea level, continued subsidence due to tectonic activity will increase the rate of relative sea-level rise. As sea-level rise increases, both the frequency and consequences of coastal storm events, and the cost of damage to the built and natural environment, will increase. Existing coastal armoring (including levees, breakwaters, and other structures) is likely to be insufficient to protect against projected sea-level rise. Crest elevations of structures will have to be raised or structures relocated to reduce hazards from higher total water levels and larger waves. Flooding Climate change projections are not sensitive enough to assess localized flooding, but the general expectation is that more intense storms would occur thereby leading to more frequent, longer and deeper flooding. Changes to precipitation regimes may increase flooding. Elevated Bay elevations due to sea-level rise will increase backwater effects exacerbating the effect of fluvial floods and storm drain backwater flooding. 65 Vulnerability Areas General Overview of Vulnerabilities Ecosystem and Habitat Changes in the seasonal patterns of temperature, precipitation, and fire due to climate change can dramatically alter ecosystems that provide habitats for California’s native species. These impacts can result in species loss, increased invasive species ranges, loss of ecosystem functions, and changes in vegetation growing ranges. Reduced rain and changes in the seasonal distribution of rainfall may alter timing of low flows in streams and rivers, which in turn would have consequences for aquatic ecosystems. Changes in rainfall patterns and air temperature may affect water temperatures, potentially affecting cold water aquatic species. Bay Area ecosystems and habitat provide important ecosystem services, such as: carbon storage, enhanced water supply and quality, flood protection, food and fiber production. Climate change is expected to substantially change several of these services. The region provides substantial aquatic and habitat-related recreational opportunities, including: fishing, wildlife viewing, an d wine industry tourism (a significant asset to the region) that may be at risk due to climate change effects. Hydropower Currently, several agencies in the Region produce or rely on hydropower produced outside of the Region for a portion of their power needs. As the hydropower is produced in the Sierra, there may be changes in the future in the timing and amount of energy produced due to changes in the timing and amount of runoff as a result of climate change. Some hydropower is also produced within the region and could also be affected by changes in the timing and amount of runoff. Source: 2013 Bay Area Integrated Regional Water Management Plan (BAIRWMP), Table 16 -3. SFPUC Climate Change Studies The SFPUC views assessment of the effects of climate change as an ongoing project requiring regular updating to reflect improvements in climate science, atmospheric/ocean modeling, and human response to the threat of greenhouse gas emissions. Climate chan ge research by the SFPUC began in 2009 and continues to be refined. In its 2012 report “Sensitivity of Upper Tuolumne River Flow to Climate Change Scenarios,” the SFPUC assessed the sensitivity of runoff into Hetch Hetchy Reservoir to a range of changes in temperature and precipitation due to climate change. 66 Key conclusions from the report include the following: With differing increases in temperature alone, the median annual runoff at Hetch Hetchy would decrease by 0.7-2.1 percent from present-day conditions by 2040 and by 2.6-10.2 percent from present-day by 2100. Adding differing decreases in precipitation on top of temperature increases, the median annual runoff at Hetch Hetchy would decrease by 7.6-8.6 percent from present-day conditions by 2040 and by 24.7-29.4 percent from present-day conditions by 2100. In critically dry years, these reductions in annual runoff at Hetch Hetchy would be significantly greater, with runoff decreasing up to 46.5 percent from present day conditions by 2100 utilizing the same climate change scenarios. In addition to the total change in runoff, there will be a shift in the annual distribution of runoff. Winter and early spring runoff would increase and late spring and summer runoff would decrease. Under all scenarios, snow accumulation would be reduced and snow would melt earlier in the spring, with significant reductions in maximum peak snow water equivalent under most scenarios. Currently, the SFPUC is planning to conduct a comprehensive assessment of the potential effects of climate change on water supply. The assessment will incorporate an investigation of new research on the current drought and is anticipated to be complet ed in late 2016 or early 2017. Plans to Assure a Reliable Water Supply The City has completed several studies and projects regarding water supply reliability. Of note, the City completed the Emergency Water Supply and Storage Project and certified the Project EIR for Phase 3 of the recycled water project. In addition, the City is continuing to evaluate other water supply alternatives as part of its ongoing Water Integrated Resource Plan (WIRP). This analysis will include the impact of long‐term water supply shortage on the total water supply. 67 Section 7 – Water Shortage Contingency Plan Law 10632. (a) The plan shall provide an urban water shortage contingency analysis that includes each of the following elements that are within the authority of the urban water supplier: (1) Stages of action to be undertaken by the urban water supplier in response to water supply shortages, including up to a 50 percent reduction in water supply, and an outline of specific water supply conditions that are applicable to each stage. 10632. (a) The plan shall provide an urban water shortage contingency analysis that includes each of the following elements that are within the authority of the urban water supplier: (3) Actions to be undertaken by the urban water supplier to prepare for, and implement during, a catastrophic interruption of water supplies including, but not limited to, a regional power outage, an earthquake, or other disaster. Background Except for recycled water, the City does not currently produce any of its own water supplies, but is dependent upon its suppliers. The City’s primary supplier is the SFPUC. The SFPUC is the only supplier in normal years. The City’s five older wells have been refurbished and the City completed construction of three new wells to remain in standby for use during emergencies and potentially to supplement the SFPUC supply during a severe drought. The SCVWD manages the county’s groundwater and levies a groundwater extraction fee for all water produced by the wells within its jurisdictions. The City has also approved and signed a mutual aid agreement for emergency water supplies with California’s Water Agency Response Network (Coastal group) that has over 75 signatories. To meet the requirements of the Urban Water Management Planning Act and for the purposes of this document, a distinction will be made between a catastrophic interruption of water supplies and a water shortage due to drought. A catastrophic interruption of water supplies may occur due to natural disaster such as an earthquake or due to a sudden problem with water quality, or because of sabotage or terrorism. A water shortage due to drought is the more likely occurrence. The City has experienced three drought water shortages in the past 35 years, in l976‐77, from l987 to l993, and the current ongoing drought. Catastrophic Interruption of Supply Regional System Reliability The City, through BAWSCA, was actively involved in the review of the SFPUC System Vulnerability Report. This study examined the vulnerability of the SFPUC system to catastrophic events (e.g., earthquakes). The study, released in January 2000, indicated that some areas in the regional system could be without water for up to 60 days. To address these deficiencies, the SFPUC developed the WSIP to repair and upgrade the regional system. The program, nearly 68 completed now, included projects to repair, replace and seismically upgrade the regional water system’s pipelines and tunnels, reservoirs and dams. Planning, Training and Exercise Following San Francisco’s experience with the 1989 Loma Prieta Earthquake, the SFPUC created a departmental SFPUC Emergency Operations Plan (EOP). The SFPUC EOP, originally released in 1992, has been updated on average every two years. The latest EOP revision was in 2012. The EOP addresses a broad range of potential emergency situations that may affect the SFPUC, and it supplements the City and County of San Francisco’s EOP, which was prepared by the Department of Emergency Management and last updated in 2007. Specifically, the purpose of the SFPUC EOP is to describe the SFPUC’s emergency management organization, roles and responsibilities and establish emergency policies and procedures. In addition, SFPUC divisions and bureaus have their own EOPs that are in alignment with the SFPUC EOP and describe their respective emergency management organization, roles and responsibilities and emergency policies and procedures. The SFPUC tests its emergency plans on a regular basis by conducting emergency exercises. Through these exercises the SFPUC learns how well the plans will or will not work in response to an emergency. Plan improvements are based on exercise and sometime real world event response and evaluation. Also, the SFPUC has an emergency response training plan that is based on federal, state and local standards and exercise and incident improvement plans. SFPUC employees have emergency training requirements that are based on their individual emergency response roles. Emergency Drinking Water Planning With respect to drinking water quality, several SFPUC plans are relevant including the: Cryptosporidium Detection action Plan Revised in 2008 Water Quality Notifications and Communications Plan revised in 2010 Water Contamination and Response and Consequence Management Plan revised in 2012 Regional Water System Emergency Disinfection and Recovery Plan revised in 2012 Water Supply and Treatment Division Emergency Operations Plan revised in 2013 Power Outage Preparedness and Response SFPUC’s water transmission system is primarily gravity fed, from the Hetch Hetchy Reservoir to the City and County of San Francisco. Within San Francisco’s in‐city distribution system, the key pump stations have generators in place and all others have connections in place that would allow portable generators to be used. Although water conveyance throughout the regional system would not be greatly impacted by power outages because it is gravity fed, the SFPUC has prepared for potential regional power outages as follows: The Tesla disinfection facility, the Sunol Valley Water Treatment Plant, and the San Antonio Pump Station, have backup power in place in the form of generators or diesel 69 powered pumps. Additionally, both the Sunol Treatment Plant and the San Antonio Pump Station would not be impacted by a failure of the regional power grid becau se it runs off of the SFPUC hydro‐power generated by the regional system Both the Harry Tracy Water Treatment Plant and the Baden Pump Station have backup generators in place. Additionally, the WSIP has expanded the SFPUC’s ability to remain in operation during power outages and other emergency situations. Capital Projects for Seismic Reliability and Overall System Reliability As described in Section 6, the SFPUC has undertaken the WSIP to enhance the ability of the SFPUC water supply system to meet identified service goals for water quality, seismic reliability, delivery reliability, and water supply. The WSIP also included projects related to standby power facilities at various locations. These projects provide for standby electrical power at six critical facilities to allow these facilities to remain in operation during power outages and other emergency situations. Local Distribution System Reliability The City has improved its emergency supply preparedness by rehabilitating five existing wells, drilling three new wells, and building an additional water storage reservoir. The well system can now support a minimum of eight hours of normal water use at the maximum day demand lev el and four hours of fire suppression at the design fire duration level. The City also maintains several critical interconnections with neighboring water utilities as shown in Table 22. These interties can be activated during critical events to ensure water supplies are not impacted and also to provide mutual aid to neighboring communities . Table 22: Interties with other Agencies Name Number Diameter (inches) East Palo Alto 1 6 Mountain 2 6 Stanford 2 8 Purissima Hills WD 2 8,12 Emergency Response Plan Response to a catastrophic interruption of supply is handled through a series of interconnected plans. All Disaster or Act of War Plans, from the state to local levels, use the Federal Civil Defense and Emergency Planning systems as role models with additions that take into consideration any unique conditions or situations that may exist within their jurisdictions. At the national level, the Federal Emergency Management Agency (FEMA) controls all functions of Civil Defense or Emergency Planning for the Federal Government. FEMA will not assume control of an emergency until the President declares a State of Emergency or an Act of War 70 occurs. At that point FEMA will assume control through the State of California Office of Emergency Services (State OES) and make available all of its resources. At the state level, the State OES will control any disaster within the state and make its resources available after a State of Disaster has been declared by the governor. The State OES further controls the Master Mutual Aid Agreement that can also be used in a local disaster (the City is a member of California’s Water Agency Response Network, Region 2, a mutual aid system for water utilities, in accordance with State requirements). At the county level, the Santa Clara County OES will control the unincorporated areas of the County. It will coordinate mutual aid within the County and act as an intermediary between local governments or utilities and the State mutual aid office. On the city level, the City will control all emergencies according to its Emergency Response Plan. The Mayor, City Council or City Manager may declare an emergency at which time representatives of all City departments will report to the Emergency Operations Center. The City’s Emergency Response Plan incorporates the CPAU Water, Gas and Wastewater Operations Emergency Response Plan (the UER Plan), which covers any emergency curtailment of water supplies. The UER Plan is a detailed outline of actions to be taken and procedures to be followed by utility personnel in event of a water emergency. This plan is maintained in the office of Water, Gas and Wastewater Operations and must be updated every 12 months. The UER Plan is designed as both an outline and a procedures manual. It covers the following primary functions: 1) Notification Procedures 2) Water Mutual Aid Agreement 3) Radio/Telephone /Communications 4) Water Receiving Station and Reservoir Check List 5) Boil Water Notifications 6) Highest Water Use Customer Load Reduction List 7) Water Interconnect Locations 8) Disinfecting of Water Mains All CPAU personnel whose duties include work on the system through maintenance or construction operations, or as Utilities Dispatchers, are highly trained and experienced in performing their normal or “common emergency” duties. If a disaster or Act of War were to occur, the City’s construction standards may have to be lowered to make temporary repairs to expedite the restoration of the system, but the procedures and safety rules by which the work would be accomplished will not change. These temporary repairs would be upgraded and made permanent or replaced, as necessary, at a later date. The City’s primary concern is the safety of the general public and all City personnel. 71 To that end, CPAU continues to maintain three diesel emergency generators in order to enhance the water system response reliability during a catastrophic seismic event causing severance from the City’s primary supply source, and is investigating additional purchases or leases. Lease acquisition of these emergency generators will fulfill this reliability goal for the medium- and the long‐term. At the same time, given the uncertainty of the future, acquisition through lease agreements for these emergency gen sets will reduce the City’s risk of generator inoperability. Generators would enable continued operation of water facilities during a transmission grid failure. Water Shortage Contingency Analysis Law 10632. (a) The plan shall provide an urban water shortage contingency analysis that includes each of the following elements that are within the authority of the urban water supplier: (4) Additional, mandatory prohibitions against specific water use practices during water shortages, including, but not limited to, prohibiting the use of potable water for street cleaning. (5) Consumption reduction methods in the most restrictive stages. Each urban water supplier may use any type of consumption reduction methods in its water shortage contingency analysis that would reduce water use, are appropriate for its area, and have the ability to achieve a water use reduction consistent with up to a 50 percent reduction in water supply. (6) Penalties or charges for excessive use, where applicable. 10632. (b) Commencing with the urban water management plan update due July 1, 2016, for purposes of developing the water shortage contingency analysis pursuant to subdivision (a), the urban water supplier shall analyze and define water features that are artificially supplied with water, including ponds, lakes, waterfalls, and fountains, separately from swimming pools and spas, as defined in subdivision (a) of Section 115921 of the Health and Safety Code. Palo Alto’s Experience with Drought Management The City has had considerable experience implementing action plans during a period of water shortage, such as a drought. The City has always been able to comply with any rationing requirement imposed by SFPUC. During the 1976/77 drought period, the City achieved reductions in citywide consumption of 16% in FY 1977 and 37% in FY 1978 compared to consumption in FY 1976. In the 1987‐1993 drought period, the City’s consumption was lower than consumption in 1987, the year just before SFPUC instituted mandatory rationing, by from 19% (in FY 1989) to over 35% (in FY 1992). In response to the voluntary 10% call for rationing in 2008‐2009, the City responded with reductions of approximately 18% relative to 2004 consumption. In 2015, the City responded to state-mandated potable water use reductions by implementing the water restrictions in Stage II of its WSCP. As of the end of January 2016, the City is on track to meet the 24% cumulative reduction target for the June 1, 2015 through October 31, 2016 compliance period compared to calendar year 2013. For the period June 1, 2015 through December 31, 2015, the City’s usage was 33% below usage during the same period in 2013. 72 During these periods of water shortage and state-mandated reductions, the community has responded exceedingly well to requests to use water in the most efficient way possible. As a result of experiencing these drought‐time water supply shortages, many residents and businesses have implemented permanent improvements in water use efficiency. During a water shortage period, the Director of Utilities is responsible for executing the Water Shortage Contingency Plan. Representatives from appropriate City Departments and Utilities Divisions would need to be involved to oversee outreach and monitoring efforts. Additional resources will need to be dedicated to this effort both for internal and external execution of the plan. A key element to developing water shortage contingency plans for the City is close coordination and cooperation with SFPUC, BAWSCA, and the SCVWD. It is critical to develop a coherent and coordinated regional response to water shortages in order to provide a consistent message to customers. Regional Interim Water Shortage Allocation Plan Tier One Drought Allocations In July 2009, as part of the WSA, the wholesale customers and San Francisco adopted a Water Shortage Allocation Plan (WSAP) to allocate water from the regional water system to retail and wholesale customers during system‐wide shortages of 20% or less (the “Tier One Plan”)39. The Tier One Plan allows for voluntary transfers of shortage allocations between the SFPUC and any wholesale customer and between wholesale customers themselves. In addition, water “banked” by a wholesale customer, through reductions in usage greater than required, may also be transferred. The Tier One Plan, which allocates water between San Francisco and the wholesale customers collectively, distributes water based on the level of shortage as shown in Table 23: Table 23: SFPUC and Wholesale Customer Share of Available Water Level of System Wide Reduction in Water Use Required Share of Available Water SFPUC Share Wholesale Customer Share 5% or less 35.5% 64.5% 6% through 10% 36.0% 64.0% 11% through 15% 37.0% 63.0% 16% through 20% 37.5% 62.5% The Tier One Plan will expire at the end of the term of the WSA on June 30, 2034, unless extended by San Francisco and the wholesale customers. 39 The previous water shortage allocation plan expired in 2009 with the termination of the previous Water Supply Agreement with the SFPUC. Details of the previous allocation plan are provided in the 2005 UWMP. 73 Tier Two Drought Allocations In 2010, the wholesale customers negotiated and adopted the Tier Two Drought Implementation Plan (Tier Two Plan), which allocates the collective wholesale customer share among each of the 26 wholesale customers. This Tier Two Plan allocation is based on a formula that takes into account multiple factors for each wholesale customer including: Individual Supply Guarantee; Seasonal use of all available water supplies; and Residential per capita use. The water supplies made available from the SFPUC will be allocated to the individ ual wholesale customers in proportion to each wholesale customer’s Allocation Basis, expressed in millions of gallons per day (MGD), which in turn is the weighted average of two components. The first component is the fixed wholesale customer’s Individual Supply Guarantee as stated in the WSA. The second component is the Base/Seasonal Component, which is variable and is calculated using each wholesale customers total monthly water use from all available water supplies during the three consecutive years prior to the onset of the drought. The second component is accorded twice the weight of the first component in calculating the Allocation Basis. Minor adjustments to the Allocation Basis are then made to ensure a minimum cutback level, a maximum cutback level, and a minimum level of supply to meet health and safety needs for certain wholesale customers. Each wholesale customer’s Allocation Factor, which represents its percentage allocation of the total available water supplies, is calculated from its proportionate share of the total of all wholesale customers’ Allocation Bases. The final shortage allocation for each wholesale customer is determined by multiplying the amount of water available to the wholesale customers’ collectively under the Tier One Plan, by the wholesale customer’s Allocation Factor. The Tier Two Plan requires that the Allocation Factors be calculated by BAWSCA each year in preparation for a potential water shortage emergency. As the wholesale customers change their water use characteristics (e.g., increases or decreases in SFPUC purchases and use of other water sources, changes in monthly water use patterns, or changes in residential per capita water use), the Allocation Factor for each wholesale customer will also change. For long-term planning purposes, each wholesale customer has been provided with the Tier Two Allocation Factors calculated by BAWSCA based upon the most recent normal year to determine its share of available RWS supplies. However, actual allocations to each wholesale customer during a future shortage event will be calculated in accordance with the Tier Two plan at the onset of the shortage. For long‐term planning purposes, the City is using the value identified in the Tier Two Plan adopted by the City Council, as calculated for FY 2013. Table 24 below illustrates how much water would be available to Palo Alto from the regional system under different reduction scenario’s using actual water demand from FY 2013. The Tier Two Plan will expire in 2018 unless extended by the wholesale customers. 74 Table 24: Palo Alto Share of Available SFPUC Water (AF/Y) Palo Alto’s Water Shortage Contingency Planning The City’s primary response to a water supply shortage will be to reduce consumption. The City’s Water Shortage Contingency Plan describes the response at four water supply shortage stages. (Water use restrictions discussed in these stages can be found in Appendix H). Stage I (5% to 10% supply reductions) calls for a low level of informational outreach and enforcement of the permanent water use ordinances. In Stage II (10% to 20%) there will be a stepped up outreach effort and the adoption of some additional water use restrictions. Drought rate schedules wi ll be implemented. Stage III (20% to 35%) calls for increased outreach activities and additional emergency water use restrictions. Drought rates in each block would increase from those in Stage II. Fines and penalties would be applied to users in violation of water usage restrictions. In some cases, water flow restriction devices would be installed on customers’ meters. Stage IV (35% to 50%) requires very close management of the available water supplies. Allocations of water for each customer will be introduced. Informational outreach activities would be operating at a very high level. Severe water use restrictions and a restrictive penalty schedule would be implemented. Water Shortage Mitigation Options Water shortage mitigation options can be classified un der two categories: Supply Side Options and Demand Side Options. This section provides descriptions of many different actions and activities that are possible in reaction to a water supply shortage situation. The City’s response to drought‐time shortages depends upon the severity of the shortage. Following this section, specific actions are outlined for the various stages of a potential shortage. Supply Side Options The City’s options to increase its short‐term water supply are limited. The City’s long‐term supply options are discussed in Section 3, “System Supplies.” The section below discusses short ‐ term alternatives to increase supply in the event of a water supply shortage. Year 1 Year 2 Year 3 System-wide Shortage 0%10%10%22%22% BAWSCA 163,429 170,934 170,934 144,722 144,722 City of Palo Alto 12,692 12,692 12,692 11,425 11,425 Availability of Water for Palo Alto 100%100%100%90%90% Allocations During Multiple Dry Years Demand (FY 2013) One Critical Dry Year Allocation 75 City Wells The status of the City’s emergency wells is discussed in the Groundwater area of Section 3, “System Supplies.” During a drought period, it would be possible to use some water from the wells to supplement the supply from the SFPUC. Recycled Water During a drought or a short‐term water emergency, recycled water would be available to the City, however, a wide distribution of recycled water would require substantial infrastructure that would be difficult to construct in a short period of time. The City or private companies with tanker trucks can obtain permits to utilize recycled water from the RWQCP. These companies can pick up recycled water and deliver it to customers who will pay for this service. During the summer of 2015, the City increased the use of water trucks to irrigate City trees on City -owned medians and several private companies utilized recycled water to deliver water to private citizens. Public awareness is enhanced by greater publicity of the availability of this alternative to customers. This recycled water is available except in a catastrophic disaster (severe earthquake) that severs all sources of water (SFPUC, wells and storage) to the system thereby eliminating the source of water to the RWQCP. However, in the event of a severe earthquake the delivery of recycled water will be a low priority. Water Purchases from Other Suppliers The City could conceivably purchase water from a new supplier in an extreme water supply shortage situation. However, any such purchase would have to be consistent with the requirements specified in the WSA40 and be coordinated with all other jurisdictions between the source and the City to ensure the supply meets deliverability requirements. The SFPUC has made such purchases of water from various suppliers in times of water shortages. The City and all other BAWSCA member agencies have received this water through the SFPUC delivery systems. It is unlikely that the City could negotiate a better deal than the SFPUC or BAWSCA in these extremely complicated arrangements, and therefore it is unlikely that the City would seek to purchase water on its own. The City is a participant in several regional efforts to evaluate and develop new supply sources, including purchasing water from other sources. The SFPUC system has several interties with adjacent water agencies, including EBMUD and the SCVWD. These interties could be used to “wheel” water that is purchased from other sources or agencies. Demand Side Options In droughts, the City expects to achieve significant amounts of demand reduction through its use of DMMs, as that term is used in the California Water Code. (See, for example, §§ 371, 10631.) These options include a combination of information outreach programs, drought rate schedules, demand side programs and water use restrictions. 40 WSA, Section 3.12 76 Defining Water Features The City owns and operates several un-metered water features including two recirculating fountains and one recreational water feature that was turned off in 2015. In addition, Baronda Lake, which uses about 250 AF over the 5 month period from mid-May through mid-October, is used for recreation and education and is habitat for several species of fish, other aquatic life and birds. The lake is also a water source for many different types of mammals. A small number of commercial customers have recirculating fountains. In the proposed and attached Water Use Restrictions ordinance, non-recirculating fountains are prohibited. The City is not aware of any non-recirculating, privately-owned water features. Demand Side Management Programs: Demand side management programs can be offered using many different program design options and delivery mechanisms. Some examples are listed below. Home Water Use Reports Home Water Reports will be used to encourage customers to save water. The Home Water Report compares a household’s water usage to neighbors with similar lot sizes, landscape area, and family demographics. The reports rank a household for how water efficient it is compared to homes with similar demographics, in an attempt to encourage more water efficient behaviors and participation in conservation programs. Information Outreach Programs Customers will be provided with information on ways to achieve needed water use reductions. The City will communicate to the customers how best to prioritize their water use needs and how to implement alternative ways to receive the same level of service while using less water. Information and public outreach programs include utility bill inserts, information on CPAU’s website, local print media campaigns, commercial targeted mailings, workshops and demonstrations, fact sheets on conservation technologies and practices, and coordination with product manufacturers and suppliers. Incentive‐based Demand Side Management Programs In a persistent water shortage or required water use reduction, most customers will take the quick and easy actions first. More complex and expensive incentive programs to provide demand side management may be needed to achieve additional results. Although incentive programs require time to develop and promote, significant water savings can be achieved. Depending upon market saturation, some programs such as delivery of relatively inexpensive hardware (e.g. low‐flow faucet aerators and showerheads) and services such as leak detection and irrigation system audits can offer quick drought ‐time savings. Other programs may include a toilet rebate program or incentives to replace high water use landscapes with water efficient landscape designs and installation of efficient irrigation hardware. 77 Customer Water Use Audit Programs Water audits are provided as an informational service to customers and typically include an individualized, one‐on‐one analysis and site‐specific recommendations for both indoor and outdoor water efficiency improvements. Audits can be enhanced by the delivery of relevant, action‐oriented information the customer can use to change behavioral practices or participate in additional audit or rebate programs. In a water emergency or shortage, additional staff may be needed to provide water audits, rebate program administration, and outreach assistance to residential and commercial customers. Drought Rate Schedules Pricing is one of the most powerful tools that a utility can use to promote its conservation goals. The overarching criteria for constitutionally compliant water rate structures—for use in droughts or not—is that all rates must be based on the cost to serve customers. Both tiered water rates and volumetric-based rates can provide an incentive to conserve. CPAU has had tiered water rates for some time, and the bulk of water revenues are from volumetric rates and not the fixed monthly meter charge. This rate design encourages efficient use of water whether in a drought or not. However, when water use declines in droughts, revenue recovery may become a problem. In September 2015, drought surcharges were developed so that, upon Council action, additional charges could be applied to ensure the financial health of the Water Fund. The drought surcharges were imposed effective September 1, 2015 to recover (via a tiered volumetric charge) the cost of operating the distribution system. Other Potential Rate Schedules and Structures Customer Class Targets In many water shortage situations, no rationing of water is required – ample communication of the water shortage coupled with drought surcharges, if needed, have been sufficient to meet the City’s water reduction targets in the prior and current drought. If rationing of water is required to meet a water reduction requirement in a drought, customer class targets should mirror the required indoor/outdoor water reduction goals that may be established during a drought. Whether there will be different rate schedules (consistent with the cost of service requirement) for each customer class will be determined by: (a) the severity of the water shortage, and (b) the capabilities and limitations of the utility billing system. Experience has shown that separating the single‐ family residential customers—which are more homogeneous than any other customer group—from all other customer groups is generally the only distinction needed. Allocation Methods Any allocation plan would take into consideration the criteria listed in Appendix G. These criteria will be a guide to selecting the most efficient and effective water use reduction method under the particular circumstances of a specific drought situation. 1. Allocations Based on Percentage of Past Use Plans that base a customer’s allocation on a percentage of past use are sometimes perceived as fair and easy to administer. However, these plans have three significant shortcomings. First, 78 selection of a base year is problematic. There have been two water shortage periods in the City since l976. It would be difficult to pick a base year unaffected by shortage year programs on the one hand, or gradually increasing water use after a drought (the “rebound effect”) on the other. The second problem is that each year the turnover of new accounts is approximately 20 to 30% (mostly multi‐family residents). In addition, many businesses have changed their practices to some extent over the years. Therefore to use this plan in 2015 and beyond would mean that a large percentage of water customers would have an allocation based on a previous occupant’s usage, a previous operation, or some alternative situation. Handling the large volume of such cases can create administrative difficulties and perceptions of inequities as revised or new allocations are assigned to these customers. The third major flaw in the “percent of past use” concept is that, regardless of base year selected, historically conservation‐minded customers may feel penalized for their past efforts while profligate users may have too large an allocation. 2. Equal Allocation for Each Home (for single‐family residential) This plan would set an identical allocation for each home designed to meet the target reduction for the class. The first tier in the rate structure41 would be set at this target amount. The second tier would be a “buffer” tier designed to accommodate seasonal water needs. The third and last tier would be a penalty rate block price considerably higher than the first two tiers. All homes would be treated the same under this plan. In addition, it would be inexpensive to administer and easy to understand and implement. However, it could be perceived as unfair by relatively large families or customers with large lots. Under this plan, hardship exemptions would be limited to those who require more water for health or safety reasons. No additional allowances would be provided for the number of persons living in the household or the landscaping requirements of the particular size lot. Enforcement of this plan would involve installing a flow restrictor on those customers who continue to exceed the allotment beyond a two‐month period. 3. Complete Per Capita Allocation Plan (for single‐family residential) Under this plan each person would be allocated a certain amount of water per month. In addition, each household would be allotted a certain amount of water per month for other essential needs, including a base minimum amount for outdoor watering of shrubs and trees. Per capita information would be based on information supplied by the customers through a special mailing. The strength of this plan is that it would probably be more acceptable to the community than the equal allotment per household plan because it takes into account the relationship between water usage and the number of persons living in a household. Its weaknesses are the inability of the current Utilities billing system to record or manage “per capita” data and verification of per capita information. 41 Any rate design must be consistent with “cost of service” principles embedded within the California constitution. 79 4. Default Per Capita Allocation Plan (for single‐family residential) Under this plan each household would receive an allocation sufficient for families of a default size. For households over that size, an additional amount would be allocated per month for the number of people over the default size. This plan is easier to administer than a complete per capita plan since the number of data entries is significantly reduced. The plan’s weakness is its lack of detail or fine‐tuning for households under the default size, which may be perceived as unfair by larger households. Mandatory Water Rationing Plans Applicable to Multi‐Family Accounts, Business, and City Departments Due to the differences between customer classes, it is difficult to construct rationing plans that meet all the criteria listed in Appendix G. During the 1987‐1993 drought period, the City introduced Baseline Consumption Allowances (BCAs) for all customer classes except single‐ family residential accounts. This includes multi‐family residential, commercial, industrial, institutional, and city facilities accounts. The BCA was intended to represent the indoor consumption of each customer. It is important for any allocation plan to take into account the specific needs of these customer classes because of their diversity and unique requirements. The BCA does this. Rate structures using the BCAs can be constructed as appropriate to meet the reduction targets required and to provide the economic incentive necessary to prompt customer action. And, the targets and the associated rate block prices could be changed as the reduction requirement changes. Weaknesses of this method are that it may not accurately represent indoor water use. For example, exemptions would have to be considered for customers with cooling towers, since lack of water for cooling towers would effectively end the customers’ ability to cool their building interiors, resulting in possible health and safety impacts of employees. Another alternative in extreme cases (Stage 3 or higher) could be an allocation per fixture plus a cooling tower credit, which is similar to the per capita method for residences. Excessive Use Penalties for All Allocation Methods Penalties for excessive use are expected to vary according to the customer class. For single ‐ family residential customers exceeding percent‐of‐past‐use, equal‐allocation‐per‐home, or per capita water use, the penalty could be installation of a flow restrictor when usage continued to exceed the allocation beyond a 2‐month period. Enforcement of this penalty would only occur after customers were notified and any reasonable appeals had been processed. For customers under a BCA (all classes except single family residential), the primary penalty is in the rate structure itself. Water Use Prohibitions, Mandatory Restrictions Adopting water use restrictions is another way to manage how customers use a limited resource. Restrictions can be classified as those preventing water waste, those “setting a tone”, and those that prohibit low priority use in times of severe shortages. 80 In the case of a system-wide water shortage, close coordination with SFPUC is necessary. One of the considerations for selecting which water use restriction ordinances to adopt is what the City’s suppliers recommend for the region. Both the SFPUC and SCVWD provide recommendations, and the City will attempt to follow those recommendations so that regional consistency is achieved. The City’s ability to enforce restrictions is also a critical variable in the selection of water use regulations. For restrictions to be credible and obeyed they must be enforceable and enforced. Therefore certain restrictions, such as limits on indoor uses such as showering, are not practical. Water use restrictions are achieved by using the methods, prohib itions and penalties described in the sections below. Appendix H lists permanent water use restrictions that the City currently has in place and is proposing to put in place, and those that may be adopted on an emergency basis in times of state-mandated reductions or water shortage42. Stages of Action Actions to be taken in response to a water shortage or state-mandated reduction depend on the severity of the shortage or the magnitude of the required reduction. The staged responses (Stage I to Stage IV) depend to some extent upon the local conditions and the length of time that customers have had to focus their attention on the water shortage. For each stage noted below, activity levels in several key areas are described. Appendix H, the Water Shortage Contingency Plan, details the planned water use restrictions for each reduction level. Reduction targets will be based on the most recent non‐drought year. If a different base year were to be selected, the programs might require modification. In all stages, action will be taken to ensure City facility water use is reduced by the appropriate amount. Some factors which influence the effectiveness of any water management plan include: (1) the customer’s behavior and perception of the need to conserve; (2) weather; (3) the duration of the shortage or mandate; (4) the customer’s economic situation; (5) the extent to which the City achieves its utility revenue targets; (6) the percentage of exemptions or variances granted; (7) the role of the media; and (8) the customer’s acceptance of the need for water use reduction. Because each water shortage situation is unique in duration, in breadth and in involvement by the state, there is a need for some flexibility in selecting the exact response strategy. Even with the same reduction target, the strategy in the first year of a drought may be different than that 42 Section 12.32.015 of the Palo Alto Municipal Code, pertaining to emergency water use regulations, previously codified and containing portions of Ordinance Nos. 3960, 3984 and 4038, was suspended, but specifically not repealed, by Ordinance No. 4150, § 2. In pertinent part, Section 2 of Ordinance No. 4150 states that Section 12.32.015 is "suspended until such time as water shortage emergency conditions shall be subsequently found, determined, and declared by the Council to exist." 81 recommended for an additional year of a long running drought. It is very important early in a drought period to develop outreach messages and policy directions using a longer‐term perspective. In this way, communications with customers throughout the drough t period will be consistent and appropriate. STAGE I: Minimum Water Shortage – 5% to 10% target water savings The SFPUC requested voluntary reductions in this range in 1987, 2009, and 2014 which the City was able to achieve. In those years, SFPUC did not impose rationing. Information Outreach and Audit Programs The City provides ongoing informational outreach and audit programs. At this water shortage stage, the focus of these programs would be on water saving information. A low level media information campaign would begin with the emphasis on reducing waste. As water consumption is monitored, the level of emphasis would be adjusted in order to meet the reduction goal. The City has permanent ordinances in place that prohibit the waste of water and additional permanent water use restrictions are proposed to Council via ordinance on a timeline parallel with the UWMP. These ordinances are sufficient for this stage of water shortage. Enforcement would be on an “as reported” basis and mostly via reminder notice s. Incentive‐based Demand Side Management Programs Programs designed to assist customers in demand side management would be continued and augmented, to the extent necessary to provide the savings required. These programs may include a toilet rebate program or incentives to remove lawn turf for less water‐thirsty landscaping or to install advanced irrigation controllers. The City would continue to monitor programs being developed by other utilities in order to take advantage of regional momentum and shorten internal development time. Drought Rate Structures No special drought rate structure is needed at this water shortage stage. The City’s standard single‐family rate structure already encourages conservation by having a relatively small fixed charge and tiered rates. STAGE II: Moderate Water Shortage – 10% to 20% target water savings The City was able to achieve this level of water reduction (19.1%) when rationing was imposed by the SFPUC in FY 1989. The program used at that time is basically the one outlined below. Information Outreach and Audit Programs The frequency of advertising and events comprising the information campaign would be increased. Water kits with low‐cost conservation devices will be available to customers. 82 Incentive‐based Demand Side Management Programs Programs designed to assist customers in demand side management would be continued and augmented to the extent necessary to provide the savings required. These programs may include incentives for replacing high water using fixtures such as toilets, clothes washers, and irrigation devices, as well as incentives to retrofit landscapes for a low water use, drought tolerant design. The City would continue to monitor programs being developed by other utilities in order to take advantage of regional momentum and shorten internal development time. Drought Rate Structures In response to water shortage conditions in the 1987-1992 drought, the City established separate drought rate schedules for single‐family residential and all other customers and increased the price difference between lower and higher consumption tiers. For all customers except single‐ family residential customers, the consumption tiers were based on a Baseline Consumption Allowance (BCA) concept. This concept is described in the section, Water Shortage Mitigation Options, as applicable to multi‐family, commercial, industrial, public facilities and City facilities accounts. Water Use Restrictions The City would be more vigilant in enforcing the water use restrictions. A system of warning s leading to possible fines and installation of a flow restrictor would be followed. During the summer of 2015, the City developed a mobile application (311) for members of the community to report wasted water. This technology allowed for much wider enforcement by City staff. A small number of emergency water use restrictions would be added. STAGE III: Severe Water Shortage – 20% to 35% target water savings The City achieved usage reductions of 31.5%, 35.4%, and 32.7% in FY 1991, FY 1992, and FY 1993, respectively, in response to SFPUC water rationing. The City is on track to exceed the 24% reduction target for the 2015/2016 state-mandated compliance period. The water conservation program implemented included the following major components: Information Outreach and Audit Programs All activities from Stage II would continue at escalated levels. In addition, emphasis would be put on targeted outreach to high water users and special categories of water users (e.g., car washes, restaurants, etc.). Incentive‐based Demand Side Management Programs Existing demand side management programs would be continued. Staff would continue to closely monitor overall water savings in order to determine if additional levels of rebate amounts would provide additional savings, or whether other programs would be necessary. Drought Rate Structures To achieve these reduction goals in past droughts, rationing was not implemented. Instead, along with an extensive information outreach effort, drought surcharges may be imposed. 83 If reduction goals were not being met, reduction targets may need to be developed for each customer class. Potential strategies for allocation plans are discussed above. The exact rates and rate structures would be established upon receipt of information regarding both the reduction requirement and applicable penalties and based on the utility’s overall revenue requirements. Water Use Restrictions Additional “emergency” water use restrictions would be added to the existing permanent restrictions. The amount of staff time dedicated to enforcement would be increased. STAGE IV: Critical Water Shortage – 35% to 50% target water savings A program to meet this level of water use reduction has not yet been implemented in the City. However, in the spring of 1991, the SFPUC adopted a program calling for reductions in this range. Although ultimately replaced with a less restrictive program, the City dis cussed what actions would be taken to meet the critical reduction targets. The program below outlines the major components of the plan to meet such a target. Information Outreach and Audit Programs All activities from Stage III would continue at further escalated levels. A greater focus will be placed on survival strategies and prioritization assistance for all customer classes. Incentive‐based Demand Side Management Programs Depending on what programs have been implemented prior to this stage, or current market saturations for certain devices, a selected number of indoor conservation incentives will be offered. These may include rebates for and/or free distribution of showerheads and faucet aerators, toilet modifications or retrofits, process water use modifications and use of recycled water. Drought Rate Structures At this level of reduction, an allotment method would be considered for each customer. The allocations would be sufficient for the most critical, high priority uses of water and the availability of water for outside use would be dramatically reduced. Various allotment methods are discussed in the previous section, Allocation/Allotment Methods. Water Use Restrictions Severe “emergency” water use restrictions, many of which will supers ede less stringent restrictions imposed in a less critical phase, will be added. Enforcement will be more rigorous in terms of hours of enforcement, number of staff involved, and the speed with which penalties are applied. 84 Alternative Water Supplies During a Water Shortage Recycled Water Use Recycled water offers an alternative source of water to those customers with valuable landscaping. The availability of contractors who can haul recycled water will be advertised. In addition, the City will rent tanker trucks to irrigate valuable City landscaping and street trees that will undoubtedly be stressed by a long‐term drought, the likely precursor to this stage of a water shortage. Groundwater In the event of a water shortage emergency, the City will evaluate the use of groundwater to meet any potable water supply deficiency. The City is limited in the amount of water that can be withdrawn from the local aquifer, so any decision to rely on groundwater will include consideration for operational limitations. Revenue and Expenditure Impacts and Measures to Overcome Impacts Law 10632. (a) The plan shall provide an urban water shortage contingency analysis which includes each of the following elements which are within the authority of the urban water supplier: …(7) An analysis of the impacts of each of the actions and conditions described in paragraphs (1) to (6), inclusive, on the revenues and expenditures of the urban water supplier, and proposed measures to overcome those impacts, such as the development of reserves and rate adjustments. (1) Stages of action to be undertaken by the urban water supplier in response to water supply shortages, including up to a 50 percent reduction in water supply, and an outline of specific water supply conditions that are applicable to each stage. (2) An estimate of the minimum water supply available during each of the next three water years based on the driest three-year historic sequence for the agency's water supply. (3) Actions to be undertaken by the urban water supplier to prepare for, and implement during, a catastrophic interruption of water supplies including, but not limited to, a regional power outage, an earthquake, or other disaster. (4) Additional, mandatory prohibitions against specific water use practices during water shortages, including, but not limited to, prohibiting the use of potable water for street cleaning. (5) Consumption reduction methods in the most restrictive stages. Each urban water supplier may use any type of consumption reduction methods in its water shortage contingency analysis that would reduce water use, are appropriate for its area, and have the ability to achieve a water use reduction consistent with up to a 50 percent reduction in water supply. (6) Penalties or charges for excessive use, where applicable. (7) An analysis of the impacts of each of the actions and conditions described in paragraphs (1) to (6), inclusive, on the revenues and expenditures of the urban water supplier, and proposed 85 measures to overcome those impacts, such as the development of reserves and rate adjustments. Impact on Expenditures Water utility expenditures can be generally categorized as fixed or variable expenses. The variable costs are almost entirely related to the costs of purchasing water supplies. Although the SFPUC supply costs are expressed as a variable commodity rate, the SFPUC system, like many water delivery systems, is almost exclusively a fixed cost conveyance and treatment system. As a retail provider, the City’s fixed costs primarily relate to the cost of operating and maintaining the City’s distribution system. Supply Reductions and Service Interruptions From a utility perspective, there is a downside to water conservation: the erosion of sales revenue. As consumers reduce their usage in response to the drought, the utility will experience a decline in sales. This decline in sales revenue will necessarily be greater than the associated decline in fixed expenses due to the volumetric retail rate structure. The impact of decreased revenues on operations can be mitigated to some extent by drawing upon cash reserve balances or enacting a rate increase. An approach for short‐term revenue shortfalls is to draw upon the utility’s cash reserves, if they are sufficient, to cover the financial obligations of the utility. Other options include short term borrowing, financing long‐term capital projects through revenue bonds rather than through current rates, or the implementation of drought surcharges to address the loss in sales revenue . Each of these approaches has its advantages and disadvantages. The appropriate response depends upon the specific circumstances facing the utility at that moment and other factors. Usage Reductions and Bans Implementation cost for the informational outreach programs, monitoring, and reporting during a water shortage increases during periods of voluntary and mandatory water use reductions. The 2015 state-mandated potable water use reductions cost the City an estimated $400,000. Estimates for those costs are $30,000 to $50,000 for voluntary programs. For mandatory programs, estimated costs are $400,000 to $600,000. The net effect is an increase in the expenses per unit of water sold. Penalties Excessive use penalties may be associated with certain drought rate structures described above. While additional staff resources would be needed to monitor customer use and install flow restrictors on excessive water users, it is difficult to quantify the cost of such a program. Reduction Measuring Mechanism Law 10632. (a) The plan shall provide an urban water shortage contingency analysis that includes each of the following elements that are within the authority of the urban water supplier: 86 …(9) A mechanism for determining actual reductions in water use pursuant to the urban water shortage contingency analysis. Under normal water supply conditions, the amount of water coming into the City from the SFPUC regional supply line is metered at the Arastradero, California, Page Mill, Sand Hill and Lytton turnouts. The daily meter readings are maintained at the Utility Control Center. Totals are reported monthly to CPAU for comparison to the billing amounts from the SFPUC. In water shortage periods, the mechanism for determining actual reductions in water use remains largely the same. The Director of Utilities would form an ad hoc Water Committee with representatives of all divisions to oversee outreach and monitoring efforts. During curtailment stages in a water shortage, supply figures are reported a daily basis. The Water Committee would provide timely reports to the City Council on the shortage and success of measures taken. If curtailment reaches Stage III or Stage IV, daily supply figures are reported to the Director of Utilities and the Water Committee. The Water Committee would report monthly to City Council or as frequently as information is requested by the City Council. Water Shortage Contingency Ordinance/Resolution Law 10632. (a) The plan shall provide an urban water shortage contingency analysis that includes each of the following elements that are within the authority of the urban water supplier: …(8) A draft water shortage contingency resolution or ordinance. The City has experienced three instances of water shortage due to drought in the last 35 years. A shorter duration drought occurred in l976‐77, and a longer water supply deficit occurred between l987 and l993. The current drought is ongoing. Appendix F provides a draft model ordinance that could be implemented during a water shortage emergency. 87 Section 8 – Supply and Demand Comparison Provisions Law 10635 (a) Every urban water supplier shall include, as part of its urban water management plan, an assessment of the reliability of its water service to its customers during normal, dry, and multiple dry water years. This water supply and demand assessment shall compare the total water supply sources available to the water supplier with the total projected water use over the next 20 years, in five‐year increments, for a normal water year, a single dry water year, and multiple dry water years. The water service reliability assessment shall be based upon the information compiled pursuant to Section 10631, including available data from the stat e, regional, or local agency population projections within the service area of the urban water supplier. Supply and Demand Comparison Since the City’s primary water supply is from the SFPUC, it is useful to examine the supply‐ demand comparison for the entire SFPUC system. Table 25 illustrates total system deliveries for both the retail and wholesale SFPUC customers. It indicates that during normal precipitation years, the SFPUC has adequate supplies to meet its contractual obligation to the wholesale customers of 184 MGD. Table 25: SFPUC System Supply (MGD)43 In adopting the WSIP, the SFPUC approved a water supply plan that provides for an Interim Supply Allocation with an automatic sunset in 2018. For the period up to the sunset of the ISL in 2018, Palo Alto’s Interim Supply Allocation is 14.70 MGD44. The SFPUC has deferred consideration of several supply issues until 2018 pending additional studies and analysis of the SFPUC system. For purposes of the 2015 UWMP, the SFPUC has provided a supply commitment of 184 MGD for the wholesale agencies through 2030. The City has an ISG of 17.07 MGD (or 19,118 AFY) and projects demands will remain below the City’s ISG through the 2010 UWMP planning horizon. Table 26 represents the City’s Supply and Demand balance for the 2015 planning horizon based on the City’s contractual entitlement with the SFPUC. 43 Letter from Paula Kehoe, SFPUC Director of Water Resources, to Nicole Sandkulla, BAWSCA, dated February 22, 2010. 44 As stated in earlier sections, the SFPUC unilaterally imposed the ISL on the BAWSCA agencies without prior agreement or discussion. The legality of the ISL is a potential future issue if deliveries from the regional system exceed the 265 MGD threshold for the ISL. Palo Alto’s ISG is a perpetual entitlement that can only be reduced pursuant to the terms outlined in the WSA. For planning purposes the City relies solely on the ISG. 2015 2020 2025 2030 2035 Wholesale Supply Total 184 184 184 184 184 SFPUC Retail Supply 81 81 81 81 81 System Supply Totals 265 265 265 265 265 88 Table 26: City of Palo Alto Supply/Demand Balance (AF) As previously discussed, projects as described in the WSIP will be required to meet demands during multiple dry years. The new water sources assumed to be available, with implementation dates, are summarized in Table 27. Table 27: SFPUC Water Supply Assumptions (AF/Y)45 46 Given the additional supplies assumed to be available, Appendix I Illustrates the level of single and multi-year water delivery shortages that can be expected in the future based on historical hydrologic periods and assuming the Wholesale customer normal year demand remains at 184 MGD. 45 Schedule for restoration of Crystal Springs Reservoir storage is tied to permitting requirements for endangered plants. 46 Release from Crystal Springs Reservoir to meet minimum in-stream flow requirement in San Mateo Creek began in January 2015. 2015 2020 2025 2030 2035 Palo Alto Demand for SFPUC Water 10,724 11,883 11,411 11,132 10,879 Individual Supply Guarantee 19,118 19,118 19,118 19,118 19,118 Difference 8,394 7,235 7,707 7,986 8,239 2015 2020 2025 2030 2035 2035 Westside Basin Groundwater (AF/Y) 8,100 8,100 8,100 8,100 8,100 Districts Transfer (AF/Y) 2,240 2,240 2,240 2,240 2,240 Crystal Springs Reservoir Capacity (20.3 BG)x x x x Calaveras Reservoir at Full Capacity x x x x x Alameda Creek Recapture (9.3 MGD)x x x x x Crystal Springs Reservoir Release for In-Stream Flow to San Mateo Creek (3.5 MGD) x x x x x x Calaveras Reservoir Release and Alameda Creek Diversion Dam Bypass for In- Stream Flow to Alameda Creek x x x x x Reservoir Operation Affecting Supply Water Supply Source 89 The impact on the City will depend on how the shortage is applied to the City. For wate r shortages up to 20%, the Tier One water shortage plan will be applied. The formula included in the Tier One plan indicates that the cutback for the City will be similar to the system‐wide cutback, but less than the average BAWSCA cutback. For system‐wide shortages greater than 20%, the SFPUC will follow the Tier One plan up to the 20% reduction, and meet and discuss incremental reductions above the Tier One plan with the wholesale customers. The SFPUC has the authority to make final allocation decision for the portion above 20%, though the wholesale customers have the contractual right to challenge the proposed approach.47 During a severe drought the City could utilize groundwater to supplement SFPUC supplies, but the City anticipates that even in dire circumstances only a small amount of groundwater would be served (e.g. < 10% of overall demand). In response to a severe drought the City would work with residents and businesses to significantly reduce water use, and groundwater from City wells would be considered a supplemental resource. Additional information on the City’s drought response is included in Section 7, “Water Shortage Contingency Plan.” 47 WSA, Section 3.11 (c )(3) 90 Page left intentionally blank for double‐sided printing. 91 APPENDIX A ‐ Resolution Adopting UWMP 92 Resolution No. _____ Resolution of the Council of the City of Palo Alto Adopting the 2015 Urban Water Management Plan to be Submitted to the California Department of Resources R E C I T A L S A. The California Legislature has enacted the Urban Water Management Planning Act, California Water Code Sections 10610 - 10656, as amended, which requires every urban water supplier providing water to more than 3,000 customers or supplying more than 3,000 acre-feet of water annually to prepare an urban water management plan ("Plan") that has as its primary objective the conservation and efficient use of water. B. The City of Palo Alto ("City"), a municipal utility and chartered city, is an urban water supplier providing water to a population over 60,000. C. The Plan must be reviewed at least once every five years by the City, which must amend the Plan, as necessary, after it has conducted a review. D. The preparation of the updated Plan has been coordinated with other public agencies to the extent practicable, and staff has encouraged the active involvement of diverse social, cultural and economic sectors of the population within the City's retail water service area during preparation of the Plan. E. The Plan must be adopted by July 1, 2016, after it is first made available for public inspection and a public hearing is noticed and held, and it must be filed with the California Department of Water Resources within thirty days of adoption. F. After reviewing a draft Plan at their April 12, 2016 meeting, the Utilities Advisory Commission recommended that the Council adopt the Plan as presented; and G. A noticed public hearing on the revised draft Plan was held by the City Council on May _______, 2016, at which time public comments were heard and considered. NOW, THEREFORE, the Council of the City of Palo Alto RESOLVES as follows: SECTION 1. The Council hereby adopts the 2015 Urban Water Management Plan of the City of Palo Alto, which shall be filed with the City Clerk. The City Manager is hereby authorized and directed to file the 2015 Urban Water Management Plan of the City of Palo Alto with the California Department of Water Resources and the State Library. 93 SECTION 2. The Council finds and determines that, under the California Water Code Section 10652, the adoption of the Plan and this resolution does not constitute a project under the California Environmental Quality Act, and no environmental assessment is required. INTRODUCED AND PASSED: AYES: NOES: ABSENT: ABSTENTIONS: ATTEST: ___________________________ ___________________________ City Clerk Mayor APPROVED AS TO FORM: APPROVED: ___________________________ ___________________________ Senior Deputy City Attorney City Manager ___________________________ Director of Utilities ___________________________ Director of Administrative Services 94 APPENDIX B ‐ Public Participation Notices 95 APPENDIX C ‐ Water Loss Report 96 Water Audit Report for:City of Palo Alto Reporting Year: All volumes to be entered as: ACRE-FEET PER YEAR WATER SUPPLIED Volume from own sources:n/a 0.000 acre-ft/yr Master meter error adjustment (enter positive value):n/a 0.000 Water imported:9 12,642.684 acre-ft/yr Water exported:n/a 0.000 acre-ft/yr WATER SUPPLIED:12,642.684 acre-ft/yr . AUTHORIZED CONSUMPTION Billed metered:7 11,584.745 acre-ft/yr Billed unmetered:n/a 0.000 acre-ft/yr Unbilled metered:n/a 0.000 acre-ft/yr Pcnt:Value: Unbilled unmetered:158.034 acre-ft/yr 1.25%24061 AUTHORIZED CONSUMPTION:11,742.779 acre-ft/yr WATER LOSSES (Water Supplied - Authorized Consumption)899.905 acre-ft/yr Apparent Losses Pcnt:Value: Unauthorized consumption:31.607 acre-ft/yr 0.25% Customer metering inaccuracies:5 277.615 acre-ft/yr 0.25% Systematic data handling errors:10 28.962 acre-ft/yr Apparent Losses:338.183 Real Losses (Current Annual Real Losses or CARL) Real Losses = Water Losses - Apparent Losses:561.722 acre-ft/yr WATER LOSSES:899.905 acre-ft/yr NON-REVENUE WATER NON-REVENUE WATER:1,057.938 acre-ft/yr = Total Water Loss + Unbilled Metered + Unbilled Unmetered SYSTEM DATA Length of mains:8 236.0 miles Number of active AND inactive service connections:6 27,701 Connection density:117 conn./mile main Average length of customer service line:5 0.0 ft Average operating pressure:10 72.2 psi COST DATA Total annual cost of operating water system:10 $39,097,916 $/Year Customer retail unit cost (applied to Apparent Losses):9 $7.62 Variable production cost (applied to Real Losses):10 $1,067.22 $/acre-ft PERFORMANCE INDICATORS Financial Indicators Non-revenue water as percent by volume of Water Supplied:8.4% Non-revenue water as percent by cost of operating system:4.8% Annual cost of Apparent Losses:$1,122,379 Annual cost of Real Losses:$599,480 Operational Efficiency Indicators Apparent Losses per service connection per day:10.90 gallons/connection/day Real Losses per service connection per day*:18.10 gallons/connection/day Real Losses per length of main per day*:N/A Real Losses per service connection per day per psi pressure:0.25 gallons/connection/day/psi Unavoidable Annual Real Losses (UARL):439.30 acre-feet/year From Above, Real Losses = Current Annual Real Losses (CARL):561.72 acre-feet/year 1.28 * only the most applicable of these two indicators will be calculated WATER AUDIT DATA VALIDITY SCORE: PRIORITY AREAS FOR ATTENTION: 1: Customer metering inaccuracies 2: Billed metered 3: Water imported Based on the information provided, audit accuracy can be improved by addressing the following components: *** YOUR SCORE IS: 82 out of 100 *** Infrastructure Leakage Index (ILI) [CARL/UARL]: Default option selected for unauthorized consumption - a grading of 5 is applied but not displayed $/100 cubic feet (ccf) A weighted scale for the components of consumption and water loss is included in the calculation of the Water Audit Data Validity Score 277.615 Choose this option to enter a percentage of billed metered consumption. This is NOT a default value Default option selected for Unbilled unmetered - a grading of 5 is applied but not displayed AWWA WLCC Free Water Audit Software: Reporting Worksheet 2014 7/2013 - 6/2014 << Enter grading in column 'E' acre-ft/yr ? ? ? ? ? ?Click to access definition ? ? ? ? ? ? Back to Instructions Please enter data in the white cells below. Where available, metered values should be used; if metered values are unavailable please estimate a value. Indicate your confidence in the accuracy of the input data by grading each component (1-10) using the drop-down list to the left of the input cell. Hover the mouse over the cell to obtain a description of the grades ? ? ? ? ? ? ? ? ? (pipe length between curbstop and customer meter or property boundary) Use buttons to select percentage of water supplied OR value ?Click here: for help using option buttons below For more information, click here to see the Grading Matrix worksheet ? Copyright © 2010, American Water Works Association. All Rights Reserved. ? ? ? ? WAS v4.2 97 APPENDIX D – DWR Standardized Tables 98 Public Water System Number Public Water System Name Number of Municipal Connections 2015 Volume of Water Supplied 2015 4310009 City of Palo Alto 19,863 10,177 19863 10,177 Table 2-1 Retail Only: Public Water Systems NOTES: TOTAL RUWMP includes a Regional Alliance RUWMP does not include a Regional Alliance Table 2-2: Plan Identification (Select One) Select One: Individual UWMP Regional UWMP (RUWMP) (checking this triggers the next line to appear) NOTES: Agency is a wholesaler Agency is a retailer UWMP Tables Are in Calendar Years UWMP Tables Are in Fiscal Years Unit AF NOTES: Table 2-3: Agency Identification Type of Agency (select one or both) Fiscal or Calendar Year (select one) If Using Fiscal Years Provide Month and Day that the Fiscal Year Begins (dd/mm) Units of Measure Used in UWMP (select from Drop down) 1/7 99 Table 2-4 Retail: Water Supplier Information Exchange The retail supplier has informed the following wholesale supplier(s) of projected water use in accordance with CWC 10631. Wholesale Water Supplier Name (Add additional rows as needed) San Francisco Public Utilities Commission NOTES: 2015 2020 2025 2030 2035 2040(opt) 67,400 70,500 73,700 77,100 80,800 84,600 Table 3-1 Retail: Population - Current and Projected Population Served NOTES: Table 3 in UWMP Use Type (Add additional rows as needed) Use Drop down list May select each use multiple times These are the only Use Types that will be recognized by the WUEdata online submittal tool Additional Description (as needed) Level of Treatment When Delivered Drop down list Volume Single Family Drinking Water 4,554 Multi-Family Drinking Water 1,530 Commercial Drinking Water 1,911 Industrial Drinking Water 397 Institutional/Governmental Drinking Water 623 Landscape Drinking Water 1,163 10,177 Table 4-1 Retail: Demands for Potable and Raw Water - Actual 2015 Actual NOTES: Table 11 in UWMP TOTAL Use Type (Add additional rows as needed) Use Drop down list May select each use multiple times These are the only Use Types that will be recognized by the WUEdata online submittal tool 2020 2025 2030 2035 2040-opt Single Family 4,972 4,829 4,712 4,605 4,523 Multi-Family 1,670 1,622 1,583 1,547 1,519 Commercial 2,086 2,026 1,977 1,932 1,898 Industrial 434 421 411 402 394 Institutional/Governmental 680 661 645 630 619 Landscape 1,269 1,233 1,203 1,176 1,155 11110.84 10792.76 10529.91 10291.67 10107.97 Table 4-2 Retail: Demands for Potable and Raw Water - Projected Additional Description (as needed) Projected Water Use Report To the Extent that Records are Available NOTES: Table 11 in UWMP TOTAL 100 2015 2020 2025 2030 2035 2040 (opt) Potable and Raw Water From Tables 4-1 and 4-2 10,177 11,111 10,793 10,530 10,292 10,108 Recycled Water Demand From Table 6-4 0 0 0 0 0 0 TOTAL WATER DEMAND 10,177 11,111 10,793 10,530 10,292 10,108 Table 4-3 Retail: Total Water Demands NOTES: Reporting Period Start Date (mm/yyyy) Volume of Water Loss 07/2013 562 NOTES: Table 4-4 Retail: 12 Month Water Loss Audit Reporting Are Future Water Savings Included in Projections? (Refer to Appendix K of UWMP Guidebook) Drop down list (y/n) No If "Yes" to above, state the section or page number, in the cell to the right, where citations of the codes, ordinances, etc… utilized in demand projections are found. Are Lower Income Residential Demands Included In Projections? Drop down list (y/n)Yes Table 4-5 Retail Only: Inclusion in Water Use Projections NOTES: Baseline Period Start Year End Year Average Baseline GPCD* 2015 Interim Target * Confirmed 2020 Target* 10-15 year 1995 2004 225 212 180 5 Year 2003 2007 208 Table 5-1 Baselines and Targets Summary Retail Agency or Regional Alliance Only *All values are in Gallons per Capita per Day (GPCD) NOTES: Extraordinary Events Economic Adjustment Weather Normalization TOTAL Adjustments Adjusted 2015 GPCD 153 198 0 0 0 0 153 153 Yes *All values are in Gallons per Capita per Day (GPCD) NOTES: Table 5-2: 2015 Compliance Retail Agency or Regional Alliance Only* Actual 2015 GPCD 2015 Interim Target GPCD 2015 GPCD (Adjusted if applicable) Did Supplier Achieve Targeted Reduction for 2015? Y/N Optional Adjustments to 2015 GPCD Enter "0" for adjustments not used From Methodology 8 101 Groundwater Type Drop Down List May use each category multiple times Location or Basin Name 2011 2012 2013 2014 2015 0 0 0 0 0 Table 6-1 Retail: Groundwater Volume Pumped Supplier does not pump groundwater. The supplier will not complete the table below. NOTES: TOTAL Add additional rows as needed Name of Wastewater Collection Agency Wastewater Volume Metered or Estimated? Drop Down List Volume of Wastewater Collected in 2015 Name of Wastewater Treatment Agency Receiving Collected Wastewater Treatment Plant Name Is WWTP Located Within UWMP Area? Drop Down List Is WWTP Operation Contracted to a Third Party? (optional) Drop Down List City of Palo Alto Metered 21,616 City of Palo Alto Regional Water Quality Control Plant Yes No 21,616 Table 6-2 Retail: Wastewater Collected Within Service Area in 2015 NOTES: Recipient of Collected Wastewater Total Wastewater Collected from Service Area in 2015: There is no wastewater collection system. The supplier will not complete the table below. Percentage of 2015 service area population covered by wastewater collection system (optional) Percentage of 2015 service area covered by wastewater collection system (optional) Wastewater Collection Add additional rows as needed Wastewater Treated Discharged Treated Wastewater Recycled Within Service Area Recycled Outside of Service Area Regional Water Quality Control Plant San Francisco Bay Bay or estuary outfall Yes Tertiary 21,616 19,759 818 410 Regional Water Quality Control Plant Bay via Emily Renzel Marsh Wetlands Yes Tertiary 629 Total 21,616 20,388 818 410 NOTES: Table 6-3 Retail: Wastewater Treatment and Discharge Within Service Area in 2015 Wastewater Treatment Plant Name Discharge Location Name or Identifier Discharge Location Description Wastewater Discharge ID Number (optional) Method of Disposal Drop down list Does This Plant Treat Wastewater Generated Outside the Service Area? Treatment Level Drop down list 2015 volumes No wastewater is treated or disposed of within the UWMP service area. The supplier will not complete the table below. Add additional rows as needed 102 General Description of 2015 Uses Level of Treatment Drop down list 2015 2020 2025 2030 2035 2040 (opt) Agricultural irrigation Landscape irrigation (excludes golf courses)Parks Tertiary 175 172 172 172 172 Golf course irrigation Palo Alto Municipal Tertiary 166 196 196 196 196 Commercial use RWQCP Tertiary 448 448 448 448 448 Geothermal and other energy production Seawater intrusion barrier Recreational impoundment Wetlands or wildlife habitat Palo Alto Duck Pond Tertiary 29 34 34 34 34 Groundwater recharge (IPR) Surface water augmentation (IPR) Direct potable reuse Other Type of Use Total:818 850 850 850 850 0 Recycled water is not used and is not planned for use within the service area of the supplier. The supplier will not complete the table below. Table 6-4 Retail: Current and Projected Recycled Water Direct Beneficial Uses Within Service Area Name of Agency Producing (Treating) the Recycled Water: Name of Agency Operating the Recycled Water Distribution System: Industrial use NOTES: Supplemental Water Added in 2015 Source of 2015 Supplemental Water Beneficial Use Type These are the only Use Types that will be recognized by the DWR online submittal tool IPR - Indirect Potable Reuse 2010 Projection for 2015 2015 actual use Landscape irrigation (excludes golf courses) Geothermal and other energy production Other Required for this use 850 815 850 815 Recycled water was not used in 2010 nor projected for use in 2015. The supplier will not complete the table below. Table 6-5 Retail: 2010 UWMP Recycled Water Use Projection Compared to 2015 Actual Use Type These are the only Use Types that will be recognized by the WUEdata online submittal tool NOTES: Recycled water was used in 2010 but the City did not provide a detailed 2015 recycled water use forecast. Total Groundwater recharge (IPR) Direct potable reuse Agricultural irrigation Industrial use Seawater intrusion barrier Recreational impoundment Wetlands or wildlife habitat Surface water augmentation (IPR) Golf course irrigation Commercial use 32-34 Name of Action Description Planned Implementation Year Expected Increase in Recycled Water Use 0 Table 6-6 Retail: Methods to Expand Future Recycled Water Use Total NOTES: Supplier does not plan to expand recycled water use in the future. Supplier will not complete the table below but will provide narrative explanation. Provide page location of narrative in UWMP Add additional rows as needed 103 21-25 Drop Down List (y/n)If Yes, Agency Name No expected future water supply projects or programs that provide a quantifiable increase to the agency's water supply. Supplier will not complete the table below. Some or all of the supplier's future water supply projects or programs are not compatible with this table and are described in a narrative format. Table 6-7 Retail: Expected Future Water Supply Projects or Programs Joint Project with other agencies? NOTES: Name of Future Projects or Programs Description (if needed) Planned Implementation Year Expected Increase in Water Supply to Agency This may be a range Planned for Use in Year Type Drop Down List User may select more than one. Provide page location of narrative in the UWMP Add additional rows as needed Water Supply Drop down list May use each category multiple times. These are the only water supply categories that will be recognized by the WUEdata online submittal tool Actual Volume Water Quality Drop Down List Total Right or Safe Yield (optional) Purchased or Imported Water SFPUC Regional Water Supply System 10,724 Drinking Water Recycled Water Recycled water from the Regional Water Quality Control Plant 858 Recycled Water 11,582 0 Table 6‐8 Retail: Water Supplies — Actual Additional Detail on Water Supply 2015 NOTES: Table 5 in UWMP Total Add additional rows as needed Water Supply Reasonably Available Volume Total Right or Safe Yield (optional) Reasonably Available Volume Total Right or Safe Yield (optional) Reasonably Available Volume Total Right or Safe Yield (optional) Reasonably Available Volume Total Right or Safe Yield (optional) Reasonably Available Volume Total Right or Safe Yield (optional) Purchased or Imported Water SFPUC Regional Water System 12,692 12,692 12,692 12,692 12,692 Recycled Water Recycled water from Regional Water Quality Control Plant 850 850 850 850 850 13,542 0 13,542 0 13,542 0 13,542 0 13,542 0 NOTES: Table 9 and Table 24 in UWMP Table 6‐9 Retail: Water Supplies — Projected Additional Detail on Water Supply Projected Water Supply Report To the Extent Practicable 2020 2025 2030 2035 2040 (opt) Total Drop down list May use each category multiple times. These are the only water supply categories that will be recognized by the WUEdata online submittal tool Add additional rows as needed 104 Volume Available % of Average Supply Average Year 2013 12,692 100% Single-Dry Year 2013 12,692 100% Multiple-Dry Years 1st Year 2013 12,692 100% Multiple-Dry Years 2nd Year 2013 11,425 90% Multiple-Dry Years 3rd Year 2013 11,425 90% Multiple-Dry Years 4th Year Optional Multiple-Dry Years 5th Year Optional Multiple-Dry Years 6th Year Optional NOTES: Table 24 in UWMP Agency may use multiple versions of Table 7-1 if different water sources have different base years and the supplier chooses to report the base years for each water source separately. If an agency uses multiple versions of Table 7-1, in the "Note" section of each table, state that multiple versions of Table 7- 1 are being used and identify the particular water source that is being reported in each table. Table 7-1 Retail: Basis of Water Year Data Year Type Base Year Agency may provide volume only, percent only, or both Available Supplies if Year Type Repeats 2020 2025 2030 2035 2040 (Opt) Supply totals (autofill from Table 6-9)13,542 13,542 13,542 13,542 13,542 Demand totals (autofill from Table 4-3)11,961 11,643 11,380 11,142 10,108 Difference 1,581 1,899 2,162 2,400 3,434 Table 7-2 Retail: Normal Year Supply and Demand Comparison NOTES: 2020 2025 2030 2035 2040 (Opt) Supply totals 13,542 13,542 13,542 13,542 13,542 Demand totals 13,542 13,542 13,542 13,542 13,542 Difference 0 0 0 0 0 Table 7-3 Retail: Single Dry Year Supply and Demand Comparison NOTES: SFPUC supply plus recycled water 105 2020 2025 2030 2035 2040 (Opt) Supply totals 13,542 13,542 13,542 13,542 Demand totals 13,542 13,542 13,542 13,542 Difference 0 0 0 0 0 Supply totals 12,275 12,275 12,275 12,275 12,275 Demand totals 13,542 13,542 13,542 13,542 13,542 Difference (1,267)(1,267)(1,267)(1,267)(1,267) Supply totals 12,275 12,275 12,275 12,275 12,275 Demand totals 13,542 13,542 13,542 13,542 13,542 Difference (1,267)(1,267)(1,267)(1,267)(1,267) Supply totals Demand totals Difference 0 0 0 0 0 Supply totals Demand totals Difference 0 0 0 0 0 Supply totals Demand totals Difference 0 0 0 0 0 Table 7-4 Retail: Multiple Dry Years Supply and Demand Comparison First year Second year Third year NOTES: Fourth year (optional) Fifth year (optional) Sixth year (optional) Percent Supply Reduction1 Numerical value as a percent Water Supply Condition (Narrative description) I 5-10%Minimum Water Shortage II 10-20%Moderate Water Shortage III 20-35%Severe Water Shortage IV 35-50%Critical Water Shortage Table 8-1 Retail Stages of Water Shortage Contingency Plan Stage Complete Both 1 One stage in the Water Shortage Contingency Plan must address a water shortage of 50%. NOTES: Add additional rows as needed 106 Stage Restrictions and Prohibitions on End Users Drop down list These are the only categories that will be accepted by the WUEdata online submittal tool Additional Explanation or Reference (optional) Penalty, Charge, or Other Enforcement? Drop Down List I Permanent restrictions in place with increased outreach Yes II Landscape - Other landscape restriction or prohibition No irrigation with potable water within 48 hours after measurable rainfall Yes II Landscape - Limit landscape irrigation to specific days 3 days per week April- October and 1 day per week November -March Yes II Other - Prohibit use of potable water for washing hard surfaces Health and safety excepted Yes II CII - Restaurants may only serve water upon request Yes II CII - Lodging establishment must offer opt out of linen service Yes III Landscape - Limit landscape irrigation to specific days 2 days per week April- october Yes III Other water feature or swimming pool restriction Filling of newly constructed pools, spas and hot tubs prohibited Yes III Other Water allocations may be imposed Yes III CII - Other CII restriction or prohibition Irrigation with potable water on golf courses limited to putting greens and tees Yes IV Other No new service connections unless customer pays for offsetting ocnservation Yes IV Landscape - Other landscape restriction or prohibition Drought-tolerant landscaping that minimizes irrigation and runoff required at construction sites Yes IV Landscape - Prohibit certain types of landscape irrigation Ornamental and turf irrigation Yes IV Other - Prohibit vehicle washing except at facilities using recycled or recirculating water Yes IV Landscape - Prohibit certain types of landscape irrigation Sprinkler irrigation prohibited Yes Table 8-2 Retail Only: Restrictions and Prohibitions on End Uses NOTES: Add additional rows as needed 107 Stage Consumption Reduction Methods by Water Supplier Drop down list These are the only categories that will be accepted by the WUEdata online submittal tool Additional Explanation or Reference (optional) I Expand Public Information Campaign I Offer Water Use Surveys I Provide Rebates on Plumbing Fixtures and Devices I Provide Rebates for Landscape Irrigation Efficiency I Provide Rebates for Turf Replacement II Other Offer free low-cost water saving devises II Increase Water Waste Patrols II Implement or Modify Drought Rate Structure or Surcharge III Other Possible allocations IV Other All of the above at increased levels Table 8-3 Retail Only: Stages of Water Shortage Contingency Plan - Consumption Reduction Methods NOTES: Pages 80-84 in UWMP Add additional rows as needed 2016 2017 2018 Available Water Supply 12,692 11,425 11,425 Table 8-4 Retail: Minimum Supply Next Three Years NOTES: Table 24 in UWMP 108 City Name 60 Day Notice Notice of Public Hearing Fremont San Mateo Brisbane x x Burlingame x x Daly City x x Hayward x x Millbrae x x Milpitas x x Mountain view x x Redwood City x x San Bruno x x Santa Clara x x Sunnyvale x x Half Moon Bay x x East Palo Alto x x Foster City x x Menlo Park x x Belmont x x Pacifica x x Los Altos Hills x x San Jose x x Stanford x x Hillsborough x x South San Francisco x x San Jose County Name Drop Down List 60 Day Notice Notice of Public Hearing Santa Clara County NOTES: Table 10-1 Retail: Notification to Cities and Counties Add additional rows as needed Add additional rows as needed 109 SB X7-7 Table 0: Units of Measure Used in UWMP* (select one from the drop down list) Acre Feet *The unit of measure must be consistent with Table 2-3 NOTES: Parameter Value Units 2008 total water deliveries 15,215.00 Acre Feet 2008 total volume of delivered recycled water 968 Acre Feet 2008 recycled water as a percent of total deliveries 6.37%Percent Number of years in baseline period1 10 Years Year beginning baseline period range 1995 Year ending baseline period range2 2004 Number of years in baseline period 5 Years Year beginning baseline period range 2003 Year ending baseline period range3 2007 SB X7-7 Table-1: Baseline Period Ranges 1 If the 2008 recycled water percent is less than 10 percent, then the first baseline period is a continuous 10-year period. If the amount of recycled water delivered in 2008 is 10 percent or greater, the first baseline period is a continuous 10- to 15-year period. 2 The ending year must be between December 31, 2004 and December 31, 2010. 3 The ending year must be between December 31, 2007 and December 31, 2010. 5-year baseline period Baseline 10- to 15-year baseline period NOTES: NOTES: SB X7-7 Table 2: Method for Population Estimates Method Used to Determine Population (may check more than one) 1. Department of Finance (DOF) DOF Table E-8 (1990 - 2000) and (2000-2010) and DOF Table E-5 (2011 - 2015) when available 3. DWR Population Tool 4. Other DWR recommends pre-review 2. Persons-per-Connection Method 110 Population Year 1 1995 56,647 Year 2 1996 56,885 Year 3 1997 57,420 Year 4 1998 57,868 Year 5 1999 58,136 Year 6 2000 58,467 Year 7 2001 59,334 Year 8 2002 60,028 Year 9 2003 59,930 Year 10 2004 59,894 Year 11 Year 12 Year 13 Year 14 Year 15 Year 1 2003 59,930 Year 2 2004 59,894 Year 3 2005 60,319 Year 4 2006 60,992 Year 5 2007 61,323 67,400 SB X7-7 Table 3: Service Area Population 10 to 15 Year Baseline Population 5 Year Baseline Population 2015 Compliance Year Population NOTES: Year 2015 111 Exported Water Change in Dist. System Storage (+/-) Indirect Recycled Water Fm SB X7-7 Table 4-B Water Delivered for Agricultural Use Process Water Fm SB X7-7 Table(s) 4-D Year 1 1995 13217.4816 0 0 0 0 0 13,217 Year 2 1996 15947.4105 0 0 0 0 0 15,947 Year 3 1997 15277.197 0 0 0 0 0 15,277 Year 4 1998 13676.2121 0 0 0 0 0 13,676 Year 5 1999 14610.8976 0 0 0 0 0 14,611 Year 6 2000 15426.6322 0 0 0 0 0 15,427 Year 7 2001 15449.9908 0 0 0 0 0 15,450 Year 8 2002 14775.4729 0 0 0 0 0 14,775 Year 9 2003 14174.3044 0 0 0 0 0 14,174 Year 10 2004 14978.5445 0 0 0 0 0 14,979 Year 11 0 0 0 0 0 Year 12 0 0 0 0 0 Year 13 0 0 0 0 0 Year 14 0 0 0 0 0 Year 15 0 0 0 0 0 9,836 Year 1 2003 14,174 0 0 0 0 0 14,174 Year 2 2004 14,979 0 0 0 0 0 14,979 Year 3 2005 13,538 0 0 0 0 0 13,538 Year 4 2006 13,322 0 0 0 0 0 13,322 Year 5 2007 14,603 0 0 0 0 0 14,603 14,123 10,724 0 0 0 0 0 10,724 Baseline Year Fm SB X7-7 Table 3 Volume Into Distribution System Fm SB X7-7 Table(s) 4-A Annual Gross Water Use Deductions * NOTE that the units of measure must remain consistent throughout the UWMP, as reported in Table 2-3 NOTES: SB X7-7 Table 4: Annual Gross Water Use * 2015 10 to 15 Year Baseline - Gross Water Use 10 - 15 year baseline average gross water use 5 Year Baseline - Gross Water Use 5 year baseline average gross water use 2015 Compliance Year - Gross Water Use 112 Volume Entering Distribution System Meter Error Adjustment* Optional (+/-) Corrected Volume Entering Distribution System Year 1 1995 13217.4816 0 13,217 Year 2 1996 15947.4105 0 15,947 Year 3 1997 15277.197 0 15,277 Year 4 1998 13676.2121 0 13,676 Year 5 1999 14610.8976 0 14,611 Year 6 2000 15426.6322 0 15,427 Year 7 2001 15449.9908 0 15,450 Year 8 2002 14775.4729 0 14,775 Year 9 2003 14174.3044 0 14,174 Year 10 2004 14978.5445 0 14,979 Year 11 0 0 Year 12 0 0 Year 13 0 0 Year 14 0 0 Year 15 0 0 Year 1 2003 14174.3044 0 14,174 Year 2 2004 14978.5445 0 14,979 Year 3 2005 13537.5689 0 13,538 Year 4 2006 13321.6506 0 13,322 Year 5 2007 14603.0762 0 14,603 10724.1345 0 10,724 SB X7-7 Table 4-A: Volume Entering the Distribution System(s) Complete one table for each source. 10 to 15 Year Baseline - Water into Distribution System 5 Year Baseline - Water into Distribution System 2015 Compliance Year - Water into Distribution System Name of Source Baseline Year Fm SB X7-7 Table 3 * Meter Error Adjustment - See guidance in Methodology 1, Step 3 of Methodologies Document NOTES: This water source is: The supplier's own water source A purchased or imported source 2015 SFPUC 113 Gross Water Use Without Process Water Deduction Industrial Water Use Percent Industrial Water Eligible for Exclusion Y/N Year 1 1995 13,217 0%NO Year 2 1996 15,947 0%NO Year 3 1997 15,277 0%NO Year 4 1998 13,676 0%NO Year 5 1999 14,611 0%NO Year 6 2000 15,427 0%NO Year 7 2001 15,450 0%NO Year 8 2002 14,775 0%NO Year 9 2003 14,174 0%NO Year 10 2004 14,979 0%NO Year 11 0 0 NO Year 12 0 0 NO Year 13 0 0 NO Year 14 0 0 NO Year 15 0 0 NO Year 1 2003 14,174 0%NO Year 2 2004 14,979 0%NO Year 3 2005 13,538 0%NO Year 4 2006 13,322 0%NO Year 5 2007 14,603 0%NO 10,724 0%NO NOTES: 2015 SB X7-7 Table 4-C.1: Process Water Deduction Eligibility Criteria 1 Industrial water use is equal to or greater than 12% of gross water use Baseline Year Fm SB X7-7 Table 3 10 to 15 Year Baseline - Process Water Deduction Eligibility 5 Year Baseline - Process Water Deduction Eligibility 2015 Compliance Year - Process Water Deduction Eligiblity 114 Industrial Water Use Population Industrial GPCD Eligible for Exclusion Y/N Year 1 1995 56,647 0 NO Year 2 1996 56,885 0 NO Year 3 1997 57,420 0 NO Year 4 1998 57,868 0 NO Year 5 1999 58,136 0 NO Year 6 2000 58,467 0 NO Year 7 2001 59,334 0 NO Year 8 2002 60,028 0 NO Year 9 2003 59,930 0 NO Year 10 2004 59,894 0 NO Year 11 0 0 NO Year 12 0 0 NO Year 13 0 0 NO Year 14 0 0 NO Year 15 0 0 NO Year 1 2003 59,930 0 NO Year 2 2004 59,894 0 NO Year 3 2005 60,319 0 NO Year 4 2006 60,992 0 NO Year 5 2007 61,323 0 NO 67,400 0 NO NOTES: 2015 SB X7-7 Table 4-C.2: Process Water Deduction Eligibility Criteria 2 Industrial water use is equal to or greater than 15 GPCD Baseline Year Fm SB X7-7 Table 3 10 to 15 Year Baseline - Process Water Deduction Eligibility 5 Year Baseline - Process Water Deduction Eligibility 2015 Compliance Year - Process Water Deduction Eligibility 115 Gross Water Use Without Process Water Deduction Fm SB X7-7 Table 4 Industrial Water Use Non-industrial Water Use Population Fm SB X7-7 Table 3 Non- Industrial GPCD Eligible for Exclusion Y/N Year 1 1995 13,217 13,217 56,647 208 NO Year 2 1996 15,947 15,947 56,885 250 NO Year 3 1997 15,277 15,277 57,420 238 NO Year 4 1998 13,676 13,676 57,868 211 NO Year 5 1999 14,611 14,611 58,136 224 NO Year 6 2000 15,427 15,427 58,467 236 NO Year 7 2001 15,450 15,450 59,334 232 NO Year 8 2002 14,775 14,775 60,028 220 NO Year 9 2003 14,174 14,174 59,930 211 NO Year 10 2004 14,979 14,979 59,894 223 NO Year 11 0 0 0 0 NO Year 12 0 0 0 0 NO Year 13 0 0 0 0 NO Year 14 0 0 0 0 NO Year 15 0 0 0 0 NO Year 1 2003 14,174 14,174 59,930 211 NO Year 2 2004 14,979 14,979 59,894 223 NO Year 3 2005 13,538 13,538 60,319 200 NO Year 4 2006 13,322 13,322 60,992 195 NO Year 5 2007 14,603 14,603 61,323 213 NO 10,724 10,724 67,400 142 NO NOTES: 2015 SB X7-7 Table 4-C.3: Process Water Deduction Eligibility Criteria 3 Non-industrial use is equal to or less than 120 GPCD Baseline Year Fm SB X7-7 Table 3 10 to 15 Year Baseline - Process Water Deduction Eligibility 5 Year Baseline - Process Water Deduction Eligibility 2015 Compliance Year - Process Water Deduction Eligiblity Service Area Median Household Income Percentage of Statewide Average Eligible for Exclusion? Y/N 2010 $53,046 0%YES NOTES: SB X7-7 Table 4-C.4: Process Water Deduction Eligibility Criteria 4 Disadvantaged Community Use IRWM DAC Mapping tool http://www.water.ca.gov/irwm/grants/resources_dac.cfm California Median Household Income 2015 Compliance Year - Process Water Deduction Eligibility A “Disadvantaged Community” is a community with a median household income less than 80 percent of the statewide average. 116 Service Area Population Fm SB X7-7 Table 3 Annual Gross Water Use Fm SB X7-7 Table 4 Daily Per Capita Water Use (GPCD) Year 1 1995 56,647 13,217 208 Year 2 1996 56,885 15,947 250 Year 3 1997 57,420 15,277 238 Year 4 1998 57,868 13,676 211 Year 5 1999 58,136 14,611 224 Year 6 2000 58,467 15,427 236 Year 7 2001 59,334 15,450 232 Year 8 2002 60,028 14,775 220 Year 9 2003 59,930 14,174 211 Year 10 2004 59,894 14,979 223 Year 11 0 0 0 Year 12 0 0 0 Year 13 0 0 0 Year 14 0 0 0 Year 15 0 0 0 225 Service Area Population Fm SB X7-7 Table 3 Gross Water Use Fm SB X7-7 Table 4 Daily Per Capita Water Use Year 1 2003 59,930 14,174 211 Year 2 2004 59,894 14,979 223 Year 3 2005 60,319 13,538 200 Year 4 2006 60,992 13,322 195 Year 5 2007 61,323 14,603 213 208 67,400 10,724 142 SB X7-7 Table 5: Gallons Per Capita Per Day (GPCD) Baseline Year Fm SB X7-7 Table 3 10 to 15 Year Baseline GPCD 10-15 Year Average Baseline GPCD 5 Year Baseline GPCD NOTES: 5 Year Average Baseline GPCD 2015 Compliance Year GPCD 2015 Baseline Year Fm SB X7-7 Table 3 225 208 2015 Compliance Year GPCD 142 SB X7-7 Table 6: Gallons per Capita per Day Summary From Table SB X7-7 Table 5 10-15 Year Baseline GPCD 5 Year Baseline GPCD NOTES: 117 Supporting Documentation Method 1 SB X7-7 Table 7A Method 2 SB X7-7 Tables 7B, 7C, and 7D Contact DWR for these tables Method 3 SB X7-7 Table 7-E Method 4 Method 4 Calculator SB X7-7 Table 7: 2020 Target Method Select Only One Target Method NOTES: 10-15 Year Baseline GPCD 2020 Target GPCD 225 180 SB X7-7 Table 7-A: Target Method 1 20% Reduction NOTES: 5 Year Baseline GPCD From SB X7-7 Table 5 Maximum 2020 Target* Calculated 2020 Target Fm Appropriate Target Table Confirmed 2020 Target 208 198 180 180 SB X7-7 Table 7-F: Confirm Minimum Reduction for 2020 Target * Maximum 2020 Target is 95% of the 5 Year Baseline GPCD NOTES: Confirmed 2020 Target Fm SB X7-7 Table 7-F 10-15 year Baseline GPCD Fm SB X7-7 Table 5 2015 Interim Target GPCD 180 225 203 SB X7-7 Table 8: 2015 Interim Target GPCD NOTES: Extraordinary Events Weather Normalization Economic Adjustment TOTAL Adjustments Adjusted 2015 GPCD 142 203 From Methodology 8 (Optional) From Methodology 8 (Optional) From Methodology 8 (Optional) 0 142.0458502 142.0458502 YES Optional Adjustments (in GPCD) NOTES: SB X7-7 Table 9: 2015 Compliance Did Supplier Achieve Targeted Reduction for 2015? Actual 2015 GPCD 2015 Interim Target GPCD 2015 GPCD (Adjusted if applicable) 118 APPENDIX E – City of Palo Alto Resolution Approving Water Shortage Allocation Plan (w/attachments) 119 120 121 122 TABLE 1- FIXED COMPONENT FOR USE IN TIER TWO ALLOCATION CALCULATION Wholesale Customer Fixed Comnonent ACWD 13.76 Brisbane/GVMID 0.98 Burlingame 5.23 Coastside 2.18 CWS Total 35.68 Daly City 4.29 East Palo Alto 1.96 Estero 5.90 Hayward 25.11 Hillsborough 4.09 Menlo Park 4.46 Mid Pen WD 3.89 Millbrae 3.15 Milpitas 9.23 Mountain View 13.46 North Coast 3.84 Palo Alto 17.07 Purissima Hills 1.62 Redwood City 10.93 San Bruno 3.25 San Jose 4.50 Santa Clara 4.50 Stanford 3.03 Sunnyvale 12.58 Westborough 1.32 123 TABLE 2 - BASE/SEASONAL CUTBACK CALCULATION FOR TIER TWO DROUGHT IMPLEMENTATION PLAN (DRIP) (Steps 1b-1f of DRIP Calculation) 124 Page 2 3. Base-Seasonal Alloc-Tbl 2 tables 125 APPENDIX F ‐ Water Shortage Contingency Plan Draft Ordinance 126 127 APPENDIX G ‐ Water Shortage Contingency Plan Evaluation Criteria 128 CRITERIA TO EVALUATE WATER SHORTAGE RESPONSE PLAN This appendix lists criteria expected to guide the selection of allocation/allotment strategies whenever water use reductions are needed. Not all of them may be applicable to every strategy but customer perception of equity is important in achieving the necessary reductions. 1. Reduce overall City consumption by reduction target required – this is the effective goal of any plan. To accomplish this goal the percentage reduction for the various customer classes will necessarily vary because their ratios of indoor/outdoor use varies. 2. Sufficient water available for personal use – the most important use of water is for basic drinking, health, and sanitary uses, and therefore, this is given the highest priority of use. This prioritization will drive both rate schedules and water use restrictions. However, within allowed limits (i.e., water use restriction ordinances), customers will be able to choose how they use their allotment between indoor and outdoor uses. 3. Acceptance by the community – many people tend to evaluate or accept a particular water‐ rationing plan in terms of how it would directly affect them. It is this aspect which makes it difficult to gain a popular consensus on any one plan. However, any plan must be generally accepted by the community to be successful. One important aspect of acceptance is the public’s understanding of the program; thus, it is viewed as important to make the plan as uncomplicated as possible. 4. Minimize unemployment or business loss – water is extensively used in both commercial and industrial functions. If water is severely limited to these consumers, increas ed unemployment and business losses could result. Staff intends that, wherever possible, this should be avoided. Still, outside water use must be sacrificed greatly if only minimal indoor reductions are required. Cooling tower use for air conditioning must also be considered. 5. Landscaping investment losses – in cases of critical or severe shortage of water, it is expected that significant landscaping losses may arise. The use of recycled water should be encouraged for certain applications. In some cases, using the City’s well system to augment the SFPUC supply will be an option to provide a minimum amount of water for landscaping. In this case, the goal should be to keep valuable and mature trees and plantings alive. Shrubs and lawns will be considered a lower priority. 6. Workable plan – the plan must be workable in order to accomplish its goal. It must take the following factors into account: a. Cost ‐ the cost of any water plan to the public should be minimized. b. Enforcement ‐ enforcement is viewed as a key component of any plan. Those plans requiring fewer resources for enforcement would be preferable. However, the success 129 of a plan is contingent upon effective enforcement and the utility must be provided the resources to meet the enforcement objective. The current staff can only absorb a certain level of additional responsibilities without unreasonably impacting service to the customer. c. The plan must be practical and feasible from a data processing viewpoint and not subject to erroneous results due to incomplete or inaccurate databases. A realistic timeframe must be allowed to perform any necessary data entry or customer programming functions. 9. Flexibility – the water shortage is a dynamic situation and may get better or worse. Thus, it is necessary that any plan be adaptable to changes in targets or adjustable if original expectations are not being met. 10. Allowance for new services – some provision must be made in any plan to serve new establishments or those under construction. 12. Recover penalties applied by suppliers – revenue should be collected to the extent necessary to recover any penalties that may be charged by suppliers. 130 APPENDIX H ‐ Water Shortage Contingency Plan Use Restrictions 131 WATER USE RESTRICTIONS Water use restrictions will depend on local conditions and on the length of the water shortage or drought. The City’s Water Shortage Contingency Plan identifies measures appropriate for various stages of action, based on reduction targets for each stage. Section A of this Appendix describes the City’s existing water use regulations. Section A-1 of this Appendix describes additional proposed permanent water use regulations to be adopted by City Council Ordinance. The restrictions in Section B are additional restrictions that could be applied in various stages or a drought or other water supply shortage. These staged restrictions are intended to serve as tools within the broader framework of the Urban Water Shortage Contingency Plan, to help the City reduce potable water consumption. Implementation of individual restrictions within each stage shall be carried out at the direction of the City Council, in response to its assessment of local water supply conditions, feasibility, and consumption trends. The Council may, in its discretion, opt to revise, delete or include different elements than those described below, so long as the restrictions implemented serve the overall purpose of reducing local consumption. A. Permanent Water Use Regulations (See Palo Alto Municipal Code Section 12.32.010) 1. Flooding or runoff of potable water into gutters, driveways, sidewalks, streets or other unlandscaped areas is prohibited. 2. An operating shut-off valve is required for hoses used to wash cars, boats, trailers, buses or other vehicles, or to wash sidewalks, building structures, other hard-surfaced areas or parts thereof. Use of a hose for such purposes should be avoided whenever possible. 3. Potable water for consolidation of backfill and other nondomestic uses in construction shall not be used if other water sources, such as reclaimed water, are available, as determined by the Director of Utilities or his or her designee. Applicants for hydrant permits from the city of Palo Alto shall be deemed to have consented to restrictions on water use which may be imposed by the Director of Utilities or his or her designee. 4. Any broken or defective plumbing, sprinklers, watering or irrigation systems which permit the escape or leakage of water shall be repaired or replaced as soon as possible, but no later than the date established by the Director of Utilities, or his or her designee, as reasonable after observation of the broken or defective system. A-1. Proposed Additional Water Use Restrictions, to be added to Palo Alto Municipal Code Section 12.32.010. 5. Ornamental landscape1 or turf irrigation with potable water shall not be allowed between 10:00 a.m. and 6:00 p.m., except via hand watering with a bucket or a hose with an operating shut-off valve. 132 6. The use of potable water in a fountain or other decorative water feature i s prohibited, except where the water is part of a recirculating system. 7. The use of potable water for street sweepers/washers is prohibited if non -potable water is available, as determined by the Director of Utilities, or his or her designee. 8. Commercial car washes must use recycled water systems, if economically feasible. B. Additional Restrictions Available for Council’s Consideration in Droughts or Other Water Supply Shortages Stage I: No additional restrictions Stage II: 1. Irrigation with potable water during and within 48 hours after a measurable rainfall, as determined by the Director of Utilities, or his or her designee, and posted on the Palo Alto website, is prohibited. 2. The irrigation of ornamental landscapes1 or turf with potable water more than three days per week is prohibited during the months of April through October.2 2. The irrigation of ornamental landscapes or turf with potable water more than one day per week is prohibited during the months of November through March. 2 3. The application of potable water to driveways and sidewalks is prohibited, except where necessary to address an immediate health and safety need or to comply with a term or condition in a permit issued by a state or federal agency. 4. Restaurants and other food service operations shall serve water to customers only upon request. 5. Operators of hotels and motels shall provide guests with the option of choosing not to have towels and linens laundered daily. The hotel or motel shall prominently display notice of this option in each guestroom using clear and easily understood language. Stage III: All water use restrictions for Stage II, and the following: 1. The irrigation of ornamental landscapes1 or turf with potable water more than two days per week is prohibited during the months of April through October.2 2. The filling of newly constructed pools, spas and hot tubs is prohibited. 3. Water allocations may be imposed. 4. Irrigation with potable water on golf courses is limited to putting greens and tees. Stage IV: All water use restrictions for Stages II and III, and the following: 1. No new water service connections are permitted unless the customer pays for sufficient conservation measures to be applied elsewhere in the City, to offset anticipated water use at the site to be served by the new water service, as determined by the City of Palo Alto. 133 2. Drought tolerant landscaping that minimizes irrigation and runoff is required at new construction sites, and non-drought tolerant landscaping is prohibited. 3. Ornamental landscape and turf irrigation with potable water is prohibited. 6. The washing of all vehicles is prohibited except for at commercial washing facility that recirculates its water or uses recycled water. 7. Sprinkler irrigation is prohibited. 1 “Ornamental landscapes” serve purely decorative purposes, and are distinguished from trees, edible gardens or landscapes that provide more than a purely aesthetic function. 2 Customers with a public or private non-residential facility containing ornamental landscapes or turf which supports a demonstrable business necessity or public benefit may apply for City approval of an alternative irrigation schedule. 134 APPENDIX I – Single and Multi Year Delivery Shortages 135 This table shows the SFPUC supplies that would be able to be delivered to the wholesale agencies in different hydrological conditions represented by each year from 1920 through 2011. This assumes that the wholesale customer demand is 184 MGD. The deliveries highlighted in yellow show hydrological years when a system-wide supply shortage of 10% would be experienced and the deliveries to the wholesale customers would be reduced by more than 15%. The deliveries shown highlighted in orange and bold are in years when a system -wide supply shortage of 20% would result in supplies to wholesale customers being reduced by more than 25%. Wholesale Demand=184 MGD Delivery For Fiscal Year 2010 2015 2020 2025 2030 1920 184 184 184 184 184 1921 184 184 184 184 184 1922 184 184 184 184 184 1923 184 184 184 184 184 1924 184 184 184 184 184 1925 154.6 184 184 184 184 1926 184 184 184 184 184 1927 184 184 184 184 184 1928 184 184 184 184 184 1929 184 184 184 184 184 1930 184 184 184 184 184 1931 184 184 184 184 184 1932 132.5 152.6 152.6 152.6 152.6 1933 184 184 184 184 184 1934 184 184 184 184 184 1935 154.6 184 184 184 184 1936 184 184 184 184 184 1937 184 184 184 184 184 1938 184 184 184 184 184 1939 184 184 184 184 184 1940 184 184 184 184 184 1941 184 184 184 184 184 1942 184 184 184 184 184 1943 184 184 184 184 184 1944 184 184 184 184 184 1945 184 184 184 184 184 1946 184 184 184 184 184 1947 184 184 184 184 184 1948 184 184 184 184 184 1949 184 184 184 184 184 1950 184 184 184 184 184 1951 184 184 184 184 184 1952 184 184 184 184 184 136 Wholesale Demand=184 MGD Delivery For Fiscal Year 2010 2015 2020 2025 2030 1953 184 184 184 184 184 1954 184 184 184 184 184 1955 184 184 184 184 184 1956 184 184 184 184 184 1957 184 184 184 184 184 1958 184 184 184 184 184 1959 184 184 184 184 184 1960 184 184 184 184 184 1961 152.6 184 184 184 184 1962 132.5 152.6 152.6 152.6 152.6 1963 184 184 184 184 184 1964 184 184 184 184 184 1965 184 184 184 184 184 1966 184 184 184 184 184 1967 184 184 184 184 184 1968 184 184 184 184 184 1969 184 184 184 184 184 1970 184 184 184 184 184 1971 184 184 184 184 184 1972 184 184 184 184 184 1973 184 184 184 184 184 1974 184 184 184 184 184 1975 184 184 184 184 184 1976 184 184 184 184 184 1977 152.6 184 184 184 184 1978 136.2 152.6 152.6 152.6 152.6 1979 184 184 184 184 184 1980 184 184 184 184 184 1981 184 184 184 184 184 1982 184 184 184 184 184 1983 184 184 184 184 184 1984 184 184 184 184 184 1985 184 184 184 184 184 1986 184 184 184 184 184 1987 184 184 184 184 184 1988 152.6 184 184 184 184 1989 132.5 152.6 152.6 152.6 152.6 1990 132.5 152.6 152.6 152.6 152.6 1991 132.5 132.5 132.5 132.5 132.5 1992 132.5 152.6 152.6 152.6 152.6 1993 136.2 132.5 132.5 132.5 132.5 1994 184 184 184 184 184 137 Wholesale Demand=184 MGD Delivery For Fiscal Year 2010 2015 2020 2025 2030 1995 154.6 184 184 184 184 1996 184 184 184 184 184 1997 184 184 184 184 184 1998 184 184 184 184 184 1999 184 184 184 184 184 2000 184 184 184 184 184 2001 184 184 184 184 184 2002 184 184 184 184 184 2003 184 184 184 184 184 2004 184 184 184 184 184 2005 184 184 184 184 184 2006 184 184 184 184 184 2007 184 184 184 184 184 2008 184 184 184 184 184 2009 184 184 184 184 184 2010 184 184 184 184 184 2011 184 184 184 184 184 Not Yet Approved 160229 jb 6053692 Resolution No. _____ Resolution of the Council of the City of Palo Alto Adopting the 2015 Urban Water Management Plan to be Submitted to the California Department of Resources R E C I T A L S A. The California Legislature has enacted the Urban Water Management Planning Act, California Water Code Sections 10610 - 10656, as amended, which requires every urban water supplier providing water to more than 3,000 customers or supplying more than 3,000 acre-feet of water annually to prepare an urban water management plan ("Plan") that has as its primary objective the conservation and efficient use of water. B. The City of Palo Alto ("City"), a municipal utility and chartered city, is an urban water supplier providing water to a population over 60,000. C. The Plan must be reviewed at least once every five years by the City, which must amend the Plan, as necessary, after it has conducted a review. D. The preparation of the updated Plan has been coordinated with other public agencies to the extent practicable, and staff has encouraged the active involvement of diverse social, cultural and economic sectors of the population within the City's retail water service area during preparation of the Plan. E. The Plan must be adopted by July 1, 2016, after it is first made available for public inspection and a public hearing is noticed and held, and it must be filed with the California Department of Water Resources within thirty days of adoption. F. After reviewing a draft Plan at their April 12, 2016 meeting, the Utilities Advisory Commission recommended that the Council adopt the Plan as presented; and G. A noticed public hearing on the revised draft Plan was held by the City Council on May _______, 2016, at which time public comments were heard and considered. NOW, THEREFORE, the Council of the City of Palo Alto RESOLVES as follows: SECTION 1. The Council hereby adopts the 2015 Urban Water Management Plan of the City of Palo Alto, which shall be filed with the City Clerk. The City Manager is hereby authorized and directed to file the 2015 Urban Water Management Plan of the City of Palo Alto with the California Department of Water Resources and the State Library. ATTACHMENT B Not Yet Approved 160229 jb 6053692 SECTION 2. The Council finds and determines that, under the California Water Code Section 10652, the adoption of the Plan and this resolution does not constitute a project under the California Environmental Quality Act, and no environmental assessment is required. INTRODUCED AND PASSED: AYES: NOES: ABSENT: ABSTENTIONS: ATTEST: ___________________________ ___________________________ City Clerk Mayor APPROVED AS TO FORM: APPROVED: ___________________________ ___________________________ Senior Deputy City Attorney City Manager ___________________________ Director of Utilities ___________________________ Director of Administrative Services NOT YET APPROVED 1 160301 jb 6053690 Ordinance No. _____ Ordinance of the Council of the City Of Palo Alto Amending Section 12.32.010, Water Use Restrictions and Section 12.32.020, Enforcement R E C I T A L S A. Article 10, Section 2 of the California Constitution declares that waters of the State are to be put to beneficial use, that waste, unreasonable use, or unreasonable method of use of water be prevented, and that water be conserved for the public welfare. B. The State of California is prone to drought conditions which result in water supply shortages. C. The City of Palo Alto recognizes the continuing need to manage water resources under its jurisdiction and control in a constitutionally compliant manner. D. Section 12.32.010 of the Palo Alto Municipal Code sets forth permanent water use restrictions applicable to all City water customers, in order to responsibly manage the City’s water resources. E. The Council wishes to adopt additional permanent water use restrictions in order to continue to responsibly manage this limited resource. F. City regulation of the time and manner of water use, rate design, the method of application of water for certain uses, and establishment of enforcement procedures in support of water use management is an effective and immediately available means of conserving water, and is authorized by Palo Alto Municipal Code Section 12.20.010. G. On September 15, 2014, the Council adopted Resolution 9460, establishing the enforcement process for violations of the three outdoor water use restrictions adopted by Council on August 4, 2014 (Resolution 9449). H. The Council now wishes to clarify the enforcement process for the water use regulations set forth in Chapter 12.32 of the Municipal Code. The Council of the City of Palo Alto ORDAINS as follows: SECTION 1. The Council hereby modifies Section 12.32.010 of the Palo Alto Municipal Code to add the following four water use restrictions to Section 12.32.010, as subsections (e) through (h): e.The irrigation of turf or ornamental landscapes, which serve purely decorative purposes, and are distinguished from trees, edible gardens or ATTACHMENT C 2 160302 syn 6053690 landscapes that provide more than a purely aesthetic function, with potable water shall not be allowed between 10:00 a.m. and 6:00 p.m., except via hand watering with a bucket or a hose with an operating shut-off valve. f. The use of potable water in a fountain or other decorative water feature is prohibited, except where the water is part of a recirculating system. g. The use of potable water for street sweepers and washers is prohibited if non-potable water is available, as determined by the Director of Utilities, or his or her designee. h. Commercial car washes must use recycled water systems, if recycled water is available, as determined by the Director of Utilities, or his or her designee, and economically feasible. SECTION 2. The Council hereby modifies Section 12.32.020 of the Palo Alto Municipal Code as follows: 12.32.020 Enforcement. In addition to enforcing the provisions of this chapter against any person as a misdemeanor, an infraction, or via the imposition of administrative fines or penalties, the city manager and his designated employees are authorized to enforce the provisions of this chapter against customers and water purchasers of the utility as follows: (a) Reports of alleged misuse of water in a manner contrary to the provisions of this chapter shall be called to the attention of the party responsible for the service connection misused and shall be investigated by the utilities department personnel to the extent possible. (b) Utilities department personnel shall issue a written warning to the responsible party or parties. (c) If a second or third incident of misuse of water in a manner contrary to the provisions of this chapter is established to the satisfaction of the utilities department personnel, up to two additional written warnings shall be issued to the responsible party or parties, advising that the City may opt to pursue available enforcement remedies, including the issuance of administrative citations, fines, infractions punishable by penalties, misdemeanors, flow restrictors, and termination of water service. (d) For any subsequent incident by the same party, customer, or water purchaser, or for any willful violation of this Chapter, the city manager or his designee may, in addition to the pursuit of any available enforcement remedies, elect to install a flow restrictor upon the service connection of the purchaser or customer at the purchaser's or customer's expense. 3 160302 syn 6053690 (i) Prior to installation of the water restrictor, the director of utilities shall give written notice to the person responsible for the service connection, which is to be restricted, of his intention to install a restrictor. The person or persons to whom notice is to be given shall have five business days from the date of service of the notice to request a hearing before the city manager or his designee in order to present any and all evidence they may have as to why a restrictor should not be installed or under what conditions it might be installed. (ii) If a hearing is requested, the city manager or his designee shall schedule a date and time for said hearing as soon as possible after the request is filed, but not later than five business days after the filing or such request for hearing. (iii) At the hearing, the person whose service connection is to be restricted may offer evidence as to why the restrictor should not be installed or under what conditions it might be installed. (iv) Utilities personnel shall also be allowed to offer whatever evidence they may have as to why the restrictor should be allowed and under what conditions. The city manager or his designees shall make a determination as to whether the restrictor shall or shall not be installed and what conditions, if any, should pertain. (v) Upon a determination to install a restrictor after hearing, or the failure of the affected party to request a hearing, the director of utilities, under whatever conditions, if any, he may deem advisable under the circumstances, may install a flow restrictor on the service connection of the customer or purchaser of water whose service connection was used in the violations observed or established and bill the costs of such installation to said customer or purchaser in accordance with the following conditions: (1) The first installation shall be for a period of three days; (2) Subsequent installations shall be for a period to be determined by the director of utilities, in an amount sufficient to accomplish the purposes of this chapter. Flow restrictors shall be installed in accordance with water utility rules and regulations. (e) Records shall be kept by the department of utilities of the city of Palo Alto of all enforcement actions taken under subsection (d) of this Section, and such records may be subject to disclosure as required by the California Public Records Act. SECTION 3. The Council hereby finds that this ordinance is categorically exempt from the provisions of the California Environmental Quality Act pursuant to Section 15307 and 4 160302 syn 6053690 15308 of the California Environmental Quality Act Guidelines (actions taken by regulatory agencies for the protection of natural resources and the environment). SECTION 4. This ordinance shall be effective on the thirty-first day after the date of its adoption. INTRODUCED: PASSED: AYES: NOES: ABSTENTIONS: ABSENT: ATTEST: _____________________________ _____________________________ City Clerk Mayor APPROVED AS TO FORM: APPROVED: _____________________________ ______________________________ Senior Deputy City Attorney City Manager ______________________________ Director of Administrative Services ______________________________ Director of Utilities